Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Oil Recovery,Wettability Alteration,"Esfandyari, Hamid; Hoseini, Atieh Haghighat; Shadizadeh, Seyed Reza; Davarpanah, Afshin",Simultaneous evaluation of capillary pressure and wettability alteration based on the USBM and imbibition tests on carbonate minerals,USBM test; Imbibition test; Nonionic natural surfactant; Capillary pressure; Wettability alteration,,"Wettability alteration would play a significant role in the hydrocarbon displacement as it can improve oil recovery factor both in conventional and unconventional reservoirs. Therefore, accurate prediction of this parameter would be of importance in displacement sweep efficiencies. In this paper, we aimed to experimentally investigate wettability changes in the presence of a nonionic natural surfactant (Cedar) for different carbonate mineral samples. To do this, Imbibition and USBM tests were taken into consideration to predict capillary pressure and how it affects oil production rate. It is observed that the presence of Cedar had a profound impact on the wettability and capillary pressure for calcite and dolomite samples. Due to the different composition of rock minerals, Cedar has a good effect on both core sample (calcite and dolomite), whereas the oil recovery for dolomite cores is more than calcite cores. This change for calcite cores corresponding oil-wet to neutral-wet or slightly water-wet and for dolomite samples become to water-wet. In addition, the most S-or decreasing occurs in dolomite samples particularly in D1 (14%). Moreover, the oil recovery for reservoir samples is less than mineral samples.",18,18,5
Oil Recovery,Wettability Alteration,"Mehrabianfar, Parviz; Bahraminejad, Hossein; Manshad, Abbas Khaksar",An introductory investigation of a polymeric surfactant from a new natural source in chemical enhanced oil recovery (CEOR),Interfacial tension (IFT); Surface tension (ST); Wettability alteration; Contact angle; Adsorption equilibrium; Adsorption isotherm model; Adsorption kinetic; Natural surfactant; Acanthephyllum,TRITERPENE SAPONINS; NONIONIC SURFACTANT; INTERFACIAL-TENSION; SOXHLET EXTRACTION; FUNCTIONAL-GROUPS; ADSORPTION; SANDSTONE; POLYSACCHARIDE; ANTIOXIDANT; IFT,"Greater than 50% of the original oil in place turns into immobile or trapped oil because of unfavored mobility and capillary forces problems. More efficient methods should be introduced in the tertiary oil recovery section as a scheme of Enhanced Oil Recovery (EOR). Surface-active-agents presented as surfactants play an important role in chemical EOR by their ability to optimize the operative parameters of interfacial/surface tension, wettability state, and modify the mobility of fluids in EOR processes. Beside all these optimizations induced to the fluid and rock of the reservoir, surfactants like other materials experience molecule losses by adsorption of solid/liquid interface. Great loss of surfactant molecules causes expensive materials cost and ineffectiveness of the benefits of these surface-active agents. Also, as literature reported, natural surfactants possess lower production costs, lower adsorption capacity, and environmentally friendly. This study introduces a new natural polymeric surfactant governed from the Acanthephyllum plant. Aqueous extraction process conducted and the extract was characterized by Fourier Transform Infrared spectroscopy (FTIR), Thermo-Gravimetric Analysis (TGA), and Proton Nuclear Magnetic Resonance spectroscopy (H-NMR). Characterization tests confirmed the polymeric state of the extract and the existence of surface-active functional groups in the extract. Interfacial tension (IFT) and surface tension (ST) between water-oil and water-air was measured respectively and showed a 92.6 and 61.6 percent optimization in their initial values in turn. Wettability alteration evaluated on a carbonate rock/crude oil/natural surfactant solution system and changed the oil wetness state of the initial oil-wet carbonate rock to a water wetness state because the wettability alteration measurements showed a reduction of the contact angle from 146 degrees to 64 degrees for only 80 min as the equilibrium time. Adsorption experiments conducted as adsorption isotherms and kinetic models. Freundlich isotherm fitted as the best model, and comparison of kinetic adsorption models for Acanthephyllum plant root extract as polymeric surfactant uptake shows that the pseudo-second-order model has the best accuracy and the pseudo-first-order model has the lowest accuracy.",15,15,6
Oil Recovery,Wettability Alteration,"Farhadi, Hamed; Ayatollahi, Shahab; Fatemi, Mobeen","The effect of brine salinity and oil components on dynamic IFT behavior of oil-brine during low salinity water flooding: Diffusion coefficient, EDL establishment time, and IFT reduction rate",Dynamic interfacial tension; Crude-oil/brine system; Time dependent adsorption; Low salinity effect; Asphaltene,INTERFACIAL-TENSION; WETTABILITY ALTERATION; CAPILLARY-PRESSURE; SURFACE-PROPERTIES; ADSORPTION; RECOVERY; SANDSTONE; RESERVOIR; ASPHALTENES; ELECTRONS,"Dynamic behavior of fluid-fluid interactions can potentially affect the performance of any enhanced oil recovery (EOR) process including low salinity water flooding. In this work, dynamic interfacial tension (IFT) of crude-oil/brine system is measured in a wide range of salinity of sea water (SW), from 50-time diluted sea water (SW50D) to 2-time concentrated sea water (SW2C). Contrary to the most of published IFT trends in the literature, for the system under investigation here, as the brine salinity increases the crude-oil/brine IFT reduces, which cannot be explained using the existing theories. The lack of a physical model to explain the observed phenomena was the motivation to develop a new model based on a drift-diffusion theory. This theory considers a current of oil polar molecules toward the oil-water interface which is caused by electrostatic attraction from aqueous ions (drift) and a resistance against this current caused by concentration gradient (diffusion). After applying this model to measured dynamic IFT data, the IFT reduction rate, and electrical double layer (EDL) establishment time are calculated. Then, these matching parameters set as criteria to explain the mechanisms behind the dynamic behavior of crude oil-saline water interfacial tension. For further investigation of the involved mechanisms which are responsible for the macroscopic behavior of crude-oil/brine dynamic IFT, the role of oil components is also examined using the IFT reduction rate and EDL establishment time. Although the obtained results show the asphaltene molecules play a vital role in the dynamic IFT behavior, the concentration of n-heptane, in the model oil containing n-heptane and toluene, is essential to capture the IFT behavior of the crude oil. Increasing n-heptane fraction in the model oil to the amount which exist in the crude oil, results in longer EDL establishment time which is in agreement with the crude oil sample.",11,11,1
Oil Recovery,Wettability Alteration,"Tetteh, Joel T.; Cudjoe, Sherifa E.; Aryana, Saman A.; Ghahfarokhi, Reza Barati",Investigation into fluid-fluid interaction phenomena during low salinity waterflooding using a reservoir-on-a-chip microfluidic model,Low salinity waterflooding; Microfluidics; Fluid-fluid interaction; Snap-off effect; Water-in-oil microdispersions,OIL-RECOVERY; CRUDE-OIL/BRINE; LIQUID-FILMS; SNAP-OFF; WATER; NANOPARTICLES; MECHANISMS; INTERFACE; FOAM; FLOW,"Injection of modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks has proven to be relevant to improved oil recovery operations. Many reports in the literature related the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which caused wettability alterations at the rock surface. Little attention appears to have been paid to fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigated the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations were correlated to visual observations of displacement processes in order to investigate the role of crude oil snap-off. Microfluidic devices featuring pore throats 50 mu m in diameter were used to observe snap-off as a function of salinity of the displacing fluid. Flow experiments suggested that, in a water-wet constricted pore throat, SWS brines suppressed crude oil snap-off as compared to formation water brine (FWS) brine. This behavior was correlated to the higher surface elasticity of oil-SWS interfaces than that of oil-FWS interfaces. Higher surface elasticity suppressed the expansion of the thin water film coating pore throat walls and hence it increased the capillary number at which snap-off of the crude oil phase was expected to occur. Moreover, water interacted with the polar components to form reverse micelles called microdispersions. These microdispersions were observed in both aged and non-aged microfluidic devices near oil-brine interfaces in the pore-network. Similarly, in a vial test performed by Tetteh and Barati (2019), microdispersion formation was only observed very close to oil-brine interfaces, caused by transport of water molecules into the oil phase due to reduced intermolecular forces at oil-LSW interfaces. This microdispersion formation was visualized using environmental scanning electron microscopy. These microdispersions remobilized, redistributed the oil, and along with a slight change in wettability in the medium, they improved the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributed to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.",9,10,5
Oil Recovery,Wettability Alteration,"Saadat, Marzieh; Yang, Junyi; Dudek, Marcin; Oye, Gisle; Tsai, Peichun Amy",Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability,Wettability alteration; Microfluidics; Surfactant flooding; Oil recovery; Enhanced oil recovery; Low salinity water flooding,LOW-SALINITY WATER; CRUDE-OIL; FINES MIGRATION; PHASE-BEHAVIOR; SURFACTANT; WET; DISPLACEMENT; EOR; ADSORPTION; SULFONATE,"Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.",8,9,11
Oil Recovery,Wettability Alteration,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Oil Recovery,Wettability Alteration,"Farhadi, Hamed; Fatemi, Mobeen; Ayatollahi, Shahab",Experimental investigation on the dominating fluid-fluid and rock-fluid interactions during low salinity water flooding in water-wet and oil-wet calcites,Low salinity water flooding; Enhanced oil recovery; Carbonate rock wettability alteration; Dynamic interfacial tension; Dynamic contact angle; Surface electric charges,INTERFACIAL INTERACTIONS; TENSION; RESERVOIR,"Low salinity water flooding (LSWF) has the potential to enhance the oil recovery by affecting the fluid-fluid and rock-fluid interactions. Therefore, a systematic investigation on the effect of initial wetting state (water-wet or oil-wet) of pure calcite is conducted to study the importance of these interactions on the effectiveness of LSWF. In the case of initially water-wet cores, more oil recovery efficiency is observed for more saline water cases. To shed light on the possible involved mechanisms, dynamic IFT, dynamic contact angle (CA), oil/brine and rock/brine surfaces zeta potentials, and effluent pH are measured. It is shown that the short-term effect of IFT reduction and long-term effect of wettability alteration toward neutral-wetness (due to change in the electric charge of the crude-oil/brine and calcite/brine) are the dominating recovery mechanisms. However, the oil recovery behavior of oil-wet cores is in the opposite direction of that of water-wet cores, which demonstrates the wettability dependency of the involved mechanisms. CA measurement shows that diluted sea water (dSW) has more ability to change wettability toward water-wetness. The zeta potential results show that as brine salinity reduces, both crude-oil and rock surfaces become more negatively charged. Therefore, the observed wettability alteration behavior with salinity reduction is attributed to larger repulsion between these surfaces at lower salinity. pH results suggest CO32- ions are responsible to make calcite surface more negative with diluting SW brine. The oil recovery behavior is also a strong function of the initial wetting state. SW brine, recovered less oil and experienced an earlier breakthrough in an initially oil-wet core compared to an initially water-wet core. Unlike the previous case, dSW experienced higher ultimate oil recovery and almost the same breakthrough time in an initially oil-wet core compared to an initially water-wet core. The superior performance of the low salinity water in an oil-wet core is a result of the wettability alteration toward more water-wetness which triggers more piston-like advancement.",7,7,3
Oil Recovery,Wettability Alteration,"Alizadeh, MohammadReza; Fatemi, Mobeen; Mousavi, Mohammad",Direct numerical simulation of the effects of fluid/fluid and fluid/rock interactions on the oil displacement by low salinity and high salinity water: Pore-scale occupancy and displacement mechanisms,Direct numerical simulation; Computational fluid dynamics; Dynamic contact angle; Dynamic interfacial tension; Low salinity water flooding,INTERFACIAL-TENSION IFT; WETTABILITY ALTERATION; SPECIES TRANSFER; POROUS-MEDIA; SMART WATER; INJECTION; RECOVERY; BRINE; FLOW; VOLUME,"Laboratory experiments have shown that performance of waterflooding in oil reservoirs could be significantly increased by lowering the ionic strength and/or manipulation of its composition, which is generally known as low salinity waterflooding (LSWF). The involved mechanisms in additional oil production can be generally categorized in two categories, fluid/fluid and fluid/rock interactions. The distribution of the phases and the involved displacement mechanisms would be strongly affected by the inter-relations between capillary and viscous forces. Although there have been recent advances in the simulation of the LSWF at core scale and beyond and some models are included in commercial core-scale/field-scale simulators, there are very few works that modelled and simulated this process at the pore scale. As a result the effects of wettability alteration and/or interfacial tension (IFT) change on the distribution of the phases at pore scale as well as dynamics of the displacement are not thoroughly investigated and not well understood, even in spite of many micromodel experiments. The aim of the present study is to investigate the fluids distribution, redistribution and dynamic of the displacement mechanisms at the true pore scale (inside a pore), by modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Simulation results show that in addition to the fluid/rock interactions, fluid/fluid interactions are also important in the effectiveness of LSWF and shall be considered in simulation studies. This is especially true in the case of non-water-wet systems. Our simulations provide new physical insights into LSWF and the dynamics of two-phase flow under wettability alteration as well as IFT changes induced by the LSWF, which cannot be easily captured by laboratory experiments. The results are also used to better explain some of the observed discrepancies in larger scales such as micromodel or coreflood experiments.",7,7,1
Oil Recovery,Wettability Alteration,"Xu, Derong; Li, Zhe; Bai, Baojun; Chen, Xin; Wu, Hairong; Hou, Jirui; Kang, Wanli",A systematic research on spontaneous imbibition of surfactant solutions for low permeability sandstone reservoirs,Surfactant imbibition; IFT reduction; Wettability alteration; Enhanced oil recovery; Low permeability reservoirs,ENHANCED OIL-RECOVERY; WETTABILITY ALTERATION; WET; MECHANISMS,"Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 degrees C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C12 surfactants), which was mainly depending on better IFT reduction ability of C16 surfactants than C12 surfactants. Appropriate IFT reduction, such as 10-1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10-2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs.",6,6,16
Oil Recovery,Wettability Alteration,"Chai, Rukuan; Liu, Yuetian; Liu, Qianjun; Gu, Wenhuan",Experimental and molecular dynamic simulation study on calcite-organic molecule-water interaction mechanism,Atomic force microscope; X-ray photoelectron spectroscopy; Molecular dynamic simulation; Calcite-organic molecule-water interaction; Bulk adsorption mechanism,FUNCTIONAL-GROUP ADSORPTION; WETTABILITY ALTERATION; CRUDE-OIL; CARBONATE; NITROGEN; ASPHALTENES; SCHEELITE; INTERFACE,"The mechanism of calcite-organic molecule-water interaction mechanism in oil-wet formation and alteration of carbonates is still ambiguous. This paper combines atomic force microscope (AFM), X-ray photoelectron spectroscopy (XPS) and molecular dynamic (MD) simulation to investigate the regularity and mechanism of calciteorganic molecule-water interaction at the molecular scale. First, the calcite-organic molecule-water interaction regularities, i.e., wettability alteration process, were studied using AFM, XPS and MD. AFM, XPS and MD results all demonstrated that acetic acid adsorbs stably on the calcite surface and can-not be displaced by water molecules, while the resistance to water displacement of the other three organic molecules decreased with decreasing molecular polarity. Subsequently, MD was used to analyze the calcite-organic molecule-water interaction mechanism from three perspectives, including the organic molecule-calcite interaction, the organic molecule-organic/water molecule interaction, and the effect of polar molecules. In the organic molecule-calcite interaction, the adsorption intensity of organic molecules on calcite surface decreases as their molecular polarity decreases. Stronger molecular polarity results in tighter adsorption layer and lower adsorption energy. In the organic molecule-organic/water molecule interaction, the interaction intensity increases as the polarity difference between the two molecules decreases. Larger polarity difference causes stronger miscibility and lower interaction energy. For polar molecules effect, the presence of polar molecules stabilizes the non-polar molecules adsorption and diminishes the displacement efficiency of water molecules. Consequently, this paper proposes the bulk adsorption mechanism to reasonably explain the wettability formation and alteration mechanism of calcite surface, which is of great importance for targeted enhanced oil recovery studies.",6,6,8
Oil Recovery,Wettability Alteration,"Ahsani, Tahoura; Tamsilian, Yousef; Rezaei, Alireza",Molecular dynamic simulation and experimental study of wettability alteration by hydrolyzed polyacrylamide for enhanced oil recovery: A new finding for polymer flooding process,Wettability alteration; Molecular dynamic; Hydrolyzed polyacrylamide; EOR process,DISPLACEMENT; TEMPERATURE; ADSORPTION,"Polymer flooding by hydrolyzed polyacrylamide (HPAM) is a well-known enhanced oil recovery (EOR) technique which is mainly applied to viscosify the pushing fluid and improve the mobility ratio; however, the role of this polymer on the rock wettability alteration, one of three main recovery mechanisms, has remained a topic of debate. In this study, the adsorption of hydrolyzed-polyacrylamide on the carbonate surface was investigated by molecular dynamic simulation considering a simple Young model based on the surface tensions of each phase to calculate the water contact angle and then continued by an experimental procedure after aging carbonate slices in the oil and polymer solutions. Dreiding and Universal force fields were selected for the simulation of water and HPAM boxes, respectively, to calculate non-bonding/bonding energies and surface tension for the water, polymer, and three-phase system including calcite rock. The polymer adsorbing decreased the final water contact angle to about 130 and 140 degrees at the ambient and reservoir temperatures, respectively, to provide a moderately oilwet state and a good agreement with the experimental results for the surface wettability alteration toward the water wetting. However, the theory and laboratory observations showed a different relation between the polymer adsorption and increasing temperature. Lennard-Jones potentials showed the polymer surface desorption at the increased kinetic energy of molecules due to the molecular distance whereas in the experiment condition the tendency of polymer adsorption on the calcite surface increased with temperature, probably because of ion exchange and thermal decarboxylation phenomenon. These findings make an opportunity to further molecular dynamic investigations of different polymers as a wettability modifier through the EOR process.",6,6,6
Oil Recovery,Wettability Alteration,"Santamaria, Oveimar; Lopera, Sergio H.; Riazi, Masoud; Minale, Mario; Cortes, Farid B.; Franco, Camilo A.",Phenomenological study of the micro- and macroscopic mechanisms during polymer flooding with SiO2 nanoparticles,Polymeric nanofluids; SiO2 nanoparticles; Microscopic oil displacement; Macroscopic oil displacement,ENHANCED-OIL-RECOVERY; RHEOLOGICAL PROPERTIES; SILICA NANOPARTICLES; POLYACRYLAMIDE SOLUTION; WETTABILITY ALTERATION; RELATIVE PERMEABILITY; ELEVATED-TEMPERATURES; POROUS-MEDIA; ADSORPTION; BEHAVIOR,"The incorporation of SiO2 nanoparticles in polymer solutions for oil recovery has generated considerable interest in recent research. Although this approach improves the polymer performance, little evidence is available about the recovery mechanisms that intervene in the polymeric nanofluid suspension or polymer nanofluid. Therefore, the purpose of this study is to describe the microscopic and macroscopic mechanisms involved during oil recovery with polymeric nanofluid flooding. Changes in the rheology and capillary forces (contact angle and interfacial tension) in the polymeric solution due to the incorporation of SiO2 nanoparticles were evaluated. Coreflooding tests were made to evaluate the retention, apparent viscosity, and impact on the relative permeability. Finally, macroscopic oil recovery was measured by displacement tests in a quarter 5-spot system, and microscopic displacement was evaluated by a microfluidic test. Results indicated that the conservation of a favorable mobility ratio in polymeric nanofluids along the porous medium is the phenomenon that most impacts macroscopic oil recovery. This behavior was associated with a reduction in loss retention and the conservation of the apparent viscosity in the porous medium. A direct relationship was observed between the concentration of SiO2 nanoparticles and the viscoelastic behavior of the polymer and the water-wet condition on the surface exposed to the nanofluid. Moreover, residual oil distribution in microscopic displacement revealed that the reduction in residual oil mainly originated from the decrease in the size of the oil clusters. Consequently, the evidence suggests that microscopic oil displacement in polymeric nanofluid is attributed to the reduction in the capillary forces and increases in the viscoelastic nature of the polymer. Results in this work indicated that the additional oil recovery obtained by polymeric nanofluid flooding is generated by the improvement of macroscopic recovery mechanisms and the activation of microscopic mechanisms.",6,6,5
Oil Recovery,Wettability Alteration,"Koegler, Felix; Mahler, Eva; Dopffel, Nicole; Schulze-Makuch, Dirk; Borovina, Ante; Visser, Foppe; Herold, Andrea; Alkan, Hakan",The Microbial Enhanced Oil Recovery (MEOR) potential of Halanaerobiales under dynamic conditions in different porous media,Microbial enhanced oil recovery; Carbonate dissolution; Dynamic experiments; Reservoir microbiology; Geomicrobiology; Halanaerobium; High salinity,WETTABILITY ALTERATION; BACILLUS; PERMEABILITY; MECHANISMS; INJECTION; RESERVOIR; MICROORGANISMS; STIMULATION; SANDSTONE; STRAINS,"As a dynamic screening tool for a high-salinity oilfield (186 g/L), anaerobic sandpacks were established to simulate Microbial Enhanced Oil Recovery (MEOR) under defined laboratory conditions. Glass beads, quartz sand or crushed reservoir rock were used to produce porous media which varied in permeability, wettability, homogeneity and geochemistry. In total, 14 sandpacks were flooded with oil and inoculated with indigenous fermentative bacteria of the order Halanaembiales. After waterflooding, these were treated with nutrients in different injection scenarios during which incremental oil recovery, permeability, microbial activity and produced metabolites were measured. Our results indicate that the efficiency of MEOR is dependent on the type of porous medium used: Both glass beads and outcrop quartz sand were found to be no suitable analogue to reservoir material because not all potential MEOR effects were accounted for. MEOR was least efficient in quartz sandpacks with a recovery factor of 7.0 +/- 1.7% with respect to the original oil in place (IRFOOIP), attributed mainly to fluid-fluid interactions. In sandpacks with reservoir rock, wettability alteration, matrix dissolution and bioplugging were additional MEOR mechanisms and resulted in an incremental recovery which was almost three-fold higher compared to pure quartz sandpacks (IRFOOIP), = 23.2 +/- 6.4%). Bioplugging was not detected in sandpacks with a permeability of 8-10 D, although cell retention was observed. Mean pore sizes of these sandpacks were calculated to be in the range of 100 mu m, thus considered to be too large to allow for significant plugging. Our findings support the use of MEOR as potential tertiary recovery method but also emphasize the importance of carefully designing laboratory experiments. We argue that porous medium properties such as permeability, pore size, wettability and mineralogy play a crucial role during dynamic MEOR feasibility studies, because they directly influence incremental recovery.",6,6,1
Oil Recovery,Wettability Alteration,"Rashidi, Mohammadamin; Kalantariasl, Azim; Saboori, Rahmatallah; Haghani, Abdolhossein; Keshavarz, Alireza",Performance of environmental friendly water-based calcium carbonate nanofluid as enhanced recovery agent for sandstone oil reservoirs,Wettability alteration; EOR; Calcium carbonate; Nanofluid; Sandstone,SURFACE-ENERGY CHARACTERIZATION; WETTABILITY ALTERATION; INTERFACIAL-TENSION; NANOPARTICLES; NANOCOMPOSITE; TEMPERATURE; SIO2; STABILIZATION; INHIBITION; FORCES,"Recent studies have demonstrated great potential of nanofluids as enhanced oil recovery (EOR) agent. Many mechanisms behind increasing oil recovery inducing alteration of surface wettability toward more water wet have been proposed when displacing oil by nanofluids. In this study, the effect of calcium carbonate nanofluid on wettability alteration of sandstone rock samples was studied. Nanoparticle was synthesized by chemical precipitation method and characterized by X-ray diffraction (XRD), fourier-transform infrared spectroscopy (FTIR), field emission scanning electron microscope (FE-SEM) and dynamic light scattering (DLS). The average particle size of nanoparticles was 55.4 nm. The rock samples were aged in oil to ensure desired oil-wet conditions. The effects of nanofluid concentration and temperature on wettability change were investigated and optimum concentration of calcium carbonate nanofluid was determined. Adsorption of nanoparticles on rock surface was characterized by FE-SEM. The wettability alteration was evaluated by measuring/calculating contact angle (static, advancing and receding), surface energy, liquid area fraction, and wettability index. 2-D oil-wet glass micromodel was used to compare the performance of optimum nanofluid concentration obtained from wettability tests against normal water flooding. Results showed alteration of wettability from oil-wet to water-wet for all nanofluid concentrations. More wettability alteration was observed at higher temperature (80 degrees C) than ambient conditions (25 degrees C). Optimum nanofluid concentration (0.025 wt%) was obtained that changed contact angle from 116.41 degrees (non-treated surface) to 46.99 degrees at 25 degrees C and 28.7 degrees at 80 degrees C. Flooding oil-wet 2-D glass micromodel with optimum nanofluid concentration resulted in 20% additional ultimate recovery factor compares to normal water flooding.",5,5,6
Oil Recovery,Wettability Alteration,"Chen, Weidong; Schechter, David S.",Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs,,WETTABILITY ALTERATION; ADSORPTION; WET,"Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures. Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure. The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition. In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants. The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.",5,5,3
Oil Recovery,Wettability Alteration,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Oil Recovery,Wettability Alteration,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Oil Recovery,Wettability Alteration,"Alnoush, Wajdi; Sayed, Amr; Solling, Theis I.; Alyafei, Nayef",Impact of calcite surface roughness in wettability assessment: Interferometry and atomic force microscopy analysis,Wettability; Contact angle measurements; AFM; Surface roughness; Interferometry,CONTACT-ANGLE MEASUREMENT; INTERFACIAL-TENSION; OIL-RECOVERY; CARBONATES; SALINITY; RESERVOIRS; MECHANISM; STORAGE; ROCK; TIME,"Wettability is a critical parameter that dictates various aspects related to the recovery of oil from reservoirs. Calcite rocks are used as minerals representative of carbonates to investigate the impact of surface roughness on wettability. Surface roughness was assessed using interferometry and atomic force microscopy (AFM). In this study, two case studies were investigated. The first case study characterizes the wettability of four different calcite samples with different surface roughnesses: naturally cleaved, and three samples grinded with diamond grit sizes of 1250, 1000 and 600. It is shown systematically that decreasing surface roughness results in acontact angle increases from 53 to 81 degrees that is towards the more water wet. In the second case study, the consistency of wettability measurements and trends from different spots of the same calcite surface was studied. For the latter, a total of four different naphthenic acids are added to n-decane to form model oils (the non-aqueous phase) that in principle will alter the wettability differently. In conjunction, four different brines with 1.5 mol% of NaCl, KCl, CaCl2 and Na2CO3, respectively were used to represent the aqueous phase. Wettability was characterized by static and dynamic (advancing and receding) contact angle measurements using the sessile and captive-drop methods, respectively. The results did not reveal any clear trend. A surface roughness analysis for the naturally cleaved calcite sample shed light on the absence of structure in how the electrolytic composition influences the contact angle. The variation in contact angle measurement is found to be large when comparing two different spots on the sample. Therefore, it is only possible to single out a trend when the parameter in concern is very evident such as the oil composition. More subtle trends, such as those that are induced by a brine variation, are hardly apparent and this may be even more important at elevated temperatures because of fluid motion.",5,5,1
Oil Recovery,Wettability Alteration,"Mahmoudpour, Maziar; Pourafshary, Peyman",Investigation of the effect of engineered water/nanofluid hybrid injection on enhanced oil recovery mechanisms in carbonate reservoirs,Engineered water; Nanoparticle; Microemulsion; Wettability alteration; Enhanced oil recovery,DETERMINING IONS CA2+; WETTABILITY ALTERATION; WATER INJECTION; CHALK; SALINITY; SEAWATER,"Changing the salinity and ionic composition of the injected water and designing ""engineered water"" (EW) is an enhanced oil recovery approach which affects the wettability of carbonate reservoirs and improves the oil recovery in many cases. Application of nanoparticles also affects oil production by various mechanisms such as altering the wettability, changing the viscosity of the oil and the injected fluid, and changing the interfacial tension. The benefits of combining these two approaches and developing a hybrid method are investigated in this paper. Experiments and measurements of different characteristics such as contact angle, zeta potential, particle size, ATR (attenuated total reflectance) analysis, ESEM (environmental scanning electron microscope) imaging, ion/nanoparticle deposition, and microemulsion formation were completed to analyze the influence of the hybrid method on rock/oil/brine interactions. Core flooding tests were also conducted to study the performance of the method to improve oil recovery. The most effective EW was selected by adjusting the concentrations of magnesium, calcium, and sulfate ions of Persian Gulf water. Nanoparticles such as SiO2, CaCO3, TiO2, and gamma Al2O3 were also studied to achieve the longest stability. Finally, the effect of combining the optimum states of engineered brine and nanoparticles on different mechanisms was investigated. Our results showed that spiking the injection brine with sulfate ions and using a hybrid method with silica nanoparticles at a concentration of 0.1 wt% provided the best effect on the enhanced oil recovery. This combination altered the wettability more than standalone methods. Also, there was a decrease in adsorption of nanoparticles on the rock surface, which controls the retention mechanism. Therefore, the presence of more nanoparticles in the fluid flow leads to the formation of microemulsions and increases in the viscosity of the injected fluid, which affects the sweep efficiency in porous media.",5,5,0
Oil Recovery,Wettability Alteration,"Okunade, Oluwagade Adenike; Yekeen, Nurudeen; Padmanabhan, Eswaran; Al-Yaseri, Ahmed; Idris, Ahmad Kamal; Khan, Javed Akbar","Shale core wettability alteration, foam and emulsion stabilization by surfactant: Impact of surfactant concentration, rock surface roughness and nanoparticles",Wettability; Surface roughness; Foam; Emulsion; Surfactants; Nanoparticles,ENHANCED OIL-RECOVERY; HUFF-N-PUFF; LAB(R) EXPERT ANALYSIS; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; SILICA NANOPARTICLES; NONIONIC SURFACTANTS; SIO2 NANOPARTICLES; CONTACT ANGLES; HIGH-PRESSURE,"Hexadecyltrimethyl ammonium bromide (HCTAB) and sodium dodecyl sulfate (SDS) are popular conventional surfactants with versatile industrial and oilfield applications. Knowledge of the optimum conditions for their applications for shale rock wettability modification, as well as foam and emulsion stabilization is relevant for hydrocarbon recovery process optimization. Influence of surfactant concentration, rock surface roughness and presence of nanoparticles in surfactant solutions on contact angles, oil-water interfacial tension (IFT), as well as foam and emulsion stabilization by HCTAB and SDS was investigated in this study. The interfacial properties measurements were conducted with Drop Shape Analyser (DSA 25), whereas the foam generation and stability properties were investigated via dynamic foam analyzer (DFA100). The emulsion stabilization and demulsification processes were investigated in Formulaction Turbiscan. Results showed an existence of optimum concentration of surfactant for obtaining the lowest contact angles, oil-water IFT reduction, as well as attaining maximum foam stability. The contact angle measured on rough core surfaces were smaller than the contact angle measured on smooth surfaces. Contact angles increased with increasing salnity concentration, but decreased with the increasing rock saturation time. Oil was more detrimental to foam stability when the generated foam was brought into contact with the resident oil, compared to when oil was added to the foaming solutions before foam generation. Lower contact angles, durable foam, and stable emulsion were produced in presence of oil and at high temperature via the synergy of nanoparticles and surfactants. Almost 66% decreased in contact angle was achieved with carbon nanotubes-SDS solutions, whereas Al2O3 nanoparticles-HCTAB foam attained a viscosity of 99 mPa-s at 60 degrees C. The foam demonstrated shear thinning Newtonian fluids behaviors but attained a plateau after sometimes. The study suggests the conditions for optimization of conventional surfactants applications in conventional and unconventional reservoir.",4,4,9
Oil Recovery,Wettability Alteration,"Souayeh, Maissa; Al-Maamari, Rashid S.; Karimi, Mahvash; Aoudia, Mohamed",Wettability alteration and oil recovery by surfactant assisted low salinity water in carbonate rock: The impact of nonionic/anionic surfactants,Wettability alteration; Nonionic surfactants; Anionic surfactants; Spontaneous imbibition; Carbonates,CLOUD POINT; SPONTANEOUS IMBIBITION; HIGH-TEMPERATURE; SMART WATER; WET; ADSORPTION; BEHAVIOR; COALESCENCE; ADDITIVES; LIMESTONE,"Combining low salinity water (LSW) and chemicals to enhance oil recovery has recently received more attention in the oil industry. In this study, a systematic experimental procedure was conducted to evaluate the performance of low salinity nonionic surfactant with/without anionic surfactant in wettability alteration and oil recovery of oil-wet carbonate having high salinity formation water (FW) (196 g/L) and moderate temperature (75 degrees C). A polyethoxylated nonionic surfactant (C13EO12 ) and two anionic surfactants: sulfonate (IOS 20-24) and carboxylate (AEC 938) were used in this study. Contact angle (CA) results showed that low salinity nonionic surfactant was effective in altering the wettability of oil-wet calcite toward water-wet state. While the low salinity anionic surfactants' systems were only able to reduce the oil-wetness of the oil-wet calcite. When nonionic surfactant is mixed with anionic surfactant, the wettability of oil-wet calcite was altered toward intermediate-wet or only a reduction of its oil-wetness occurred depending on the type of the anionic surfactant. Spontaneous imbibition tests using oil-wet limestone cores showed that among the low salinity single surfactants' systems, carboxylate anionic surfactant resulted in the highest oil recovery (61% of oil initially in place (OIIP)) and sulfonate anionic surfactant resulted in the lowest oil recovery (31% of OIIP). The low salinity nonionic surfactant recovered 51% of OIIP by spontaneous imbibition. Addition of sulfonate anionic surfactant to the nonionic surfactant resulted in an oil recovery of 49% of OIIP while addition of carboxylate anionic surfactant to the nonionic surfactant considerably improved the oil recovery to 74% of OIIP. Hence, selection of proper surfactant class is crucial for a successful oil recovery.",4,4,6
Oil Recovery,Wettability Alteration,"Al-Shirawi, Mariya; Karimi, Mahvash; Al-Maamari, Rashid S.",Impact of carbonate surface mineralogy on wettability alteration using stearic acid,Wettability alteration; Calcite; Limestone; Dolomite; Stearic acid,ORGANIC-COMPOUNDS; NATURAL CALCITE; FATTY-ACIDS; DOLOMITE; ADSORPTION; BEHAVIOR; IONS; SANDSTONE; PH,"Wettability alteration of the reservoir rock toward a favorable wetting state is one of the main recovery mechanisms during enhanced oil recovery (EOR) processes. A clear understanding of the initial wettability of the reservoir rock can be considered the first step toward a successful wettability alteration during any applied EOR technique. The present study investigates the impact of stearic acid on the wetting properties of several carbonate surfaces (calcite, limestone, and dolomite). A systematic experimental approach was followed in which contact angle measurements, Fourier transform infrared (FTIR) spectroscopy, energy dispersive X-ray spectroscopy (EDXS), scanning electron microscopy (SEM), thermo-gravimetric analysis (TGA), and zeta potential measurements were conducted on fresh carbonate samples as well as treated samples with stearic acid. Contact angle results revealed that all fresh carbonate surfaces were strongly water-wet. Aging in the model oil altered the wettability of the carbonates toward oil-wetness with an average contact angle of 159 degrees, 151 degrees, and 137 degrees for calcite, limestone, and dolomite surfaces, respectively. FTIR and EDXS results demonstrated the adsorption of stearic acid on the carbonate surfaces. Moreover, TGA results showed that the amount of adsorbed stearic acid on carbonate surfaces decreases in the following order: calcite (158.3 mu mol/g) > limestone (116.1 mu mol/g) > dolomite (46.4 mu mol/g). Zeta potential measurements revealed a shift toward more negative values after aging the carbonate surfaces in the model oil which confirms the adsorption of the stearic acid on surfaces. Despite the similarities between carbonate surfaces, the experimental observations clearly highlighted the significant impact of the mineralogical composition of the carbonate surface on the electrical and wetting properties of the surfaces. More positively charged surface of calcite resulted in more electrostatic attraction between the calcite and stearate ions which led to superior affinity of stearic acid toward calcite as compared with limestone and dolomite. The presence of other minerals with calcite on the carbonate surfaces affected the adsorption of stearic acid and the electrical properties of the surface.",4,4,6
Oil Recovery,Wettability Alteration,"Kondori, Javad; Miah, Mohammad Islam; Zendehboudi, Sohrab; Khan, Faisal; Heagle, Dru",Hybrid connectionist models to assess recovery performance of low salinity water injection,Low salinity water injection; Recovery factor; Smart tools; Statistical analysis; Variable ranking,ENHANCED OIL-RECOVERY; ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINES; REAL-TIME PREDICTION; WETTABILITY ALTERATION; COMPRESSIVE STRENGTH; POROUS-MEDIA; CRUDE-OIL; REGRESSION; RESERVOIRS,"The low salinity water injection (LSWI) is one of the emerging enhanced oil recovery techniques to improve both microscopic and macroscopic displacement efficiencies by creating a new streamline in petroleum reservoirs. While experimental studies are tedious, costly, and time-consuming, the smart connectionist tools are more reliable and cost-effective approaches to predict oil recovery factor (RF) without considerations of governing equations and physics behind production mechanisms in oil reservoirs. The main objective of this study is to investigate the data-driven model performance and variable contribution while predicting RF of LSWI processes. We introduce connectionist models using hybridized least squares support vector machine (LSSVM) with global optimization technique of coupled simulated annealing (CSA), and adaptive network-based fuzzy inference system (ANFIS). The extremely randomized tree or extra tree (ET) tool is also applied to forecast the RF and investigate the parameter contribution in the employed model. The model performance is examined using statistical parameters, including coefficient of determination, relative error, mean absolute percentage error, and mean squared error. According to the results, the ET and hybridized LSSVM-CSA models perform better than the ANFIS model in estimating RF. Utilizing the ET smart model, the total dissolved salts (TDS, ppm) is the most influential parameter, while the fluid injection rate has the minimum importance in the determination of RF. The current research confirms that LSSVM-CSA and ET techniques are able to obtain RF of LSWI with high accuracy and reliability, which can be used by researchers and engineers for better management of oil reservoirs under LSWI.",4,4,3
Oil Recovery,Wettability Alteration,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Oil Recovery,Wettability Alteration,"Afekare, Dayo; Garno, Jayne; Rao, Dandina",Enhancing oil recovery using silica nanoparticles: Nanoscale wettability alteration effects and implications for shale oil recovery,Nanofluid; Enhanced oil recovery; Atomic force microscope; Wettability; Nanoparticle; Tuscaloosa marine shale,PHASE-BEHAVIOR; ADHESION; ADSORPTION; PRESSURE; CONTACT; CURVES; CORES; FINES,"Enhanced oil recovery (EOR) techniques have the potential to improve recovery in unconventional shale oil reservoirs which have prolific short-term success but elusive near-to-long term outlook. The use of silicon dioxide nanoparticles for enhancing shale oil recovery has recently gained significant attention in the oil industry. However, the technique remains novel partly due to inadequate fundamental understanding of oil release mechanisms. Herein, the oil recovery potential of untreated and treated silica nanoparticles is investigated using an atomic force microscope (AFM) by studying nanoscale interactions between different crude oil functional species and substrates of pure minerals found in a shale oil reservoir. Quartz and muscovite mica (clay substitute) were employed as substrates as these are the dominant rock minerals identified in the most productive zone of Tuscaloosa Marine Shale (TMS). Thiolates of undecane (CH3) and phenyl (C6H5) compounds were used to simulate alkane and aromatic fractions of TMS crude oil respectively, while undecanoic acid (COOH) thiol was used to represent carboxylic acid found in asphaltene and resin components. Following our in-house experimental protocol for liquid cell force spectroscopy, adhesion forces and surface energies between functionalized AFM probes and mineral substrates were characterized in untreated and amino-treated silica nanoparticle dispersions. Zeta potential of respective nanofluid solutions was measured and AFM adsorption data were supported with scanning electron microscope (SEM) micrographs of TMS rock samples. Results showed that aqueous dispersions of hydrophilic silicon dioxide nanoparticles promote wettability towards a less oil-wet state by significantly lowering the adhesion force and energy barrier to spontaneously detach oil molecules from clay and quartz mineral surfaces in shale reservoirs, shown at the nanoscale with AFM studies. However, the grafting of aminosilanes onto surfaces of silica nanoparticles generally increased adhesion forces and surface energies due to surface charge effect and hydrophobicity. Findings pertinent to nanoparticle silanization were consistent in molecular interactions on mica in nanofluids but not necessarily predictable with quartz surfaces, highlighting mineralogical effects. The irreversible adsorption of silica nanoparticles was also observed. Adhesion force and energy are resolved in various intermolecular forces such as electric double layer repulsion, non-electrostatic interaction and structural forces. The scientific significance and broad engineering implications of results were comprehensively discussed in the context of previously reported core-to-field scale observations of nanofluid EOR. This study pitches new light on the scientific understanding of silica-based nanofluid EOR by probing nanoscale wetting effects of silica nanoparticles with implications for shale oil recovery. The findings herein can help for better understanding of the design of nanofluid EOR reagents and the conditions that favor application of silica nanofluid EOR.",3,3,8
Oil Recovery,Wettability Alteration,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Oil Recovery,Wettability Alteration,"Ali, Hassan; Soleimani, Hassan; Yahya, Noorhana; Khodapanah, Leila; Kozlowski, Gregory; Sabet, Maziyar; Demiral, Birol M. R.; Adebayo, Lawal Lanre; Hussain, Tanvir",Experimental investigation and two-phase flow simulation of oil and nanofluids on micro CT images of sandstone for wettability alteration of the system,Capillary pressure; Oil reservoir; Porous media; Permeability; Oil saturation,PORE NETWORK MODEL; POROUS-MEDIA; PERMEABILITY; TRANSPORT; WATER; MIGRATION; BRINE,"This work provides an analysis of the effect of nanofluids on the wettability of sandstone for the application of enhanced oil recovery. The wettability of sandstone with brine and nanofluids of ZnO, BiFeO3, and SrFeO3 is studied experimentally using contact angle calculations. Also, the direct simulations for the displacement of oil with brine and nanofluids are carried out on a micro-CT scanned porous sandstone structure for the measurement of capillary pressure and relative permeability. Fluid properties such as viscosity and density of the nanofluids, brine, and oil to be used in simulations were obtained using viscometer and densimeter. The experimental results show that the contact angle of crude oil on the sandstone surface has a higher value for nanofluids as 125.89 degrees for ZnO, 122.88 degrees for BiFeO3, and 104.98 for SrFeO3 as compared to brine 28.66 degrees, which means the wettability of the system changes from oil-wet to water-wet by the addition of nanofluids. The simulation results indicate that BiFeO3 nanofluid has a greater tendency to change the wettability of porous medium as compared to brine, ZnO, and SrFeO3 nanofluids, as it shows better values of relative permeability and capillary pressure.",3,3,5
Oil Recovery,Wettability Alteration,"Seetharaman, Gomathi Rajalakshmi; Jadhav, Rohan M.; Sangwai, Jitendra S.",Effect of monovalent and divalent alkali [NaOH and Ca(OH)(2)] on the interfacial tension of pure hydrocarbon-water systems relevant for enhanced oil recovery,Alkali; Hydrocarbons; Hydroxide ions; Interfacial tension; Temperature,SURFACE-TENSION; WETTABILITY ALTERATION; IONIC LIQUIDS; ASP; HYDROXIDE; IMIDAZOLIUM; SALINITY; BEHAVIOR; SALTS,"Although various efficient enhanced oil recovery (EOR) techniques have been proposed, the use of chemicals such as alkali, surfactants, and polymer in the field of EOR makes chemical EOR a promising method. The residual oil left behind after the secondary recovery process can be successfully displaced by decreasing the interfacial tension (IFT) between the liquid-liquid systems. Moreover, understanding the IFT between the liquid-liquid systems are essential in formulating and controlling the multiphase and multicomponent processes. As crude oil is a complex mixture of organic, inorganic compounds and heteroatoms, understanding the IFT of the pure hydrocarbon-water system is vital to develop robust models. In this study, the IFT between pure hydrocarbon-water systems in the presence of alkali has been explored. The IFT measurements were performed using a dynamic contact angle tensiometer using a Wilhelmy plate. Different hydrocarbon liquids such as hexane, heptane, decane and aromatics such as benzene and toluene were used. The monovalent NaOH and divalent alkali Ca(OH)(2) in the concentration range of 0-37.5 mM are used to understand the effect of alkali on the IFT of the oil-water system. This paper also elaborates on the effect of temperature at 298.15 K, 323.15 K and 348.15 K on the IFT of hydrocarbon-water systems. The experimental results show that the increase in the concentration of alkali continuously decreased the IFT of hydrocarbon-water systems. Moreover, it has been found that the type of alkali also has a reasonable impact on the IFT of the hydrocarbon-water system. The divalent alkali [Ca(OH)(2)] is found to be more efficient in reducing the IFT of both alkane-water and aromatic-water systems than the moderately performed monovalent alkali (NaOH). The possible mechanism for the continuous reduction in IFT has been proposed using surface adsorption of hydroxide ions at the interface of the oil-water system.",3,3,3
Oil Recovery,Surfactant,"Chaturvedi, Krishna Raghav; Sharma, Tushar",Rheological analysis and EOR potential of surfactant treated single-step silica nanofluid at high temperature and salinity,Agglomeration; Nanofluid; Oil recovery; Rheology; Salt; Surfactant; Viscosity,ENHANCED OIL-RECOVERY; INTERFACIAL-TENSION; POLYMER; NANOPARTICLE; STABILITY; POLYACRYLAMIDE; ADSORPTION; VISCOSITY; ABSORPTION; KINETICS,"Single-step nanofluids have shown better stability and size control properties than conventional two-step nanofluids under similar conditions. However, for wide-spread oilfield acceptance, there is a need to investigate the role of oilfield conditions viz., temperature, salt and pH on stability of single-step nanofluids. Thus, in this study, single-step silica nanofluids were synthesized in base fluid (1000 ppm polyacrylamide, PAM) and their stability was investigated using methods such as dynamic light scattering (DLS) and rheological analysis to establish their viability as suitable enhanced oil recovery (EOR) agents. PAM is a widely used oilfield practically applicable polymer. Primarily, the single-step silica nanofluids were found to destabilize at higher temperatures (>= 90 degrees C) due to thermal stability issues of PAM at high temperatures. This was also understood by PAM rheology. The inclusion of salt reduced the stability of nanofluids due to the suppression of inter-particle repulsive forces. The variation in pH also influenced nanofluid stability and pH range of 8-10 was observed for the stable behavior of nanofluids. The addition of an anionic surfactant (SDS) improved nanofluid stability by reducing salt-induced NP agglomeration; increasing surfactant concentration initially improved nanofluid resistance to salt induced agglomeration and at high surfactant concentrations, the nanofluids exhibited greater NP agglomeration even in the absence of salt. The oil recovery results also showed that surfactant use in the synthesis of silica nanofluid for oil recovery applications may provide better results than sole silica nanofluid. Based on the observations, surfactant treated single-step silica nanofluid use was found favorable for oilfield practices where conventional nanofluids may show challenges.",18,18,7
Oil Recovery,Surfactant,"Esfandyari, Hamid; Hoseini, Atieh Haghighat; Shadizadeh, Seyed Reza; Davarpanah, Afshin",Simultaneous evaluation of capillary pressure and wettability alteration based on the USBM and imbibition tests on carbonate minerals,USBM test; Imbibition test; Nonionic natural surfactant; Capillary pressure; Wettability alteration,,"Wettability alteration would play a significant role in the hydrocarbon displacement as it can improve oil recovery factor both in conventional and unconventional reservoirs. Therefore, accurate prediction of this parameter would be of importance in displacement sweep efficiencies. In this paper, we aimed to experimentally investigate wettability changes in the presence of a nonionic natural surfactant (Cedar) for different carbonate mineral samples. To do this, Imbibition and USBM tests were taken into consideration to predict capillary pressure and how it affects oil production rate. It is observed that the presence of Cedar had a profound impact on the wettability and capillary pressure for calcite and dolomite samples. Due to the different composition of rock minerals, Cedar has a good effect on both core sample (calcite and dolomite), whereas the oil recovery for dolomite cores is more than calcite cores. This change for calcite cores corresponding oil-wet to neutral-wet or slightly water-wet and for dolomite samples become to water-wet. In addition, the most S-or decreasing occurs in dolomite samples particularly in D1 (14%). Moreover, the oil recovery for reservoir samples is less than mineral samples.",18,18,5
Oil Recovery,Surfactant,"Mehrabianfar, Parviz; Bahraminejad, Hossein; Manshad, Abbas Khaksar",An introductory investigation of a polymeric surfactant from a new natural source in chemical enhanced oil recovery (CEOR),Interfacial tension (IFT); Surface tension (ST); Wettability alteration; Contact angle; Adsorption equilibrium; Adsorption isotherm model; Adsorption kinetic; Natural surfactant; Acanthephyllum,TRITERPENE SAPONINS; NONIONIC SURFACTANT; INTERFACIAL-TENSION; SOXHLET EXTRACTION; FUNCTIONAL-GROUPS; ADSORPTION; SANDSTONE; POLYSACCHARIDE; ANTIOXIDANT; IFT,"Greater than 50% of the original oil in place turns into immobile or trapped oil because of unfavored mobility and capillary forces problems. More efficient methods should be introduced in the tertiary oil recovery section as a scheme of Enhanced Oil Recovery (EOR). Surface-active-agents presented as surfactants play an important role in chemical EOR by their ability to optimize the operative parameters of interfacial/surface tension, wettability state, and modify the mobility of fluids in EOR processes. Beside all these optimizations induced to the fluid and rock of the reservoir, surfactants like other materials experience molecule losses by adsorption of solid/liquid interface. Great loss of surfactant molecules causes expensive materials cost and ineffectiveness of the benefits of these surface-active agents. Also, as literature reported, natural surfactants possess lower production costs, lower adsorption capacity, and environmentally friendly. This study introduces a new natural polymeric surfactant governed from the Acanthephyllum plant. Aqueous extraction process conducted and the extract was characterized by Fourier Transform Infrared spectroscopy (FTIR), Thermo-Gravimetric Analysis (TGA), and Proton Nuclear Magnetic Resonance spectroscopy (H-NMR). Characterization tests confirmed the polymeric state of the extract and the existence of surface-active functional groups in the extract. Interfacial tension (IFT) and surface tension (ST) between water-oil and water-air was measured respectively and showed a 92.6 and 61.6 percent optimization in their initial values in turn. Wettability alteration evaluated on a carbonate rock/crude oil/natural surfactant solution system and changed the oil wetness state of the initial oil-wet carbonate rock to a water wetness state because the wettability alteration measurements showed a reduction of the contact angle from 146 degrees to 64 degrees for only 80 min as the equilibrium time. Adsorption experiments conducted as adsorption isotherms and kinetic models. Freundlich isotherm fitted as the best model, and comparison of kinetic adsorption models for Acanthephyllum plant root extract as polymeric surfactant uptake shows that the pseudo-second-order model has the best accuracy and the pseudo-first-order model has the lowest accuracy.",15,15,6
Oil Recovery,Surfactant,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Oil Recovery,Surfactant,"Saadat, Marzieh; Yang, Junyi; Dudek, Marcin; Oye, Gisle; Tsai, Peichun Amy",Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability,Wettability alteration; Microfluidics; Surfactant flooding; Oil recovery; Enhanced oil recovery; Low salinity water flooding,LOW-SALINITY WATER; CRUDE-OIL; FINES MIGRATION; PHASE-BEHAVIOR; SURFACTANT; WET; DISPLACEMENT; EOR; ADSORPTION; SULFONATE,"Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.",8,9,11
Oil Recovery,Surfactant,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Oil Recovery,Surfactant,"Onaizi, Sagheer A.; Alsulaimani, Mohammed; Al-Sakkaf, Mohammed K.; Bahadi, Salem A.; Mahmoud, Mohamed; Alshami, Ali",Crude oil/water nanoemulsions stabilized by biosurfactant: Stability and pH-Switchability,Crude oil/water nanoemulsions; Emulsion stability; Rhamnolipid biosurfactant; pH-responsive; Demulsification; Droplet size,OIL-IN-WATER; INTERFACIAL-TENSION; POROUS-MEDIA; SURFACTIN BIOSURFACTANT; SILICA NANOPARTICLES; RECOVERY; EMULSIONS; EMULSIFICATION; COMBINATION; BACTERIA,"Emulsification is one of the proposed mechanisms for enhancing crude oil recovery in chemical flooding. The replacement of chemical surfactants in enhanced oil recovery (EOR) applications with biosurfactants is an attractive alternative; yet, there is a lack of studies on the crude oil emulsification using biosurfactants. Particularly, the formulation of crude oil/water (crude O/W) nanoemulsions with an extreme stability and a pH-responsiveness behavior is still not documented in the literature, to the best of our knowledge. Accordingly, we report in this study the preparation of both light and heavy crude oil/water emulsions using different concentrations of the rhamnolipid biosurfactant. The emulsions were prepared in a two-step process: stirring overnight to create coarse emulsions followed by sonication. All the prepared emulsions have a nanoscale size (e.g., about 50% of the formed droplets at 0.1 wt% rhamnolipid are < 200 nm in size), which decreases with increasing the biosurfactant concentration. The zeta potential values of the formed crude O/W nanoemulsions were highly negative (<=-39.3). Increasing the biosurfactant concentration resulted in a more negative zeta potential. The formulated crude O/W nanoemulsions were extremely stable with 0% oil or water separation even after a month of storage. Despite the extreme stability of these crude O/W nanoemulsions, they could be easily switched off (i. e., demulsified) within 1 h by pH-swing via the addition of 50 mM sulfuric acid (H2SO4) regardless of the bioemulsifier (i.e., rhamnolipid) concentration. It was also possible to switch on/off the crude O/W nanoemulsions a number of times (at least five times) through this pH-swing mechanism. We also demonstrated that the crude O/W nanoemulsions can be completely switched off through the addition of NaOH, particularly, when these crude O/W nanoemulsions are stabilized by low rhamnolipid dosages (<= 0.5 wt%); such an observation is very unusual. The findings reported in this study clearly demonstrate the ability of creating extremely stable crude O/W nanoemulsions, which is desirable in EOR; however, the emulsified crude oil can be easily and economically recovered via a simple and an economic process (i.e., pH-switch) with the ability to switch off/on the emulsion several times.",7,7,6
Oil Recovery,Surfactant,"Xu, Derong; Li, Zhe; Bai, Baojun; Chen, Xin; Wu, Hairong; Hou, Jirui; Kang, Wanli",A systematic research on spontaneous imbibition of surfactant solutions for low permeability sandstone reservoirs,Surfactant imbibition; IFT reduction; Wettability alteration; Enhanced oil recovery; Low permeability reservoirs,ENHANCED OIL-RECOVERY; WETTABILITY ALTERATION; WET; MECHANISMS,"Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 degrees C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C12 surfactants), which was mainly depending on better IFT reduction ability of C16 surfactants than C12 surfactants. Appropriate IFT reduction, such as 10-1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10-2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs.",6,6,16
Oil Recovery,Surfactant,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Oil Recovery,Surfactant,"Elmobarak, Wamda F.; Almomani, Fares",Application of magnetic nanoparticles for the removal of oil from oil-in-water emulsion: Regeneration/reuse of spent particles,Oil-in-water emulsion (O-in-W-Emu); Fe3O4 magnetic nanoparticles; Demulsification efficiency; Oil removal,IRON-OXIDE NANOPARTICLES; SOLUTION-COMBUSTION SYNTHESIS; WASTE-WATER; FE3O4 NANOPARTICLES; HYDROTHERMAL SYNTHESIS; EFFICIENT SEPARATION; EPITAXIAL-FILMS; CRUDE-OIL; ADSORPTION; FACILE,"The recovery of oil from produced water (PW) is integral for minimizing energy resource loses and creating an appropriate treatment method for a sustainable environment. In this study, Fe3O4 magnetic nanoparticles (Fe-MNP) were synthesized using the combustion synthesis method (CSM) in the temperature range of 150 to 350 degrees C. The Fe-MNP were characterized using various analytical techniques and were used to recover oil from oil-inwater emulsion (O-in-W-emu) at various concentrations. The effects of the process parameters including, pH, oil concentration (C-oil), Fe-MNP dose (D-MNP), the surfactant concentration (C-sur) on the demulsification efficiency (%(eta dem)), and the percentage oil removal (%R-oil) were studied. Further, the re-usability of the assynthetized Fe-MNP were examined and reported. The as-synthetized Fe-MNP achieved a %(eta dem) >= 98% for C-oil in the range of 200-660 mg/L. Up to 98.6% of the %(eta dem) was attained for C-oil in the range from 0 to 800 mg/L using only a DMNP of 10 mg/L. A lower D-MNP of 5 mg/L recovered up to 55.6% of the oil, while increasing the D-MNP > 50 mg/L did not significantly affect the %(eta dem) nor the %(eta dem). The observed %(eta dem) at a pH of 4 and C-sur of 0.05 g/L was observed to be > 90 + 0.1% and decreased by either rising the pH to 7 or increasing the C-sur to 0.1 g/L. This change is due to the decrease in the emulsion stability and the formation of fine oil droplets. Stability and re-usability tests of the as-synthetized Fe-MNP exhibited an effective oil recovery of up to 90% after 7 cycles. The as-synthesized Fe-MNP demulsifier exhibited an excellent adsorption capacity of 51 mg/g and best fit the Langmuir and Freundlich models. The kinetics of the oil recovery process are properly adapted to fit the pseudosecond-order model for the C-oil and D-MNP. The tests indicated that the fastest and highest adsorption capacity was achieved at a D-MNP (100 mg/L). As such, the results indicate that the developed Fe-MNP are an effective and reusable demulsifier, which are suitable for the oil recovery of produced water (PW).",5,5,7
Oil Recovery,Surfactant,"Chen, Weidong; Schechter, David S.",Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs,,WETTABILITY ALTERATION; ADSORPTION; WET,"Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures. Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure. The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition. In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants. The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.",5,5,3
Oil Recovery,Surfactant,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Oil Recovery,Surfactant,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
Oil Recovery,Surfactant,"Jing, Wenlong; Fu, Shuaishi; Zhang, Lei; Li, Aifen; Ren, Xiaoxia; Xu, Chao; Gao, Ziheng",Pore scale experimental and numerical study of surfactant flooding for enhanced oil recovery,Surfactant flooding; Glass etching model; Enhanced oil recovery; Numerical simulation,PERMEABILITY; MECHANISMS,"Surfactant flooding is a traditional method to enhance oil recovery. The surfactant flooding experiment based on glass etching model allows researchers to observe directly how the remaining oil is displaced by surfactant through microscope, so as to explore the mechanism of surfactant enhanced oil recovery. However, microscopic experiments mostly stay at the level of physical experiments, and the operation of physical experiments is too complex and cumbersome. This study is the first to combine surfactant flooding experiment with numerical simulation in glass etching model. Firstly, based on the real pore and throat structure of the real low permeability reservoir core, the glass etching model was developed, and the micro-oil-water displacement experiment was carried out. Through microscopic observation and analysis, combined with testing and image processing technology, the effect of water flooding was quantitatively investigated. Then the surfactant flooding was carried out. Three surfactants were used for displacement. It was found that residual oil in pore network was greatly reduced. The recovery factor has been greatly improved. Finally, numerical simulation of water flooding and surfactant flooding based on micro-physical experiment was carried out. The results of numerical simulation were compared with the experimental results. It is found that the recovery factor and the form of residual oil are basically the same. By analyzing the results of numerical simulation of oil recovery, it is found that the extent of surfactant enhancing oil recovery is different under different interfacial tension. The results showed that the surfactant with interfacial tension of 0.22 mN/m has the highest ability to enhance oil recovery. This work provides a reference for surfactant selection in oilfield development. It can select the best surfactant according to the factors of time, efficiency and cost.",4,4,13
Oil Recovery,Surfactant,"Okunade, Oluwagade Adenike; Yekeen, Nurudeen; Padmanabhan, Eswaran; Al-Yaseri, Ahmed; Idris, Ahmad Kamal; Khan, Javed Akbar","Shale core wettability alteration, foam and emulsion stabilization by surfactant: Impact of surfactant concentration, rock surface roughness and nanoparticles",Wettability; Surface roughness; Foam; Emulsion; Surfactants; Nanoparticles,ENHANCED OIL-RECOVERY; HUFF-N-PUFF; LAB(R) EXPERT ANALYSIS; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; SILICA NANOPARTICLES; NONIONIC SURFACTANTS; SIO2 NANOPARTICLES; CONTACT ANGLES; HIGH-PRESSURE,"Hexadecyltrimethyl ammonium bromide (HCTAB) and sodium dodecyl sulfate (SDS) are popular conventional surfactants with versatile industrial and oilfield applications. Knowledge of the optimum conditions for their applications for shale rock wettability modification, as well as foam and emulsion stabilization is relevant for hydrocarbon recovery process optimization. Influence of surfactant concentration, rock surface roughness and presence of nanoparticles in surfactant solutions on contact angles, oil-water interfacial tension (IFT), as well as foam and emulsion stabilization by HCTAB and SDS was investigated in this study. The interfacial properties measurements were conducted with Drop Shape Analyser (DSA 25), whereas the foam generation and stability properties were investigated via dynamic foam analyzer (DFA100). The emulsion stabilization and demulsification processes were investigated in Formulaction Turbiscan. Results showed an existence of optimum concentration of surfactant for obtaining the lowest contact angles, oil-water IFT reduction, as well as attaining maximum foam stability. The contact angle measured on rough core surfaces were smaller than the contact angle measured on smooth surfaces. Contact angles increased with increasing salnity concentration, but decreased with the increasing rock saturation time. Oil was more detrimental to foam stability when the generated foam was brought into contact with the resident oil, compared to when oil was added to the foaming solutions before foam generation. Lower contact angles, durable foam, and stable emulsion were produced in presence of oil and at high temperature via the synergy of nanoparticles and surfactants. Almost 66% decreased in contact angle was achieved with carbon nanotubes-SDS solutions, whereas Al2O3 nanoparticles-HCTAB foam attained a viscosity of 99 mPa-s at 60 degrees C. The foam demonstrated shear thinning Newtonian fluids behaviors but attained a plateau after sometimes. The study suggests the conditions for optimization of conventional surfactants applications in conventional and unconventional reservoir.",4,4,9
Oil Recovery,Surfactant,"Souayeh, Maissa; Al-Maamari, Rashid S.; Karimi, Mahvash; Aoudia, Mohamed",Wettability alteration and oil recovery by surfactant assisted low salinity water in carbonate rock: The impact of nonionic/anionic surfactants,Wettability alteration; Nonionic surfactants; Anionic surfactants; Spontaneous imbibition; Carbonates,CLOUD POINT; SPONTANEOUS IMBIBITION; HIGH-TEMPERATURE; SMART WATER; WET; ADSORPTION; BEHAVIOR; COALESCENCE; ADDITIVES; LIMESTONE,"Combining low salinity water (LSW) and chemicals to enhance oil recovery has recently received more attention in the oil industry. In this study, a systematic experimental procedure was conducted to evaluate the performance of low salinity nonionic surfactant with/without anionic surfactant in wettability alteration and oil recovery of oil-wet carbonate having high salinity formation water (FW) (196 g/L) and moderate temperature (75 degrees C). A polyethoxylated nonionic surfactant (C13EO12 ) and two anionic surfactants: sulfonate (IOS 20-24) and carboxylate (AEC 938) were used in this study. Contact angle (CA) results showed that low salinity nonionic surfactant was effective in altering the wettability of oil-wet calcite toward water-wet state. While the low salinity anionic surfactants' systems were only able to reduce the oil-wetness of the oil-wet calcite. When nonionic surfactant is mixed with anionic surfactant, the wettability of oil-wet calcite was altered toward intermediate-wet or only a reduction of its oil-wetness occurred depending on the type of the anionic surfactant. Spontaneous imbibition tests using oil-wet limestone cores showed that among the low salinity single surfactants' systems, carboxylate anionic surfactant resulted in the highest oil recovery (61% of oil initially in place (OIIP)) and sulfonate anionic surfactant resulted in the lowest oil recovery (31% of OIIP). The low salinity nonionic surfactant recovered 51% of OIIP by spontaneous imbibition. Addition of sulfonate anionic surfactant to the nonionic surfactant resulted in an oil recovery of 49% of OIIP while addition of carboxylate anionic surfactant to the nonionic surfactant considerably improved the oil recovery to 74% of OIIP. Hence, selection of proper surfactant class is crucial for a successful oil recovery.",4,4,6
Oil Recovery,Surfactant,"Raffa, Patrizio; Picchioni, Francesco",Preliminary evaluation of amphiphilic block polyelectrolytes as potential flooding agents for low salinity chemical enhanced oil recovery,Polymer flooding; Enhanced oil recovery; Low salinity; Amphiphilic polymers; Polymeric surfactants; Polyelectrolytes,POLYMERIC SURFACTANTS; FIELD APPLICATIONS; FOSSIL-FUELS; COPOLYMERS; RHEOLOGY; PART; POLYACRYLAMIDES; NANOTECHNOLOGY; NANOPARTICLES; RETENTION,"Amphiphilic block polyelectrolytes are known for their remarkable thickening properties in water solution, originating from their ability to self-assemble into large micellar aggregates. This makes them promising flooding agent for chemical enhanced oil recovery (cEOR). However, to the best of our knowledge, they have not yet been directly investigated for this purpose. In this work, a survey of relevant properties for EOR (rheology, filterability and emulsification), and laboratory scale oil recovery experiments, were performed on water solutions of polystyrene-block-poly(methacrylic acid) amphiphilic block polyelectrolytes, and compared with a commercial partially hydrolyzed polyacrylamide (HPAM), to evaluate the real potential in EOR applications for the first time. It was found that the recovery of amphiphilic block copolymers in low salinity brine (0.2% concentration of NaCl) is remarkably higher than that of HPAM at comparable weight concentration and shear viscosity, despite a much lower molecular weight. Effect of salinity and emulsification properties of the studied polymers have also been preliminarily investigated. Our results suggest that the recovery mechanism of these polymers differs from the traditional mechanism of polymer flooding, possibly due to emulsification of the oil. In conclusion, the studied amphiphilic block polyelectrolytes show promise as chemical agents in low salinity polymer flooding.",4,4,6
Oil Recovery,Surfactant,"Ge, Meng-Ru; Miao, Si-Jia; Liu, Jin-Feng; Gang, Hong-Ze; Yang, Shi-Zhong; Mu, Bo-Zhong",Laboratory studies on a novel salt-tolerant and alkali-free flooding system composed of a biopolymer and a bio-based surfactant for oil recovery,Biopolymer/surfactant formula; Ultra-low interfacial tension; Enhanced oil recovery; Salt-tolerant; Alkali-free,HIGH-TEMPERATURE; WELAN GUM; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; NONIONIC SURFACTANT; ASSOCIATING POLYMER; AQUEOUS WELAN; XANTHAN GUM; STRAIN; POLYSACCHARIDES,"Alkali/surfactant/polymer (ASP) flooding is one of the most effective tertiary oil recovery technologies. However, the formation of an alkali scale potentially results in the reduction of the formation permeability and pipeline corrosion, which affect its industrial application. Recently, the surfactant/polymer (SP) flooding system in the absence of alkali has received increasing attention. Here, we screened a high-yielding strain, which is capable of producing salt-tolerant biopolymer. The results of rheological properties evaluation showed that this biopolymer possessed a stable viscosity at high salinities (up to 200 g/L NaCl, 100 g/L Ca2+, and 100 g/L Mg2+) and a wide range of pH (4-11), indicating its superior salt and pH resistance. Based on these properties, a novel salt-tolerant and alkali-free binary flooding system was constructed with this biopolymer and bio-based surfactant newly synthesized in our lab. The ultra-low interfacial tension (IFT) between crude oil and the binary system containing 0.5 wt % biopolymer and 1.00 g/L surfactant could be achieved in the presence of 100 g/L NaCl or 400 mg/L Ca2+. Moreover, it exhibited good resistance to oil sands adsorption, excellent anti-dilution, and ageing stability. These results indicate that the biopolymer produced by the Kosakonia oryzae strain possessed great potential in the construction of an alkali-free SP system for enhanced oil recovery (EOR) in high salinity and high temperature oil reservoirs.",4,4,5
Oil Recovery,Surfactant,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Oil Recovery,Surfactant,"Zheng, Jiangtao; Wang, Zenglin; Ju, Yang; Tian, Yuqin; Jin, Yanxin; Chang, Wei",Visualization of water channeling and displacement diversion by polymer gel treatment in 3D printed heterogeneous porous media,Polymer gel; Enhanced oil recovery (EOR); Water channeling; Diversion; 3D printing,CONFORMANCE CONTROL; OIL-RECOVERY; SHALE; INJECTION; SYSTEM; FLOODS; FLUID; FIELD; ROCK; EOR,"Polymer gels are widely applied to increase the sweep efficiency in mature oil fields facing severe water channeling problems after years of water flooding. The formation of water channeling and successful polymer gel treatment are rooted in complex pore-scale displacement and diversion. Thus, accurate characterization of the pore space and direct visualization of the interior displacement processes in real reservoir rocks such as water flooding, polymer gel injection, and chase floods are crucial in determining the controlling mechanisms of water channeling and polymer gel diversion. In this study, 3D X-ray micro-computed tomography (uCT) was used to characterize the porous structures of three distinct levels in water-flooded reservoir sandstones. A heterogeneous digital model was designed, which comprised representative layers of the obtained porous structures. Then, 3D-printing technology was used to manufacture a transparent model based on the digital prototype. A series of displacement experiments were conducted in the printed model to directly visualize the flow behaviors in the actual pore geometries. In the experiments, the model was first saturated with white oil and flooded by formation water until the outlet discharged only the water phase. Then, an immediately prepared polymer gel was injected. After three days of gelation, an antidilution polymer was injected to sweep the residual oil in the model. Finally, a surfactant flooding agent was injected designed to further increase the oil recovery. The entire four-step displacement process was directly visualized, and the saturation of each injection and the oil recovery were calculated. During water flooding, preferential flooding channels formed in the highest water-flooded porous layers due to the low viscosity ratio between the injected formation water and the displaced white oil, as well as the permeability contrast in the heterogeneous model. The injected polymer gel mainly followed the preferential flooding channels because of the low resistance force in these channels. After gelation, the polymer gel blocked the main preferential channels and diverted the chase floods to nearby pores. A desirable diversion of the polymer gel highly depends on its propagation path during injection and effective blocking after gelation. Experimental visualization and displacement mechanism analysis indicate the efficacy of the flow diversion by the polymer gel treatment in the heterogeneous porous model. The results provide useful information on the displacement behavior in heterogeneous porous structures, and the conclusions apply to similarly scaled systems at the reservoir scale.",3,3,7
Oil Recovery,Surfactant,"Das, Alolika; Mohanty, Kishore; Nguyen, Quoc",A pore-scale study of foam-microemulsion interaction during low tension gas flooding using microfluidics-Tertiary recovery,Enhanced oil recovery; Foam; Ultralow interfacial tension; Microemulsion; Microfluidics,OIL DISPLACEMENT,"The emerging EOR technology of Low-Tension-Gas (LTG) flooding has been proven to be successful for tertiary oil recovery in laboratory scale coreflooding experiments. However, there has not been a detailed study of the pore-scale phenomena which occur during LTG flooding. In the current study, alternate injection of a suitable surfactant formulation and air has been used to simulate the mechanism of LTG flooding in a borosilicate waterwet micromodel. The main phenomenon that was investigated was the interaction between different microemulsion types (Winsor I and III) and foam. Results show that presence of foam facilitates faster and better oil displacement. Microemulsion equilibration time was improved in the presence of foam, due to increased mixing of the liquid phases. Presence of trapped gas helped to divert the flowing surfactant/microemulsion to regions with trapped remaining oil and thus improved oil recovery. For equilibrated Type III microemulsion, completely miscible flooding (or ultralow tension displacement) was observed. For Type I systems, oil-in-water macroemulsions were observed. For equilibrated Type III microemulsion, the presence of foam mainly improved the oil recovery rate. In case of Type III surfactant solution injection, the presence of foam improved both the oil recovery rate and the overall oil recovery. For Type I systems, the presence of foam enabled the transition of oil-in water macroemulsions to water-entrained macroemulsions, thus improving both the oil recovery rate and the overall oil recovery.",3,3,7
Oil Recovery,Surfactant,"Guo, Ya-bing; Yue, Xiang-an; Yang, Chang-chun",New method to quantitatively characterize the emulsification capability of chemical flooding agents,Enhanced oil recovery; Chemical flooding; Emulsification capability; Emulsification index,IN-WATER EMULSIONS; INTERFACIAL-TENSION; HIGH-TEMPERATURE; OIL-RECOVERY; SURFACTANTS; MECHANISM; FLOW,"In enhanced oil recovery, the characterization of the emulsification capability of a chemical flooding agent is an important concern that is hitherto still unanswered. Aiming at this concern, this paper introduces a novel characterization method for the emulsification of a surfactant-oil system induced by ultrasonic vibration. This method quantitatively evaluates the emulsification capability of chemical flooding agents using a parameter called emulsification index (EI), which fully characteristics the emulsification speed and amount. This method was applied to a set of oil displacement experiments and the results support the notion that emulsification index is a reasonable parameter for characterization of the emulsification capability of chemical flooding agents.",3,4,6
Oil Recovery,Surfactant,"Ahmed, S.; Alameri, W.; Ahmed, W. W.; Khan, S. A.",Rheological behavior of scCO(2)-Foam for improved hydrocarbon recovery: Experimental and deep learning approach,,REAL-TIME PREDICTION; FRACTURING FLUID; SHALE-GAS; DRILLING-FLUIDS; FOAM STABILITY; OIL; PERFORMANCE; VISCOSITY; TEMPERATURE; PRESSURE,"CO2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO2 foam is a key factor to control the efficiency of fracturing process that is strongly influenced by different process parameters such as foam quality, temperature, pressure, and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO2 foams by varying different process variables. CO2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (<1.8%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO2 foam projects for fracturing unconventional reservoirs.",3,3,5
Oil Recovery,Surfactant,"Akhlaghi, Naser; Riahi, Siavash; Parvaneh, Ronak","Interfacial tension behavior of a nonionic surfactant in oil/water system; salinity, pH, temperature, and ionic strength effects",Triton X-100; IFT; CMC; Enhanced oil recovery; PH; Salinity,ENHANCED OIL-RECOVERY; ASSISTED GRAVITY DRAINAGE; ACIDIC CRUDE-OIL; WATER; IFT; WETTABILITY; BRINE; PERFORMANCE; ASPHALTENE; COMPONENTS,"Since most of the world's oil reservoirs are in the second half lifetime, the use of Enhanced Oil Recovery (EOR) methods is inevitable. Interfacial Tension (IFT) is one of the effective parameters on EOR can be changed by surfactants. But surfactant injection is one of the costly methods and chemistry of the surfactant solutions such as salinity (one and two valence ions) and pH should be engineered. Furthermore, the temperature is an effective parameter affecting on IFT. In this study, the effect of salinity, especially hard salinity, temperature and pH on IFT between Triton X-100 surfactant and an Iranian oil sample has been investigated. In order to, evaluate the effect of salinity, different concentrations of NaCl, CaCl2, MgCl2, and Na2SO4 salts (0, 0.1, 0.5, and 1 wt%) were used in different concentrations of surfactant. IFT results showed that magnesium and calcium divalent cations had a greater effect on IFT reduction than monovalent sodium cation. Also, all the studied cations were more effective than sulfate as a divalent anion. The ionic strength of the solutions was inversely proportional to the IFT amounts. Less value of IFT in the presence of magnesium ions than calcium ions was due to the higher ionic strength of solutions containing magnesium compared with calcium. IFT results at three temperatures (20, 40, and 60 degrees C) proved that by increasing temperature IFT increased. Also, the effect of pH on IFT in three pHs including acidic, almost neutral and alkaline in the presence of surfactant was studied. Results indicated that IFT decreased with increasing pH, especially in concentrations lower than critical micelle concentration (CMC).",3,3,4
Oil Recovery,Surfactant,"Wen, Yiping; Lai, Nanjun; Li, Wenhong; Zhang, Yongqiang; Du, Zhaofeng; Han, Lijuan; Song, Zhiling",Factors influencing the stability of natural gas foam prepared by alkyl polyglycosides and its decay rules,Alkyl polyglycosides; Natural gas foam; Drainage kinetics; Decay rules; Statistics methods; Surface properties,HIGH-TEMPERATURE; NITROGEN FOAM; SURFACTANT; PERFORMANCE; DRAINAGE; BEHAVIOR; PARTICLES,"By using alkyl polyglycoside (APG) as foaming agent and natural gas as gas phase, the natural gas foam system was prepared, and the influence of alkyl chain length, metal cation valence and concentration, and polymer types on the foam stability was studied. By completely observing the volume and time required for the foam drainage liquid under different conditions, a foam drainage kinetics model was established. The drainage rate constant, the maximum drainage rate and its occurrence time during the foam drainage process can be acquired by derivation of the fitting function. The Arrhenius equation was adopted to fit the drainage rate constant at different temperature, and the drainage activation energy is obtained. The drainage process of foam was further analyzed from the perspective of kinetics. Moreover, the changes in geometric geometries such as bubble number, particle size distribution frequency and the average diameter of the bubble in the decay process under different conditions was counted. According to the mathematical relationship between the average diameter and time, the Ostwald ripening rate and gas molecule diffusion constant are calculated. Finally, through the investigation of the interface properties and the micromorphology of the solution, the reasons for the above rules are explained. The research shows that: 1) the increase of the alkyl chain length of APG within a certain range (8-10.9) is beneficial to the improvement of the foam stability, and the continuous increase of chain length (10.9-12) is adverse to the foam stability, 2) the increase in the salinity of prepared water and the metal ions valence enhances the foam stability to a certain extent, 3) DG is more stable to APG foam than XG and KYPAM-6s. This study enriches the stability rules of APG foam with natural gas as the gas phase under different conditions, and provides ideas and methods for quantitatively analyzing the foam decay process from the perspectives of kinetics and statistics, which provides theoretical support for the application of natural gas foam in enhance oil recovery.",3,3,4
Oil Recovery,Surfactant,"Raza, Salim; Gates, Ian D.",Effect of cellulose nanocrystal nanofluid on displacement of oil in a Hele-Shaw cell,Cellulose nanocrystals; Co-current flow; Hele-shaw cell; Interface interactions; Relative permeability,2-PHASE FLOW; RELATIVE PERMEABILITY; SURFACTANT; RESERVOIRS; VISCOSITY; FRACTURE; VELOCITY; MODEL,"Fractured oil reservoirs are a major source of petroleum globally but recovery from them is extremely challenging. Extensive research is carried out to improve oil recovery from fractured reservoirs by using water, surfactant and polymer solutions and up to some extent nanofluids flooding but no significant success is achieved. Aim of the research documented here is to examine the impact of different concentrations of nanofluids on the displacement of oil from a thin gap and to understand the behavior of the interfaces by studying the interfaces on both macro and micro scales, and by examining variation in the relative permeabilities, mobility ratios and capillary numbers. 1 wt% and 2 wt% of CNC nanofluids are flooded at different flow rates to recover mineral oil from a thin gap in a Hele-Shaw cell. Results for each concentration is compared with each other as well as with the water flooding system. It was observed that 2 wt% concentration nanofluids creates a stable interface resulting in an enormous increase in the oil recovery (piston like displacement) i.e., up to 98%. Microscopic analysis of the interfaces reveals that the nanofluid penetrates the oil phase forming a micro-emulsion upstream of the main interface. The results could be helpful for flooding design consideration to improve oil recovery from the fractured reservoirs.",3,3,3
Oil Recovery,Surfactant,"Seetharaman, Gomathi Rajalakshmi; Jadhav, Rohan M.; Sangwai, Jitendra S.",Effect of monovalent and divalent alkali [NaOH and Ca(OH)(2)] on the interfacial tension of pure hydrocarbon-water systems relevant for enhanced oil recovery,Alkali; Hydrocarbons; Hydroxide ions; Interfacial tension; Temperature,SURFACE-TENSION; WETTABILITY ALTERATION; IONIC LIQUIDS; ASP; HYDROXIDE; IMIDAZOLIUM; SALINITY; BEHAVIOR; SALTS,"Although various efficient enhanced oil recovery (EOR) techniques have been proposed, the use of chemicals such as alkali, surfactants, and polymer in the field of EOR makes chemical EOR a promising method. The residual oil left behind after the secondary recovery process can be successfully displaced by decreasing the interfacial tension (IFT) between the liquid-liquid systems. Moreover, understanding the IFT between the liquid-liquid systems are essential in formulating and controlling the multiphase and multicomponent processes. As crude oil is a complex mixture of organic, inorganic compounds and heteroatoms, understanding the IFT of the pure hydrocarbon-water system is vital to develop robust models. In this study, the IFT between pure hydrocarbon-water systems in the presence of alkali has been explored. The IFT measurements were performed using a dynamic contact angle tensiometer using a Wilhelmy plate. Different hydrocarbon liquids such as hexane, heptane, decane and aromatics such as benzene and toluene were used. The monovalent NaOH and divalent alkali Ca(OH)(2) in the concentration range of 0-37.5 mM are used to understand the effect of alkali on the IFT of the oil-water system. This paper also elaborates on the effect of temperature at 298.15 K, 323.15 K and 348.15 K on the IFT of hydrocarbon-water systems. The experimental results show that the increase in the concentration of alkali continuously decreased the IFT of hydrocarbon-water systems. Moreover, it has been found that the type of alkali also has a reasonable impact on the IFT of the hydrocarbon-water system. The divalent alkali [Ca(OH)(2)] is found to be more efficient in reducing the IFT of both alkane-water and aromatic-water systems than the moderately performed monovalent alkali (NaOH). The possible mechanism for the continuous reduction in IFT has been proposed using surface adsorption of hydroxide ions at the interface of the oil-water system.",3,3,3
Oil Recovery,Surfactant,"Mejia, Miguel; Parra, Jose E.; Mejia, Lucas; Pope, Gary A.; Balhoff, Matthew T.",Experiments and numerical simulations of chemical enhanced oil recovery in fractured carbonate rocks,Surfactant FOR; Fractured carbonates; Microemulsion phase behavior; Numerical simulation,SURFACTANT IMBIBITION; PERMEABILITY; SALINITY; DRAINAGE; PHASE; FLOW,"Secondary oil recovery from naturally fractured, oil wet carbonate reservoirs is challenging due to high permeability fractures and unfavorable capillary forces. A series of new tertiary surfactant coreflood experiments in fractured oil wet limestone cores were performed in which surfactants lowered the IFT and formed viscous microemulsions upon mixing with crude oil and brine. The viscous microemulsions cause favorable transverse pressure gradients that result in increased oil recovery. The effects of surfactant slug size, salinity and injection rate were investigated experimentally. In all cases, the injected surfactant solutions recovered significantly more oil than waterflooding. Numerical simulations were used to interpret the experimental results. The experimental oil recovery and pressure drop data were matched by reducing the fluid mobility in the fracture. A new experiment verified that a viscous phase formed in the fracture, which resulted in a significant improvement in oil recovery.",3,3,2
Oil Recovery,Porous Media,"Wu, Zhongwei; Cui, Chuanzhi; Ye, Yinzhu; Cheng, Xiangzhi; Trivedi, Japan",A fractal model for quantitative evaluating the effects of spontaneous imbibition and displacement on the recovery of tight reservoirs,Spontaneous imbibition (SI); Displacement; Quantitative evaluation; Tight reservoir; Fractal theory,KOZENY-CARMAN CONSTANT; POROUS-MEDIA; CAPILLARY IMBIBITION; OIL-RESERVOIRS; FLOW,"In the petroleum industry, there is a consensus that the spontaneous imbibition (SI) is important for improving the recovery of tight reservoirs. However, how great is the effect of SI on the recovery of tight reservoirs when comparing with displacement? In the paper, a model for quantitative evaluating the effects of SI and displacement on tight reservoir development is built by fractal theory and verified by comparing with published experimental data. Two evaluation parameters (EP and EPR), which can be determined by the proposed model, are introduced to discuss the problem that how great the effect of SI on the recovery of tight reservoirs when comparing with displacement is. The influences of related parameters on EP and EPR are conducted. The results show that reservoir properties have a great effect on the imbibition time. And the effects of reservoir properties on the flow rate of SI is similar to that of displacement. The effect of SI becomes significant comparing with displacement when the water viscosity decreases. However, with the decrease of contact angle or the increase of interfacial tension force (ITF), the effect of SI becomes significant. The decrease of displacement pressure difference indicates the effect of SI becoming relatively significant. When the ITF and displacement pressure difference are 35.5 mN/m and 1 x 10(4) Pa, respectively, the maximum oil flow rate of SI is 1.85 times of displacement. This work has a crucial role in promoting the development of tight reservoirs.",12,12,17
Oil Recovery,Porous Media,"Varfolomeev, Mikhail A.; Yuan, Chengdong; V. Bolotov, Alexander; Minkhanov, Ilgiz F.; Mehrabi-Kalajahi, Seyedsaeed; Saifullin, Emil R.; Marvanov, Marat M.; Baygildin, Emil R.; Sabiryanov, Raushan M.; Rojas, Allan; Emelianov, Dmitrii A.; Al-Muntaser, Ameen A.; Ganiev, Bulat G.; Zaripov, Azat T.; Beregovoi, Anton N.; Shaihutdinov, Damir K.",Effect of copper stearate as catalysts on the performance of in-situ combustion process for heavy oil recovery and upgrading,In-situ combustion; In-situ upgrading; Heavy oil; Copper stearate; Oil-soluble catalyst; Catalytic combustion,LIGHT CRUDE-OIL; OXIDATION BEHAVIOR; NANOPARTICLES; ASPHALTENES; KINETICS; DECOMPOSITION; ADSORPTION; PYROLYSIS,"Using copper stearate as catalysts, catalytic in-situ combustion (ISC) of heavy oil was studied by porous medium thermo-effect cell (PMTEC) and combustion tube experiments. Significant acceleration of combustion was observed in porous media in PMTEC when copper stearate was added. Copper stearate promoted fuel deposition and its combustion and made them occur easier in low temperature, thus shifting both low-temperature oxidation (LTO) and high-temperature oxidation (HTO) into lower temperatures, and even totally merge HTO into LTO in some conditions. We found that the promotion on fuel deposition by catalysts might be related to the change of H/C ratio in fuel. The improvement in the performance of ISC by copper stearate in combustion tube experiments mainly manifests in lower ignition temperature, lower H/C ratio, increased air/fuel ratio, higher oil recovery, and higher level of in-situ oil upgrading, which makes copper stearate a good candidate for catalyzing ISC in field application.",9,9,6
Oil Recovery,Porous Media,"Onaizi, Sagheer A.; Alsulaimani, Mohammed; Al-Sakkaf, Mohammed K.; Bahadi, Salem A.; Mahmoud, Mohamed; Alshami, Ali",Crude oil/water nanoemulsions stabilized by biosurfactant: Stability and pH-Switchability,Crude oil/water nanoemulsions; Emulsion stability; Rhamnolipid biosurfactant; pH-responsive; Demulsification; Droplet size,OIL-IN-WATER; INTERFACIAL-TENSION; POROUS-MEDIA; SURFACTIN BIOSURFACTANT; SILICA NANOPARTICLES; RECOVERY; EMULSIONS; EMULSIFICATION; COMBINATION; BACTERIA,"Emulsification is one of the proposed mechanisms for enhancing crude oil recovery in chemical flooding. The replacement of chemical surfactants in enhanced oil recovery (EOR) applications with biosurfactants is an attractive alternative; yet, there is a lack of studies on the crude oil emulsification using biosurfactants. Particularly, the formulation of crude oil/water (crude O/W) nanoemulsions with an extreme stability and a pH-responsiveness behavior is still not documented in the literature, to the best of our knowledge. Accordingly, we report in this study the preparation of both light and heavy crude oil/water emulsions using different concentrations of the rhamnolipid biosurfactant. The emulsions were prepared in a two-step process: stirring overnight to create coarse emulsions followed by sonication. All the prepared emulsions have a nanoscale size (e.g., about 50% of the formed droplets at 0.1 wt% rhamnolipid are < 200 nm in size), which decreases with increasing the biosurfactant concentration. The zeta potential values of the formed crude O/W nanoemulsions were highly negative (<=-39.3). Increasing the biosurfactant concentration resulted in a more negative zeta potential. The formulated crude O/W nanoemulsions were extremely stable with 0% oil or water separation even after a month of storage. Despite the extreme stability of these crude O/W nanoemulsions, they could be easily switched off (i. e., demulsified) within 1 h by pH-swing via the addition of 50 mM sulfuric acid (H2SO4) regardless of the bioemulsifier (i.e., rhamnolipid) concentration. It was also possible to switch on/off the crude O/W nanoemulsions a number of times (at least five times) through this pH-swing mechanism. We also demonstrated that the crude O/W nanoemulsions can be completely switched off through the addition of NaOH, particularly, when these crude O/W nanoemulsions are stabilized by low rhamnolipid dosages (<= 0.5 wt%); such an observation is very unusual. The findings reported in this study clearly demonstrate the ability of creating extremely stable crude O/W nanoemulsions, which is desirable in EOR; however, the emulsified crude oil can be easily and economically recovered via a simple and an economic process (i.e., pH-switch) with the ability to switch off/on the emulsion several times.",7,7,6
Oil Recovery,Porous Media,"Scheffer, Kamila; Meheust, Yves; Carvalho, Marcio S.; Mauricio, Marcos H. P.; Paciornik, Sidnei",Enhancement of oil recovery by emulsion injection: A pore scale analysis from X-ray micro-tomography measurements,EOR; Emulsion; Secondary recovery; Microfluidics; Micro-CT; 3D image analysis,IN-WATER EMULSIONS; POROUS-MEDIA; FILTRATION MODEL; STABLE EMULSIONS; MULTIPHASE FLOW; RESIDUAL OIL; FLUID-FLOW; DISPLACEMENT; CT; EMULSIFICATION,"The efficiency of emulsion injection as an enhanced oil recovery (EOR) method is investigated in a synthetic porous medium consisting of sintered bi-disperse glass beads, which emulates the porosity and permeability of real oil-bearing rocks. Synthetic seawater and an oil-in-water emulsion are successively used to displace a mineral oil which initially saturates the porous space. Micro-CT images with a 4 mu m resolution are acquired at the end of the different stages of the process; the water phase is doped with KI to optimize the contrast between the liquid phases. Thus, three-dimensional (3D) images showing the beads, doped water and residual oil present a 3-modal histogram. After denoising with a non-local means filter, alignment and segmentation, the 3D images provide the spatial distributions of the water and oil phases, and thus allow comparing the populations of residual oil ganglia prior to and after the injection of the emulsion. Visual comparison of the spatial phase distributions show that the oil droplets of the oil-water emulsion divert the water path, mobilizing previously trapped oil ganglia. The probability density functions (PDFs) of different geometrical properties of the trapped oil ganglia (10(4) ganglia with volumes spanning 6 orders of magnitude) after water injection show well defined power law behaviors between a size corresponding to the typical pore throat and that typical of 10 typical pore volumes, and a few very large clusters of sizes between 10 and 5x 10(5) typical pore volumes. The largest of them alone accounts for 97% of the trapped oil. The same PDFs after emulsion injection demonstrate successful fragmentation of these few very large ganglia, which in this case is the key to efficient EOR procedure through diversion of the water flow by emulsion oil droplets to less permeable regions.",7,7,3
Oil Recovery,Porous Media,"Alizadeh, MohammadReza; Fatemi, Mobeen; Mousavi, Mohammad",Direct numerical simulation of the effects of fluid/fluid and fluid/rock interactions on the oil displacement by low salinity and high salinity water: Pore-scale occupancy and displacement mechanisms,Direct numerical simulation; Computational fluid dynamics; Dynamic contact angle; Dynamic interfacial tension; Low salinity water flooding,INTERFACIAL-TENSION IFT; WETTABILITY ALTERATION; SPECIES TRANSFER; POROUS-MEDIA; SMART WATER; INJECTION; RECOVERY; BRINE; FLOW; VOLUME,"Laboratory experiments have shown that performance of waterflooding in oil reservoirs could be significantly increased by lowering the ionic strength and/or manipulation of its composition, which is generally known as low salinity waterflooding (LSWF). The involved mechanisms in additional oil production can be generally categorized in two categories, fluid/fluid and fluid/rock interactions. The distribution of the phases and the involved displacement mechanisms would be strongly affected by the inter-relations between capillary and viscous forces. Although there have been recent advances in the simulation of the LSWF at core scale and beyond and some models are included in commercial core-scale/field-scale simulators, there are very few works that modelled and simulated this process at the pore scale. As a result the effects of wettability alteration and/or interfacial tension (IFT) change on the distribution of the phases at pore scale as well as dynamics of the displacement are not thoroughly investigated and not well understood, even in spite of many micromodel experiments. The aim of the present study is to investigate the fluids distribution, redistribution and dynamic of the displacement mechanisms at the true pore scale (inside a pore), by modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Simulation results show that in addition to the fluid/rock interactions, fluid/fluid interactions are also important in the effectiveness of LSWF and shall be considered in simulation studies. This is especially true in the case of non-water-wet systems. Our simulations provide new physical insights into LSWF and the dynamics of two-phase flow under wettability alteration as well as IFT changes induced by the LSWF, which cannot be easily captured by laboratory experiments. The results are also used to better explain some of the observed discrepancies in larger scales such as micromodel or coreflood experiments.",7,7,1
Oil Recovery,Porous Media,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Oil Recovery,Porous Media,"Santamaria, Oveimar; Lopera, Sergio H.; Riazi, Masoud; Minale, Mario; Cortes, Farid B.; Franco, Camilo A.",Phenomenological study of the micro- and macroscopic mechanisms during polymer flooding with SiO2 nanoparticles,Polymeric nanofluids; SiO2 nanoparticles; Microscopic oil displacement; Macroscopic oil displacement,ENHANCED-OIL-RECOVERY; RHEOLOGICAL PROPERTIES; SILICA NANOPARTICLES; POLYACRYLAMIDE SOLUTION; WETTABILITY ALTERATION; RELATIVE PERMEABILITY; ELEVATED-TEMPERATURES; POROUS-MEDIA; ADSORPTION; BEHAVIOR,"The incorporation of SiO2 nanoparticles in polymer solutions for oil recovery has generated considerable interest in recent research. Although this approach improves the polymer performance, little evidence is available about the recovery mechanisms that intervene in the polymeric nanofluid suspension or polymer nanofluid. Therefore, the purpose of this study is to describe the microscopic and macroscopic mechanisms involved during oil recovery with polymeric nanofluid flooding. Changes in the rheology and capillary forces (contact angle and interfacial tension) in the polymeric solution due to the incorporation of SiO2 nanoparticles were evaluated. Coreflooding tests were made to evaluate the retention, apparent viscosity, and impact on the relative permeability. Finally, macroscopic oil recovery was measured by displacement tests in a quarter 5-spot system, and microscopic displacement was evaluated by a microfluidic test. Results indicated that the conservation of a favorable mobility ratio in polymeric nanofluids along the porous medium is the phenomenon that most impacts macroscopic oil recovery. This behavior was associated with a reduction in loss retention and the conservation of the apparent viscosity in the porous medium. A direct relationship was observed between the concentration of SiO2 nanoparticles and the viscoelastic behavior of the polymer and the water-wet condition on the surface exposed to the nanofluid. Moreover, residual oil distribution in microscopic displacement revealed that the reduction in residual oil mainly originated from the decrease in the size of the oil clusters. Consequently, the evidence suggests that microscopic oil displacement in polymeric nanofluid is attributed to the reduction in the capillary forces and increases in the viscoelastic nature of the polymer. Results in this work indicated that the additional oil recovery obtained by polymeric nanofluid flooding is generated by the improvement of macroscopic recovery mechanisms and the activation of microscopic mechanisms.",6,6,5
Oil Recovery,Porous Media,"Koegler, Felix; Mahler, Eva; Dopffel, Nicole; Schulze-Makuch, Dirk; Borovina, Ante; Visser, Foppe; Herold, Andrea; Alkan, Hakan",The Microbial Enhanced Oil Recovery (MEOR) potential of Halanaerobiales under dynamic conditions in different porous media,Microbial enhanced oil recovery; Carbonate dissolution; Dynamic experiments; Reservoir microbiology; Geomicrobiology; Halanaerobium; High salinity,WETTABILITY ALTERATION; BACILLUS; PERMEABILITY; MECHANISMS; INJECTION; RESERVOIR; MICROORGANISMS; STIMULATION; SANDSTONE; STRAINS,"As a dynamic screening tool for a high-salinity oilfield (186 g/L), anaerobic sandpacks were established to simulate Microbial Enhanced Oil Recovery (MEOR) under defined laboratory conditions. Glass beads, quartz sand or crushed reservoir rock were used to produce porous media which varied in permeability, wettability, homogeneity and geochemistry. In total, 14 sandpacks were flooded with oil and inoculated with indigenous fermentative bacteria of the order Halanaembiales. After waterflooding, these were treated with nutrients in different injection scenarios during which incremental oil recovery, permeability, microbial activity and produced metabolites were measured. Our results indicate that the efficiency of MEOR is dependent on the type of porous medium used: Both glass beads and outcrop quartz sand were found to be no suitable analogue to reservoir material because not all potential MEOR effects were accounted for. MEOR was least efficient in quartz sandpacks with a recovery factor of 7.0 +/- 1.7% with respect to the original oil in place (IRFOOIP), attributed mainly to fluid-fluid interactions. In sandpacks with reservoir rock, wettability alteration, matrix dissolution and bioplugging were additional MEOR mechanisms and resulted in an incremental recovery which was almost three-fold higher compared to pure quartz sandpacks (IRFOOIP), = 23.2 +/- 6.4%). Bioplugging was not detected in sandpacks with a permeability of 8-10 D, although cell retention was observed. Mean pore sizes of these sandpacks were calculated to be in the range of 100 mu m, thus considered to be too large to allow for significant plugging. Our findings support the use of MEOR as potential tertiary recovery method but also emphasize the importance of carefully designing laboratory experiments. We argue that porous medium properties such as permeability, pore size, wettability and mineralogy play a crucial role during dynamic MEOR feasibility studies, because they directly influence incremental recovery.",6,6,1
Oil Recovery,Porous Media,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Oil Recovery,Porous Media,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Oil Recovery,Porous Media,"Mahmoudpour, Maziar; Pourafshary, Peyman",Investigation of the effect of engineered water/nanofluid hybrid injection on enhanced oil recovery mechanisms in carbonate reservoirs,Engineered water; Nanoparticle; Microemulsion; Wettability alteration; Enhanced oil recovery,DETERMINING IONS CA2+; WETTABILITY ALTERATION; WATER INJECTION; CHALK; SALINITY; SEAWATER,"Changing the salinity and ionic composition of the injected water and designing ""engineered water"" (EW) is an enhanced oil recovery approach which affects the wettability of carbonate reservoirs and improves the oil recovery in many cases. Application of nanoparticles also affects oil production by various mechanisms such as altering the wettability, changing the viscosity of the oil and the injected fluid, and changing the interfacial tension. The benefits of combining these two approaches and developing a hybrid method are investigated in this paper. Experiments and measurements of different characteristics such as contact angle, zeta potential, particle size, ATR (attenuated total reflectance) analysis, ESEM (environmental scanning electron microscope) imaging, ion/nanoparticle deposition, and microemulsion formation were completed to analyze the influence of the hybrid method on rock/oil/brine interactions. Core flooding tests were also conducted to study the performance of the method to improve oil recovery. The most effective EW was selected by adjusting the concentrations of magnesium, calcium, and sulfate ions of Persian Gulf water. Nanoparticles such as SiO2, CaCO3, TiO2, and gamma Al2O3 were also studied to achieve the longest stability. Finally, the effect of combining the optimum states of engineered brine and nanoparticles on different mechanisms was investigated. Our results showed that spiking the injection brine with sulfate ions and using a hybrid method with silica nanoparticles at a concentration of 0.1 wt% provided the best effect on the enhanced oil recovery. This combination altered the wettability more than standalone methods. Also, there was a decrease in adsorption of nanoparticles on the rock surface, which controls the retention mechanism. Therefore, the presence of more nanoparticles in the fluid flow leads to the formation of microemulsions and increases in the viscosity of the injected fluid, which affects the sweep efficiency in porous media.",5,5,0
Oil Recovery,Porous Media,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
Oil Recovery,Porous Media,"Kondori, Javad; Miah, Mohammad Islam; Zendehboudi, Sohrab; Khan, Faisal; Heagle, Dru",Hybrid connectionist models to assess recovery performance of low salinity water injection,Low salinity water injection; Recovery factor; Smart tools; Statistical analysis; Variable ranking,ENHANCED OIL-RECOVERY; ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINES; REAL-TIME PREDICTION; WETTABILITY ALTERATION; COMPRESSIVE STRENGTH; POROUS-MEDIA; CRUDE-OIL; REGRESSION; RESERVOIRS,"The low salinity water injection (LSWI) is one of the emerging enhanced oil recovery techniques to improve both microscopic and macroscopic displacement efficiencies by creating a new streamline in petroleum reservoirs. While experimental studies are tedious, costly, and time-consuming, the smart connectionist tools are more reliable and cost-effective approaches to predict oil recovery factor (RF) without considerations of governing equations and physics behind production mechanisms in oil reservoirs. The main objective of this study is to investigate the data-driven model performance and variable contribution while predicting RF of LSWI processes. We introduce connectionist models using hybridized least squares support vector machine (LSSVM) with global optimization technique of coupled simulated annealing (CSA), and adaptive network-based fuzzy inference system (ANFIS). The extremely randomized tree or extra tree (ET) tool is also applied to forecast the RF and investigate the parameter contribution in the employed model. The model performance is examined using statistical parameters, including coefficient of determination, relative error, mean absolute percentage error, and mean squared error. According to the results, the ET and hybridized LSSVM-CSA models perform better than the ANFIS model in estimating RF. Utilizing the ET smart model, the total dissolved salts (TDS, ppm) is the most influential parameter, while the fluid injection rate has the minimum importance in the determination of RF. The current research confirms that LSSVM-CSA and ET techniques are able to obtain RF of LSWI with high accuracy and reliability, which can be used by researchers and engineers for better management of oil reservoirs under LSWI.",4,4,3
Oil Recovery,Porous Media,"Zheng, Jiangtao; Wang, Zenglin; Ju, Yang; Tian, Yuqin; Jin, Yanxin; Chang, Wei",Visualization of water channeling and displacement diversion by polymer gel treatment in 3D printed heterogeneous porous media,Polymer gel; Enhanced oil recovery (EOR); Water channeling; Diversion; 3D printing,CONFORMANCE CONTROL; OIL-RECOVERY; SHALE; INJECTION; SYSTEM; FLOODS; FLUID; FIELD; ROCK; EOR,"Polymer gels are widely applied to increase the sweep efficiency in mature oil fields facing severe water channeling problems after years of water flooding. The formation of water channeling and successful polymer gel treatment are rooted in complex pore-scale displacement and diversion. Thus, accurate characterization of the pore space and direct visualization of the interior displacement processes in real reservoir rocks such as water flooding, polymer gel injection, and chase floods are crucial in determining the controlling mechanisms of water channeling and polymer gel diversion. In this study, 3D X-ray micro-computed tomography (uCT) was used to characterize the porous structures of three distinct levels in water-flooded reservoir sandstones. A heterogeneous digital model was designed, which comprised representative layers of the obtained porous structures. Then, 3D-printing technology was used to manufacture a transparent model based on the digital prototype. A series of displacement experiments were conducted in the printed model to directly visualize the flow behaviors in the actual pore geometries. In the experiments, the model was first saturated with white oil and flooded by formation water until the outlet discharged only the water phase. Then, an immediately prepared polymer gel was injected. After three days of gelation, an antidilution polymer was injected to sweep the residual oil in the model. Finally, a surfactant flooding agent was injected designed to further increase the oil recovery. The entire four-step displacement process was directly visualized, and the saturation of each injection and the oil recovery were calculated. During water flooding, preferential flooding channels formed in the highest water-flooded porous layers due to the low viscosity ratio between the injected formation water and the displaced white oil, as well as the permeability contrast in the heterogeneous model. The injected polymer gel mainly followed the preferential flooding channels because of the low resistance force in these channels. After gelation, the polymer gel blocked the main preferential channels and diverted the chase floods to nearby pores. A desirable diversion of the polymer gel highly depends on its propagation path during injection and effective blocking after gelation. Experimental visualization and displacement mechanism analysis indicate the efficacy of the flow diversion by the polymer gel treatment in the heterogeneous porous model. The results provide useful information on the displacement behavior in heterogeneous porous structures, and the conclusions apply to similarly scaled systems at the reservoir scale.",3,3,7
Oil Recovery,Porous Media,"Gaol, Calvin Lumban; Ganzer, Leonhard; Mukherjee, Soujatya; Alkan, Hakan",Parameters govern microbial enhanced oil recovery (MEOR) performance in real-structure micromodels,Microbial enhanced oil recovery; Microfluidics; Real-structure micromodels; Flooding experiments; Monod model,POROUS-MEDIA; IMPACT; WETTABILITY,"Several parameters govern the oil displacement efficiency during microbial enhanced oil recovery (MEOR) processes. These parameters can be classified into four main parameters including (1) microbial growth, which is controlled by nutrient concentration and incubation conditions as well as the flooding sequence management, (2) bacteria community, (3) properties of porous media such as pore size and wettability and (4) other parameters. This paper presents the effects of these parameters on MEOR performance during two-phase flooding experiments in micromodels using reservoir fluid from a German high-salinity oil field. New micromodels generated based on mu CT images of a Bentheimer core plug were used to investigate the MEOR displacement process under elevated pressure, temperature, and anaerobic and sterile conditions. As a result, it was found that microbial growth and its end-products have a significant role in the oil displacement efficiency during the MEOR process. Based on flooding experiments, a significant effect of bioplugging that improved the macroscopic conformance was observed during the MEOR process. This work gives new insights into the pore-scale mechanisms and factors affecting MEOR performance in porous media. The results presented in this paper could be used to support MEOR studies on a larger scale, such as those in the core plug or sandpack before field implementation.",3,3,7
Oil Recovery,Porous Media,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Oil Recovery,Porous Media,"Ali, Hassan; Soleimani, Hassan; Yahya, Noorhana; Khodapanah, Leila; Kozlowski, Gregory; Sabet, Maziyar; Demiral, Birol M. R.; Adebayo, Lawal Lanre; Hussain, Tanvir",Experimental investigation and two-phase flow simulation of oil and nanofluids on micro CT images of sandstone for wettability alteration of the system,Capillary pressure; Oil reservoir; Porous media; Permeability; Oil saturation,PORE NETWORK MODEL; POROUS-MEDIA; PERMEABILITY; TRANSPORT; WATER; MIGRATION; BRINE,"This work provides an analysis of the effect of nanofluids on the wettability of sandstone for the application of enhanced oil recovery. The wettability of sandstone with brine and nanofluids of ZnO, BiFeO3, and SrFeO3 is studied experimentally using contact angle calculations. Also, the direct simulations for the displacement of oil with brine and nanofluids are carried out on a micro-CT scanned porous sandstone structure for the measurement of capillary pressure and relative permeability. Fluid properties such as viscosity and density of the nanofluids, brine, and oil to be used in simulations were obtained using viscometer and densimeter. The experimental results show that the contact angle of crude oil on the sandstone surface has a higher value for nanofluids as 125.89 degrees for ZnO, 122.88 degrees for BiFeO3, and 104.98 for SrFeO3 as compared to brine 28.66 degrees, which means the wettability of the system changes from oil-wet to water-wet by the addition of nanofluids. The simulation results indicate that BiFeO3 nanofluid has a greater tendency to change the wettability of porous medium as compared to brine, ZnO, and SrFeO3 nanofluids, as it shows better values of relative permeability and capillary pressure.",3,3,5
Oil Recovery,Porous Media,"Pinilla, Andres; Asuaje, Miguel; Hurtado, Camila; Hoyos, Angela; Ramirez, Luis; Padron, Aaron; Ratkovich, Nicolas",3D CFD simulation of a horizontal well at pore scale for heavy oil fields,Viscous fingering; Pore-scale; Horizontal well; CFD; Heavy oil; Recovery factor,POROUS-MEDIA; CO2 DISPLACEMENT; FLOW; CAPILLARY; PRESSURE; WATER; FRACTURE; DRAINAGE,"Water production in the oil industry has become so common that colloquial expressions such as ""oil companies no longer produce oil, but water"" have been unconsciously accepted in this industry. Nevertheless, water production is a serious issue in heavy oil fields with strong aquifers or fields under waterflooding for two reasons: It increases the costs affecting the economic viability of a project, and it has a serious environmental impact due to increasing energy consumption and CO2 emissions. The root cause behind this problem is a phenomenon called Viscous Fingering, which appears mainly by the viscosity ratio between the phases. This study aims to understand better the Viscous Fingering phenomenon associated with a horizontal well in 3D. For the first time, a scaled horizontal well in a numerical constructed porous media was studied using a full 3D Computational Fluid Dynamics (CFD) model. The horizontal well was scaled using the Reynolds law of similarity from a real section of a horizontal well. While the porous media was made with the DEM physical model using spherical 7mmparticles, which allows reproducing rock properties such as permeability and porosity. This phenomenon was studied at three different scaled production rates, 1000, 1500, and 2000 bbl/d. Finally, three different oils were considered to study the influence of the viscosity ratio in the CFD modeling of the fingering. It was determined that CM was capable of simulating Viscous Fingering for horizontal wells at the pore scale. Also, it could give information such as production and water cut-profiles, location and time of breakthrough, and specific locations of unrecoverable oil along the reservoir. The information given by the CFD approach could be useful for the development and improvement of completion and enhanced recovery techniques.",3,3,4
Oil Recovery,Porous Media,"Xiao, Lianwei; Zhu, Guangpu; Zhang, Lei; Yao, Jun; Sun, Hai",Effects of pore-size disorder and wettability on forced imbibition in porous media,Imbibition; Pore-size disorder; Wettability; Capillary number; Porous media,IMMISCIBLE DISPLACEMENT; FLUID DISPLACEMENT; SCALE DISORDER; PHASE-DIAGRAM; FLOW; DYNAMICS; DRAINAGE; INVASION; OIL,"Imbibition is the process by which the wetting fluid displaces the non-wetting fluid driven by capillary force. It occurs in many natural and industrial processes, such as enhanced oil recovery and geological carbon sequestration. The imbibition process is highly affected by wettability, viscosity ratio and injection flow rate, and the competition between these factors becomes more complicated when pore-size disorder is involved. In this study, we systematically investigate forced imbibition in four two-dimensional (2D) porous media with different disorders over a broad range of wettability conditions and flow rates. We analyze the relationship between the interfacial length and the invading fluid saturation, and the relationship between displacement front and invading fluid saturation. Results show that disorder and wettability have different impacts on the imbibition process under different capillary numbers. At low capillary number, displacement process is not sensitive to disorder due to the contradicting effects and the imbibition process is governed by the wettability. At intermediate capillary number, only the largest disorder has obvious influence on the displacement process due to the highest entry pressure. The transition from capillary fingering to viscous fingering occurs leading to a higher displacement efficiency. At high capillary number, disorder has a great influence on the front morphology and displacement efficiency while the wettability has relatively weak impact. The pattern transition is also observed at strong imbibition because of the competing effects between the capillary force and the viscous force.",3,4,4
Oil Recovery,Porous Media,"Giraldo, Lady J.; Diez, Rebeka; Acevedo, Socrates; Cortes, Farid B.; Franco, Camilo A.",The effects of chemical composition of fines and nanoparticles on inhibition of formation damage caused by fines migration: Insights through a simplex-centroid mixture design of experiments,Fines migration; Retention; Nanoparticles; Formation damage; Selectivity,PARTICLE-DEPOSITION; POROUS-MEDIA; ADSORPTION; RECOVERY; MOVEMENT; OIL,"Fines migration in the reservoir can leads to damage associated with the mobilization of particles and their posterior accumulation in throat pores, producing obstructions in the flow of fluids, resulting in a decrease of reservoir permeability. An emergent alternative to solve this issue is the use of nanoparticles/nanofluids due to their physicochemical properties that can favor the trapping capacity of fines. Hence, this experimental work aims to evaluate the chemical nature effect of different fines and their respective interaction with three kinds of nanoparticles used in specialized literature for formation damage. In this work was emulated experimentally the retention phenomena through a packed sand bed treated with the different nanofluids and then assessed with the suspension of the fines. The sand beds were prepared with Ottawa sand in two ways: water-wet and sand restored to reservoir wettability (oil-wet). The sand beds were soaked with the specific nanofluids which were with deionized water as carrier fluid for the nanoparticles of iron, silica, and alumina at a dosage of 0.01% in a mass fraction respectively. The suspension of fines was constituted by quartz, kaolinite, illite, at a dosage of 0.2 wt%; the chemical nature was based on an average composition of a Colombian field. The Adams-Bohart, Thomas, and Wolborska models were used for describing the results of breakthrough curves. The beds treated with alumina nanoparticles at 0.01 wt% presented a higher capacity to retain and stabilize the Kaolinite fines, increasing the retention capacity up to 50%. The results agree with the total energy interaction of the fines-nanoparticles system reported for alumina nanofluids. Additionally, critical rate tests at reservoir conditions were performed, obtaining successful results by the increasing of critical rate by more than 50% for water and oil flow velocities in comparison to the untreated system. In this sense, this work presents a comprehensive analysis of selectivity of fines-nanoparticles couples through the design of the optimized experiment, focused on selecting select the best nanofluid treatment for the problem of fines migration.",3,3,2
Oil Recovery,Samples,"Esfandyari, Hamid; Hoseini, Atieh Haghighat; Shadizadeh, Seyed Reza; Davarpanah, Afshin",Simultaneous evaluation of capillary pressure and wettability alteration based on the USBM and imbibition tests on carbonate minerals,USBM test; Imbibition test; Nonionic natural surfactant; Capillary pressure; Wettability alteration,,"Wettability alteration would play a significant role in the hydrocarbon displacement as it can improve oil recovery factor both in conventional and unconventional reservoirs. Therefore, accurate prediction of this parameter would be of importance in displacement sweep efficiencies. In this paper, we aimed to experimentally investigate wettability changes in the presence of a nonionic natural surfactant (Cedar) for different carbonate mineral samples. To do this, Imbibition and USBM tests were taken into consideration to predict capillary pressure and how it affects oil production rate. It is observed that the presence of Cedar had a profound impact on the wettability and capillary pressure for calcite and dolomite samples. Due to the different composition of rock minerals, Cedar has a good effect on both core sample (calcite and dolomite), whereas the oil recovery for dolomite cores is more than calcite cores. This change for calcite cores corresponding oil-wet to neutral-wet or slightly water-wet and for dolomite samples become to water-wet. In addition, the most S-or decreasing occurs in dolomite samples particularly in D1 (14%). Moreover, the oil recovery for reservoir samples is less than mineral samples.",18,18,5
Oil Recovery,Samples,"Rashidi, Sina; Mehrad, Mohammad; Ghorbani, Hamzeh; Wood, David A.; Mohamadian, Nima; Moghadasi, Jamshid; Davoodi, Shadfar",Determination of bubble point pressure & oil formation volume factor of crude oils applying multiple hidden layers extreme learning machine algorithms,Oil formation volume factor; Bubble point pressure; Multi-layer extreme learning machine; Hybrid machine learning algorithms; Least squares support vector machine,SUPPORT VECTOR MACHINE; SHEAR-WAVE VELOCITY; PVT PROPERTIES; CORRELATION-COEFFICIENTS; RELATIVE PERMEABILITY; RESERVOIR; PREDICTION; MODEL; SYSTEMS; PERFORMANCE,"An important requirement of reservoir management is to understand the properties of reservoir fluids and dependent phase behaviors. This makes it possible to determine the properties of reservoir fluids in laboratory pressure-volume-temperature (PVT) tests. Such laboratory tests are costly and time consuming, and reservoir data are sometimes not available. When estimating the in-place fluid volumes and/or designing enhanced recovery processes information on bubble point pressure (BPP) and oil formation volume factor (OFVF) is required. Predicting these two parameters is therefore one of the priorities of reservoir engineers. It is becoming increasingly beneficial to be able to predict BPP and OFVF with efficient machine-learning algorithms based on underlying variables that are more easily measured directly in the field. In this study, a dataset of 638 data records of published crude oil fluid samples from around the world is evaluated. After filtering the dataset for outliers, 591 data records for BPP and 599 datasets for OFVF are evaluated with efficient hybrid machinelearning algorithms (multi-layer extreme learning machine ?MELM? and least squares support vector machine ? LSSVM) optimized using a genetic algorithm ?GA? and a particle swarm optimizer ?PSO? to improve their prediction performance. Four underlying variables are considered for each data record: temperature (T), solution gas oil ratio (Rs), gas specific gravity (?g) and oil gravity (API). The PSO- MELM-PSO hybrid algorithm achieved the highest prediction accuracy measured in terms of root mean square errors (RMSE) of 33.5 psi for BPP and 0.0199 for OFVF. The four-hybrid machine-learning-optimization algorithms evaluated all outperform the empirical relationships used for many decades in the oil industry to predict BPP and OFVF.",11,11,1
Oil Recovery,Samples,"Farhadi, Hamed; Ayatollahi, Shahab; Fatemi, Mobeen","The effect of brine salinity and oil components on dynamic IFT behavior of oil-brine during low salinity water flooding: Diffusion coefficient, EDL establishment time, and IFT reduction rate",Dynamic interfacial tension; Crude-oil/brine system; Time dependent adsorption; Low salinity effect; Asphaltene,INTERFACIAL-TENSION; WETTABILITY ALTERATION; CAPILLARY-PRESSURE; SURFACE-PROPERTIES; ADSORPTION; RECOVERY; SANDSTONE; RESERVOIR; ASPHALTENES; ELECTRONS,"Dynamic behavior of fluid-fluid interactions can potentially affect the performance of any enhanced oil recovery (EOR) process including low salinity water flooding. In this work, dynamic interfacial tension (IFT) of crude-oil/brine system is measured in a wide range of salinity of sea water (SW), from 50-time diluted sea water (SW50D) to 2-time concentrated sea water (SW2C). Contrary to the most of published IFT trends in the literature, for the system under investigation here, as the brine salinity increases the crude-oil/brine IFT reduces, which cannot be explained using the existing theories. The lack of a physical model to explain the observed phenomena was the motivation to develop a new model based on a drift-diffusion theory. This theory considers a current of oil polar molecules toward the oil-water interface which is caused by electrostatic attraction from aqueous ions (drift) and a resistance against this current caused by concentration gradient (diffusion). After applying this model to measured dynamic IFT data, the IFT reduction rate, and electrical double layer (EDL) establishment time are calculated. Then, these matching parameters set as criteria to explain the mechanisms behind the dynamic behavior of crude oil-saline water interfacial tension. For further investigation of the involved mechanisms which are responsible for the macroscopic behavior of crude-oil/brine dynamic IFT, the role of oil components is also examined using the IFT reduction rate and EDL establishment time. Although the obtained results show the asphaltene molecules play a vital role in the dynamic IFT behavior, the concentration of n-heptane, in the model oil containing n-heptane and toluene, is essential to capture the IFT behavior of the crude oil. Increasing n-heptane fraction in the model oil to the amount which exist in the crude oil, results in longer EDL establishment time which is in agreement with the crude oil sample.",11,11,1
Oil Recovery,Samples,"Mohammadi, Mohammad-Reza; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Husein, Maen M.; Ranjbar, Mohammad",Application of cascade forward neural network and group method of data handling to modeling crude oil pyrolysis during thermal enhanced oil recovery,In-situ combustion; EOR; Pyrolysis; TGA; Artificial neural networks; Group method of data handling,IN-SITU COMBUSTION; MINIMUM MISCIBILITY PRESSURE; GENERALIZED REGRESSION; COMPRESSIBILITY FACTOR; KINETICS; PREDICTION; VISCOSITY; HYBRID; ASPHALTENES; OXIDATION,"Oil recovery during in situ combustion is majorly controlled by hydrocarbon oxidation and pyrolysis reactions, which govern fuel formation and heat evolution. Fuel deposition, in turn, can be accurately predicted in part through crude oil pyrolysis using thermogravimetry analysis (TGA). The theoretical models based on TGA runs, however, may be limited to crude oil samples at hand. In this study, we develop more general models to predict the residual mass during crude oil pyrolysis based on multi-layer perceptron (MLP), cascade forward (CFNN), generalized regression (GRNN), and radial basis function (RBF) neural networks. More than 2000 experimental data spanning wide range of weight percentages of asphaltenes and resins as well as oAPI gravities, heating rates, and temperatures are used. Moreover, six optimization algorithms; including Bayesian regularization (BR), scaled conjugate gradient (SCG), Levenberg-Marquardt (LM), conjugate gradient backpropagation with FletcherReeves updates (CGF), resilient backpropagation (RB), and conjugate gradient backpropagation with PolakRibie ' re updates (CGP) are used to improve the performance and prediction ability of the MLP and CFNN neural networks. The CFNN model optimized with the LM algorithm best fits all the experimental data with a mean absolute percent relative error of 1.04%. Lastly, a mathematical correlation is developed utilizing the group method of data handling (GMDH) to estimate the residual mass of crude oil pyrolysis in TGA. Despite its simplicity, the correlation also provides very good estimates. Sensitivity analysis showed that temperature followed by asphaltenes and resin content showed the highest effect on mass loss during crude oil pyrolysis. Outliers estimation applying the Leverage approach suggested only 1% of the data points could be doubtful.",11,11,1
Oil Recovery,Samples,"Strelets, Larisa A.; Ilyin, Sergey O.",Effect of enhanced oil recovery on the composition and rheological properties of heavy crude oil,Heavy crude oil; Enhanced oil recovery; Oil composition; Rheology; Viscosity; Viscoelasticity,GLASS-FORMING LIQUIDS; POLYMER; ASPHALTENE; AGGREGATION; BITUMEN; MEDIA; STATE,"The composition and rheological properties of ten samples of heavy crude oil from five different wells were investigated before and after integrated oilfield treatment with gel-forming and oil-displacing systems for increasing oil recovery. The study of the viscosity and viscoelastic properties of oil samples in a wide temperature range (from -30 to 70 degrees C) made it possible to determine their gelation and glass transition temperatures and also to establish the effect of enhanced oil recovery treatment on these characteristics. It was found that the treatment can either increase or decrease the viscosity of oil, and the same applies to the gelation and glass transition temperatures as well as to the contents of saturates, resins, and asphaltenes. The rheological properties of oil samples were closely related to their group composition, while the changes in the latter as a result of oilfield treatment were dependent on the relative position of the injection and production wells. The work allowed finding universal correlations between the group composition of heavy oil, its viscosity, and test temperature.",10,10,4
Oil Recovery,Samples,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Oil Recovery,Samples,"Pirizadeh, Mohsen; Alemohammad, Nafiseh; Manthouri, Mohammad; Pirizadeh, Meysam",A new machine learning ensemble model for class imbalance problem of screening enhanced oil recovery methods,Classification; Ensemble learning; EOR screening; Class imbalance problem; Mutual information; Hyper-parameter tuning,NEAREST-NEIGHBOR; CLASSIFICATION,"Enhanced Oil Recovery (EOR) methods have received a lot of attention today due to the increase in global oil demand and the reduction of oil production capacity from natural extraction methods. EOR methods are the solution for extracting oil from heavy and extra-heavy reservoirs, but the problem for reservoir engineers is choosing the right EOR method for an oilfield. In fact, the number of EOR methods and the features associated with them are very high, so the financial risk of implementing the wrong EOR method leads to feeling the need for an expert screening tool. Until now, various individual classifiers have been used for this purpose, but due to the class imbalance problem of the EOR dataset, most of them do not have good results, therefore, to increase the accuracy of the model, EOR methods with low records in the dataset are ignored, while industry needs all EOR methods. In this study, an ensemble learning-based approach is used to overcome the problem of class imbalance at the algorithmic level instead of the data level. For this purpose, an effective model called B2S is proposed by gathering the advantages of each of the ensemble-based methods, including Bagging, Boosting, and Stacking. As a result, B2S by creating a balance between variance and bias achieved an average test accuracy of 96.94% on the dataset including 426 samples from 10 different EOR methods that had a highly skewed distribution. The average accuracy also increases to 98.12% with a standard deviation of 1.63%, after grouping some relatively similar EOR methods, which indicates the stability of the proposed method. The study also demonstrates direct relation between model performance and the impact of precise pre-processing, nonlinear feature selection using Mutual Information rather than conventional linear methods, and hyper-parameters tuning with newer methods such as Random Search.",7,7,2
Oil Recovery,Samples,"Zhou, Junping; Yang, Kang; Zhou, Lei; Jiang, Yongdong; Xian, Xuefu; Zhang, Chengpeng; Tian, Shifeng; Fan, Maolin; Lu, Zhaohui",Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure,Shale reservoir; Supercritical carbon dioxide fracturing; Carbon dioxide sequestration; Mechanical alteration; Carbon dioxide-water-shale interaction,SUPERCRITICAL CO2 TREATMENT; PORE STRUCTURE; CARBON-DIOXIDE; FRACTAL ANALYSIS; MULTIFRACTAL CHARACTERISTICS; ADSORPTION BEHAVIORS; FAILURE MECHANISMS; GAS; NMR; WATER,"CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D-1 and pore volume fractal dimensions D-2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO(2), and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D-1 and D-2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.",5,6,24
Oil Recovery,Samples,"Rashidi, Mohammadamin; Kalantariasl, Azim; Saboori, Rahmatallah; Haghani, Abdolhossein; Keshavarz, Alireza",Performance of environmental friendly water-based calcium carbonate nanofluid as enhanced recovery agent for sandstone oil reservoirs,Wettability alteration; EOR; Calcium carbonate; Nanofluid; Sandstone,SURFACE-ENERGY CHARACTERIZATION; WETTABILITY ALTERATION; INTERFACIAL-TENSION; NANOPARTICLES; NANOCOMPOSITE; TEMPERATURE; SIO2; STABILIZATION; INHIBITION; FORCES,"Recent studies have demonstrated great potential of nanofluids as enhanced oil recovery (EOR) agent. Many mechanisms behind increasing oil recovery inducing alteration of surface wettability toward more water wet have been proposed when displacing oil by nanofluids. In this study, the effect of calcium carbonate nanofluid on wettability alteration of sandstone rock samples was studied. Nanoparticle was synthesized by chemical precipitation method and characterized by X-ray diffraction (XRD), fourier-transform infrared spectroscopy (FTIR), field emission scanning electron microscope (FE-SEM) and dynamic light scattering (DLS). The average particle size of nanoparticles was 55.4 nm. The rock samples were aged in oil to ensure desired oil-wet conditions. The effects of nanofluid concentration and temperature on wettability change were investigated and optimum concentration of calcium carbonate nanofluid was determined. Adsorption of nanoparticles on rock surface was characterized by FE-SEM. The wettability alteration was evaluated by measuring/calculating contact angle (static, advancing and receding), surface energy, liquid area fraction, and wettability index. 2-D oil-wet glass micromodel was used to compare the performance of optimum nanofluid concentration obtained from wettability tests against normal water flooding. Results showed alteration of wettability from oil-wet to water-wet for all nanofluid concentrations. More wettability alteration was observed at higher temperature (80 degrees C) than ambient conditions (25 degrees C). Optimum nanofluid concentration (0.025 wt%) was obtained that changed contact angle from 116.41 degrees (non-treated surface) to 46.99 degrees at 25 degrees C and 28.7 degrees at 80 degrees C. Flooding oil-wet 2-D glass micromodel with optimum nanofluid concentration resulted in 20% additional ultimate recovery factor compares to normal water flooding.",5,5,6
Oil Recovery,Samples,"Chen, Weidong; Schechter, David S.",Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs,,WETTABILITY ALTERATION; ADSORPTION; WET,"Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures. Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure. The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition. In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants. The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.",5,5,3
Oil Recovery,Samples,"Alnoush, Wajdi; Sayed, Amr; Solling, Theis I.; Alyafei, Nayef",Impact of calcite surface roughness in wettability assessment: Interferometry and atomic force microscopy analysis,Wettability; Contact angle measurements; AFM; Surface roughness; Interferometry,CONTACT-ANGLE MEASUREMENT; INTERFACIAL-TENSION; OIL-RECOVERY; CARBONATES; SALINITY; RESERVOIRS; MECHANISM; STORAGE; ROCK; TIME,"Wettability is a critical parameter that dictates various aspects related to the recovery of oil from reservoirs. Calcite rocks are used as minerals representative of carbonates to investigate the impact of surface roughness on wettability. Surface roughness was assessed using interferometry and atomic force microscopy (AFM). In this study, two case studies were investigated. The first case study characterizes the wettability of four different calcite samples with different surface roughnesses: naturally cleaved, and three samples grinded with diamond grit sizes of 1250, 1000 and 600. It is shown systematically that decreasing surface roughness results in acontact angle increases from 53 to 81 degrees that is towards the more water wet. In the second case study, the consistency of wettability measurements and trends from different spots of the same calcite surface was studied. For the latter, a total of four different naphthenic acids are added to n-decane to form model oils (the non-aqueous phase) that in principle will alter the wettability differently. In conjunction, four different brines with 1.5 mol% of NaCl, KCl, CaCl2 and Na2CO3, respectively were used to represent the aqueous phase. Wettability was characterized by static and dynamic (advancing and receding) contact angle measurements using the sessile and captive-drop methods, respectively. The results did not reveal any clear trend. A surface roughness analysis for the naturally cleaved calcite sample shed light on the absence of structure in how the electrolytic composition influences the contact angle. The variation in contact angle measurement is found to be large when comparing two different spots on the sample. Therefore, it is only possible to single out a trend when the parameter in concern is very evident such as the oil composition. More subtle trends, such as those that are induced by a brine variation, are hardly apparent and this may be even more important at elevated temperatures because of fluid motion.",5,5,1
Oil Recovery,Samples,"Jia, Bao; Chen, Zeliang; Xian, Chenggang",Investigations of CO2 storage capacity and flow behavior in shale formation,Shale; CO2; Adsorption; Molecular diffusion,ENHANCED OIL-RECOVERY; CARBON-DIOXIDE; ADSORPTION; PRESSURE; RESERVOIRS; METHANE; INJECTION; NETWORKS; SORPTION; EOR,"CO2 storage, CO2 stimulation, CO2-enhanced oil recovery (EOR), and CO2-enhanced gas recovery (EGR) in shale reservoirs have recently attracted attention. Thorough investigations mimicking high pressure and high-temperature subsurface conditions are necessary to understand the interaction between CO2 and organic-rich shales, advance the fundamental understating of flow mechanisms in unconventional reservoirs, and successfully implement a field project. Most of the previous work focused on one aspect of adsorption, flow behavior, and reservoir numerical simulation. We suggest that a single approach investigation may lead to incomplete conclusions of CO2 injection in shales. This work comprehensively evaluates CO2 storage potential and injectivity in the Bakken Formation through various approaches. Samples are tested from the Lower Bakken Shale (LBS), the Middle Bakken (MB), and the Upper Bakken Shale (UBS). In terms of absolute and Gibbs/excess, adsorption isotherms of these two types are both measured, and the adsorbate density is estimated. We differentiate two adsorption isotherms and emphasize the correct use of the isotherm in the current commercial reservoir simulator, which is relatively obscure in the existing literature body. Nuclear magnetic resonance (NMR) confirms a portion of bitumen/absorption mobilization because of CO2 exposure. In the compositional simulations of CO2 injection in shales, several novel conclusions are obtained regarding analyzing main control factors; the most important one is that adsorption outweighs molecular diffusion in determining CO2 injection rate.",4,4,19
Oil Recovery,Samples,"Al-Shirawi, Mariya; Karimi, Mahvash; Al-Maamari, Rashid S.",Impact of carbonate surface mineralogy on wettability alteration using stearic acid,Wettability alteration; Calcite; Limestone; Dolomite; Stearic acid,ORGANIC-COMPOUNDS; NATURAL CALCITE; FATTY-ACIDS; DOLOMITE; ADSORPTION; BEHAVIOR; IONS; SANDSTONE; PH,"Wettability alteration of the reservoir rock toward a favorable wetting state is one of the main recovery mechanisms during enhanced oil recovery (EOR) processes. A clear understanding of the initial wettability of the reservoir rock can be considered the first step toward a successful wettability alteration during any applied EOR technique. The present study investigates the impact of stearic acid on the wetting properties of several carbonate surfaces (calcite, limestone, and dolomite). A systematic experimental approach was followed in which contact angle measurements, Fourier transform infrared (FTIR) spectroscopy, energy dispersive X-ray spectroscopy (EDXS), scanning electron microscopy (SEM), thermo-gravimetric analysis (TGA), and zeta potential measurements were conducted on fresh carbonate samples as well as treated samples with stearic acid. Contact angle results revealed that all fresh carbonate surfaces were strongly water-wet. Aging in the model oil altered the wettability of the carbonates toward oil-wetness with an average contact angle of 159 degrees, 151 degrees, and 137 degrees for calcite, limestone, and dolomite surfaces, respectively. FTIR and EDXS results demonstrated the adsorption of stearic acid on the carbonate surfaces. Moreover, TGA results showed that the amount of adsorbed stearic acid on carbonate surfaces decreases in the following order: calcite (158.3 mu mol/g) > limestone (116.1 mu mol/g) > dolomite (46.4 mu mol/g). Zeta potential measurements revealed a shift toward more negative values after aging the carbonate surfaces in the model oil which confirms the adsorption of the stearic acid on surfaces. Despite the similarities between carbonate surfaces, the experimental observations clearly highlighted the significant impact of the mineralogical composition of the carbonate surface on the electrical and wetting properties of the surfaces. More positively charged surface of calcite resulted in more electrostatic attraction between the calcite and stearate ions which led to superior affinity of stearic acid toward calcite as compared with limestone and dolomite. The presence of other minerals with calcite on the carbonate surfaces affected the adsorption of stearic acid and the electrical properties of the surface.",4,4,6
Oil Recovery,Samples,"Yusuff, Afeez Oluwatobi; Yahya, Noorhana; Zakariya, Mohd Azman; Sikiru, Surajudeen",Investigations of graphene impact on oil mobility and physicochemical interaction with sandstone surface,Enhanced oil recovery; Graphene; Physicochemical interaction; Viscosity; Diffusion coefficient; Molecular dynamic simulation,SHEAR VISCOSITY; NANOPARTICLES; DIFFUSION; RECOVERY; AGGREGATION; PERFORMANCE; SIMULATION; MECHANISM; MEDIA; MODEL,"Enhanced oil recovery (EOR) is the recovery of oil trapped in the reservoir after primary and secondary recovery processes through novel techniques. Viscosity is primarily a major cause of the high proportion of hydrocarbon fluid entrapped. Recently, emergence of nanotechnology has gained attention in oil industry. The major factor hindering the efficiency of nanoparticles is poor transport inside the reservoir due to high adsorption energy to grains surfaces, leading to their retention. Some studies have reported the effectiveness of nanoparticles on oil viscosity. However, report on the use of pristine graphene has been missing along with requisite transportation behaviour on sandstone surface. This work investigates the applicability of graphene in EOR. The effects of graphene concentrations (0.01, 0.05 & 0.1 wt%) on flowability of oil (50 cP and 0.85 cP), and its adsorption energy are reported. Experimentally, viscosity of the more viscous crude oil was reduced by 43-65%. Using molecular simulation, diffusion coefficient estimation indicate improvement in diffusivity of light decane by 112%. Furthermore, the adsorption energy of graphene is surprisingly found to be low (-9.11 kcal/mol). This study concluded that graphene is applicable, the oil sample is Newtonian and viscosity well reduced.",4,4,4
Oil Recovery,Samples,"Weschenfelder, S. E.; Fonseca, M. J. C.; Borges, C. P.",Treatment of produced water from polymer flooding in oil production by ceramic membranes,Enhanced oil recovery; Reinjection; Oil and grease; Removal; Ultrafiltration; Produced water,POLYACRYLAMIDE; EFFICIENCY; STABILITY,"Polymeric additives are widely used in the oil and gas industry to increase the viscosity of the water injected into the reservoirs for enhancing oil recovery. This technique, also known as polymer flooding (PF), promotes the cogeneration of polymeric residues in the produced water stream. These residues cause an important efficiency reduction on the removal of oil and greases, by commonly used systems installed on offshore oil production platforms. Since ultrafiltration ceramic membranes have been considered as an improvement for designing more efficient treatment processes for new offshore installation units, the authors decided to conduct this work. The study aimed to assess the impact promoted by the presence of a polymer frequently used for PF on the performance of produced water treatment by an ultrafiltration ceramic membrane. For all the experimental conditions, it was observed that the selected membrane, with an average 0.1 mu m pore size of, was able to generate a permeate stream with oil and greases concentration (C-O) less than 5 mg/L. However, the polymer caused a significant impact on the membrane permeation flux, even when present in the saline samples at the concentration of 0.1 g/L. Under this condition, a reduction of 84% from the initial permeation flux (430 L/h.m(2)) was observed after 40 min of operation. Increasing the polymer concentration to 1.0 g/L resulted in an additional cutback of 9% from this value. When this sheared sample was prepared without salt, the permeation flux decrease was less intense, but still very significant. In this case, the final flux was 70 L/h.m(2), representing a reduction of 83% from the initial value.",4,4,0
Oil Recovery,Samples,"Li, Hanyong; Gao, Hang; Zhao, Xiaonan; Xia, Zijie; Yu, Bo; Sun, Dongliang",Experimental study on viscosity reduction of heavy oil with water content by synergistic effect of microwave and nano-catalyst,Viscosity reduction; Microwave heating; Nano-catalyst; Heavy oil; Water content,CRUDE-OIL; ASPHALTENES; DEMULSIFICATION; NANOPARTICLES; EMULSIONS; RECOVERY,"With the depleting of conventional oil and gas resources, viscosity reduction of heavy oil became more and more important as a research focus. As a new method of viscosity reduction, the mechanism of microwave-assisted with nano-catalysts is still unclear. In this paper, the viscosity reduction of nano-catalyst and microwave treatment of heavy oil in different water content was studied. The experimental results showed that the maximum viscosity reduction was 96.81 % when the water content was 50 wt% under the conditions of microwave heating power of 614w, microwave heating temperature of 68 degrees C and nickel nano-catalyst concentration of 0.8 wt%. The oil samples before and after three treatments were analyzed by infrared spectroscopy, element analysis, four-component separation, and two-dimensional gas chromatography-mass spectrometry. By analyzing the changes of functional group, element composition, and component content, the effects of microwave and nano-catalyst were studied. The results showed that the resin and asphaltene content decreased by 17.3 wt%, and the hydrogen to carbon ratio was 2.14 when the water content was 30 wt% under the conditions of microwave heating power of 666w, microwave heating temperature of 65 degrees C and nickel nano-catalyst concentration of 2.3 wt%, which proved that microwave treatment assisted with nano-catalysts could increase the cracking capacity of macromolecules and the production of coke.",3,3,10
Oil Recovery,Samples,"Liu, Hongping; Luo, Yang; Meng, Yujing; Xiao, Gaojian; Zhao, Yanchao; Zhou, Sibin; Shao, Longkan",Effects of pore structure on the moveable oil saturation in water-driven tight oil sandstone reservoirs,Tight oil sandstone; Pore structure; Waterflooding; CT scanning; Movable oil saturation,NUCLEAR-MAGNETIC-RESONANCE; MOVABLE FLUID; ORDOS BASIN; YANCHANG FORMATION; MERCURY INTRUSION; PERMEABILITY; POROSITY; PARAMETERS; FIELD; NMR,"Tight oil sandstones have large oil reserves but low waterflooding efficiency and oil recovery. The movable oil saturation (MOS) is a critical parameter for evaluating oil recovery in water-driven tight oil sandstone reservoirs. However, its controlling factors in tight oil sandstones are still not well understood. In this study, the tight/low-permeability sandstones in the Chang 8 and Chang 9 Members of the Honghe Oil Field in the Ordos Basin (China) provide an opportunity to determine the effects of pore structure on the MOS. Porosity, permeability, thin sections, scanning electron microscopy (SEM), large field-of-view SEM imaging method (MAPS technique), highpressure mercury intrusion (MICP), and micro-CT scanning were systemically conducted to analyze the pore structure analysis. MOS values were obtained from the relative permeability tests. The results show that porosity, pore-throat size, and the sorting coefficient have no evident relationship with the MOS. Many of the higher-permeability samples even show lower MOS values. Moreover, analysis of micro-CT images before and after waterflooding indicates that the lower-permeability samples tend to swept larger areas than the higher-permeability samples, resulting in greater oil-displacement efficiencies and MOS values. Instead, the cumulative mercury saturation at the apex of the mercury injection hyperbola curve (S apex ), the ratio of the maximum pore-throat radius and the medium pore-throat radius (R-max/R-50), and movable fluid saturation (MFS) show a good linear relationship with the MOS. The displaced oil is primarily from intergranular pores and partly from intragranular pores. The micropores that are widely distributed at the grain-grain contact display low original oil saturation and low oil displacement efficiency. It is proposed that the volume of the well-connected pores that contribute to permeability is the key factor controlling the MOS regardless of the type of rock.",3,2,9
Oil Recovery,Samples,"Afekare, Dayo; Garno, Jayne; Rao, Dandina",Enhancing oil recovery using silica nanoparticles: Nanoscale wettability alteration effects and implications for shale oil recovery,Nanofluid; Enhanced oil recovery; Atomic force microscope; Wettability; Nanoparticle; Tuscaloosa marine shale,PHASE-BEHAVIOR; ADHESION; ADSORPTION; PRESSURE; CONTACT; CURVES; CORES; FINES,"Enhanced oil recovery (EOR) techniques have the potential to improve recovery in unconventional shale oil reservoirs which have prolific short-term success but elusive near-to-long term outlook. The use of silicon dioxide nanoparticles for enhancing shale oil recovery has recently gained significant attention in the oil industry. However, the technique remains novel partly due to inadequate fundamental understanding of oil release mechanisms. Herein, the oil recovery potential of untreated and treated silica nanoparticles is investigated using an atomic force microscope (AFM) by studying nanoscale interactions between different crude oil functional species and substrates of pure minerals found in a shale oil reservoir. Quartz and muscovite mica (clay substitute) were employed as substrates as these are the dominant rock minerals identified in the most productive zone of Tuscaloosa Marine Shale (TMS). Thiolates of undecane (CH3) and phenyl (C6H5) compounds were used to simulate alkane and aromatic fractions of TMS crude oil respectively, while undecanoic acid (COOH) thiol was used to represent carboxylic acid found in asphaltene and resin components. Following our in-house experimental protocol for liquid cell force spectroscopy, adhesion forces and surface energies between functionalized AFM probes and mineral substrates were characterized in untreated and amino-treated silica nanoparticle dispersions. Zeta potential of respective nanofluid solutions was measured and AFM adsorption data were supported with scanning electron microscope (SEM) micrographs of TMS rock samples. Results showed that aqueous dispersions of hydrophilic silicon dioxide nanoparticles promote wettability towards a less oil-wet state by significantly lowering the adhesion force and energy barrier to spontaneously detach oil molecules from clay and quartz mineral surfaces in shale reservoirs, shown at the nanoscale with AFM studies. However, the grafting of aminosilanes onto surfaces of silica nanoparticles generally increased adhesion forces and surface energies due to surface charge effect and hydrophobicity. Findings pertinent to nanoparticle silanization were consistent in molecular interactions on mica in nanofluids but not necessarily predictable with quartz surfaces, highlighting mineralogical effects. The irreversible adsorption of silica nanoparticles was also observed. Adhesion force and energy are resolved in various intermolecular forces such as electric double layer repulsion, non-electrostatic interaction and structural forces. The scientific significance and broad engineering implications of results were comprehensively discussed in the context of previously reported core-to-field scale observations of nanofluid EOR. This study pitches new light on the scientific understanding of silica-based nanofluid EOR by probing nanoscale wetting effects of silica nanoparticles with implications for shale oil recovery. The findings herein can help for better understanding of the design of nanofluid EOR reagents and the conditions that favor application of silica nanofluid EOR.",3,3,8
Oil Recovery,Samples,"Wang, Yuxia; Shang, Qinghua; Zhou, Lifa; Jiao, Zunsheng",Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin,Permeability heterogeneity; CO2 flooding; EOR; Tight sandstone reservoir; Ordos Basin,OIL-RECOVERY; CARBON-DIOXIDE; INJECTION,"Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200-1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with elastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO 2 -EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high-low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high-low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.",3,3,6
Oil Recovery,Samples,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Oil Recovery,Samples,"Akhlaghi, Naser; Riahi, Siavash; Parvaneh, Ronak","Interfacial tension behavior of a nonionic surfactant in oil/water system; salinity, pH, temperature, and ionic strength effects",Triton X-100; IFT; CMC; Enhanced oil recovery; PH; Salinity,ENHANCED OIL-RECOVERY; ASSISTED GRAVITY DRAINAGE; ACIDIC CRUDE-OIL; WATER; IFT; WETTABILITY; BRINE; PERFORMANCE; ASPHALTENE; COMPONENTS,"Since most of the world's oil reservoirs are in the second half lifetime, the use of Enhanced Oil Recovery (EOR) methods is inevitable. Interfacial Tension (IFT) is one of the effective parameters on EOR can be changed by surfactants. But surfactant injection is one of the costly methods and chemistry of the surfactant solutions such as salinity (one and two valence ions) and pH should be engineered. Furthermore, the temperature is an effective parameter affecting on IFT. In this study, the effect of salinity, especially hard salinity, temperature and pH on IFT between Triton X-100 surfactant and an Iranian oil sample has been investigated. In order to, evaluate the effect of salinity, different concentrations of NaCl, CaCl2, MgCl2, and Na2SO4 salts (0, 0.1, 0.5, and 1 wt%) were used in different concentrations of surfactant. IFT results showed that magnesium and calcium divalent cations had a greater effect on IFT reduction than monovalent sodium cation. Also, all the studied cations were more effective than sulfate as a divalent anion. The ionic strength of the solutions was inversely proportional to the IFT amounts. Less value of IFT in the presence of magnesium ions than calcium ions was due to the higher ionic strength of solutions containing magnesium compared with calcium. IFT results at three temperatures (20, 40, and 60 degrees C) proved that by increasing temperature IFT increased. Also, the effect of pH on IFT in three pHs including acidic, almost neutral and alkaline in the presence of surfactant was studied. Results indicated that IFT decreased with increasing pH, especially in concentrations lower than critical micelle concentration (CMC).",3,3,4
Oil Recovery,Samples,"Fu, Qinwen; Cudjoe, Sherifa; Ghahfarokhi, Reza Barati; Tsau, Jyun-Syung; Li, Xiaoli; Peltier, K.; Mohrbacher, D.; Baldwin, A.; Nicoud, B.; Bradford, K.",Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection-an Eagle Ford study,Molecular diffusion; Hydrocarbon gas huff-n-puff; Dual-permeability; Rock-fluid property; Gas injection; Eagle Ford shale; Unconventional reservoirs; EOR; IOR,OIL,"Fracture complexity, variation in fluid properties, variations in rock types and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research has been conducted to define diffusion coefficients coupled with rock tortuosity resulting in calculation of effective diffusion. The objective of this work is to conduct a comprehensive experimental and simulation study on lower Eagle Ford rock samples to measure diffusion coefficients for different injection cycles in three representative rock samples from the main flow unit. Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and effluent oil and gas compositions were measured. NMR measurement was repeated at the end. Three compositional simulation models were set up for three different samples using tortuosity values from FIB-SEM analysis to simulate experimental diffusion and production. For history matching, relative permeability curves, fracture properties, and tortuosity were tuned to match pressure and production results for three representative samples. Pressure profiles vary significantly between different cycles caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Effective diffusion coefficients were calculated using representative tortuosity values. Diffusion was represented by pressure drop during soaking time. This pressure drop varies across different lithofacies and for different rock samples. For produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate components increased. Gas huff-n-puff injection into shale oil reservoirs were being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments, conducted using a constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, show favorable results. Recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively.",3,3,4
Oil Recovery,Samples,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Oil Recovery,Samples,"Tatar, Amin; Mohammadi, Saba; Soleymanzadeh, Aboozar; Kord, Shahin",Predictive mixing law models of rock thermal conductivity: Applicability analysis,Thermal conductivity; Mixing model; Geometric mean,THERMOPHYSICAL PROPERTIES; FLUID; PRINCIPLES; POROSITY,"Thermal conductivity is defined as the ability of a material to conduct the heat. Rock thermal conductivity is influenced by several parameters such as mineral composition, geometrical factors, porosity, and saturation condition. Value of the rock thermal conductivity is necessary in all thermal processes in petroleum engineering such as thermal methods of enhanced oil recovery. Laboratory measurement of the thermal conductivity of rock samples is time-consuming and expensive. Therefore, a large number of correlations and models have been presented to predict the rock thermal conductivity. These correlations and models are divided into three categories, i.e. mixing models, empirical and semi-empirical correlations, and theoretical models. In this paper, it was attempted to investigate 15 different predictive mixing models of rock thermal conductivity and examine their applications for different rock types and different saturation conditions using 159 collected data points. Validity and applicability of these predictive models were discussed using graphical and statistical error analysis. Results indicated that geometric mean model and Albert model can provide an accurate estimation of rock thermal conductivity with average absolute relative deviation (AARD) of 11.58% and 13.87%, respectively. Moreover, the applicability of each model was evaluated for different conditions of rock type and saturation. This evaluation revealed that Walsh, Alishaev, and Zimmerman models are more accurate than geometric mean model and Albert model for some specific conditions of rock type and saturation. Indeed, Walsh model is the best predictive thermal conductivity model for air saturated crystalline rocks, Alishaev model is the best model for predicting thermal conductivity of water saturated crystalline rocks and Zimmerman model provides the best estimation of the thermal conductivity of water saturated dolomite rocks. It should be noted that structural properties, which affect the rock thermal conductivity, are not considered in the mixing models which is the main limitation of this type of predictive models.",3,3,2
Oil Recovery,Gas,"Abdelghany, Wael K.; Radwan, Ahmed E.; Elkhawaga, Mohamed A.; Wood, David A.; Sen, Souvik; Kassem, Ahmed A.",Geomechanical modeling using the depth-of-damage approach to achieve successful underbalanced drilling in the Gulf of Suez rift basin,Sub-surface stress regime; Depth of damage; Wellbore breakout; Over-pressured formations; Underbalanced drilling; High-pressure formations; Wellbore stability,HYDRAULIC FRACTURE INITIATION; BOREHOLE STABILITY ANALYSIS; CONSOLIDATED ROCK STRATA; PRESENT-DAY STATE; WELLBORE-STABILITY; BADRI FIELD; BELAYIM FORMATION; EFFECTIVE STRESS; TECTONIC STRESS; PORE PRESSURE,"Typical oil and gas reservoirs producing in the Gulf of Suez are now extensively depleted in terms of recovery of conventional resources and display declining production levels and heterogeneous pore pressure regimes. To continue production on a commercially viable basis and enhance the recovery of remaining oil and gas from the mature reservoirs currently in production, drilling decision-makers can no longer rely on traditional balanced or overbalanced drilling methods. Hence, underbalanced drilling is an essential requirement for such reservoirs. However, inducing underbalanced conditions increases the risk of the borehole instability. In the studied area, three previous wellbore stability studies were performed associated with the Hilal-X platform wells using the breakout-width-failure concept. Nevertheless, several wellbore instability issues were recorded there due to that method determining a mud-weight window that was too conservative. New wellbore stability analysis has been performed using a depth-of-damage approach. This analysis has helped to deliver excellent results during underbalanced drilling, after many attempts in previously drilled wells in overbalanced conditions that resulted in borehole instability and/or formation damage. This study documents how successful underbalanced drilling has been achieved in this basin for the first time by mud weights being guided by depth-of-damage analysis, highlight the requirements of that method using a case study for a specific well. In-situ stresses and an 1D-geomechanical earth model were generated using well log data from offset wells. The modified Lade method was used as a failure criterion, while the depth-of-damage approach was used for wellbore stability analysis in HilalX4 well. The study reveals that: 1) the Hilal field reservoirs have variable pore pressure regimes, 2) the breakoutwidth-failure concept provides misleading results in the studied reservoir formation, 3) the depth-of-damage approach reflects reservoir conditions more effectively and allows for successful underbalanced drilling without any instability events, 4) a new casing design for the Hilal Field wells has led to enhanced production performance, and 5) underbalanced drilling, when downhole pressures are carefully managed, is a safe and reliable technique for the mature fields of the Gulf of Suez rift basin.",25,25,10
Oil Recovery,Gas,"Rashidi, Sina; Mehrad, Mohammad; Ghorbani, Hamzeh; Wood, David A.; Mohamadian, Nima; Moghadasi, Jamshid; Davoodi, Shadfar",Determination of bubble point pressure & oil formation volume factor of crude oils applying multiple hidden layers extreme learning machine algorithms,Oil formation volume factor; Bubble point pressure; Multi-layer extreme learning machine; Hybrid machine learning algorithms; Least squares support vector machine,SUPPORT VECTOR MACHINE; SHEAR-WAVE VELOCITY; PVT PROPERTIES; CORRELATION-COEFFICIENTS; RELATIVE PERMEABILITY; RESERVOIR; PREDICTION; MODEL; SYSTEMS; PERFORMANCE,"An important requirement of reservoir management is to understand the properties of reservoir fluids and dependent phase behaviors. This makes it possible to determine the properties of reservoir fluids in laboratory pressure-volume-temperature (PVT) tests. Such laboratory tests are costly and time consuming, and reservoir data are sometimes not available. When estimating the in-place fluid volumes and/or designing enhanced recovery processes information on bubble point pressure (BPP) and oil formation volume factor (OFVF) is required. Predicting these two parameters is therefore one of the priorities of reservoir engineers. It is becoming increasingly beneficial to be able to predict BPP and OFVF with efficient machine-learning algorithms based on underlying variables that are more easily measured directly in the field. In this study, a dataset of 638 data records of published crude oil fluid samples from around the world is evaluated. After filtering the dataset for outliers, 591 data records for BPP and 599 datasets for OFVF are evaluated with efficient hybrid machinelearning algorithms (multi-layer extreme learning machine ?MELM? and least squares support vector machine ? LSSVM) optimized using a genetic algorithm ?GA? and a particle swarm optimizer ?PSO? to improve their prediction performance. Four underlying variables are considered for each data record: temperature (T), solution gas oil ratio (Rs), gas specific gravity (?g) and oil gravity (API). The PSO- MELM-PSO hybrid algorithm achieved the highest prediction accuracy measured in terms of root mean square errors (RMSE) of 33.5 psi for BPP and 0.0199 for OFVF. The four-hybrid machine-learning-optimization algorithms evaluated all outperform the empirical relationships used for many decades in the oil industry to predict BPP and OFVF.",11,11,1
Oil Recovery,Gas,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Oil Recovery,Gas,"Qin, Guowei; Dai, Xu; Sui, Lei; Geng, Meng; Sun, Linghui; Zheng, Yanzhao; Bai, Yanming",Study of massive water huff-n-puff technique in tight oil field and its field application,Massive water huff-n-puff; Tight oil reservoir; Imbibition; Horizontal well,RECOVERY; GAS,"Based on the characteristics of horizontal oil wells in tight reservoirs during their late stage, which are exploited by elastic drive of natural energy and stimulated by large-scale volume fracturing; the massive water huff-n-puff technique is proposed for the use of supplementing the energy of the depleted formations, which can effectively increase the productivity of single horizontal oil well in addition to its financial benefits. In this paper, the massive water huff-n-puff technique is defined and discussed from the following aspects of the mechanism, reservoir engineering, laboratory experiments and so forth. Additionally, comprehensive analyses of the advantages of applying this technique in the development of tight oil reservoirs are provided. By the studies of the pressure composition diagram and the definition of residual injection pressure (RIP) in reservoirs, a massive water huff-n-puff mathematical model was established and the critical parameters for water-flooding were calculated. Laboratory experiments of this technique have shown that it can induce a certain number of micro-fracture networks and its application in actual oilfields also shown positive results. The pilot tests have achieved remarkable increases in productivity and economic benefits. For example, the average daily oil production from a single well is increased by 4.5 t/d (0.8 -> 5.3 t/d), the formation pressure has increased by 9.3 MPa (6.9 -> 16.2 MPa), accumulated oil production has reached 1,987t, and its input-output ratio has shown an enhancement in the range of 1.00:1.74-1.00:4.06. The research results of this technique provide a new way and an important model for efficient development of horizontal wells in tight oil reservoirs.",6,5,3
Oil Recovery,Gas,"Wei, Wei; Rezazadeh, Alan; Wang, Jingyi; Gates, Ian D.",An analysis of toe-to-heel air injection for heavy oil production using machine learning,Heavy oil; In situ combustion; Toe-to-heel air injection; Machine learning; Data analytics; Clustering analysis,IN-SITU COMBUSTION; GRAVITY DRAINAGE; REACTION MODEL; RECOVERY; SIMULATION; SANDS,"With strong potential for improving productivity, economics, and efficiencies, data analytics and machine learning are rapidly emerging in the oil and gas industry. However, their application in heavy oil production is scarce. In this study, we use clustering methods to analyze the Kerrobert Toe-to-Heel Air Injection (THAI) project to understand the inter-relationships of production variables and seek for optimal operating strategy to maximize production rate. More specifically, we use the K-means, normal mixtures and hierarchical clustering methods to determine how operating parameters contribute to oil production. The results reveal that, at current operation mode, air injection rate is constrained for production maximization due to the balance between heat generation and cooling of combustion system by excess air supply. The results also provide insight for improved productivity from THAI suggesting that cyclic injection may improve process performance. The new insights demonstrate that data analytics can provide new understanding of recovery processes as well as potential process improvement.",6,6,0
Oil Recovery,Gas,"Zhou, Junping; Yang, Kang; Zhou, Lei; Jiang, Yongdong; Xian, Xuefu; Zhang, Chengpeng; Tian, Shifeng; Fan, Maolin; Lu, Zhaohui",Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure,Shale reservoir; Supercritical carbon dioxide fracturing; Carbon dioxide sequestration; Mechanical alteration; Carbon dioxide-water-shale interaction,SUPERCRITICAL CO2 TREATMENT; PORE STRUCTURE; CARBON-DIOXIDE; FRACTAL ANALYSIS; MULTIFRACTAL CHARACTERISTICS; ADSORPTION BEHAVIORS; FAILURE MECHANISMS; GAS; NMR; WATER,"CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D-1 and pore volume fractal dimensions D-2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO(2), and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D-1 and D-2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.",5,6,24
Oil Recovery,Gas,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Oil Recovery,Gas,"Zheng, Heng; Liao, Ruiquan; Cheng, Ning; Shi, Shanzhi",Microscopic mechanism of fracturing fluid imbibition in stimulated tight oil reservoir,Fracturing fluid; Imbibition; Micro-characteristics; Experiments; Kinetic energy,INTERFACIAL-TENSION; WATER BLOCKING; IFT REDUCTION; 2-PHASE FLOW; PORE-SCALE; PERMEABILITY; SANDSTONE; WETTABILITY; RECOVERY; GAS,"The imbibition of fracturing fluid is of great significance to improve the development of fractured tight oil reservoirs. Understanding the micro-characteristics of fracturing fluid imbibition is necessary to improve the imbibition efficiency. In this work, the experiments of the spontaneous imbibition under simulated in-situ condition is conducted to understand the micro-characteristics of fracturing fluid imbibition, and the Nuclear magnetic resonance (NMR) and high-resolution X-rays computed tomography (CT) scanning are applied to monitor the process and the liquid distribution of spontaneous imbibition. The experimental results indicate that the spontaneous imbibition is mainly occurred in macropores at the initial stage, and the velocity of fracturing fluid is lower than that of formation water in spontaneous imbibition due to the weaker motivity generated from the lower oil-fracturing fluid interfacial tension. The fracturing fluid can promote the spontaneous imbibition due to it can decrease the kinetic energy loss when it transforms into the interfacial free energy. Thus, the oil recovery obtained from the fracturing fluid imbibition increased to 20.7% from 15.8% by formation water imbibition. The main reason accounts for it is that the wettability of fracturing fluid is stronger than that of formation water, thus can promote the whole process of spontaneous imbibition, and the lower viscosity would reduce the flow resistance at the latter stage. A higher oil-water interfacial tension (IFT) can accelerate the velocity of spontaneous imbibition at the initial stage, while a proper interfacial tension is favorable at the latter stage.",4,4,21
Oil Recovery,Gas,"Jia, Bao; Chen, Zeliang; Xian, Chenggang",Investigations of CO2 storage capacity and flow behavior in shale formation,Shale; CO2; Adsorption; Molecular diffusion,ENHANCED OIL-RECOVERY; CARBON-DIOXIDE; ADSORPTION; PRESSURE; RESERVOIRS; METHANE; INJECTION; NETWORKS; SORPTION; EOR,"CO2 storage, CO2 stimulation, CO2-enhanced oil recovery (EOR), and CO2-enhanced gas recovery (EGR) in shale reservoirs have recently attracted attention. Thorough investigations mimicking high pressure and high-temperature subsurface conditions are necessary to understand the interaction between CO2 and organic-rich shales, advance the fundamental understating of flow mechanisms in unconventional reservoirs, and successfully implement a field project. Most of the previous work focused on one aspect of adsorption, flow behavior, and reservoir numerical simulation. We suggest that a single approach investigation may lead to incomplete conclusions of CO2 injection in shales. This work comprehensively evaluates CO2 storage potential and injectivity in the Bakken Formation through various approaches. Samples are tested from the Lower Bakken Shale (LBS), the Middle Bakken (MB), and the Upper Bakken Shale (UBS). In terms of absolute and Gibbs/excess, adsorption isotherms of these two types are both measured, and the adsorbate density is estimated. We differentiate two adsorption isotherms and emphasize the correct use of the isotherm in the current commercial reservoir simulator, which is relatively obscure in the existing literature body. Nuclear magnetic resonance (NMR) confirms a portion of bitumen/absorption mobilization because of CO2 exposure. In the compositional simulations of CO2 injection in shales, several novel conclusions are obtained regarding analyzing main control factors; the most important one is that adsorption outweighs molecular diffusion in determining CO2 injection rate.",4,4,19
Oil Recovery,Gas,"Pinto, Helen; Wang, Xin; Gates, Ian",On the ratio of energy produced to energy injected in SAGD: Long-term consequences of early stage operational decisions,Steam-assisted gravity drainage; Energy efficiency; Thermal recovery; Energy produced versus energy injected (EPEI); Time-limited operator influence,,"Steam-Assisted Gravity Drainage (SAGD) is a recovery process used to extract bitumen from underground reservoirs. The efficiency of SAGD is determined by the volume of steam injected (reflecting cost and greenhouse gas emissions) relative to the volume of oil recovered (revenue). Another way to look at this relationship is as a ratio of cumulative energy produced to energy injected (EPEI). First described in this study, EPEI ratios offer a novel perspective on SAGD because they reduce the inter-well comparison bias caused by operational choices such as steam temperature, steam quality and well length. There are numerous studies on SAGD from an experimental, analytical or numerical simulation perspective, but all require assumptions and constraints specified in advance, and can only return an approximation of field performance. Studies that work exclusively with field data have typically been used for prediction modeling only. In contrast, this study employs a novel methodology by working within the existing constraints and operational choices of SAGD field wells to infer the number of steam-oil performance relationships present, and how long they last. One by one, we eliminate parameters that cannot cause the performance differences seen in the field using only deductive reasoning and multi-parameter sensitivity analysis, and arrive at possible reasons for the performance relationships found. 1520 SAGD well pairs in Alberta, Canada are used, which is more than 90% of the wells in Alberta over the last 20 years, and to the best of our knowledge, the largest field well set of any SAGD study to date. This comprehensive data set ensures that findings are applicable across the industry. Results reveal a new and surprising finding that the EPEI ratio is set during the first few months on production, and is very difficult to change thereafter. Hence, operators have a short, time-limited opportunity to influence each well's recovery ratio (and therefore its profitability and greenhouse gas emissions). This reflects the importance of process start-up and the first few months after start-up when the near well region of the reservoir is conditioned. Finally, the stability of the EPEI ratio permits a simple, new model capable of predicting cumulative recovery months in advance.",4,4,0
Oil Recovery,Gas,"Weschenfelder, S. E.; Fonseca, M. J. C.; Borges, C. P.",Treatment of produced water from polymer flooding in oil production by ceramic membranes,Enhanced oil recovery; Reinjection; Oil and grease; Removal; Ultrafiltration; Produced water,POLYACRYLAMIDE; EFFICIENCY; STABILITY,"Polymeric additives are widely used in the oil and gas industry to increase the viscosity of the water injected into the reservoirs for enhancing oil recovery. This technique, also known as polymer flooding (PF), promotes the cogeneration of polymeric residues in the produced water stream. These residues cause an important efficiency reduction on the removal of oil and greases, by commonly used systems installed on offshore oil production platforms. Since ultrafiltration ceramic membranes have been considered as an improvement for designing more efficient treatment processes for new offshore installation units, the authors decided to conduct this work. The study aimed to assess the impact promoted by the presence of a polymer frequently used for PF on the performance of produced water treatment by an ultrafiltration ceramic membrane. For all the experimental conditions, it was observed that the selected membrane, with an average 0.1 mu m pore size of, was able to generate a permeate stream with oil and greases concentration (C-O) less than 5 mg/L. However, the polymer caused a significant impact on the membrane permeation flux, even when present in the saline samples at the concentration of 0.1 g/L. Under this condition, a reduction of 84% from the initial permeation flux (430 L/h.m(2)) was observed after 40 min of operation. Increasing the polymer concentration to 1.0 g/L resulted in an additional cutback of 9% from this value. When this sheared sample was prepared without salt, the permeation flux decrease was less intense, but still very significant. In this case, the final flux was 70 L/h.m(2), representing a reduction of 83% from the initial value.",4,4,0
Oil Recovery,Gas,"Li, Hanyong; Gao, Hang; Zhao, Xiaonan; Xia, Zijie; Yu, Bo; Sun, Dongliang",Experimental study on viscosity reduction of heavy oil with water content by synergistic effect of microwave and nano-catalyst,Viscosity reduction; Microwave heating; Nano-catalyst; Heavy oil; Water content,CRUDE-OIL; ASPHALTENES; DEMULSIFICATION; NANOPARTICLES; EMULSIONS; RECOVERY,"With the depleting of conventional oil and gas resources, viscosity reduction of heavy oil became more and more important as a research focus. As a new method of viscosity reduction, the mechanism of microwave-assisted with nano-catalysts is still unclear. In this paper, the viscosity reduction of nano-catalyst and microwave treatment of heavy oil in different water content was studied. The experimental results showed that the maximum viscosity reduction was 96.81 % when the water content was 50 wt% under the conditions of microwave heating power of 614w, microwave heating temperature of 68 degrees C and nickel nano-catalyst concentration of 0.8 wt%. The oil samples before and after three treatments were analyzed by infrared spectroscopy, element analysis, four-component separation, and two-dimensional gas chromatography-mass spectrometry. By analyzing the changes of functional group, element composition, and component content, the effects of microwave and nano-catalyst were studied. The results showed that the resin and asphaltene content decreased by 17.3 wt%, and the hydrogen to carbon ratio was 2.14 when the water content was 30 wt% under the conditions of microwave heating power of 666w, microwave heating temperature of 65 degrees C and nickel nano-catalyst concentration of 2.3 wt%, which proved that microwave treatment assisted with nano-catalysts could increase the cracking capacity of macromolecules and the production of coke.",3,3,10
Oil Recovery,Gas,"Das, Alolika; Mohanty, Kishore; Nguyen, Quoc",A pore-scale study of foam-microemulsion interaction during low tension gas flooding using microfluidics-Tertiary recovery,Enhanced oil recovery; Foam; Ultralow interfacial tension; Microemulsion; Microfluidics,OIL DISPLACEMENT,"The emerging EOR technology of Low-Tension-Gas (LTG) flooding has been proven to be successful for tertiary oil recovery in laboratory scale coreflooding experiments. However, there has not been a detailed study of the pore-scale phenomena which occur during LTG flooding. In the current study, alternate injection of a suitable surfactant formulation and air has been used to simulate the mechanism of LTG flooding in a borosilicate waterwet micromodel. The main phenomenon that was investigated was the interaction between different microemulsion types (Winsor I and III) and foam. Results show that presence of foam facilitates faster and better oil displacement. Microemulsion equilibration time was improved in the presence of foam, due to increased mixing of the liquid phases. Presence of trapped gas helped to divert the flowing surfactant/microemulsion to regions with trapped remaining oil and thus improved oil recovery. For equilibrated Type III microemulsion, completely miscible flooding (or ultralow tension displacement) was observed. For Type I systems, oil-in-water macroemulsions were observed. For equilibrated Type III microemulsion, the presence of foam mainly improved the oil recovery rate. In case of Type III surfactant solution injection, the presence of foam improved both the oil recovery rate and the overall oil recovery. For Type I systems, the presence of foam enabled the transition of oil-in water macroemulsions to water-entrained macroemulsions, thus improving both the oil recovery rate and the overall oil recovery.",3,3,7
Oil Recovery,Gas,"Liang, Tuo; Hou, Jirui",Fluids flow behaviors of nitrogen and foam-assisted nitrogen floods in 2D visual fault-karst carbonate reservoir physical models,Fractured-vuggy reservoir; Fluids flow characteristics; Nitrogen and foam driven; EOR,,"Fault-karst fractured-vuggy carbonate reservoir is an important type of fractured-vuggy carbonate reservoirs in Tahe oilfield of China. The fluids flow behaviors in fault-karst fractured-vuggy carbonate reservoir are complex and unclear due to the complexity of the connection between fractures and vugs. In this work, the novel 2D visual fault-karst fractured-vuggy carbonate reservoir physical models (longitudinal model and horizontal model) were designed and fabricated to investigate the flow characteristics and phase behaviors of nitrogen gas and foam-assisted nitrogen gas floods. Experimental results showed that oil-water and gas-oil interfaces fluctuations had positive effect on improving oil recovery. Foam-assisted nitrogen gas can effectively inhibit the occurrence of gas channeling, improve swept volume and increase oil recovery. A four-phase dimensionless index (Nr') was first proposed to describe the synergistic effects among the gas cap, foam cap and bottom water during foam-assisted nitrogen flooding process. Based on the analysis of oil recovery results, there was a turning point on oil recovery curve for foam-assisted nitrogen gas flooding. Moreover, the optimal production mode that was injection in high position of reservoir and recovery from low position of reservoir (HI-LR) in fault-karst carbonate reservoir was determined. This study is helpful to understand the flow characteristics of foam and nitrogen gas and provides a guide for increasing oil recovery in fault-karst fractured-vuggy carbonate reservoirs.",3,3,6
Oil Recovery,Gas,"Wang, Yuxia; Shang, Qinghua; Zhou, Lifa; Jiao, Zunsheng",Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin,Permeability heterogeneity; CO2 flooding; EOR; Tight sandstone reservoir; Ordos Basin,OIL-RECOVERY; CARBON-DIOXIDE; INJECTION,"Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200-1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with elastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO 2 -EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high-low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high-low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.",3,3,6
Oil Recovery,Gas,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Oil Recovery,Gas,"Fu, Qinwen; Cudjoe, Sherifa; Ghahfarokhi, Reza Barati; Tsau, Jyun-Syung; Li, Xiaoli; Peltier, K.; Mohrbacher, D.; Baldwin, A.; Nicoud, B.; Bradford, K.",Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection-an Eagle Ford study,Molecular diffusion; Hydrocarbon gas huff-n-puff; Dual-permeability; Rock-fluid property; Gas injection; Eagle Ford shale; Unconventional reservoirs; EOR; IOR,OIL,"Fracture complexity, variation in fluid properties, variations in rock types and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research has been conducted to define diffusion coefficients coupled with rock tortuosity resulting in calculation of effective diffusion. The objective of this work is to conduct a comprehensive experimental and simulation study on lower Eagle Ford rock samples to measure diffusion coefficients for different injection cycles in three representative rock samples from the main flow unit. Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and effluent oil and gas compositions were measured. NMR measurement was repeated at the end. Three compositional simulation models were set up for three different samples using tortuosity values from FIB-SEM analysis to simulate experimental diffusion and production. For history matching, relative permeability curves, fracture properties, and tortuosity were tuned to match pressure and production results for three representative samples. Pressure profiles vary significantly between different cycles caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Effective diffusion coefficients were calculated using representative tortuosity values. Diffusion was represented by pressure drop during soaking time. This pressure drop varies across different lithofacies and for different rock samples. For produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate components increased. Gas huff-n-puff injection into shale oil reservoirs were being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments, conducted using a constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, show favorable results. Recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively.",3,3,4
Oil Recovery,Gas,"Wen, Yiping; Lai, Nanjun; Li, Wenhong; Zhang, Yongqiang; Du, Zhaofeng; Han, Lijuan; Song, Zhiling",Factors influencing the stability of natural gas foam prepared by alkyl polyglycosides and its decay rules,Alkyl polyglycosides; Natural gas foam; Drainage kinetics; Decay rules; Statistics methods; Surface properties,HIGH-TEMPERATURE; NITROGEN FOAM; SURFACTANT; PERFORMANCE; DRAINAGE; BEHAVIOR; PARTICLES,"By using alkyl polyglycoside (APG) as foaming agent and natural gas as gas phase, the natural gas foam system was prepared, and the influence of alkyl chain length, metal cation valence and concentration, and polymer types on the foam stability was studied. By completely observing the volume and time required for the foam drainage liquid under different conditions, a foam drainage kinetics model was established. The drainage rate constant, the maximum drainage rate and its occurrence time during the foam drainage process can be acquired by derivation of the fitting function. The Arrhenius equation was adopted to fit the drainage rate constant at different temperature, and the drainage activation energy is obtained. The drainage process of foam was further analyzed from the perspective of kinetics. Moreover, the changes in geometric geometries such as bubble number, particle size distribution frequency and the average diameter of the bubble in the decay process under different conditions was counted. According to the mathematical relationship between the average diameter and time, the Ostwald ripening rate and gas molecule diffusion constant are calculated. Finally, through the investigation of the interface properties and the micromorphology of the solution, the reasons for the above rules are explained. The research shows that: 1) the increase of the alkyl chain length of APG within a certain range (8-10.9) is beneficial to the improvement of the foam stability, and the continuous increase of chain length (10.9-12) is adverse to the foam stability, 2) the increase in the salinity of prepared water and the metal ions valence enhances the foam stability to a certain extent, 3) DG is more stable to APG foam than XG and KYPAM-6s. This study enriches the stability rules of APG foam with natural gas as the gas phase under different conditions, and provides ideas and methods for quantitatively analyzing the foam decay process from the perspectives of kinetics and statistics, which provides theoretical support for the application of natural gas foam in enhance oil recovery.",3,3,4
Oil Recovery,Gas,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Oil Recovery,Low Permeability,"Cui, Guodong; Yang, Lihong; Fang, Jichao; Qiu, Zhichao; Wang, Yuting; Ren, Shaoran",Geochemical reactions and their influence on petrophysical properties of ultra-low permeability oil reservoirs during water and CO2 flooding,Geochemical reactions; Water compatibility; Reactive flow simulation; Petrophysical properties,SANDSTONE; INJECTION; STORAGE; SEQUESTRATION; TEMPERATURES,"Complex geochemical reactions can occur during the water and CO2 flooding for improved oil recovery, influencing the reservoir porosity and permeability, especially for low-permeability reservoirs. Core flooding experiments can be adopted to assess this effect, but it usually takes months or even years to accomplish. In this study, scaling and geochemical reaction experiments were firstly conducted to investigate the precipitation and dissolution of the main minerals induced by water and CO2 injection, based on a typical low-permeability oil reservoir in Xinjiang Oilfield China. Secondly, reactive flow simulation models were then established, based on the experimental data, to evaluate the influence of the geochemical reactions on the porosity and permeability in the reservoir. The experimental results show that the injection water can result in severe mineral precipitation after it mixes with the original formation water, while the injected CO2 can acidize the formation water and result in the dissolution of some minerals (e.g. calcite and silicate) and precipitation of dolomite, which can change the composition of the formation water. The simulation results show that severe carbonate precipitation can occur near the injection well, resulting in a decrease in porosity and permeability after 10 years of water injection. However, the change of rock minerals induced by CO2 injection can cause a slight increase in porosity and permeability near the injector, which benefits the injection of ultra-low permeability reservoirs. Therefore, CO2 flooding is recommended for improved oil recovery.",10,10,4
Oil Recovery,Low Permeability,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Oil Recovery,Low Permeability,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Oil Recovery,Low Permeability,"Xu, Derong; Li, Zhe; Bai, Baojun; Chen, Xin; Wu, Hairong; Hou, Jirui; Kang, Wanli",A systematic research on spontaneous imbibition of surfactant solutions for low permeability sandstone reservoirs,Surfactant imbibition; IFT reduction; Wettability alteration; Enhanced oil recovery; Low permeability reservoirs,ENHANCED OIL-RECOVERY; WETTABILITY ALTERATION; WET; MECHANISMS,"Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 degrees C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C12 surfactants), which was mainly depending on better IFT reduction ability of C16 surfactants than C12 surfactants. Appropriate IFT reduction, such as 10-1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10-2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs.",6,6,16
Oil Recovery,Low Permeability,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Oil Recovery,Low Permeability,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Oil Recovery,Low Permeability,"Jing, Wenlong; Fu, Shuaishi; Zhang, Lei; Li, Aifen; Ren, Xiaoxia; Xu, Chao; Gao, Ziheng",Pore scale experimental and numerical study of surfactant flooding for enhanced oil recovery,Surfactant flooding; Glass etching model; Enhanced oil recovery; Numerical simulation,PERMEABILITY; MECHANISMS,"Surfactant flooding is a traditional method to enhance oil recovery. The surfactant flooding experiment based on glass etching model allows researchers to observe directly how the remaining oil is displaced by surfactant through microscope, so as to explore the mechanism of surfactant enhanced oil recovery. However, microscopic experiments mostly stay at the level of physical experiments, and the operation of physical experiments is too complex and cumbersome. This study is the first to combine surfactant flooding experiment with numerical simulation in glass etching model. Firstly, based on the real pore and throat structure of the real low permeability reservoir core, the glass etching model was developed, and the micro-oil-water displacement experiment was carried out. Through microscopic observation and analysis, combined with testing and image processing technology, the effect of water flooding was quantitatively investigated. Then the surfactant flooding was carried out. Three surfactants were used for displacement. It was found that residual oil in pore network was greatly reduced. The recovery factor has been greatly improved. Finally, numerical simulation of water flooding and surfactant flooding based on micro-physical experiment was carried out. The results of numerical simulation were compared with the experimental results. It is found that the recovery factor and the form of residual oil are basically the same. By analyzing the results of numerical simulation of oil recovery, it is found that the extent of surfactant enhancing oil recovery is different under different interfacial tension. The results showed that the surfactant with interfacial tension of 0.22 mN/m has the highest ability to enhance oil recovery. This work provides a reference for surfactant selection in oilfield development. It can select the best surfactant according to the factors of time, efficiency and cost.",4,4,13
Oil Recovery,Low Permeability,"Zhao, Shuda; Zhu, Daoyi; Bai, Baojun",Experimental study of degradable preformed particle gel (DPPG) as temporary plugging agent for carbonate reservoir matrix acidizing to improve oil recovery,Preformed particle gels; Degradable; Temporary plugging agents; Matrix acidizing; Improve oil recovery,CONFORMANCE CONTROL; STIMULATION; PROPAGATION; TRANSPORT,"Preformed particle gel (PPG) is an effective technique for conformance improvement in petroleum reservoirs. It can selectively penetrate high-permeability channels to form effective plugging and divert the chasing injection fluid to low-permeability unswept oil zones. However, conventional PPG would be dehydrated under acidic conditions and could not be easily degraded, which will cause a certain amount of damage to the target formation. Therefore, this study proposed to introduce acid-resistant functional groups and a self-degradable crosslinking structure into the conventional PPG's compositions to develop a degradable PPG (DPPG). The influence mechanism of the chemical composition, swelling performance, and temporary plugging performance of DPPG was studied. Results show that the DPPG can swell up to 70 times its original size by absorbing water, and swollen DPPG can finally self-degrade to a water-like fluid in acid solution. After injecting of DPPG swelled by 20 times its original volume, the injection pressure could reach 1250 psi. Even during the chase acid treatment period, the average pressure was around 130 psi, which shows excellent plugging performance. Subsequent injection of acid would react with carbonate rocks around the plugging zones, increasing the swept volume. In addition, after acid treatments, the DPPG could be self-degraded into a dilute solution like water, so it has very little damage to the reservoir matrix. Therefore, the DPPG has good temporary plugging and acidizing steering performance in acidizing operations. The research in this article can provide the experimental basis and reference for expanding the further application of DPPG in petroleum reservoir stimulation.",4,4,10
Oil Recovery,Low Permeability,"Dou, Liangbin; Xiao, Yingjian; Gao, Hui; Wang, Rui; Liu, Chenglu; Sun, Hengbin",The study of enhanced displacement efficiency in tight sandstone from the combination of spontaneous and dynamic imbibition,Tight sandstone reservoir; Spontaneous imbibition; Dynamic imbibition; Nuclear magnetic resonance; Oil recovery in pore,,"Spontaneous imbibition is critical in the oil recovery process for low permeability and tight reservoirs, which is driven by the capillary pressure. In the waterflooding process, dynamic imbibition has been determined as an important means of oil recovery for ultra-low permeability reservoirs. It functions significantly to the oil recovery in cyclic water injection. Unfortunately, some mechanisms are not fully understood within the spontaneous and dynamic imbibition such as the effect of pore size on imbibition and their collaboration on oil recovery. In this paper, three micro mechanisms were studied to understand their effects on oil recovery efficiency: spontaneous imbibition, dynamic imbibition and the combination of spontaneous and dynamic imbibition. The Nuclear Magnetic Resonance (NMR) technique was applied to investigate the sandstone formation of Yanchang group in Ordos basin. First, we analyzed the T2 spectrum characteristics of tight sandstone, by which the pore size was grouped into three along with the high-pressure mercury injection data. Second, we studied the quantitative effect of imbibition time and interfacial tension on the oil recovery efficiency of tight sandstone, with respect to various pore sizes during the spontaneous imbibition process. Simultaneously, the effect of interfacial tension on dynamic imbibition was evaluated at various pore sizes by means of displacement experiments and low-field NMR. Third, we proposed the methodology of the utilization of spontaneous and dynamic imbibition to enhance the displacement efficiency in tight sandstone, based on their characteristics. Meanwhile, the displacement characteristics were compared at various pore sizes from the three imbibition types. A feasible workflow was provided for field applications to enhance oil recovery by means of spontaneous and dynamic imbibition. This research fills the gap of waterflooding in tight sandstone and low permeability reservoirs and improves the waterflooding technique.",3,3,11
Oil Recovery,Low Permeability,"Liu, Hongping; Luo, Yang; Meng, Yujing; Xiao, Gaojian; Zhao, Yanchao; Zhou, Sibin; Shao, Longkan",Effects of pore structure on the moveable oil saturation in water-driven tight oil sandstone reservoirs,Tight oil sandstone; Pore structure; Waterflooding; CT scanning; Movable oil saturation,NUCLEAR-MAGNETIC-RESONANCE; MOVABLE FLUID; ORDOS BASIN; YANCHANG FORMATION; MERCURY INTRUSION; PERMEABILITY; POROSITY; PARAMETERS; FIELD; NMR,"Tight oil sandstones have large oil reserves but low waterflooding efficiency and oil recovery. The movable oil saturation (MOS) is a critical parameter for evaluating oil recovery in water-driven tight oil sandstone reservoirs. However, its controlling factors in tight oil sandstones are still not well understood. In this study, the tight/low-permeability sandstones in the Chang 8 and Chang 9 Members of the Honghe Oil Field in the Ordos Basin (China) provide an opportunity to determine the effects of pore structure on the MOS. Porosity, permeability, thin sections, scanning electron microscopy (SEM), large field-of-view SEM imaging method (MAPS technique), highpressure mercury intrusion (MICP), and micro-CT scanning were systemically conducted to analyze the pore structure analysis. MOS values were obtained from the relative permeability tests. The results show that porosity, pore-throat size, and the sorting coefficient have no evident relationship with the MOS. Many of the higher-permeability samples even show lower MOS values. Moreover, analysis of micro-CT images before and after waterflooding indicates that the lower-permeability samples tend to swept larger areas than the higher-permeability samples, resulting in greater oil-displacement efficiencies and MOS values. Instead, the cumulative mercury saturation at the apex of the mercury injection hyperbola curve (S apex ), the ratio of the maximum pore-throat radius and the medium pore-throat radius (R-max/R-50), and movable fluid saturation (MFS) show a good linear relationship with the MOS. The displaced oil is primarily from intergranular pores and partly from intragranular pores. The micropores that are widely distributed at the grain-grain contact display low original oil saturation and low oil displacement efficiency. It is proposed that the volume of the well-connected pores that contribute to permeability is the key factor controlling the MOS regardless of the type of rock.",3,2,9
Oil Recovery,Low Permeability,"Zheng, Jiangtao; Wang, Zenglin; Ju, Yang; Tian, Yuqin; Jin, Yanxin; Chang, Wei",Visualization of water channeling and displacement diversion by polymer gel treatment in 3D printed heterogeneous porous media,Polymer gel; Enhanced oil recovery (EOR); Water channeling; Diversion; 3D printing,CONFORMANCE CONTROL; OIL-RECOVERY; SHALE; INJECTION; SYSTEM; FLOODS; FLUID; FIELD; ROCK; EOR,"Polymer gels are widely applied to increase the sweep efficiency in mature oil fields facing severe water channeling problems after years of water flooding. The formation of water channeling and successful polymer gel treatment are rooted in complex pore-scale displacement and diversion. Thus, accurate characterization of the pore space and direct visualization of the interior displacement processes in real reservoir rocks such as water flooding, polymer gel injection, and chase floods are crucial in determining the controlling mechanisms of water channeling and polymer gel diversion. In this study, 3D X-ray micro-computed tomography (uCT) was used to characterize the porous structures of three distinct levels in water-flooded reservoir sandstones. A heterogeneous digital model was designed, which comprised representative layers of the obtained porous structures. Then, 3D-printing technology was used to manufacture a transparent model based on the digital prototype. A series of displacement experiments were conducted in the printed model to directly visualize the flow behaviors in the actual pore geometries. In the experiments, the model was first saturated with white oil and flooded by formation water until the outlet discharged only the water phase. Then, an immediately prepared polymer gel was injected. After three days of gelation, an antidilution polymer was injected to sweep the residual oil in the model. Finally, a surfactant flooding agent was injected designed to further increase the oil recovery. The entire four-step displacement process was directly visualized, and the saturation of each injection and the oil recovery were calculated. During water flooding, preferential flooding channels formed in the highest water-flooded porous layers due to the low viscosity ratio between the injected formation water and the displaced white oil, as well as the permeability contrast in the heterogeneous model. The injected polymer gel mainly followed the preferential flooding channels because of the low resistance force in these channels. After gelation, the polymer gel blocked the main preferential channels and diverted the chase floods to nearby pores. A desirable diversion of the polymer gel highly depends on its propagation path during injection and effective blocking after gelation. Experimental visualization and displacement mechanism analysis indicate the efficacy of the flow diversion by the polymer gel treatment in the heterogeneous porous model. The results provide useful information on the displacement behavior in heterogeneous porous structures, and the conclusions apply to similarly scaled systems at the reservoir scale.",3,3,7
Oil Recovery,Low Permeability,"Wang, Yuxia; Shang, Qinghua; Zhou, Lifa; Jiao, Zunsheng",Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin,Permeability heterogeneity; CO2 flooding; EOR; Tight sandstone reservoir; Ordos Basin,OIL-RECOVERY; CARBON-DIOXIDE; INJECTION,"Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200-1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with elastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO 2 -EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high-low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high-low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.",3,3,6
Oil Recovery,Low Permeability,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Oil Recovery,Low Permeability,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Oil Recovery,Low Permeability,"Li, Songqi; Liu, Yuetian; Xue, Liang; Yang, Li; Yuan, Zhiwang; Jian, Changsong",An investigation on water flooding performance and pattern of porous carbonate reservoirs with bottom water,Porous carbonate reservoir; 3D physical model; Water flooding performance and pattern; Remaining oil distribution,,"Water flooding is the most common oil recovery technology for carbonate reservoirs in Middle East. However, because of the various reservoir physical properties, serious problems, such as water breakthrough and uncharted distribution characteristics of remaining oil, bring great challenges to successful water flooding development. In this research, the scaled 3D water flooding experiment with an interlayer heterogeneous and anisotropic physical model was performed to achieve quantitative characterization of water flooding performance and pattern and the distribution of remaining oil after displacement in a porous carbonate reservoir with bottom water. Results indicate that the water flooding performance of bottom water varies with the various permeabilities in different layers. It can be divided into two patterns, characterized by smooth spread in high-permeability layers and coning type breakthrough in low-permeability layers. Specifically, in high-permeability layers, the horizontal flow is faster than vertical flow because the bottom water is mainly controlled by higher horizontal permeability and the lower production pressure difference can't overcome the gravity. Therefore, the whole layer is flooded and there is less remaining oil in high-permeability layers. On the contrary, in low-permeability layers, production pressure difference will drive water to climb up near the vertical wellbore and the water cone appears significantly, resulting in the remaining oil between the wells. In conclusion, the main mechanism behind the water flooding performance can be the heterogeneous and anisotropic characteristics of permeability.",3,3,4
Oil Recovery,Spontaneous Imbibition,"Liu, Dengke; Ren, Dazhong; Du, Kun; Qi, Yiru; Ye, Feng",Impacts of mineral composition and pore structure on spontaneous imbibition in tight sandstone,Spontaneous imbibition; Mineral composition; Pore structure; Tight sandstone,DIRECT NUMERICAL-SIMULATION; TRIASSIC YANCHANG FORMATION; ORDOS BASIN; NITROGEN ADSORPTION; OIL; RESERVOIR; SALINITY; TRANSPORT,"Spontaneous imbibition is a fundamental mechanism to figure out the rock-fluid interplay during waterflooding and hydraulic fracturing. Mineral composition and pore structure play significant roles in imbibition efficiency, but how these parameters influence the oil production efficiency still is a myth. This research conducted the spontaneous imbibition experiments combined with low-temperature adsorption and nuclear magnetic resonance to (1) study how minerals and pore structures impact fluid movement features for tight sandstones; (2) systematically investigate the contribution to oil recovery of different pores' types and the impact of pore connectivity on spontaneous imbibition. The results show that the brine is inclined to attach hydrophilic minerals because of the wettability, increasing the imbibition efficiency. Additionally, with the tiny pores' development, the oil is more easily replaced by the brine due to strong capillary pressure. Last, as the mainstream imbibition area grows, the oil is preferentially displaced by the brine. The research provides insights into how mineral compositions and pore structures can influence spontaneous imbibition efficiency and improves the understanding of the complicated interaction between fluid and minerals in tight sandstones.",17,15,9
Oil Recovery,Spontaneous Imbibition,"Wu, Zhongwei; Cui, Chuanzhi; Ye, Yinzhu; Cheng, Xiangzhi; Trivedi, Japan",A fractal model for quantitative evaluating the effects of spontaneous imbibition and displacement on the recovery of tight reservoirs,Spontaneous imbibition (SI); Displacement; Quantitative evaluation; Tight reservoir; Fractal theory,KOZENY-CARMAN CONSTANT; POROUS-MEDIA; CAPILLARY IMBIBITION; OIL-RESERVOIRS; FLOW,"In the petroleum industry, there is a consensus that the spontaneous imbibition (SI) is important for improving the recovery of tight reservoirs. However, how great is the effect of SI on the recovery of tight reservoirs when comparing with displacement? In the paper, a model for quantitative evaluating the effects of SI and displacement on tight reservoir development is built by fractal theory and verified by comparing with published experimental data. Two evaluation parameters (EP and EPR), which can be determined by the proposed model, are introduced to discuss the problem that how great the effect of SI on the recovery of tight reservoirs when comparing with displacement is. The influences of related parameters on EP and EPR are conducted. The results show that reservoir properties have a great effect on the imbibition time. And the effects of reservoir properties on the flow rate of SI is similar to that of displacement. The effect of SI becomes significant comparing with displacement when the water viscosity decreases. However, with the decrease of contact angle or the increase of interfacial tension force (ITF), the effect of SI becomes significant. The decrease of displacement pressure difference indicates the effect of SI becoming relatively significant. When the ITF and displacement pressure difference are 35.5 mN/m and 1 x 10(4) Pa, respectively, the maximum oil flow rate of SI is 1.85 times of displacement. This work has a crucial role in promoting the development of tight reservoirs.",12,12,17
Oil Recovery,Spontaneous Imbibition,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Oil Recovery,Spontaneous Imbibition,"Xu, Derong; Li, Zhe; Bai, Baojun; Chen, Xin; Wu, Hairong; Hou, Jirui; Kang, Wanli",A systematic research on spontaneous imbibition of surfactant solutions for low permeability sandstone reservoirs,Surfactant imbibition; IFT reduction; Wettability alteration; Enhanced oil recovery; Low permeability reservoirs,ENHANCED OIL-RECOVERY; WETTABILITY ALTERATION; WET; MECHANISMS,"Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 degrees C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C12 surfactants), which was mainly depending on better IFT reduction ability of C16 surfactants than C12 surfactants. Appropriate IFT reduction, such as 10-1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10-2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs.",6,6,16
Oil Recovery,Spontaneous Imbibition,"Chen, Weidong; Schechter, David S.",Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs,,WETTABILITY ALTERATION; ADSORPTION; WET,"Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures. Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure. The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition. In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants. The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.",5,5,3
Oil Recovery,Spontaneous Imbibition,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Oil Recovery,Spontaneous Imbibition,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Oil Recovery,Spontaneous Imbibition,"Zheng, Heng; Liao, Ruiquan; Cheng, Ning; Shi, Shanzhi",Microscopic mechanism of fracturing fluid imbibition in stimulated tight oil reservoir,Fracturing fluid; Imbibition; Micro-characteristics; Experiments; Kinetic energy,INTERFACIAL-TENSION; WATER BLOCKING; IFT REDUCTION; 2-PHASE FLOW; PORE-SCALE; PERMEABILITY; SANDSTONE; WETTABILITY; RECOVERY; GAS,"The imbibition of fracturing fluid is of great significance to improve the development of fractured tight oil reservoirs. Understanding the micro-characteristics of fracturing fluid imbibition is necessary to improve the imbibition efficiency. In this work, the experiments of the spontaneous imbibition under simulated in-situ condition is conducted to understand the micro-characteristics of fracturing fluid imbibition, and the Nuclear magnetic resonance (NMR) and high-resolution X-rays computed tomography (CT) scanning are applied to monitor the process and the liquid distribution of spontaneous imbibition. The experimental results indicate that the spontaneous imbibition is mainly occurred in macropores at the initial stage, and the velocity of fracturing fluid is lower than that of formation water in spontaneous imbibition due to the weaker motivity generated from the lower oil-fracturing fluid interfacial tension. The fracturing fluid can promote the spontaneous imbibition due to it can decrease the kinetic energy loss when it transforms into the interfacial free energy. Thus, the oil recovery obtained from the fracturing fluid imbibition increased to 20.7% from 15.8% by formation water imbibition. The main reason accounts for it is that the wettability of fracturing fluid is stronger than that of formation water, thus can promote the whole process of spontaneous imbibition, and the lower viscosity would reduce the flow resistance at the latter stage. A higher oil-water interfacial tension (IFT) can accelerate the velocity of spontaneous imbibition at the initial stage, while a proper interfacial tension is favorable at the latter stage.",4,4,21
Oil Recovery,Spontaneous Imbibition,"Okunade, Oluwagade Adenike; Yekeen, Nurudeen; Padmanabhan, Eswaran; Al-Yaseri, Ahmed; Idris, Ahmad Kamal; Khan, Javed Akbar","Shale core wettability alteration, foam and emulsion stabilization by surfactant: Impact of surfactant concentration, rock surface roughness and nanoparticles",Wettability; Surface roughness; Foam; Emulsion; Surfactants; Nanoparticles,ENHANCED OIL-RECOVERY; HUFF-N-PUFF; LAB(R) EXPERT ANALYSIS; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; SILICA NANOPARTICLES; NONIONIC SURFACTANTS; SIO2 NANOPARTICLES; CONTACT ANGLES; HIGH-PRESSURE,"Hexadecyltrimethyl ammonium bromide (HCTAB) and sodium dodecyl sulfate (SDS) are popular conventional surfactants with versatile industrial and oilfield applications. Knowledge of the optimum conditions for their applications for shale rock wettability modification, as well as foam and emulsion stabilization is relevant for hydrocarbon recovery process optimization. Influence of surfactant concentration, rock surface roughness and presence of nanoparticles in surfactant solutions on contact angles, oil-water interfacial tension (IFT), as well as foam and emulsion stabilization by HCTAB and SDS was investigated in this study. The interfacial properties measurements were conducted with Drop Shape Analyser (DSA 25), whereas the foam generation and stability properties were investigated via dynamic foam analyzer (DFA100). The emulsion stabilization and demulsification processes were investigated in Formulaction Turbiscan. Results showed an existence of optimum concentration of surfactant for obtaining the lowest contact angles, oil-water IFT reduction, as well as attaining maximum foam stability. The contact angle measured on rough core surfaces were smaller than the contact angle measured on smooth surfaces. Contact angles increased with increasing salnity concentration, but decreased with the increasing rock saturation time. Oil was more detrimental to foam stability when the generated foam was brought into contact with the resident oil, compared to when oil was added to the foaming solutions before foam generation. Lower contact angles, durable foam, and stable emulsion were produced in presence of oil and at high temperature via the synergy of nanoparticles and surfactants. Almost 66% decreased in contact angle was achieved with carbon nanotubes-SDS solutions, whereas Al2O3 nanoparticles-HCTAB foam attained a viscosity of 99 mPa-s at 60 degrees C. The foam demonstrated shear thinning Newtonian fluids behaviors but attained a plateau after sometimes. The study suggests the conditions for optimization of conventional surfactants applications in conventional and unconventional reservoir.",4,4,9
Oil Recovery,Spontaneous Imbibition,"Souayeh, Maissa; Al-Maamari, Rashid S.; Karimi, Mahvash; Aoudia, Mohamed",Wettability alteration and oil recovery by surfactant assisted low salinity water in carbonate rock: The impact of nonionic/anionic surfactants,Wettability alteration; Nonionic surfactants; Anionic surfactants; Spontaneous imbibition; Carbonates,CLOUD POINT; SPONTANEOUS IMBIBITION; HIGH-TEMPERATURE; SMART WATER; WET; ADSORPTION; BEHAVIOR; COALESCENCE; ADDITIVES; LIMESTONE,"Combining low salinity water (LSW) and chemicals to enhance oil recovery has recently received more attention in the oil industry. In this study, a systematic experimental procedure was conducted to evaluate the performance of low salinity nonionic surfactant with/without anionic surfactant in wettability alteration and oil recovery of oil-wet carbonate having high salinity formation water (FW) (196 g/L) and moderate temperature (75 degrees C). A polyethoxylated nonionic surfactant (C13EO12 ) and two anionic surfactants: sulfonate (IOS 20-24) and carboxylate (AEC 938) were used in this study. Contact angle (CA) results showed that low salinity nonionic surfactant was effective in altering the wettability of oil-wet calcite toward water-wet state. While the low salinity anionic surfactants' systems were only able to reduce the oil-wetness of the oil-wet calcite. When nonionic surfactant is mixed with anionic surfactant, the wettability of oil-wet calcite was altered toward intermediate-wet or only a reduction of its oil-wetness occurred depending on the type of the anionic surfactant. Spontaneous imbibition tests using oil-wet limestone cores showed that among the low salinity single surfactants' systems, carboxylate anionic surfactant resulted in the highest oil recovery (61% of oil initially in place (OIIP)) and sulfonate anionic surfactant resulted in the lowest oil recovery (31% of OIIP). The low salinity nonionic surfactant recovered 51% of OIIP by spontaneous imbibition. Addition of sulfonate anionic surfactant to the nonionic surfactant resulted in an oil recovery of 49% of OIIP while addition of carboxylate anionic surfactant to the nonionic surfactant considerably improved the oil recovery to 74% of OIIP. Hence, selection of proper surfactant class is crucial for a successful oil recovery.",4,4,6
Oil Recovery,Spontaneous Imbibition,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Oil Recovery,Spontaneous Imbibition,"Dou, Liangbin; Xiao, Yingjian; Gao, Hui; Wang, Rui; Liu, Chenglu; Sun, Hengbin",The study of enhanced displacement efficiency in tight sandstone from the combination of spontaneous and dynamic imbibition,Tight sandstone reservoir; Spontaneous imbibition; Dynamic imbibition; Nuclear magnetic resonance; Oil recovery in pore,,"Spontaneous imbibition is critical in the oil recovery process for low permeability and tight reservoirs, which is driven by the capillary pressure. In the waterflooding process, dynamic imbibition has been determined as an important means of oil recovery for ultra-low permeability reservoirs. It functions significantly to the oil recovery in cyclic water injection. Unfortunately, some mechanisms are not fully understood within the spontaneous and dynamic imbibition such as the effect of pore size on imbibition and their collaboration on oil recovery. In this paper, three micro mechanisms were studied to understand their effects on oil recovery efficiency: spontaneous imbibition, dynamic imbibition and the combination of spontaneous and dynamic imbibition. The Nuclear Magnetic Resonance (NMR) technique was applied to investigate the sandstone formation of Yanchang group in Ordos basin. First, we analyzed the T2 spectrum characteristics of tight sandstone, by which the pore size was grouped into three along with the high-pressure mercury injection data. Second, we studied the quantitative effect of imbibition time and interfacial tension on the oil recovery efficiency of tight sandstone, with respect to various pore sizes during the spontaneous imbibition process. Simultaneously, the effect of interfacial tension on dynamic imbibition was evaluated at various pore sizes by means of displacement experiments and low-field NMR. Third, we proposed the methodology of the utilization of spontaneous and dynamic imbibition to enhance the displacement efficiency in tight sandstone, based on their characteristics. Meanwhile, the displacement characteristics were compared at various pore sizes from the three imbibition types. A feasible workflow was provided for field applications to enhance oil recovery by means of spontaneous and dynamic imbibition. This research fills the gap of waterflooding in tight sandstone and low permeability reservoirs and improves the waterflooding technique.",3,3,11
Oil Recovery,Spontaneous Imbibition,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Oil Recovery,Low Salinity,"Farhadi, Hamed; Ayatollahi, Shahab; Fatemi, Mobeen","The effect of brine salinity and oil components on dynamic IFT behavior of oil-brine during low salinity water flooding: Diffusion coefficient, EDL establishment time, and IFT reduction rate",Dynamic interfacial tension; Crude-oil/brine system; Time dependent adsorption; Low salinity effect; Asphaltene,INTERFACIAL-TENSION; WETTABILITY ALTERATION; CAPILLARY-PRESSURE; SURFACE-PROPERTIES; ADSORPTION; RECOVERY; SANDSTONE; RESERVOIR; ASPHALTENES; ELECTRONS,"Dynamic behavior of fluid-fluid interactions can potentially affect the performance of any enhanced oil recovery (EOR) process including low salinity water flooding. In this work, dynamic interfacial tension (IFT) of crude-oil/brine system is measured in a wide range of salinity of sea water (SW), from 50-time diluted sea water (SW50D) to 2-time concentrated sea water (SW2C). Contrary to the most of published IFT trends in the literature, for the system under investigation here, as the brine salinity increases the crude-oil/brine IFT reduces, which cannot be explained using the existing theories. The lack of a physical model to explain the observed phenomena was the motivation to develop a new model based on a drift-diffusion theory. This theory considers a current of oil polar molecules toward the oil-water interface which is caused by electrostatic attraction from aqueous ions (drift) and a resistance against this current caused by concentration gradient (diffusion). After applying this model to measured dynamic IFT data, the IFT reduction rate, and electrical double layer (EDL) establishment time are calculated. Then, these matching parameters set as criteria to explain the mechanisms behind the dynamic behavior of crude oil-saline water interfacial tension. For further investigation of the involved mechanisms which are responsible for the macroscopic behavior of crude-oil/brine dynamic IFT, the role of oil components is also examined using the IFT reduction rate and EDL establishment time. Although the obtained results show the asphaltene molecules play a vital role in the dynamic IFT behavior, the concentration of n-heptane, in the model oil containing n-heptane and toluene, is essential to capture the IFT behavior of the crude oil. Increasing n-heptane fraction in the model oil to the amount which exist in the crude oil, results in longer EDL establishment time which is in agreement with the crude oil sample.",11,11,1
Oil Recovery,Low Salinity,"Tetteh, Joel T.; Cudjoe, Sherifa E.; Aryana, Saman A.; Ghahfarokhi, Reza Barati",Investigation into fluid-fluid interaction phenomena during low salinity waterflooding using a reservoir-on-a-chip microfluidic model,Low salinity waterflooding; Microfluidics; Fluid-fluid interaction; Snap-off effect; Water-in-oil microdispersions,OIL-RECOVERY; CRUDE-OIL/BRINE; LIQUID-FILMS; SNAP-OFF; WATER; NANOPARTICLES; MECHANISMS; INTERFACE; FOAM; FLOW,"Injection of modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks has proven to be relevant to improved oil recovery operations. Many reports in the literature related the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which caused wettability alterations at the rock surface. Little attention appears to have been paid to fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigated the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations were correlated to visual observations of displacement processes in order to investigate the role of crude oil snap-off. Microfluidic devices featuring pore throats 50 mu m in diameter were used to observe snap-off as a function of salinity of the displacing fluid. Flow experiments suggested that, in a water-wet constricted pore throat, SWS brines suppressed crude oil snap-off as compared to formation water brine (FWS) brine. This behavior was correlated to the higher surface elasticity of oil-SWS interfaces than that of oil-FWS interfaces. Higher surface elasticity suppressed the expansion of the thin water film coating pore throat walls and hence it increased the capillary number at which snap-off of the crude oil phase was expected to occur. Moreover, water interacted with the polar components to form reverse micelles called microdispersions. These microdispersions were observed in both aged and non-aged microfluidic devices near oil-brine interfaces in the pore-network. Similarly, in a vial test performed by Tetteh and Barati (2019), microdispersion formation was only observed very close to oil-brine interfaces, caused by transport of water molecules into the oil phase due to reduced intermolecular forces at oil-LSW interfaces. This microdispersion formation was visualized using environmental scanning electron microscopy. These microdispersions remobilized, redistributed the oil, and along with a slight change in wettability in the medium, they improved the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributed to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.",9,10,5
Oil Recovery,Low Salinity,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Oil Recovery,Low Salinity,"Saadat, Marzieh; Yang, Junyi; Dudek, Marcin; Oye, Gisle; Tsai, Peichun Amy",Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability,Wettability alteration; Microfluidics; Surfactant flooding; Oil recovery; Enhanced oil recovery; Low salinity water flooding,LOW-SALINITY WATER; CRUDE-OIL; FINES MIGRATION; PHASE-BEHAVIOR; SURFACTANT; WET; DISPLACEMENT; EOR; ADSORPTION; SULFONATE,"Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.",8,9,11
Oil Recovery,Low Salinity,"Farhadi, Hamed; Fatemi, Mobeen; Ayatollahi, Shahab",Experimental investigation on the dominating fluid-fluid and rock-fluid interactions during low salinity water flooding in water-wet and oil-wet calcites,Low salinity water flooding; Enhanced oil recovery; Carbonate rock wettability alteration; Dynamic interfacial tension; Dynamic contact angle; Surface electric charges,INTERFACIAL INTERACTIONS; TENSION; RESERVOIR,"Low salinity water flooding (LSWF) has the potential to enhance the oil recovery by affecting the fluid-fluid and rock-fluid interactions. Therefore, a systematic investigation on the effect of initial wetting state (water-wet or oil-wet) of pure calcite is conducted to study the importance of these interactions on the effectiveness of LSWF. In the case of initially water-wet cores, more oil recovery efficiency is observed for more saline water cases. To shed light on the possible involved mechanisms, dynamic IFT, dynamic contact angle (CA), oil/brine and rock/brine surfaces zeta potentials, and effluent pH are measured. It is shown that the short-term effect of IFT reduction and long-term effect of wettability alteration toward neutral-wetness (due to change in the electric charge of the crude-oil/brine and calcite/brine) are the dominating recovery mechanisms. However, the oil recovery behavior of oil-wet cores is in the opposite direction of that of water-wet cores, which demonstrates the wettability dependency of the involved mechanisms. CA measurement shows that diluted sea water (dSW) has more ability to change wettability toward water-wetness. The zeta potential results show that as brine salinity reduces, both crude-oil and rock surfaces become more negatively charged. Therefore, the observed wettability alteration behavior with salinity reduction is attributed to larger repulsion between these surfaces at lower salinity. pH results suggest CO32- ions are responsible to make calcite surface more negative with diluting SW brine. The oil recovery behavior is also a strong function of the initial wetting state. SW brine, recovered less oil and experienced an earlier breakthrough in an initially oil-wet core compared to an initially water-wet core. Unlike the previous case, dSW experienced higher ultimate oil recovery and almost the same breakthrough time in an initially oil-wet core compared to an initially water-wet core. The superior performance of the low salinity water in an oil-wet core is a result of the wettability alteration toward more water-wetness which triggers more piston-like advancement.",7,7,3
Oil Recovery,Low Salinity,"Alizadeh, MohammadReza; Fatemi, Mobeen; Mousavi, Mohammad",Direct numerical simulation of the effects of fluid/fluid and fluid/rock interactions on the oil displacement by low salinity and high salinity water: Pore-scale occupancy and displacement mechanisms,Direct numerical simulation; Computational fluid dynamics; Dynamic contact angle; Dynamic interfacial tension; Low salinity water flooding,INTERFACIAL-TENSION IFT; WETTABILITY ALTERATION; SPECIES TRANSFER; POROUS-MEDIA; SMART WATER; INJECTION; RECOVERY; BRINE; FLOW; VOLUME,"Laboratory experiments have shown that performance of waterflooding in oil reservoirs could be significantly increased by lowering the ionic strength and/or manipulation of its composition, which is generally known as low salinity waterflooding (LSWF). The involved mechanisms in additional oil production can be generally categorized in two categories, fluid/fluid and fluid/rock interactions. The distribution of the phases and the involved displacement mechanisms would be strongly affected by the inter-relations between capillary and viscous forces. Although there have been recent advances in the simulation of the LSWF at core scale and beyond and some models are included in commercial core-scale/field-scale simulators, there are very few works that modelled and simulated this process at the pore scale. As a result the effects of wettability alteration and/or interfacial tension (IFT) change on the distribution of the phases at pore scale as well as dynamics of the displacement are not thoroughly investigated and not well understood, even in spite of many micromodel experiments. The aim of the present study is to investigate the fluids distribution, redistribution and dynamic of the displacement mechanisms at the true pore scale (inside a pore), by modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Simulation results show that in addition to the fluid/rock interactions, fluid/fluid interactions are also important in the effectiveness of LSWF and shall be considered in simulation studies. This is especially true in the case of non-water-wet systems. Our simulations provide new physical insights into LSWF and the dynamics of two-phase flow under wettability alteration as well as IFT changes induced by the LSWF, which cannot be easily captured by laboratory experiments. The results are also used to better explain some of the observed discrepancies in larger scales such as micromodel or coreflood experiments.",7,7,1
Oil Recovery,Low Salinity,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Oil Recovery,Low Salinity,"Souayeh, Maissa; Al-Maamari, Rashid S.; Karimi, Mahvash; Aoudia, Mohamed",Wettability alteration and oil recovery by surfactant assisted low salinity water in carbonate rock: The impact of nonionic/anionic surfactants,Wettability alteration; Nonionic surfactants; Anionic surfactants; Spontaneous imbibition; Carbonates,CLOUD POINT; SPONTANEOUS IMBIBITION; HIGH-TEMPERATURE; SMART WATER; WET; ADSORPTION; BEHAVIOR; COALESCENCE; ADDITIVES; LIMESTONE,"Combining low salinity water (LSW) and chemicals to enhance oil recovery has recently received more attention in the oil industry. In this study, a systematic experimental procedure was conducted to evaluate the performance of low salinity nonionic surfactant with/without anionic surfactant in wettability alteration and oil recovery of oil-wet carbonate having high salinity formation water (FW) (196 g/L) and moderate temperature (75 degrees C). A polyethoxylated nonionic surfactant (C13EO12 ) and two anionic surfactants: sulfonate (IOS 20-24) and carboxylate (AEC 938) were used in this study. Contact angle (CA) results showed that low salinity nonionic surfactant was effective in altering the wettability of oil-wet calcite toward water-wet state. While the low salinity anionic surfactants' systems were only able to reduce the oil-wetness of the oil-wet calcite. When nonionic surfactant is mixed with anionic surfactant, the wettability of oil-wet calcite was altered toward intermediate-wet or only a reduction of its oil-wetness occurred depending on the type of the anionic surfactant. Spontaneous imbibition tests using oil-wet limestone cores showed that among the low salinity single surfactants' systems, carboxylate anionic surfactant resulted in the highest oil recovery (61% of oil initially in place (OIIP)) and sulfonate anionic surfactant resulted in the lowest oil recovery (31% of OIIP). The low salinity nonionic surfactant recovered 51% of OIIP by spontaneous imbibition. Addition of sulfonate anionic surfactant to the nonionic surfactant resulted in an oil recovery of 49% of OIIP while addition of carboxylate anionic surfactant to the nonionic surfactant considerably improved the oil recovery to 74% of OIIP. Hence, selection of proper surfactant class is crucial for a successful oil recovery.",4,4,6
Oil Recovery,Low Salinity,"Raffa, Patrizio; Picchioni, Francesco",Preliminary evaluation of amphiphilic block polyelectrolytes as potential flooding agents for low salinity chemical enhanced oil recovery,Polymer flooding; Enhanced oil recovery; Low salinity; Amphiphilic polymers; Polymeric surfactants; Polyelectrolytes,POLYMERIC SURFACTANTS; FIELD APPLICATIONS; FOSSIL-FUELS; COPOLYMERS; RHEOLOGY; PART; POLYACRYLAMIDES; NANOTECHNOLOGY; NANOPARTICLES; RETENTION,"Amphiphilic block polyelectrolytes are known for their remarkable thickening properties in water solution, originating from their ability to self-assemble into large micellar aggregates. This makes them promising flooding agent for chemical enhanced oil recovery (cEOR). However, to the best of our knowledge, they have not yet been directly investigated for this purpose. In this work, a survey of relevant properties for EOR (rheology, filterability and emulsification), and laboratory scale oil recovery experiments, were performed on water solutions of polystyrene-block-poly(methacrylic acid) amphiphilic block polyelectrolytes, and compared with a commercial partially hydrolyzed polyacrylamide (HPAM), to evaluate the real potential in EOR applications for the first time. It was found that the recovery of amphiphilic block copolymers in low salinity brine (0.2% concentration of NaCl) is remarkably higher than that of HPAM at comparable weight concentration and shear viscosity, despite a much lower molecular weight. Effect of salinity and emulsification properties of the studied polymers have also been preliminarily investigated. Our results suggest that the recovery mechanism of these polymers differs from the traditional mechanism of polymer flooding, possibly due to emulsification of the oil. In conclusion, the studied amphiphilic block polyelectrolytes show promise as chemical agents in low salinity polymer flooding.",4,4,6
Oil Recovery,Low Salinity,"Kondori, Javad; Miah, Mohammad Islam; Zendehboudi, Sohrab; Khan, Faisal; Heagle, Dru",Hybrid connectionist models to assess recovery performance of low salinity water injection,Low salinity water injection; Recovery factor; Smart tools; Statistical analysis; Variable ranking,ENHANCED OIL-RECOVERY; ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINES; REAL-TIME PREDICTION; WETTABILITY ALTERATION; COMPRESSIVE STRENGTH; POROUS-MEDIA; CRUDE-OIL; REGRESSION; RESERVOIRS,"The low salinity water injection (LSWI) is one of the emerging enhanced oil recovery techniques to improve both microscopic and macroscopic displacement efficiencies by creating a new streamline in petroleum reservoirs. While experimental studies are tedious, costly, and time-consuming, the smart connectionist tools are more reliable and cost-effective approaches to predict oil recovery factor (RF) without considerations of governing equations and physics behind production mechanisms in oil reservoirs. The main objective of this study is to investigate the data-driven model performance and variable contribution while predicting RF of LSWI processes. We introduce connectionist models using hybridized least squares support vector machine (LSSVM) with global optimization technique of coupled simulated annealing (CSA), and adaptive network-based fuzzy inference system (ANFIS). The extremely randomized tree or extra tree (ET) tool is also applied to forecast the RF and investigate the parameter contribution in the employed model. The model performance is examined using statistical parameters, including coefficient of determination, relative error, mean absolute percentage error, and mean squared error. According to the results, the ET and hybridized LSSVM-CSA models perform better than the ANFIS model in estimating RF. Utilizing the ET smart model, the total dissolved salts (TDS, ppm) is the most influential parameter, while the fluid injection rate has the minimum importance in the determination of RF. The current research confirms that LSSVM-CSA and ET techniques are able to obtain RF of LSWI with high accuracy and reliability, which can be used by researchers and engineers for better management of oil reservoirs under LSWI.",4,4,3
Oil Recovery,Low Salinity,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Oil Recovery,Low Salinity,"Mahmoudvand, Mohsen; Javadi, Aliyar; Pourafshary, Peyman; Vatanparast, Hamid; Bahramian, Alireza",Effects of cation salinity on the dynamic interfacial tension and viscoelasticity of a water-oil system,Crude oil; Brine; Dynamic interfacial tension; Salinity concentration; Asphaltene; Monolayer; Viscoelasticity; Low salinity water; Smart water; Enhanced oil recovery,SALTING-OUT; ADSORPTION-KINETICS; SMART WATER; OIL/WATER INTERFACE; SURFACE-TENSION; ASPHALTENES; RECOVERY; INJECTION; DISSOLUTION; ASSOCIATION,"This experimental study aims to obtain insights into the effect of brine salinity on the dynamic interfacial tension (IFT) and interfacial behavior of a water-oil system. The effects of monovalent and divalent cations (Na+, Ca2+, and Mg2+) in a salinity range of 0.01-0.1 mol/l on the equilibrium and dynamic interfacial tension of the wateroil system are studied using pendant drop experiments. To understand the adsorbed layer of surface active components (asphaltene and resin) at the interface, surface dilational elasticity is also studied. The results reveal that the types of the ions, salinity concentration, and type of the surface-active components in the crude oil, are dominant parameters that affect the interfacial properties. Divalent cations especially Mg2+ show a much stronger interaction with surface-active components at the brine-oil interface while monovalent cations have a negligible effect. The IFT of the water-oil system decreases in the presence of salts up to a minimum point and a further increase in the salinity leads to an increment in the IFT. The effect of salinity on the formation of asphaltene and resin components at the drop surface is studied by employing surface area compression experiments. When asphaltene components are at the interface, the drop profile shows a sharp increase in standard deviation from Laplacian form at the closely-packed state, while for maltene (deasphalted oil), no rise is observed in the standard deviation values. The closely-packed state and the asphaltene layer collapse happen at an earlier time with increasing salt concentration up to an optimum point due to the presence of the higher amount of complexes at the interface.",3,3,2
Oil Recovery,Prediction,"Esfandyari, Hamid; Hoseini, Atieh Haghighat; Shadizadeh, Seyed Reza; Davarpanah, Afshin",Simultaneous evaluation of capillary pressure and wettability alteration based on the USBM and imbibition tests on carbonate minerals,USBM test; Imbibition test; Nonionic natural surfactant; Capillary pressure; Wettability alteration,,"Wettability alteration would play a significant role in the hydrocarbon displacement as it can improve oil recovery factor both in conventional and unconventional reservoirs. Therefore, accurate prediction of this parameter would be of importance in displacement sweep efficiencies. In this paper, we aimed to experimentally investigate wettability changes in the presence of a nonionic natural surfactant (Cedar) for different carbonate mineral samples. To do this, Imbibition and USBM tests were taken into consideration to predict capillary pressure and how it affects oil production rate. It is observed that the presence of Cedar had a profound impact on the wettability and capillary pressure for calcite and dolomite samples. Due to the different composition of rock minerals, Cedar has a good effect on both core sample (calcite and dolomite), whereas the oil recovery for dolomite cores is more than calcite cores. This change for calcite cores corresponding oil-wet to neutral-wet or slightly water-wet and for dolomite samples become to water-wet. In addition, the most S-or decreasing occurs in dolomite samples particularly in D1 (14%). Moreover, the oil recovery for reservoir samples is less than mineral samples.",18,18,5
Oil Recovery,Prediction,"Rashidi, Sina; Mehrad, Mohammad; Ghorbani, Hamzeh; Wood, David A.; Mohamadian, Nima; Moghadasi, Jamshid; Davoodi, Shadfar",Determination of bubble point pressure & oil formation volume factor of crude oils applying multiple hidden layers extreme learning machine algorithms,Oil formation volume factor; Bubble point pressure; Multi-layer extreme learning machine; Hybrid machine learning algorithms; Least squares support vector machine,SUPPORT VECTOR MACHINE; SHEAR-WAVE VELOCITY; PVT PROPERTIES; CORRELATION-COEFFICIENTS; RELATIVE PERMEABILITY; RESERVOIR; PREDICTION; MODEL; SYSTEMS; PERFORMANCE,"An important requirement of reservoir management is to understand the properties of reservoir fluids and dependent phase behaviors. This makes it possible to determine the properties of reservoir fluids in laboratory pressure-volume-temperature (PVT) tests. Such laboratory tests are costly and time consuming, and reservoir data are sometimes not available. When estimating the in-place fluid volumes and/or designing enhanced recovery processes information on bubble point pressure (BPP) and oil formation volume factor (OFVF) is required. Predicting these two parameters is therefore one of the priorities of reservoir engineers. It is becoming increasingly beneficial to be able to predict BPP and OFVF with efficient machine-learning algorithms based on underlying variables that are more easily measured directly in the field. In this study, a dataset of 638 data records of published crude oil fluid samples from around the world is evaluated. After filtering the dataset for outliers, 591 data records for BPP and 599 datasets for OFVF are evaluated with efficient hybrid machinelearning algorithms (multi-layer extreme learning machine ?MELM? and least squares support vector machine ? LSSVM) optimized using a genetic algorithm ?GA? and a particle swarm optimizer ?PSO? to improve their prediction performance. Four underlying variables are considered for each data record: temperature (T), solution gas oil ratio (Rs), gas specific gravity (?g) and oil gravity (API). The PSO- MELM-PSO hybrid algorithm achieved the highest prediction accuracy measured in terms of root mean square errors (RMSE) of 33.5 psi for BPP and 0.0199 for OFVF. The four-hybrid machine-learning-optimization algorithms evaluated all outperform the empirical relationships used for many decades in the oil industry to predict BPP and OFVF.",11,11,1
Oil Recovery,Prediction,"Mohammadi, Mohammad-Reza; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Husein, Maen M.; Ranjbar, Mohammad",Application of cascade forward neural network and group method of data handling to modeling crude oil pyrolysis during thermal enhanced oil recovery,In-situ combustion; EOR; Pyrolysis; TGA; Artificial neural networks; Group method of data handling,IN-SITU COMBUSTION; MINIMUM MISCIBILITY PRESSURE; GENERALIZED REGRESSION; COMPRESSIBILITY FACTOR; KINETICS; PREDICTION; VISCOSITY; HYBRID; ASPHALTENES; OXIDATION,"Oil recovery during in situ combustion is majorly controlled by hydrocarbon oxidation and pyrolysis reactions, which govern fuel formation and heat evolution. Fuel deposition, in turn, can be accurately predicted in part through crude oil pyrolysis using thermogravimetry analysis (TGA). The theoretical models based on TGA runs, however, may be limited to crude oil samples at hand. In this study, we develop more general models to predict the residual mass during crude oil pyrolysis based on multi-layer perceptron (MLP), cascade forward (CFNN), generalized regression (GRNN), and radial basis function (RBF) neural networks. More than 2000 experimental data spanning wide range of weight percentages of asphaltenes and resins as well as oAPI gravities, heating rates, and temperatures are used. Moreover, six optimization algorithms; including Bayesian regularization (BR), scaled conjugate gradient (SCG), Levenberg-Marquardt (LM), conjugate gradient backpropagation with FletcherReeves updates (CGF), resilient backpropagation (RB), and conjugate gradient backpropagation with PolakRibie ' re updates (CGP) are used to improve the performance and prediction ability of the MLP and CFNN neural networks. The CFNN model optimized with the LM algorithm best fits all the experimental data with a mean absolute percent relative error of 1.04%. Lastly, a mathematical correlation is developed utilizing the group method of data handling (GMDH) to estimate the residual mass of crude oil pyrolysis in TGA. Despite its simplicity, the correlation also provides very good estimates. Sensitivity analysis showed that temperature followed by asphaltenes and resin content showed the highest effect on mass loss during crude oil pyrolysis. Outliers estimation applying the Leverage approach suggested only 1% of the data points could be doubtful.",11,11,1
Oil Recovery,Prediction,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Oil Recovery,Prediction,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Oil Recovery,Prediction,"Zhou, Junping; Yang, Kang; Zhou, Lei; Jiang, Yongdong; Xian, Xuefu; Zhang, Chengpeng; Tian, Shifeng; Fan, Maolin; Lu, Zhaohui",Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure,Shale reservoir; Supercritical carbon dioxide fracturing; Carbon dioxide sequestration; Mechanical alteration; Carbon dioxide-water-shale interaction,SUPERCRITICAL CO2 TREATMENT; PORE STRUCTURE; CARBON-DIOXIDE; FRACTAL ANALYSIS; MULTIFRACTAL CHARACTERISTICS; ADSORPTION BEHAVIORS; FAILURE MECHANISMS; GAS; NMR; WATER,"CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D-1 and pore volume fractal dimensions D-2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO(2), and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D-1 and D-2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.",5,6,24
Oil Recovery,Prediction,"Cheraghi, Yasaman; Kord, Shahin; Mashayekhizadeh, Vahid",Application of machine learning techniques for selecting the most suitable enhanced oil recovery method; challenges and opportunities,Enhanced oil recovery; Reservoir engineering; EOR Screening; Advanced EOR Screening; Machine learning,,"A reliable method for selecting the most suitable Enhanced Oil Recovery (EOR) method is of a high necessity in reservoir engineering. Machine Learning (ML) techniques have been widely adopted as an effective and fast approach in primary stage of EOR screening. This paper presents a step-by-step procedure of applying ML in EOR screening with focusing on two main goals. Firstly, the problem of EOR screening is investigated from ML point of view. A large database consisting of more than 1000 experiences of worldwide EOR projects has been gathered from various sources. On the basis of this database, several ML models have been developed for predicting the suitable category of EOR methods for a candidate reservoir. These models include: Shallow and Deep Artificial Neural Networks (ANN), Naive Bayes (NB), Decision Tree (DT), Random Forest (RF) and Dimension Reduction using Principal Component Analysis (PCA). Almost all models performed well in predicting non-observed data with an average accuracy ranging from 80 to 90%. However, RF and the deep ANN models delivered the best performance with an average accuracy of 90%. The results demonstrated that RF model performed much better in comparison with the DT model and improved the classification accuracy from 85 to 91%. In case of ANNs, it was observed that the deeper ANN developed here, improved the classification accuracy from 83 to 90% in comparison with the shallow ANN with one hidden layer. The weakest performance was delivered by NB classifier with an average accuracy of 49%. As the second purpose of this research, reliability of screening results from applying ML techniques is discussed in details. Because, this approach suffers from some serious limitations and challenges, which could unfavorably affect the screening results and never had been considered in previous works. In this work, potential challenges and limitations associated with this well-known approach are introduced from database issues to modeling problems. Accordingly, an important conclusion is that application of ML, although providing a very good insight into primary EOR screening, should not be relied upon as the only method for predictions. It is recommended that the obtained results from this approach should be cross-checked with other EOR screening approaches or with methods based on expert's knowledge.",5,5,3
Oil Recovery,Prediction,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
Oil Recovery,Prediction,"Kondori, Javad; Miah, Mohammad Islam; Zendehboudi, Sohrab; Khan, Faisal; Heagle, Dru",Hybrid connectionist models to assess recovery performance of low salinity water injection,Low salinity water injection; Recovery factor; Smart tools; Statistical analysis; Variable ranking,ENHANCED OIL-RECOVERY; ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINES; REAL-TIME PREDICTION; WETTABILITY ALTERATION; COMPRESSIVE STRENGTH; POROUS-MEDIA; CRUDE-OIL; REGRESSION; RESERVOIRS,"The low salinity water injection (LSWI) is one of the emerging enhanced oil recovery techniques to improve both microscopic and macroscopic displacement efficiencies by creating a new streamline in petroleum reservoirs. While experimental studies are tedious, costly, and time-consuming, the smart connectionist tools are more reliable and cost-effective approaches to predict oil recovery factor (RF) without considerations of governing equations and physics behind production mechanisms in oil reservoirs. The main objective of this study is to investigate the data-driven model performance and variable contribution while predicting RF of LSWI processes. We introduce connectionist models using hybridized least squares support vector machine (LSSVM) with global optimization technique of coupled simulated annealing (CSA), and adaptive network-based fuzzy inference system (ANFIS). The extremely randomized tree or extra tree (ET) tool is also applied to forecast the RF and investigate the parameter contribution in the employed model. The model performance is examined using statistical parameters, including coefficient of determination, relative error, mean absolute percentage error, and mean squared error. According to the results, the ET and hybridized LSSVM-CSA models perform better than the ANFIS model in estimating RF. Utilizing the ET smart model, the total dissolved salts (TDS, ppm) is the most influential parameter, while the fluid injection rate has the minimum importance in the determination of RF. The current research confirms that LSSVM-CSA and ET techniques are able to obtain RF of LSWI with high accuracy and reliability, which can be used by researchers and engineers for better management of oil reservoirs under LSWI.",4,4,3
Oil Recovery,Prediction,"Pinto, Helen; Wang, Xin; Gates, Ian",On the ratio of energy produced to energy injected in SAGD: Long-term consequences of early stage operational decisions,Steam-assisted gravity drainage; Energy efficiency; Thermal recovery; Energy produced versus energy injected (EPEI); Time-limited operator influence,,"Steam-Assisted Gravity Drainage (SAGD) is a recovery process used to extract bitumen from underground reservoirs. The efficiency of SAGD is determined by the volume of steam injected (reflecting cost and greenhouse gas emissions) relative to the volume of oil recovered (revenue). Another way to look at this relationship is as a ratio of cumulative energy produced to energy injected (EPEI). First described in this study, EPEI ratios offer a novel perspective on SAGD because they reduce the inter-well comparison bias caused by operational choices such as steam temperature, steam quality and well length. There are numerous studies on SAGD from an experimental, analytical or numerical simulation perspective, but all require assumptions and constraints specified in advance, and can only return an approximation of field performance. Studies that work exclusively with field data have typically been used for prediction modeling only. In contrast, this study employs a novel methodology by working within the existing constraints and operational choices of SAGD field wells to infer the number of steam-oil performance relationships present, and how long they last. One by one, we eliminate parameters that cannot cause the performance differences seen in the field using only deductive reasoning and multi-parameter sensitivity analysis, and arrive at possible reasons for the performance relationships found. 1520 SAGD well pairs in Alberta, Canada are used, which is more than 90% of the wells in Alberta over the last 20 years, and to the best of our knowledge, the largest field well set of any SAGD study to date. This comprehensive data set ensures that findings are applicable across the industry. Results reveal a new and surprising finding that the EPEI ratio is set during the first few months on production, and is very difficult to change thereafter. Hence, operators have a short, time-limited opportunity to influence each well's recovery ratio (and therefore its profitability and greenhouse gas emissions). This reflects the importance of process start-up and the first few months after start-up when the near well region of the reservoir is conditioned. Finally, the stability of the EPEI ratio permits a simple, new model capable of predicting cumulative recovery months in advance.",4,4,0
Oil Recovery,Prediction,"Ahmed, S.; Alameri, W.; Ahmed, W. W.; Khan, S. A.",Rheological behavior of scCO(2)-Foam for improved hydrocarbon recovery: Experimental and deep learning approach,,REAL-TIME PREDICTION; FRACTURING FLUID; SHALE-GAS; DRILLING-FLUIDS; FOAM STABILITY; OIL; PERFORMANCE; VISCOSITY; TEMPERATURE; PRESSURE,"CO2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO2 foam is a key factor to control the efficiency of fracturing process that is strongly influenced by different process parameters such as foam quality, temperature, pressure, and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO2 foams by varying different process variables. CO2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (<1.8%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO2 foam projects for fracturing unconventional reservoirs.",3,3,5
Oil Recovery,Prediction,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Oil Recovery,Prediction,"Tatar, Amin; Mohammadi, Saba; Soleymanzadeh, Aboozar; Kord, Shahin",Predictive mixing law models of rock thermal conductivity: Applicability analysis,Thermal conductivity; Mixing model; Geometric mean,THERMOPHYSICAL PROPERTIES; FLUID; PRINCIPLES; POROSITY,"Thermal conductivity is defined as the ability of a material to conduct the heat. Rock thermal conductivity is influenced by several parameters such as mineral composition, geometrical factors, porosity, and saturation condition. Value of the rock thermal conductivity is necessary in all thermal processes in petroleum engineering such as thermal methods of enhanced oil recovery. Laboratory measurement of the thermal conductivity of rock samples is time-consuming and expensive. Therefore, a large number of correlations and models have been presented to predict the rock thermal conductivity. These correlations and models are divided into three categories, i.e. mixing models, empirical and semi-empirical correlations, and theoretical models. In this paper, it was attempted to investigate 15 different predictive mixing models of rock thermal conductivity and examine their applications for different rock types and different saturation conditions using 159 collected data points. Validity and applicability of these predictive models were discussed using graphical and statistical error analysis. Results indicated that geometric mean model and Albert model can provide an accurate estimation of rock thermal conductivity with average absolute relative deviation (AARD) of 11.58% and 13.87%, respectively. Moreover, the applicability of each model was evaluated for different conditions of rock type and saturation. This evaluation revealed that Walsh, Alishaev, and Zimmerman models are more accurate than geometric mean model and Albert model for some specific conditions of rock type and saturation. Indeed, Walsh model is the best predictive thermal conductivity model for air saturated crystalline rocks, Alishaev model is the best model for predicting thermal conductivity of water saturated crystalline rocks and Zimmerman model provides the best estimation of the thermal conductivity of water saturated dolomite rocks. It should be noted that structural properties, which affect the rock thermal conductivity, are not considered in the mixing models which is the main limitation of this type of predictive models.",3,3,2
Oil Recovery,Heavy Oil,"Strelets, Larisa A.; Ilyin, Sergey O.",Effect of enhanced oil recovery on the composition and rheological properties of heavy crude oil,Heavy crude oil; Enhanced oil recovery; Oil composition; Rheology; Viscosity; Viscoelasticity,GLASS-FORMING LIQUIDS; POLYMER; ASPHALTENE; AGGREGATION; BITUMEN; MEDIA; STATE,"The composition and rheological properties of ten samples of heavy crude oil from five different wells were investigated before and after integrated oilfield treatment with gel-forming and oil-displacing systems for increasing oil recovery. The study of the viscosity and viscoelastic properties of oil samples in a wide temperature range (from -30 to 70 degrees C) made it possible to determine their gelation and glass transition temperatures and also to establish the effect of enhanced oil recovery treatment on these characteristics. It was found that the treatment can either increase or decrease the viscosity of oil, and the same applies to the gelation and glass transition temperatures as well as to the contents of saturates, resins, and asphaltenes. The rheological properties of oil samples were closely related to their group composition, while the changes in the latter as a result of oilfield treatment were dependent on the relative position of the injection and production wells. The work allowed finding universal correlations between the group composition of heavy oil, its viscosity, and test temperature.",10,10,4
Oil Recovery,Heavy Oil,"Varfolomeev, Mikhail A.; Yuan, Chengdong; V. Bolotov, Alexander; Minkhanov, Ilgiz F.; Mehrabi-Kalajahi, Seyedsaeed; Saifullin, Emil R.; Marvanov, Marat M.; Baygildin, Emil R.; Sabiryanov, Raushan M.; Rojas, Allan; Emelianov, Dmitrii A.; Al-Muntaser, Ameen A.; Ganiev, Bulat G.; Zaripov, Azat T.; Beregovoi, Anton N.; Shaihutdinov, Damir K.",Effect of copper stearate as catalysts on the performance of in-situ combustion process for heavy oil recovery and upgrading,In-situ combustion; In-situ upgrading; Heavy oil; Copper stearate; Oil-soluble catalyst; Catalytic combustion,LIGHT CRUDE-OIL; OXIDATION BEHAVIOR; NANOPARTICLES; ASPHALTENES; KINETICS; DECOMPOSITION; ADSORPTION; PYROLYSIS,"Using copper stearate as catalysts, catalytic in-situ combustion (ISC) of heavy oil was studied by porous medium thermo-effect cell (PMTEC) and combustion tube experiments. Significant acceleration of combustion was observed in porous media in PMTEC when copper stearate was added. Copper stearate promoted fuel deposition and its combustion and made them occur easier in low temperature, thus shifting both low-temperature oxidation (LTO) and high-temperature oxidation (HTO) into lower temperatures, and even totally merge HTO into LTO in some conditions. We found that the promotion on fuel deposition by catalysts might be related to the change of H/C ratio in fuel. The improvement in the performance of ISC by copper stearate in combustion tube experiments mainly manifests in lower ignition temperature, lower H/C ratio, increased air/fuel ratio, higher oil recovery, and higher level of in-situ oil upgrading, which makes copper stearate a good candidate for catalyzing ISC in field application.",9,9,6
Oil Recovery,Heavy Oil,"Onaizi, Sagheer A.; Alsulaimani, Mohammed; Al-Sakkaf, Mohammed K.; Bahadi, Salem A.; Mahmoud, Mohamed; Alshami, Ali",Crude oil/water nanoemulsions stabilized by biosurfactant: Stability and pH-Switchability,Crude oil/water nanoemulsions; Emulsion stability; Rhamnolipid biosurfactant; pH-responsive; Demulsification; Droplet size,OIL-IN-WATER; INTERFACIAL-TENSION; POROUS-MEDIA; SURFACTIN BIOSURFACTANT; SILICA NANOPARTICLES; RECOVERY; EMULSIONS; EMULSIFICATION; COMBINATION; BACTERIA,"Emulsification is one of the proposed mechanisms for enhancing crude oil recovery in chemical flooding. The replacement of chemical surfactants in enhanced oil recovery (EOR) applications with biosurfactants is an attractive alternative; yet, there is a lack of studies on the crude oil emulsification using biosurfactants. Particularly, the formulation of crude oil/water (crude O/W) nanoemulsions with an extreme stability and a pH-responsiveness behavior is still not documented in the literature, to the best of our knowledge. Accordingly, we report in this study the preparation of both light and heavy crude oil/water emulsions using different concentrations of the rhamnolipid biosurfactant. The emulsions were prepared in a two-step process: stirring overnight to create coarse emulsions followed by sonication. All the prepared emulsions have a nanoscale size (e.g., about 50% of the formed droplets at 0.1 wt% rhamnolipid are < 200 nm in size), which decreases with increasing the biosurfactant concentration. The zeta potential values of the formed crude O/W nanoemulsions were highly negative (<=-39.3). Increasing the biosurfactant concentration resulted in a more negative zeta potential. The formulated crude O/W nanoemulsions were extremely stable with 0% oil or water separation even after a month of storage. Despite the extreme stability of these crude O/W nanoemulsions, they could be easily switched off (i. e., demulsified) within 1 h by pH-swing via the addition of 50 mM sulfuric acid (H2SO4) regardless of the bioemulsifier (i.e., rhamnolipid) concentration. It was also possible to switch on/off the crude O/W nanoemulsions a number of times (at least five times) through this pH-swing mechanism. We also demonstrated that the crude O/W nanoemulsions can be completely switched off through the addition of NaOH, particularly, when these crude O/W nanoemulsions are stabilized by low rhamnolipid dosages (<= 0.5 wt%); such an observation is very unusual. The findings reported in this study clearly demonstrate the ability of creating extremely stable crude O/W nanoemulsions, which is desirable in EOR; however, the emulsified crude oil can be easily and economically recovered via a simple and an economic process (i.e., pH-switch) with the ability to switch off/on the emulsion several times.",7,7,6
Oil Recovery,Heavy Oil,"Pirizadeh, Mohsen; Alemohammad, Nafiseh; Manthouri, Mohammad; Pirizadeh, Meysam",A new machine learning ensemble model for class imbalance problem of screening enhanced oil recovery methods,Classification; Ensemble learning; EOR screening; Class imbalance problem; Mutual information; Hyper-parameter tuning,NEAREST-NEIGHBOR; CLASSIFICATION,"Enhanced Oil Recovery (EOR) methods have received a lot of attention today due to the increase in global oil demand and the reduction of oil production capacity from natural extraction methods. EOR methods are the solution for extracting oil from heavy and extra-heavy reservoirs, but the problem for reservoir engineers is choosing the right EOR method for an oilfield. In fact, the number of EOR methods and the features associated with them are very high, so the financial risk of implementing the wrong EOR method leads to feeling the need for an expert screening tool. Until now, various individual classifiers have been used for this purpose, but due to the class imbalance problem of the EOR dataset, most of them do not have good results, therefore, to increase the accuracy of the model, EOR methods with low records in the dataset are ignored, while industry needs all EOR methods. In this study, an ensemble learning-based approach is used to overcome the problem of class imbalance at the algorithmic level instead of the data level. For this purpose, an effective model called B2S is proposed by gathering the advantages of each of the ensemble-based methods, including Bagging, Boosting, and Stacking. As a result, B2S by creating a balance between variance and bias achieved an average test accuracy of 96.94% on the dataset including 426 samples from 10 different EOR methods that had a highly skewed distribution. The average accuracy also increases to 98.12% with a standard deviation of 1.63%, after grouping some relatively similar EOR methods, which indicates the stability of the proposed method. The study also demonstrates direct relation between model performance and the impact of precise pre-processing, nonlinear feature selection using Mutual Information rather than conventional linear methods, and hyper-parameters tuning with newer methods such as Random Search.",7,7,2
Oil Recovery,Heavy Oil,"Wei, Wei; Rezazadeh, Alan; Wang, Jingyi; Gates, Ian D.",An analysis of toe-to-heel air injection for heavy oil production using machine learning,Heavy oil; In situ combustion; Toe-to-heel air injection; Machine learning; Data analytics; Clustering analysis,IN-SITU COMBUSTION; GRAVITY DRAINAGE; REACTION MODEL; RECOVERY; SIMULATION; SANDS,"With strong potential for improving productivity, economics, and efficiencies, data analytics and machine learning are rapidly emerging in the oil and gas industry. However, their application in heavy oil production is scarce. In this study, we use clustering methods to analyze the Kerrobert Toe-to-Heel Air Injection (THAI) project to understand the inter-relationships of production variables and seek for optimal operating strategy to maximize production rate. More specifically, we use the K-means, normal mixtures and hierarchical clustering methods to determine how operating parameters contribute to oil production. The results reveal that, at current operation mode, air injection rate is constrained for production maximization due to the balance between heat generation and cooling of combustion system by excess air supply. The results also provide insight for improved productivity from THAI suggesting that cyclic injection may improve process performance. The new insights demonstrate that data analytics can provide new understanding of recovery processes as well as potential process improvement.",6,6,0
Oil Recovery,Heavy Oil,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Oil Recovery,Heavy Oil,"Li, Hanyong; Gao, Hang; Zhao, Xiaonan; Xia, Zijie; Yu, Bo; Sun, Dongliang",Experimental study on viscosity reduction of heavy oil with water content by synergistic effect of microwave and nano-catalyst,Viscosity reduction; Microwave heating; Nano-catalyst; Heavy oil; Water content,CRUDE-OIL; ASPHALTENES; DEMULSIFICATION; NANOPARTICLES; EMULSIONS; RECOVERY,"With the depleting of conventional oil and gas resources, viscosity reduction of heavy oil became more and more important as a research focus. As a new method of viscosity reduction, the mechanism of microwave-assisted with nano-catalysts is still unclear. In this paper, the viscosity reduction of nano-catalyst and microwave treatment of heavy oil in different water content was studied. The experimental results showed that the maximum viscosity reduction was 96.81 % when the water content was 50 wt% under the conditions of microwave heating power of 614w, microwave heating temperature of 68 degrees C and nickel nano-catalyst concentration of 0.8 wt%. The oil samples before and after three treatments were analyzed by infrared spectroscopy, element analysis, four-component separation, and two-dimensional gas chromatography-mass spectrometry. By analyzing the changes of functional group, element composition, and component content, the effects of microwave and nano-catalyst were studied. The results showed that the resin and asphaltene content decreased by 17.3 wt%, and the hydrogen to carbon ratio was 2.14 when the water content was 30 wt% under the conditions of microwave heating power of 666w, microwave heating temperature of 65 degrees C and nickel nano-catalyst concentration of 2.3 wt%, which proved that microwave treatment assisted with nano-catalysts could increase the cracking capacity of macromolecules and the production of coke.",3,3,10
Oil Recovery,Heavy Oil,"Pinilla, Andres; Asuaje, Miguel; Hurtado, Camila; Hoyos, Angela; Ramirez, Luis; Padron, Aaron; Ratkovich, Nicolas",3D CFD simulation of a horizontal well at pore scale for heavy oil fields,Viscous fingering; Pore-scale; Horizontal well; CFD; Heavy oil; Recovery factor,POROUS-MEDIA; CO2 DISPLACEMENT; FLOW; CAPILLARY; PRESSURE; WATER; FRACTURE; DRAINAGE,"Water production in the oil industry has become so common that colloquial expressions such as ""oil companies no longer produce oil, but water"" have been unconsciously accepted in this industry. Nevertheless, water production is a serious issue in heavy oil fields with strong aquifers or fields under waterflooding for two reasons: It increases the costs affecting the economic viability of a project, and it has a serious environmental impact due to increasing energy consumption and CO2 emissions. The root cause behind this problem is a phenomenon called Viscous Fingering, which appears mainly by the viscosity ratio between the phases. This study aims to understand better the Viscous Fingering phenomenon associated with a horizontal well in 3D. For the first time, a scaled horizontal well in a numerical constructed porous media was studied using a full 3D Computational Fluid Dynamics (CFD) model. The horizontal well was scaled using the Reynolds law of similarity from a real section of a horizontal well. While the porous media was made with the DEM physical model using spherical 7mmparticles, which allows reproducing rock properties such as permeability and porosity. This phenomenon was studied at three different scaled production rates, 1000, 1500, and 2000 bbl/d. Finally, three different oils were considered to study the influence of the viscosity ratio in the CFD modeling of the fingering. It was determined that CM was capable of simulating Viscous Fingering for horizontal wells at the pore scale. Also, it could give information such as production and water cut-profiles, location and time of breakthrough, and specific locations of unrecoverable oil along the reservoir. The information given by the CFD approach could be useful for the development and improvement of completion and enhanced recovery techniques.",3,3,4
Oil Recovery,Heavy Oil,"Lamas, L. F.; Botechia, V. E.; Schiozer, D. J.; Rocha, M. L.; Delshad, M.",Application of polymer flooding in the revitalization of a mature heavy oil field,Polymer flooding; Mature fields; Reservoir management; Revitalization of fields; Reservoir simulation,,"Polymer flooding is a chemical enhanced oil recovery that aims to improve mobility control, by increasing the viscosity of injection brine and thus reducing the mobility ratio. Starting the polymer injection as early as possible brings the best economic results because it prevents the formation of viscous fingering and sweeps more efficiently the reservoir. It is possible, however, to obtain gains with polymer flooding even after massive waterfloods. In this work, three different model-based approaches are developed to revitalize mature oilfields and tested considering the use of water and polymer as injection fluid. These strategies were tested using a synthetic reservoir model based on data from an offshore field in Brazil. The reservoir is sandstone (average permeability = 1650mD, average porosity = 20%). The oleic phase is heavy viscous oil (similar to 70 cP, 14 degrees API). The first simulation approach considered a strategy based on a standard waterflood until its economic limit. For this case, the maximum net present value (NPV) was reached after 15 years of production with a recovery factor of 25%. The revitalization strategy of this field considers an abandonment status for all wells. To emulate the time necessary to install all new facilities, all wells were assumed to be closed for six months. The first approach consists simply of reopening the injectors by changing the injection fluid to an aqueous polymer solution. The second approach has an additional degree of freedom: it allows all wells to be converted from injectors to producers and vice-versa. Finally, the third approach consists of the addition of new wells. Equations for quality maps for placing injectors and producers are presented. Using these equations, new producers and injectors could be placed at the best locations to produce the remaining oil spots. All three approaches increased the oil recovery factor. The additional oil recovery and variations in NPV were higher for the polymer flooding when compared with the standard waterflood, ensuring a longer productive life. This significant increase in oil production means that, for the selected case, producers needed to be closed in the water flooding period, due to economic performance, leaving a significant amount of oil still in the reservoir. The methodologies presented in this paper are easy to apply and can allow mature fields to economically produce more oil. The conversion of old wells by changing from producers to injectors or vice-versa allows new and creative production strategies. This can be done in onshore and dry completed offshore fields demanding small budgets and intervention times. This paper shows that it is possible to increase both the recovery factor and net present value of fields in the later stages of production life.",3,3,4
Oil Recovery,Heavy Oil,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Oil Recovery,Foam,"Tetteh, Joel T.; Cudjoe, Sherifa E.; Aryana, Saman A.; Ghahfarokhi, Reza Barati",Investigation into fluid-fluid interaction phenomena during low salinity waterflooding using a reservoir-on-a-chip microfluidic model,Low salinity waterflooding; Microfluidics; Fluid-fluid interaction; Snap-off effect; Water-in-oil microdispersions,OIL-RECOVERY; CRUDE-OIL/BRINE; LIQUID-FILMS; SNAP-OFF; WATER; NANOPARTICLES; MECHANISMS; INTERFACE; FOAM; FLOW,"Injection of modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks has proven to be relevant to improved oil recovery operations. Many reports in the literature related the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which caused wettability alterations at the rock surface. Little attention appears to have been paid to fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigated the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations were correlated to visual observations of displacement processes in order to investigate the role of crude oil snap-off. Microfluidic devices featuring pore throats 50 mu m in diameter were used to observe snap-off as a function of salinity of the displacing fluid. Flow experiments suggested that, in a water-wet constricted pore throat, SWS brines suppressed crude oil snap-off as compared to formation water brine (FWS) brine. This behavior was correlated to the higher surface elasticity of oil-SWS interfaces than that of oil-FWS interfaces. Higher surface elasticity suppressed the expansion of the thin water film coating pore throat walls and hence it increased the capillary number at which snap-off of the crude oil phase was expected to occur. Moreover, water interacted with the polar components to form reverse micelles called microdispersions. These microdispersions were observed in both aged and non-aged microfluidic devices near oil-brine interfaces in the pore-network. Similarly, in a vial test performed by Tetteh and Barati (2019), microdispersion formation was only observed very close to oil-brine interfaces, caused by transport of water molecules into the oil phase due to reduced intermolecular forces at oil-LSW interfaces. This microdispersion formation was visualized using environmental scanning electron microscopy. These microdispersions remobilized, redistributed the oil, and along with a slight change in wettability in the medium, they improved the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributed to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.",9,10,5
Oil Recovery,Foam,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Oil Recovery,Foam,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Oil Recovery,Foam,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
Oil Recovery,Foam,"Okunade, Oluwagade Adenike; Yekeen, Nurudeen; Padmanabhan, Eswaran; Al-Yaseri, Ahmed; Idris, Ahmad Kamal; Khan, Javed Akbar","Shale core wettability alteration, foam and emulsion stabilization by surfactant: Impact of surfactant concentration, rock surface roughness and nanoparticles",Wettability; Surface roughness; Foam; Emulsion; Surfactants; Nanoparticles,ENHANCED OIL-RECOVERY; HUFF-N-PUFF; LAB(R) EXPERT ANALYSIS; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; SILICA NANOPARTICLES; NONIONIC SURFACTANTS; SIO2 NANOPARTICLES; CONTACT ANGLES; HIGH-PRESSURE,"Hexadecyltrimethyl ammonium bromide (HCTAB) and sodium dodecyl sulfate (SDS) are popular conventional surfactants with versatile industrial and oilfield applications. Knowledge of the optimum conditions for their applications for shale rock wettability modification, as well as foam and emulsion stabilization is relevant for hydrocarbon recovery process optimization. Influence of surfactant concentration, rock surface roughness and presence of nanoparticles in surfactant solutions on contact angles, oil-water interfacial tension (IFT), as well as foam and emulsion stabilization by HCTAB and SDS was investigated in this study. The interfacial properties measurements were conducted with Drop Shape Analyser (DSA 25), whereas the foam generation and stability properties were investigated via dynamic foam analyzer (DFA100). The emulsion stabilization and demulsification processes were investigated in Formulaction Turbiscan. Results showed an existence of optimum concentration of surfactant for obtaining the lowest contact angles, oil-water IFT reduction, as well as attaining maximum foam stability. The contact angle measured on rough core surfaces were smaller than the contact angle measured on smooth surfaces. Contact angles increased with increasing salnity concentration, but decreased with the increasing rock saturation time. Oil was more detrimental to foam stability when the generated foam was brought into contact with the resident oil, compared to when oil was added to the foaming solutions before foam generation. Lower contact angles, durable foam, and stable emulsion were produced in presence of oil and at high temperature via the synergy of nanoparticles and surfactants. Almost 66% decreased in contact angle was achieved with carbon nanotubes-SDS solutions, whereas Al2O3 nanoparticles-HCTAB foam attained a viscosity of 99 mPa-s at 60 degrees C. The foam demonstrated shear thinning Newtonian fluids behaviors but attained a plateau after sometimes. The study suggests the conditions for optimization of conventional surfactants applications in conventional and unconventional reservoir.",4,4,9
Oil Recovery,Foam,"Das, Alolika; Mohanty, Kishore; Nguyen, Quoc",A pore-scale study of foam-microemulsion interaction during low tension gas flooding using microfluidics-Tertiary recovery,Enhanced oil recovery; Foam; Ultralow interfacial tension; Microemulsion; Microfluidics,OIL DISPLACEMENT,"The emerging EOR technology of Low-Tension-Gas (LTG) flooding has been proven to be successful for tertiary oil recovery in laboratory scale coreflooding experiments. However, there has not been a detailed study of the pore-scale phenomena which occur during LTG flooding. In the current study, alternate injection of a suitable surfactant formulation and air has been used to simulate the mechanism of LTG flooding in a borosilicate waterwet micromodel. The main phenomenon that was investigated was the interaction between different microemulsion types (Winsor I and III) and foam. Results show that presence of foam facilitates faster and better oil displacement. Microemulsion equilibration time was improved in the presence of foam, due to increased mixing of the liquid phases. Presence of trapped gas helped to divert the flowing surfactant/microemulsion to regions with trapped remaining oil and thus improved oil recovery. For equilibrated Type III microemulsion, completely miscible flooding (or ultralow tension displacement) was observed. For Type I systems, oil-in-water macroemulsions were observed. For equilibrated Type III microemulsion, the presence of foam mainly improved the oil recovery rate. In case of Type III surfactant solution injection, the presence of foam improved both the oil recovery rate and the overall oil recovery. For Type I systems, the presence of foam enabled the transition of oil-in water macroemulsions to water-entrained macroemulsions, thus improving both the oil recovery rate and the overall oil recovery.",3,3,7
Oil Recovery,Foam,"Liang, Tuo; Hou, Jirui",Fluids flow behaviors of nitrogen and foam-assisted nitrogen floods in 2D visual fault-karst carbonate reservoir physical models,Fractured-vuggy reservoir; Fluids flow characteristics; Nitrogen and foam driven; EOR,,"Fault-karst fractured-vuggy carbonate reservoir is an important type of fractured-vuggy carbonate reservoirs in Tahe oilfield of China. The fluids flow behaviors in fault-karst fractured-vuggy carbonate reservoir are complex and unclear due to the complexity of the connection between fractures and vugs. In this work, the novel 2D visual fault-karst fractured-vuggy carbonate reservoir physical models (longitudinal model and horizontal model) were designed and fabricated to investigate the flow characteristics and phase behaviors of nitrogen gas and foam-assisted nitrogen gas floods. Experimental results showed that oil-water and gas-oil interfaces fluctuations had positive effect on improving oil recovery. Foam-assisted nitrogen gas can effectively inhibit the occurrence of gas channeling, improve swept volume and increase oil recovery. A four-phase dimensionless index (Nr') was first proposed to describe the synergistic effects among the gas cap, foam cap and bottom water during foam-assisted nitrogen flooding process. Based on the analysis of oil recovery results, there was a turning point on oil recovery curve for foam-assisted nitrogen gas flooding. Moreover, the optimal production mode that was injection in high position of reservoir and recovery from low position of reservoir (HI-LR) in fault-karst carbonate reservoir was determined. This study is helpful to understand the flow characteristics of foam and nitrogen gas and provides a guide for increasing oil recovery in fault-karst fractured-vuggy carbonate reservoirs.",3,3,6
Oil Recovery,Foam,"Ahmed, S.; Alameri, W.; Ahmed, W. W.; Khan, S. A.",Rheological behavior of scCO(2)-Foam for improved hydrocarbon recovery: Experimental and deep learning approach,,REAL-TIME PREDICTION; FRACTURING FLUID; SHALE-GAS; DRILLING-FLUIDS; FOAM STABILITY; OIL; PERFORMANCE; VISCOSITY; TEMPERATURE; PRESSURE,"CO2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO2 foam is a key factor to control the efficiency of fracturing process that is strongly influenced by different process parameters such as foam quality, temperature, pressure, and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO2 foams by varying different process variables. CO2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (<1.8%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO2 foam projects for fracturing unconventional reservoirs.",3,3,5
Oil Recovery,Foam,"Wen, Yiping; Lai, Nanjun; Li, Wenhong; Zhang, Yongqiang; Du, Zhaofeng; Han, Lijuan; Song, Zhiling",Factors influencing the stability of natural gas foam prepared by alkyl polyglycosides and its decay rules,Alkyl polyglycosides; Natural gas foam; Drainage kinetics; Decay rules; Statistics methods; Surface properties,HIGH-TEMPERATURE; NITROGEN FOAM; SURFACTANT; PERFORMANCE; DRAINAGE; BEHAVIOR; PARTICLES,"By using alkyl polyglycoside (APG) as foaming agent and natural gas as gas phase, the natural gas foam system was prepared, and the influence of alkyl chain length, metal cation valence and concentration, and polymer types on the foam stability was studied. By completely observing the volume and time required for the foam drainage liquid under different conditions, a foam drainage kinetics model was established. The drainage rate constant, the maximum drainage rate and its occurrence time during the foam drainage process can be acquired by derivation of the fitting function. The Arrhenius equation was adopted to fit the drainage rate constant at different temperature, and the drainage activation energy is obtained. The drainage process of foam was further analyzed from the perspective of kinetics. Moreover, the changes in geometric geometries such as bubble number, particle size distribution frequency and the average diameter of the bubble in the decay process under different conditions was counted. According to the mathematical relationship between the average diameter and time, the Ostwald ripening rate and gas molecule diffusion constant are calculated. Finally, through the investigation of the interface properties and the micromorphology of the solution, the reasons for the above rules are explained. The research shows that: 1) the increase of the alkyl chain length of APG within a certain range (8-10.9) is beneficial to the improvement of the foam stability, and the continuous increase of chain length (10.9-12) is adverse to the foam stability, 2) the increase in the salinity of prepared water and the metal ions valence enhances the foam stability to a certain extent, 3) DG is more stable to APG foam than XG and KYPAM-6s. This study enriches the stability rules of APG foam with natural gas as the gas phase under different conditions, and provides ideas and methods for quantitatively analyzing the foam decay process from the perspectives of kinetics and statistics, which provides theoretical support for the application of natural gas foam in enhance oil recovery.",3,3,4
Oil Recovery,Shale,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Oil Recovery,Shale,"Zhou, Junping; Yang, Kang; Zhou, Lei; Jiang, Yongdong; Xian, Xuefu; Zhang, Chengpeng; Tian, Shifeng; Fan, Maolin; Lu, Zhaohui",Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure,Shale reservoir; Supercritical carbon dioxide fracturing; Carbon dioxide sequestration; Mechanical alteration; Carbon dioxide-water-shale interaction,SUPERCRITICAL CO2 TREATMENT; PORE STRUCTURE; CARBON-DIOXIDE; FRACTAL ANALYSIS; MULTIFRACTAL CHARACTERISTICS; ADSORPTION BEHAVIORS; FAILURE MECHANISMS; GAS; NMR; WATER,"CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D-1 and pore volume fractal dimensions D-2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO(2), and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D-1 and D-2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.",5,6,24
Oil Recovery,Shale,"Jia, Bao; Chen, Zeliang; Xian, Chenggang",Investigations of CO2 storage capacity and flow behavior in shale formation,Shale; CO2; Adsorption; Molecular diffusion,ENHANCED OIL-RECOVERY; CARBON-DIOXIDE; ADSORPTION; PRESSURE; RESERVOIRS; METHANE; INJECTION; NETWORKS; SORPTION; EOR,"CO2 storage, CO2 stimulation, CO2-enhanced oil recovery (EOR), and CO2-enhanced gas recovery (EGR) in shale reservoirs have recently attracted attention. Thorough investigations mimicking high pressure and high-temperature subsurface conditions are necessary to understand the interaction between CO2 and organic-rich shales, advance the fundamental understating of flow mechanisms in unconventional reservoirs, and successfully implement a field project. Most of the previous work focused on one aspect of adsorption, flow behavior, and reservoir numerical simulation. We suggest that a single approach investigation may lead to incomplete conclusions of CO2 injection in shales. This work comprehensively evaluates CO2 storage potential and injectivity in the Bakken Formation through various approaches. Samples are tested from the Lower Bakken Shale (LBS), the Middle Bakken (MB), and the Upper Bakken Shale (UBS). In terms of absolute and Gibbs/excess, adsorption isotherms of these two types are both measured, and the adsorbate density is estimated. We differentiate two adsorption isotherms and emphasize the correct use of the isotherm in the current commercial reservoir simulator, which is relatively obscure in the existing literature body. Nuclear magnetic resonance (NMR) confirms a portion of bitumen/absorption mobilization because of CO2 exposure. In the compositional simulations of CO2 injection in shales, several novel conclusions are obtained regarding analyzing main control factors; the most important one is that adsorption outweighs molecular diffusion in determining CO2 injection rate.",4,4,19
Oil Recovery,Shale,"Okunade, Oluwagade Adenike; Yekeen, Nurudeen; Padmanabhan, Eswaran; Al-Yaseri, Ahmed; Idris, Ahmad Kamal; Khan, Javed Akbar","Shale core wettability alteration, foam and emulsion stabilization by surfactant: Impact of surfactant concentration, rock surface roughness and nanoparticles",Wettability; Surface roughness; Foam; Emulsion; Surfactants; Nanoparticles,ENHANCED OIL-RECOVERY; HUFF-N-PUFF; LAB(R) EXPERT ANALYSIS; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; SILICA NANOPARTICLES; NONIONIC SURFACTANTS; SIO2 NANOPARTICLES; CONTACT ANGLES; HIGH-PRESSURE,"Hexadecyltrimethyl ammonium bromide (HCTAB) and sodium dodecyl sulfate (SDS) are popular conventional surfactants with versatile industrial and oilfield applications. Knowledge of the optimum conditions for their applications for shale rock wettability modification, as well as foam and emulsion stabilization is relevant for hydrocarbon recovery process optimization. Influence of surfactant concentration, rock surface roughness and presence of nanoparticles in surfactant solutions on contact angles, oil-water interfacial tension (IFT), as well as foam and emulsion stabilization by HCTAB and SDS was investigated in this study. The interfacial properties measurements were conducted with Drop Shape Analyser (DSA 25), whereas the foam generation and stability properties were investigated via dynamic foam analyzer (DFA100). The emulsion stabilization and demulsification processes were investigated in Formulaction Turbiscan. Results showed an existence of optimum concentration of surfactant for obtaining the lowest contact angles, oil-water IFT reduction, as well as attaining maximum foam stability. The contact angle measured on rough core surfaces were smaller than the contact angle measured on smooth surfaces. Contact angles increased with increasing salnity concentration, but decreased with the increasing rock saturation time. Oil was more detrimental to foam stability when the generated foam was brought into contact with the resident oil, compared to when oil was added to the foaming solutions before foam generation. Lower contact angles, durable foam, and stable emulsion were produced in presence of oil and at high temperature via the synergy of nanoparticles and surfactants. Almost 66% decreased in contact angle was achieved with carbon nanotubes-SDS solutions, whereas Al2O3 nanoparticles-HCTAB foam attained a viscosity of 99 mPa-s at 60 degrees C. The foam demonstrated shear thinning Newtonian fluids behaviors but attained a plateau after sometimes. The study suggests the conditions for optimization of conventional surfactants applications in conventional and unconventional reservoir.",4,4,9
Oil Recovery,Shale,"Afekare, Dayo; Garno, Jayne; Rao, Dandina",Enhancing oil recovery using silica nanoparticles: Nanoscale wettability alteration effects and implications for shale oil recovery,Nanofluid; Enhanced oil recovery; Atomic force microscope; Wettability; Nanoparticle; Tuscaloosa marine shale,PHASE-BEHAVIOR; ADHESION; ADSORPTION; PRESSURE; CONTACT; CURVES; CORES; FINES,"Enhanced oil recovery (EOR) techniques have the potential to improve recovery in unconventional shale oil reservoirs which have prolific short-term success but elusive near-to-long term outlook. The use of silicon dioxide nanoparticles for enhancing shale oil recovery has recently gained significant attention in the oil industry. However, the technique remains novel partly due to inadequate fundamental understanding of oil release mechanisms. Herein, the oil recovery potential of untreated and treated silica nanoparticles is investigated using an atomic force microscope (AFM) by studying nanoscale interactions between different crude oil functional species and substrates of pure minerals found in a shale oil reservoir. Quartz and muscovite mica (clay substitute) were employed as substrates as these are the dominant rock minerals identified in the most productive zone of Tuscaloosa Marine Shale (TMS). Thiolates of undecane (CH3) and phenyl (C6H5) compounds were used to simulate alkane and aromatic fractions of TMS crude oil respectively, while undecanoic acid (COOH) thiol was used to represent carboxylic acid found in asphaltene and resin components. Following our in-house experimental protocol for liquid cell force spectroscopy, adhesion forces and surface energies between functionalized AFM probes and mineral substrates were characterized in untreated and amino-treated silica nanoparticle dispersions. Zeta potential of respective nanofluid solutions was measured and AFM adsorption data were supported with scanning electron microscope (SEM) micrographs of TMS rock samples. Results showed that aqueous dispersions of hydrophilic silicon dioxide nanoparticles promote wettability towards a less oil-wet state by significantly lowering the adhesion force and energy barrier to spontaneously detach oil molecules from clay and quartz mineral surfaces in shale reservoirs, shown at the nanoscale with AFM studies. However, the grafting of aminosilanes onto surfaces of silica nanoparticles generally increased adhesion forces and surface energies due to surface charge effect and hydrophobicity. Findings pertinent to nanoparticle silanization were consistent in molecular interactions on mica in nanofluids but not necessarily predictable with quartz surfaces, highlighting mineralogical effects. The irreversible adsorption of silica nanoparticles was also observed. Adhesion force and energy are resolved in various intermolecular forces such as electric double layer repulsion, non-electrostatic interaction and structural forces. The scientific significance and broad engineering implications of results were comprehensively discussed in the context of previously reported core-to-field scale observations of nanofluid EOR. This study pitches new light on the scientific understanding of silica-based nanofluid EOR by probing nanoscale wetting effects of silica nanoparticles with implications for shale oil recovery. The findings herein can help for better understanding of the design of nanofluid EOR reagents and the conditions that favor application of silica nanofluid EOR.",3,3,8
Oil Recovery,Shale,"Cui, Jiangfeng; Si, Guangyao",Equivalent anisotropic permeability of shale rocks: Effect of micro-fractures,Shale; Equivalent permeability; Bedding fracture; Structural fracture; Numerical simulation,MICROFRACTURES; NANOPORES; TRANSPORT; OIL,"The extensive opening-mode micro-fractures, including horizontal bedding fractures and vertical structural fractures, are prevalent in shale rocks. Because of a huge difference with many orders of magnitude in permeability from the nearly impermeable shale matrix and those highly conductive micro-fractures, the microfractures are believed to contribute substantially to the macro-scale anisotropic flow properties of shale. Nevertheless, up to the present day, there has been no comprehensive research on this topic. Previous works simply employed a fixed pattern of micro-fractures and did their simulations. In this work, the finite difference method is employed to perform steady-state numerical simulation. The impact of micro-fractures on the flow capacity of shale rocks is characterized by the concept of normalized equivalent permeability. The concepts of bedding thickness, filling spacing and filling ratio are utilized to characterize the distribution pattern of horizontal bedding fractures. The length and number of vertical structural fractures are also considered. The validation of several simplistic scenarios against known results guarantees the correctness and accuracy of the numerical code. Comprehensive sensitivity analysis using realistic ranges of parameters based on literature is conducted for the two scenarios: (i) horizontal bedding fractures only, and (ii) horizontal bedding fractures and vertical structural fractures, moreover, both uniform and random distributions are discussed and then compared. Effects of bedding thickness, filling spacing and filling ratio of horizontal bedding fractures, the length and number of vertical structural fractures, the connectivity between horizontal bedding and vertical structural fractures, and the random distribution attribute of fractures on the anisotropic permeability of shale, including horizontal and vertical components, are discussed. This is the very first work that comprehensively investigates the effect of micro-fractures on the anisotropic permeability of shale rocks, which can help improve the understanding of the flow capacity of shale rocks and even the hydraulic properties of similar kinds of fractured material. Also, it is very useful for modeling the fluid flow to enhance oil/gas recovery in shale reservoirs.",3,3,8
Oil Recovery,Shale,"Zheng, Jiangtao; Wang, Zenglin; Ju, Yang; Tian, Yuqin; Jin, Yanxin; Chang, Wei",Visualization of water channeling and displacement diversion by polymer gel treatment in 3D printed heterogeneous porous media,Polymer gel; Enhanced oil recovery (EOR); Water channeling; Diversion; 3D printing,CONFORMANCE CONTROL; OIL-RECOVERY; SHALE; INJECTION; SYSTEM; FLOODS; FLUID; FIELD; ROCK; EOR,"Polymer gels are widely applied to increase the sweep efficiency in mature oil fields facing severe water channeling problems after years of water flooding. The formation of water channeling and successful polymer gel treatment are rooted in complex pore-scale displacement and diversion. Thus, accurate characterization of the pore space and direct visualization of the interior displacement processes in real reservoir rocks such as water flooding, polymer gel injection, and chase floods are crucial in determining the controlling mechanisms of water channeling and polymer gel diversion. In this study, 3D X-ray micro-computed tomography (uCT) was used to characterize the porous structures of three distinct levels in water-flooded reservoir sandstones. A heterogeneous digital model was designed, which comprised representative layers of the obtained porous structures. Then, 3D-printing technology was used to manufacture a transparent model based on the digital prototype. A series of displacement experiments were conducted in the printed model to directly visualize the flow behaviors in the actual pore geometries. In the experiments, the model was first saturated with white oil and flooded by formation water until the outlet discharged only the water phase. Then, an immediately prepared polymer gel was injected. After three days of gelation, an antidilution polymer was injected to sweep the residual oil in the model. Finally, a surfactant flooding agent was injected designed to further increase the oil recovery. The entire four-step displacement process was directly visualized, and the saturation of each injection and the oil recovery were calculated. During water flooding, preferential flooding channels formed in the highest water-flooded porous layers due to the low viscosity ratio between the injected formation water and the displaced white oil, as well as the permeability contrast in the heterogeneous model. The injected polymer gel mainly followed the preferential flooding channels because of the low resistance force in these channels. After gelation, the polymer gel blocked the main preferential channels and diverted the chase floods to nearby pores. A desirable diversion of the polymer gel highly depends on its propagation path during injection and effective blocking after gelation. Experimental visualization and displacement mechanism analysis indicate the efficacy of the flow diversion by the polymer gel treatment in the heterogeneous porous model. The results provide useful information on the displacement behavior in heterogeneous porous structures, and the conclusions apply to similarly scaled systems at the reservoir scale.",3,3,7
Oil Recovery,Shale,"Fu, Qinwen; Cudjoe, Sherifa; Ghahfarokhi, Reza Barati; Tsau, Jyun-Syung; Li, Xiaoli; Peltier, K.; Mohrbacher, D.; Baldwin, A.; Nicoud, B.; Bradford, K.",Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection-an Eagle Ford study,Molecular diffusion; Hydrocarbon gas huff-n-puff; Dual-permeability; Rock-fluid property; Gas injection; Eagle Ford shale; Unconventional reservoirs; EOR; IOR,OIL,"Fracture complexity, variation in fluid properties, variations in rock types and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research has been conducted to define diffusion coefficients coupled with rock tortuosity resulting in calculation of effective diffusion. The objective of this work is to conduct a comprehensive experimental and simulation study on lower Eagle Ford rock samples to measure diffusion coefficients for different injection cycles in three representative rock samples from the main flow unit. Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and effluent oil and gas compositions were measured. NMR measurement was repeated at the end. Three compositional simulation models were set up for three different samples using tortuosity values from FIB-SEM analysis to simulate experimental diffusion and production. For history matching, relative permeability curves, fracture properties, and tortuosity were tuned to match pressure and production results for three representative samples. Pressure profiles vary significantly between different cycles caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Effective diffusion coefficients were calculated using representative tortuosity values. Diffusion was represented by pressure drop during soaking time. This pressure drop varies across different lithofacies and for different rock samples. For produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate components increased. Gas huff-n-puff injection into shale oil reservoirs were being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments, conducted using a constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, show favorable results. Recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively.",3,3,4
Oil Recovery,Shale,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Oil Recovery,Gravity Drainage,"Wei, Wei; Rezazadeh, Alan; Wang, Jingyi; Gates, Ian D.",An analysis of toe-to-heel air injection for heavy oil production using machine learning,Heavy oil; In situ combustion; Toe-to-heel air injection; Machine learning; Data analytics; Clustering analysis,IN-SITU COMBUSTION; GRAVITY DRAINAGE; REACTION MODEL; RECOVERY; SIMULATION; SANDS,"With strong potential for improving productivity, economics, and efficiencies, data analytics and machine learning are rapidly emerging in the oil and gas industry. However, their application in heavy oil production is scarce. In this study, we use clustering methods to analyze the Kerrobert Toe-to-Heel Air Injection (THAI) project to understand the inter-relationships of production variables and seek for optimal operating strategy to maximize production rate. More specifically, we use the K-means, normal mixtures and hierarchical clustering methods to determine how operating parameters contribute to oil production. The results reveal that, at current operation mode, air injection rate is constrained for production maximization due to the balance between heat generation and cooling of combustion system by excess air supply. The results also provide insight for improved productivity from THAI suggesting that cyclic injection may improve process performance. The new insights demonstrate that data analytics can provide new understanding of recovery processes as well as potential process improvement.",6,6,0
Oil Recovery,Gravity Drainage,"Sun, Xingge; Xu, Bin; Qian, Genbao; Li, Biao",The application of geomechanical SAGD dilation startup in a Xinjiang oil field heavy-oil reservoir,Geomechanics; Dilation startup; Dilation initiation pressure; SAGD; Thermal recovery,GRAVITY DRAINAGE; STEAM; TEMPERATURE; DESIGN; SANDS,"Steam-assisted gravity drainage (SAGD) methods have been widely applied in oil-sands exploitation globally. SAGD processes are effective only after thermal and hydraulic communication between the injector and producer has been established during the start-up operation of the well pair. The geomechanical SAGD dilation startup has been considered a promising technology that can enhance permeabilities of heavy-oil reservoirs and reduce thermal conformance time. However, limited studies have focused on the practical operational procedures of geomechanical SAGD dilation startup. This paper presents the application of SAGD dilation startup technology in a shallow super heavy-oil reservoir in the Karamay oil field, China. The general reservoir geology and geomechanical characteristics were investigated and used to propose a practical approach to determine dilation initiation pressure. We also summarize the SAGD well completions and geomechanical SAGD dilation startup procedures. A case study using a real SAGD well is presented and analyzed. We then share the field operation procedures and results after dilation startup. The objective of the research was to reduce the steam circulation time and achieve uniform thermal conformance along the SAGD well. Our field results highlight the promising potential of using water injection to create a dilated zone and dramatically enhance reservoir permeability. The performance of SAGD dilation startup in the Karamay oil field is evaluated by comparing the cumulative oil production rate with those from SAGD wells using conventional startup.",5,5,1
Oil Recovery,Gravity Drainage,"Pinto, Helen; Wang, Xin; Gates, Ian",On the ratio of energy produced to energy injected in SAGD: Long-term consequences of early stage operational decisions,Steam-assisted gravity drainage; Energy efficiency; Thermal recovery; Energy produced versus energy injected (EPEI); Time-limited operator influence,,"Steam-Assisted Gravity Drainage (SAGD) is a recovery process used to extract bitumen from underground reservoirs. The efficiency of SAGD is determined by the volume of steam injected (reflecting cost and greenhouse gas emissions) relative to the volume of oil recovered (revenue). Another way to look at this relationship is as a ratio of cumulative energy produced to energy injected (EPEI). First described in this study, EPEI ratios offer a novel perspective on SAGD because they reduce the inter-well comparison bias caused by operational choices such as steam temperature, steam quality and well length. There are numerous studies on SAGD from an experimental, analytical or numerical simulation perspective, but all require assumptions and constraints specified in advance, and can only return an approximation of field performance. Studies that work exclusively with field data have typically been used for prediction modeling only. In contrast, this study employs a novel methodology by working within the existing constraints and operational choices of SAGD field wells to infer the number of steam-oil performance relationships present, and how long they last. One by one, we eliminate parameters that cannot cause the performance differences seen in the field using only deductive reasoning and multi-parameter sensitivity analysis, and arrive at possible reasons for the performance relationships found. 1520 SAGD well pairs in Alberta, Canada are used, which is more than 90% of the wells in Alberta over the last 20 years, and to the best of our knowledge, the largest field well set of any SAGD study to date. This comprehensive data set ensures that findings are applicable across the industry. Results reveal a new and surprising finding that the EPEI ratio is set during the first few months on production, and is very difficult to change thereafter. Hence, operators have a short, time-limited opportunity to influence each well's recovery ratio (and therefore its profitability and greenhouse gas emissions). This reflects the importance of process start-up and the first few months after start-up when the near well region of the reservoir is conditioned. Finally, the stability of the EPEI ratio permits a simple, new model capable of predicting cumulative recovery months in advance.",4,4,0
Oil Recovery,Gravity Drainage,"Akhlaghi, Naser; Riahi, Siavash; Parvaneh, Ronak","Interfacial tension behavior of a nonionic surfactant in oil/water system; salinity, pH, temperature, and ionic strength effects",Triton X-100; IFT; CMC; Enhanced oil recovery; PH; Salinity,ENHANCED OIL-RECOVERY; ASSISTED GRAVITY DRAINAGE; ACIDIC CRUDE-OIL; WATER; IFT; WETTABILITY; BRINE; PERFORMANCE; ASPHALTENE; COMPONENTS,"Since most of the world's oil reservoirs are in the second half lifetime, the use of Enhanced Oil Recovery (EOR) methods is inevitable. Interfacial Tension (IFT) is one of the effective parameters on EOR can be changed by surfactants. But surfactant injection is one of the costly methods and chemistry of the surfactant solutions such as salinity (one and two valence ions) and pH should be engineered. Furthermore, the temperature is an effective parameter affecting on IFT. In this study, the effect of salinity, especially hard salinity, temperature and pH on IFT between Triton X-100 surfactant and an Iranian oil sample has been investigated. In order to, evaluate the effect of salinity, different concentrations of NaCl, CaCl2, MgCl2, and Na2SO4 salts (0, 0.1, 0.5, and 1 wt%) were used in different concentrations of surfactant. IFT results showed that magnesium and calcium divalent cations had a greater effect on IFT reduction than monovalent sodium cation. Also, all the studied cations were more effective than sulfate as a divalent anion. The ionic strength of the solutions was inversely proportional to the IFT amounts. Less value of IFT in the presence of magnesium ions than calcium ions was due to the higher ionic strength of solutions containing magnesium compared with calcium. IFT results at three temperatures (20, 40, and 60 degrees C) proved that by increasing temperature IFT increased. Also, the effect of pH on IFT in three pHs including acidic, almost neutral and alkaline in the presence of surfactant was studied. Results indicated that IFT decreased with increasing pH, especially in concentrations lower than critical micelle concentration (CMC).",3,3,4
Crude Oil,Wettability Alteration,"Farhadi, Hamed; Ayatollahi, Shahab; Fatemi, Mobeen","The effect of brine salinity and oil components on dynamic IFT behavior of oil-brine during low salinity water flooding: Diffusion coefficient, EDL establishment time, and IFT reduction rate",Dynamic interfacial tension; Crude-oil/brine system; Time dependent adsorption; Low salinity effect; Asphaltene,INTERFACIAL-TENSION; WETTABILITY ALTERATION; CAPILLARY-PRESSURE; SURFACE-PROPERTIES; ADSORPTION; RECOVERY; SANDSTONE; RESERVOIR; ASPHALTENES; ELECTRONS,"Dynamic behavior of fluid-fluid interactions can potentially affect the performance of any enhanced oil recovery (EOR) process including low salinity water flooding. In this work, dynamic interfacial tension (IFT) of crude-oil/brine system is measured in a wide range of salinity of sea water (SW), from 50-time diluted sea water (SW50D) to 2-time concentrated sea water (SW2C). Contrary to the most of published IFT trends in the literature, for the system under investigation here, as the brine salinity increases the crude-oil/brine IFT reduces, which cannot be explained using the existing theories. The lack of a physical model to explain the observed phenomena was the motivation to develop a new model based on a drift-diffusion theory. This theory considers a current of oil polar molecules toward the oil-water interface which is caused by electrostatic attraction from aqueous ions (drift) and a resistance against this current caused by concentration gradient (diffusion). After applying this model to measured dynamic IFT data, the IFT reduction rate, and electrical double layer (EDL) establishment time are calculated. Then, these matching parameters set as criteria to explain the mechanisms behind the dynamic behavior of crude oil-saline water interfacial tension. For further investigation of the involved mechanisms which are responsible for the macroscopic behavior of crude-oil/brine dynamic IFT, the role of oil components is also examined using the IFT reduction rate and EDL establishment time. Although the obtained results show the asphaltene molecules play a vital role in the dynamic IFT behavior, the concentration of n-heptane, in the model oil containing n-heptane and toluene, is essential to capture the IFT behavior of the crude oil. Increasing n-heptane fraction in the model oil to the amount which exist in the crude oil, results in longer EDL establishment time which is in agreement with the crude oil sample.",11,11,1
Crude Oil,Wettability Alteration,"Tetteh, Joel T.; Cudjoe, Sherifa E.; Aryana, Saman A.; Ghahfarokhi, Reza Barati",Investigation into fluid-fluid interaction phenomena during low salinity waterflooding using a reservoir-on-a-chip microfluidic model,Low salinity waterflooding; Microfluidics; Fluid-fluid interaction; Snap-off effect; Water-in-oil microdispersions,OIL-RECOVERY; CRUDE-OIL/BRINE; LIQUID-FILMS; SNAP-OFF; WATER; NANOPARTICLES; MECHANISMS; INTERFACE; FOAM; FLOW,"Injection of modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks has proven to be relevant to improved oil recovery operations. Many reports in the literature related the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which caused wettability alterations at the rock surface. Little attention appears to have been paid to fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigated the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations were correlated to visual observations of displacement processes in order to investigate the role of crude oil snap-off. Microfluidic devices featuring pore throats 50 mu m in diameter were used to observe snap-off as a function of salinity of the displacing fluid. Flow experiments suggested that, in a water-wet constricted pore throat, SWS brines suppressed crude oil snap-off as compared to formation water brine (FWS) brine. This behavior was correlated to the higher surface elasticity of oil-SWS interfaces than that of oil-FWS interfaces. Higher surface elasticity suppressed the expansion of the thin water film coating pore throat walls and hence it increased the capillary number at which snap-off of the crude oil phase was expected to occur. Moreover, water interacted with the polar components to form reverse micelles called microdispersions. These microdispersions were observed in both aged and non-aged microfluidic devices near oil-brine interfaces in the pore-network. Similarly, in a vial test performed by Tetteh and Barati (2019), microdispersion formation was only observed very close to oil-brine interfaces, caused by transport of water molecules into the oil phase due to reduced intermolecular forces at oil-LSW interfaces. This microdispersion formation was visualized using environmental scanning electron microscopy. These microdispersions remobilized, redistributed the oil, and along with a slight change in wettability in the medium, they improved the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributed to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.",9,10,5
Crude Oil,Wettability Alteration,"Saadat, Marzieh; Yang, Junyi; Dudek, Marcin; Oye, Gisle; Tsai, Peichun Amy",Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability,Wettability alteration; Microfluidics; Surfactant flooding; Oil recovery; Enhanced oil recovery; Low salinity water flooding,LOW-SALINITY WATER; CRUDE-OIL; FINES MIGRATION; PHASE-BEHAVIOR; SURFACTANT; WET; DISPLACEMENT; EOR; ADSORPTION; SULFONATE,"Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.",8,9,11
Crude Oil,Wettability Alteration,"Farhadi, Hamed; Fatemi, Mobeen; Ayatollahi, Shahab",Experimental investigation on the dominating fluid-fluid and rock-fluid interactions during low salinity water flooding in water-wet and oil-wet calcites,Low salinity water flooding; Enhanced oil recovery; Carbonate rock wettability alteration; Dynamic interfacial tension; Dynamic contact angle; Surface electric charges,INTERFACIAL INTERACTIONS; TENSION; RESERVOIR,"Low salinity water flooding (LSWF) has the potential to enhance the oil recovery by affecting the fluid-fluid and rock-fluid interactions. Therefore, a systematic investigation on the effect of initial wetting state (water-wet or oil-wet) of pure calcite is conducted to study the importance of these interactions on the effectiveness of LSWF. In the case of initially water-wet cores, more oil recovery efficiency is observed for more saline water cases. To shed light on the possible involved mechanisms, dynamic IFT, dynamic contact angle (CA), oil/brine and rock/brine surfaces zeta potentials, and effluent pH are measured. It is shown that the short-term effect of IFT reduction and long-term effect of wettability alteration toward neutral-wetness (due to change in the electric charge of the crude-oil/brine and calcite/brine) are the dominating recovery mechanisms. However, the oil recovery behavior of oil-wet cores is in the opposite direction of that of water-wet cores, which demonstrates the wettability dependency of the involved mechanisms. CA measurement shows that diluted sea water (dSW) has more ability to change wettability toward water-wetness. The zeta potential results show that as brine salinity reduces, both crude-oil and rock surfaces become more negatively charged. Therefore, the observed wettability alteration behavior with salinity reduction is attributed to larger repulsion between these surfaces at lower salinity. pH results suggest CO32- ions are responsible to make calcite surface more negative with diluting SW brine. The oil recovery behavior is also a strong function of the initial wetting state. SW brine, recovered less oil and experienced an earlier breakthrough in an initially oil-wet core compared to an initially water-wet core. Unlike the previous case, dSW experienced higher ultimate oil recovery and almost the same breakthrough time in an initially oil-wet core compared to an initially water-wet core. The superior performance of the low salinity water in an oil-wet core is a result of the wettability alteration toward more water-wetness which triggers more piston-like advancement.",7,7,3
Crude Oil,Wettability Alteration,"Chai, Rukuan; Liu, Yuetian; Liu, Qianjun; Gu, Wenhuan",Experimental and molecular dynamic simulation study on calcite-organic molecule-water interaction mechanism,Atomic force microscope; X-ray photoelectron spectroscopy; Molecular dynamic simulation; Calcite-organic molecule-water interaction; Bulk adsorption mechanism,FUNCTIONAL-GROUP ADSORPTION; WETTABILITY ALTERATION; CRUDE-OIL; CARBONATE; NITROGEN; ASPHALTENES; SCHEELITE; INTERFACE,"The mechanism of calcite-organic molecule-water interaction mechanism in oil-wet formation and alteration of carbonates is still ambiguous. This paper combines atomic force microscope (AFM), X-ray photoelectron spectroscopy (XPS) and molecular dynamic (MD) simulation to investigate the regularity and mechanism of calciteorganic molecule-water interaction at the molecular scale. First, the calcite-organic molecule-water interaction regularities, i.e., wettability alteration process, were studied using AFM, XPS and MD. AFM, XPS and MD results all demonstrated that acetic acid adsorbs stably on the calcite surface and can-not be displaced by water molecules, while the resistance to water displacement of the other three organic molecules decreased with decreasing molecular polarity. Subsequently, MD was used to analyze the calcite-organic molecule-water interaction mechanism from three perspectives, including the organic molecule-calcite interaction, the organic molecule-organic/water molecule interaction, and the effect of polar molecules. In the organic molecule-calcite interaction, the adsorption intensity of organic molecules on calcite surface decreases as their molecular polarity decreases. Stronger molecular polarity results in tighter adsorption layer and lower adsorption energy. In the organic molecule-organic/water molecule interaction, the interaction intensity increases as the polarity difference between the two molecules decreases. Larger polarity difference causes stronger miscibility and lower interaction energy. For polar molecules effect, the presence of polar molecules stabilizes the non-polar molecules adsorption and diminishes the displacement efficiency of water molecules. Consequently, this paper proposes the bulk adsorption mechanism to reasonably explain the wettability formation and alteration mechanism of calcite surface, which is of great importance for targeted enhanced oil recovery studies.",6,6,8
Crude Oil,Wettability Alteration,"Chen, Weidong; Schechter, David S.",Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs,,WETTABILITY ALTERATION; ADSORPTION; WET,"Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures. Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure. The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition. In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants. The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.",5,5,3
Crude Oil,Wettability Alteration,"Kondori, Javad; Miah, Mohammad Islam; Zendehboudi, Sohrab; Khan, Faisal; Heagle, Dru",Hybrid connectionist models to assess recovery performance of low salinity water injection,Low salinity water injection; Recovery factor; Smart tools; Statistical analysis; Variable ranking,ENHANCED OIL-RECOVERY; ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINES; REAL-TIME PREDICTION; WETTABILITY ALTERATION; COMPRESSIVE STRENGTH; POROUS-MEDIA; CRUDE-OIL; REGRESSION; RESERVOIRS,"The low salinity water injection (LSWI) is one of the emerging enhanced oil recovery techniques to improve both microscopic and macroscopic displacement efficiencies by creating a new streamline in petroleum reservoirs. While experimental studies are tedious, costly, and time-consuming, the smart connectionist tools are more reliable and cost-effective approaches to predict oil recovery factor (RF) without considerations of governing equations and physics behind production mechanisms in oil reservoirs. The main objective of this study is to investigate the data-driven model performance and variable contribution while predicting RF of LSWI processes. We introduce connectionist models using hybridized least squares support vector machine (LSSVM) with global optimization technique of coupled simulated annealing (CSA), and adaptive network-based fuzzy inference system (ANFIS). The extremely randomized tree or extra tree (ET) tool is also applied to forecast the RF and investigate the parameter contribution in the employed model. The model performance is examined using statistical parameters, including coefficient of determination, relative error, mean absolute percentage error, and mean squared error. According to the results, the ET and hybridized LSSVM-CSA models perform better than the ANFIS model in estimating RF. Utilizing the ET smart model, the total dissolved salts (TDS, ppm) is the most influential parameter, while the fluid injection rate has the minimum importance in the determination of RF. The current research confirms that LSSVM-CSA and ET techniques are able to obtain RF of LSWI with high accuracy and reliability, which can be used by researchers and engineers for better management of oil reservoirs under LSWI.",4,4,3
Crude Oil,Wettability Alteration,"Rafiei, Arsalan; Khamehchi, Ehsan",Design of smart water composition based on scale minimization and its effect on wettability alteration in the presence of nanoparticles and mineral scales,Smart water; Nanoparticles; Wettability alteration; Scale deposition,LOW-SALINITY WATER; BRINE COMPOSITION; FINES MIGRATION; OIL-RECOVERY; CRUDE-OIL; IONS,"Smart Water (SW) injection is one of the most popular and inexpensive methods of FOR in sandstone and carbonate reservoirs. By modifying water chemistry with changes in salinity and composition optimization, we can obtain the appropriate smart water composition. So finding the optimal composition of smart water is one of the essential parts of its operations in reservoirs. On the other hand, due to the numerous applications of nanoparticles in the petroleum industry, the most critical part of nanofluids is the dispersion and stabilization of nanoparticles in the fluid. In this paper, a comprehensive study has been conducted on optimizing the composition of smart water based on scale formation and obtaining the optimum composition of the ions. Numerous experiments have been carried out to stabilize the nanoparticles in the optimized water composition under reservoir temperature, and the effect of each parameter has been determined. Also, the impact of optimized smart water on wettability alteration compared with other compositions has been reported. The effect of dispersed nanoparticles on wettability alteration in different Smart Water compositions was also shown. According to the results of this paper, the incompatibility of smart water and formation water can affect the purpose of injecting smart water, such that water containing the least scale due to incompatibility has the most significant effect on wettability alteration. Also, smart water composition that was incompatible with formation water has reduced the wettability alteration. Moreover, the presence of nanoparticles can slow down the process of wettability alteration. Thus, the presence of nanoparticles in injected water has reduced the hydrophilicity of rock.",4,4,0
Crude Oil,Wettability Alteration,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Crude Oil,Wettability Alteration,"Afekare, Dayo; Garno, Jayne; Rao, Dandina",Enhancing oil recovery using silica nanoparticles: Nanoscale wettability alteration effects and implications for shale oil recovery,Nanofluid; Enhanced oil recovery; Atomic force microscope; Wettability; Nanoparticle; Tuscaloosa marine shale,PHASE-BEHAVIOR; ADHESION; ADSORPTION; PRESSURE; CONTACT; CURVES; CORES; FINES,"Enhanced oil recovery (EOR) techniques have the potential to improve recovery in unconventional shale oil reservoirs which have prolific short-term success but elusive near-to-long term outlook. The use of silicon dioxide nanoparticles for enhancing shale oil recovery has recently gained significant attention in the oil industry. However, the technique remains novel partly due to inadequate fundamental understanding of oil release mechanisms. Herein, the oil recovery potential of untreated and treated silica nanoparticles is investigated using an atomic force microscope (AFM) by studying nanoscale interactions between different crude oil functional species and substrates of pure minerals found in a shale oil reservoir. Quartz and muscovite mica (clay substitute) were employed as substrates as these are the dominant rock minerals identified in the most productive zone of Tuscaloosa Marine Shale (TMS). Thiolates of undecane (CH3) and phenyl (C6H5) compounds were used to simulate alkane and aromatic fractions of TMS crude oil respectively, while undecanoic acid (COOH) thiol was used to represent carboxylic acid found in asphaltene and resin components. Following our in-house experimental protocol for liquid cell force spectroscopy, adhesion forces and surface energies between functionalized AFM probes and mineral substrates were characterized in untreated and amino-treated silica nanoparticle dispersions. Zeta potential of respective nanofluid solutions was measured and AFM adsorption data were supported with scanning electron microscope (SEM) micrographs of TMS rock samples. Results showed that aqueous dispersions of hydrophilic silicon dioxide nanoparticles promote wettability towards a less oil-wet state by significantly lowering the adhesion force and energy barrier to spontaneously detach oil molecules from clay and quartz mineral surfaces in shale reservoirs, shown at the nanoscale with AFM studies. However, the grafting of aminosilanes onto surfaces of silica nanoparticles generally increased adhesion forces and surface energies due to surface charge effect and hydrophobicity. Findings pertinent to nanoparticle silanization were consistent in molecular interactions on mica in nanofluids but not necessarily predictable with quartz surfaces, highlighting mineralogical effects. The irreversible adsorption of silica nanoparticles was also observed. Adhesion force and energy are resolved in various intermolecular forces such as electric double layer repulsion, non-electrostatic interaction and structural forces. The scientific significance and broad engineering implications of results were comprehensively discussed in the context of previously reported core-to-field scale observations of nanofluid EOR. This study pitches new light on the scientific understanding of silica-based nanofluid EOR by probing nanoscale wetting effects of silica nanoparticles with implications for shale oil recovery. The findings herein can help for better understanding of the design of nanofluid EOR reagents and the conditions that favor application of silica nanofluid EOR.",3,3,8
Crude Oil,Wettability Alteration,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Crude Oil,Wettability Alteration,"Ali, Hassan; Soleimani, Hassan; Yahya, Noorhana; Khodapanah, Leila; Kozlowski, Gregory; Sabet, Maziyar; Demiral, Birol M. R.; Adebayo, Lawal Lanre; Hussain, Tanvir",Experimental investigation and two-phase flow simulation of oil and nanofluids on micro CT images of sandstone for wettability alteration of the system,Capillary pressure; Oil reservoir; Porous media; Permeability; Oil saturation,PORE NETWORK MODEL; POROUS-MEDIA; PERMEABILITY; TRANSPORT; WATER; MIGRATION; BRINE,"This work provides an analysis of the effect of nanofluids on the wettability of sandstone for the application of enhanced oil recovery. The wettability of sandstone with brine and nanofluids of ZnO, BiFeO3, and SrFeO3 is studied experimentally using contact angle calculations. Also, the direct simulations for the displacement of oil with brine and nanofluids are carried out on a micro-CT scanned porous sandstone structure for the measurement of capillary pressure and relative permeability. Fluid properties such as viscosity and density of the nanofluids, brine, and oil to be used in simulations were obtained using viscometer and densimeter. The experimental results show that the contact angle of crude oil on the sandstone surface has a higher value for nanofluids as 125.89 degrees for ZnO, 122.88 degrees for BiFeO3, and 104.98 for SrFeO3 as compared to brine 28.66 degrees, which means the wettability of the system changes from oil-wet to water-wet by the addition of nanofluids. The simulation results indicate that BiFeO3 nanofluid has a greater tendency to change the wettability of porous medium as compared to brine, ZnO, and SrFeO3 nanofluids, as it shows better values of relative permeability and capillary pressure.",3,3,5
Crude Oil,Wettability Alteration,"Seetharaman, Gomathi Rajalakshmi; Jadhav, Rohan M.; Sangwai, Jitendra S.",Effect of monovalent and divalent alkali [NaOH and Ca(OH)(2)] on the interfacial tension of pure hydrocarbon-water systems relevant for enhanced oil recovery,Alkali; Hydrocarbons; Hydroxide ions; Interfacial tension; Temperature,SURFACE-TENSION; WETTABILITY ALTERATION; IONIC LIQUIDS; ASP; HYDROXIDE; IMIDAZOLIUM; SALINITY; BEHAVIOR; SALTS,"Although various efficient enhanced oil recovery (EOR) techniques have been proposed, the use of chemicals such as alkali, surfactants, and polymer in the field of EOR makes chemical EOR a promising method. The residual oil left behind after the secondary recovery process can be successfully displaced by decreasing the interfacial tension (IFT) between the liquid-liquid systems. Moreover, understanding the IFT between the liquid-liquid systems are essential in formulating and controlling the multiphase and multicomponent processes. As crude oil is a complex mixture of organic, inorganic compounds and heteroatoms, understanding the IFT of the pure hydrocarbon-water system is vital to develop robust models. In this study, the IFT between pure hydrocarbon-water systems in the presence of alkali has been explored. The IFT measurements were performed using a dynamic contact angle tensiometer using a Wilhelmy plate. Different hydrocarbon liquids such as hexane, heptane, decane and aromatics such as benzene and toluene were used. The monovalent NaOH and divalent alkali Ca(OH)(2) in the concentration range of 0-37.5 mM are used to understand the effect of alkali on the IFT of the oil-water system. This paper also elaborates on the effect of temperature at 298.15 K, 323.15 K and 348.15 K on the IFT of hydrocarbon-water systems. The experimental results show that the increase in the concentration of alkali continuously decreased the IFT of hydrocarbon-water systems. Moreover, it has been found that the type of alkali also has a reasonable impact on the IFT of the hydrocarbon-water system. The divalent alkali [Ca(OH)(2)] is found to be more efficient in reducing the IFT of both alkane-water and aromatic-water systems than the moderately performed monovalent alkali (NaOH). The possible mechanism for the continuous reduction in IFT has been proposed using surface adsorption of hydroxide ions at the interface of the oil-water system.",3,3,3
Crude Oil,"Low Salinity,Low-salinity Water","Farhadi, Hamed; Ayatollahi, Shahab; Fatemi, Mobeen","The effect of brine salinity and oil components on dynamic IFT behavior of oil-brine during low salinity water flooding: Diffusion coefficient, EDL establishment time, and IFT reduction rate",Dynamic interfacial tension; Crude-oil/brine system; Time dependent adsorption; Low salinity effect; Asphaltene,INTERFACIAL-TENSION; WETTABILITY ALTERATION; CAPILLARY-PRESSURE; SURFACE-PROPERTIES; ADSORPTION; RECOVERY; SANDSTONE; RESERVOIR; ASPHALTENES; ELECTRONS,"Dynamic behavior of fluid-fluid interactions can potentially affect the performance of any enhanced oil recovery (EOR) process including low salinity water flooding. In this work, dynamic interfacial tension (IFT) of crude-oil/brine system is measured in a wide range of salinity of sea water (SW), from 50-time diluted sea water (SW50D) to 2-time concentrated sea water (SW2C). Contrary to the most of published IFT trends in the literature, for the system under investigation here, as the brine salinity increases the crude-oil/brine IFT reduces, which cannot be explained using the existing theories. The lack of a physical model to explain the observed phenomena was the motivation to develop a new model based on a drift-diffusion theory. This theory considers a current of oil polar molecules toward the oil-water interface which is caused by electrostatic attraction from aqueous ions (drift) and a resistance against this current caused by concentration gradient (diffusion). After applying this model to measured dynamic IFT data, the IFT reduction rate, and electrical double layer (EDL) establishment time are calculated. Then, these matching parameters set as criteria to explain the mechanisms behind the dynamic behavior of crude oil-saline water interfacial tension. For further investigation of the involved mechanisms which are responsible for the macroscopic behavior of crude-oil/brine dynamic IFT, the role of oil components is also examined using the IFT reduction rate and EDL establishment time. Although the obtained results show the asphaltene molecules play a vital role in the dynamic IFT behavior, the concentration of n-heptane, in the model oil containing n-heptane and toluene, is essential to capture the IFT behavior of the crude oil. Increasing n-heptane fraction in the model oil to the amount which exist in the crude oil, results in longer EDL establishment time which is in agreement with the crude oil sample.",11,11,1
Crude Oil,"Low Salinity,Low-salinity Water","Siadatifar, Seyed Emad; Fatemi, Mobeen; Masihi, Mohsen",Pore scale visualization of fluid-fluid and rock-fluid interactions during low-salinity waterflooding in carbonate and sandstone representing micromodels,Low salinity waterflooding (LSWF); Microfluidics; Fluid/fluid interactions; Rock/fluid interactions; Visco-elastic interface,OIL-RECOVERY; WATER; MECHANISMS; SURFACE; DIFFUSION; OIL/WATER; WET,"Low Salinity Waterflooding (LSWF) has become a popular tertiary injection EOR method recently. Both fluid-fluid and fluid-rock interactions are suggested as the contributing mechanisms on the effectiveness of LSWF. Considering the contradictory remarks in the literature, the dominating mechanisms and necessary conditions for Low Salinity Effect (LSE) varies for different crude oil-brine-rock (CBR) systems. The aim of the present study is to investigate LSE for an oil field in the Middle East that is composed of separate sandstone and limestone layers. Contact angles and Interfacial Tension (IFT) are measured to have more insight on the CBR under investigation. Visual experiments were conducted in micromodels to determine the dominating mechanisms of LSE. Experiments were conducted under water-wet and oil-wet conditions for both sandstone and limestone representing micromodels. Several secondary and tertiary injection scenarios were performed with different levels of salinities. Consecutive injection of high-salinity and low-salinity water illustrated that LSE occurs under certain conditions. For both rock types, during the secondary high salinity injection, the oil trapping mechanism was mostly snap-off under water-wet condition, while fingering/bypassing was dominant under oil-wet conditions. LSWF causes diminutive changes of saturation redistribution in water-wet micromodels. Even in rare occasions that oil ganglia started to reshape or redistribute, it became trapped again in the downstream pores of the model, and not produced effectively. Contrary to this, LSWF was very effective under oil-wetting conditions. Continuous oil films, which exist in oil-wet condition, are beneficial for the effectiveness of LSE. Measured IFT and contact angles cannot justify the observed LSE. Additionally in the designed micromodels, any contribution of clay or fine migration to the LSE is ruled out. Spontaneous formation of the micro-emulsion was a very weak mechanism in our experiments and did not contribute to pushing oil out of the dead end pores or divert the flow path to the un-swept areas. Visual investigations suggested that formation of the visco-elastic interface can be the dominating mechanism for LSE in the investigated CBRs which is more effective in the case of oil-wet system due to the lack of snap-off trapping mechanism.",10,10,3
Crude Oil,"Low Salinity,Low-salinity Water","Tetteh, Joel T.; Cudjoe, Sherifa E.; Aryana, Saman A.; Ghahfarokhi, Reza Barati",Investigation into fluid-fluid interaction phenomena during low salinity waterflooding using a reservoir-on-a-chip microfluidic model,Low salinity waterflooding; Microfluidics; Fluid-fluid interaction; Snap-off effect; Water-in-oil microdispersions,OIL-RECOVERY; CRUDE-OIL/BRINE; LIQUID-FILMS; SNAP-OFF; WATER; NANOPARTICLES; MECHANISMS; INTERFACE; FOAM; FLOW,"Injection of modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks has proven to be relevant to improved oil recovery operations. Many reports in the literature related the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which caused wettability alterations at the rock surface. Little attention appears to have been paid to fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigated the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations were correlated to visual observations of displacement processes in order to investigate the role of crude oil snap-off. Microfluidic devices featuring pore throats 50 mu m in diameter were used to observe snap-off as a function of salinity of the displacing fluid. Flow experiments suggested that, in a water-wet constricted pore throat, SWS brines suppressed crude oil snap-off as compared to formation water brine (FWS) brine. This behavior was correlated to the higher surface elasticity of oil-SWS interfaces than that of oil-FWS interfaces. Higher surface elasticity suppressed the expansion of the thin water film coating pore throat walls and hence it increased the capillary number at which snap-off of the crude oil phase was expected to occur. Moreover, water interacted with the polar components to form reverse micelles called microdispersions. These microdispersions were observed in both aged and non-aged microfluidic devices near oil-brine interfaces in the pore-network. Similarly, in a vial test performed by Tetteh and Barati (2019), microdispersion formation was only observed very close to oil-brine interfaces, caused by transport of water molecules into the oil phase due to reduced intermolecular forces at oil-LSW interfaces. This microdispersion formation was visualized using environmental scanning electron microscopy. These microdispersions remobilized, redistributed the oil, and along with a slight change in wettability in the medium, they improved the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributed to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.",9,10,5
Crude Oil,"Low Salinity,Low-salinity Water","Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Crude Oil,"Low Salinity,Low-salinity Water","Saadat, Marzieh; Yang, Junyi; Dudek, Marcin; Oye, Gisle; Tsai, Peichun Amy",Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability,Wettability alteration; Microfluidics; Surfactant flooding; Oil recovery; Enhanced oil recovery; Low salinity water flooding,LOW-SALINITY WATER; CRUDE-OIL; FINES MIGRATION; PHASE-BEHAVIOR; SURFACTANT; WET; DISPLACEMENT; EOR; ADSORPTION; SULFONATE,"Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.",8,9,11
Crude Oil,"Low Salinity,Low-salinity Water","Zhang, Kun; Liu, Rong; Liu, Zhaojun","Sedimentary sequence evolution and organic matter accumulation characteristics of the Chang 8-Chang 7 members in the Upper Triassic Yanchang Formation, southwest Ordos Basin, central China",Sedimentary environment; Paleoclimate; Organic matter accumulation; Yanchang formation; Ordos basin,SILURIAN LONGMAXI FORMATION; DEVONIAN DUVERNAY FORMATION; TIGHT SANDSTONE RESERVOIRS; GEOCHEMICAL CHARACTERISTICS; DEPOSITIONAL ENVIRONMENT; BLACK SHALES; OIL-SHALE; STRATIGRAPHIC ANALYSIS; ELEMENT GEOCHEMISTRY; MARCELLUS FORMATION,"Lacustrine organic-rich shales are widely developed in the Chang 7 member of the Yanchang Formation in the Ordos Basin. These shales have been proven to be the source rocks for crude oil and shale oil. The study of sedimentary evolution and the characteristics of organic matter (OM) accumulation is an important factor for the exploration and development of oil and gas resources. Based on the lithological assemblages, lithofacies, mineral contents, log curves and geochemical data, the sequence stratigraphic framework of the Chang 8-Chang 7 members of the Yanchang Formation in the southern margin of the Ordos Basin were established. A complete third-order sequence was identified, and it included four systems tracts: a lowstand systems tract (LST), a transgressive systems tract (TST), a highstand systems tract (HST) and a regressive systems tract (RST). By using organic petrology, organic geochemistry and elemental geochemistry, the abundance and source of OM, paleoclimate, paleowater conditions, paleoproductivity, and deposition rates of the different systems tracts of the Chang 8-Chang 7 are studied in detail. Various factors controlled the accumulation of OM in the different systems tracts. The abundance of OM in the LST is low, the kerogen type is mainly type III (including vitrinite); the abundance of OM increased gradually in the TST, the kerogen types are III and II2 (including vitrinite and sporophyte); the OM is mainly concentrated in the HST, and the kerogen type is mainly type ID (including alginite), biomarker compounds show that OM has a mixed source of land plant and planktonic material; the abundance of OM in the RST is relatively high, the kerogen type is mainly type II2 and III (including vitrinite and alginite). The main controlling factor for OM accumulation was paleoclimate, which affected the primary productivity of lake and the chemical properties of the water column (redox and paleosalinity), leading to differences in OM accumulation under different climatic conditions. Hydrothermal activities contributed to anoxia and a salinity increase in lake bottom waters, with volcanic ash providing large amounts of essential nutrients for algal blooms. Based on the V/Cr, Sr/Ba, P/Ti and (La/Yb)(N) ratios with TOC values, the abundance of OM is positively correlated with paleoproductivity and water column reducibility, and negatively correlated with paleosalinity. The abundance of OM first increases and then decreases with increasing sedimentation rate. In general, the accumulation of OM was promoted under warm and humid climates, anoxic fresh to brackish water and adequate paleoproductivity.",8,8,9
Crude Oil,"Low Salinity,Low-salinity Water","Farhadi, Hamed; Fatemi, Mobeen; Ayatollahi, Shahab",Experimental investigation on the dominating fluid-fluid and rock-fluid interactions during low salinity water flooding in water-wet and oil-wet calcites,Low salinity water flooding; Enhanced oil recovery; Carbonate rock wettability alteration; Dynamic interfacial tension; Dynamic contact angle; Surface electric charges,INTERFACIAL INTERACTIONS; TENSION; RESERVOIR,"Low salinity water flooding (LSWF) has the potential to enhance the oil recovery by affecting the fluid-fluid and rock-fluid interactions. Therefore, a systematic investigation on the effect of initial wetting state (water-wet or oil-wet) of pure calcite is conducted to study the importance of these interactions on the effectiveness of LSWF. In the case of initially water-wet cores, more oil recovery efficiency is observed for more saline water cases. To shed light on the possible involved mechanisms, dynamic IFT, dynamic contact angle (CA), oil/brine and rock/brine surfaces zeta potentials, and effluent pH are measured. It is shown that the short-term effect of IFT reduction and long-term effect of wettability alteration toward neutral-wetness (due to change in the electric charge of the crude-oil/brine and calcite/brine) are the dominating recovery mechanisms. However, the oil recovery behavior of oil-wet cores is in the opposite direction of that of water-wet cores, which demonstrates the wettability dependency of the involved mechanisms. CA measurement shows that diluted sea water (dSW) has more ability to change wettability toward water-wetness. The zeta potential results show that as brine salinity reduces, both crude-oil and rock surfaces become more negatively charged. Therefore, the observed wettability alteration behavior with salinity reduction is attributed to larger repulsion between these surfaces at lower salinity. pH results suggest CO32- ions are responsible to make calcite surface more negative with diluting SW brine. The oil recovery behavior is also a strong function of the initial wetting state. SW brine, recovered less oil and experienced an earlier breakthrough in an initially oil-wet core compared to an initially water-wet core. Unlike the previous case, dSW experienced higher ultimate oil recovery and almost the same breakthrough time in an initially oil-wet core compared to an initially water-wet core. The superior performance of the low salinity water in an oil-wet core is a result of the wettability alteration toward more water-wetness which triggers more piston-like advancement.",7,7,3
Crude Oil,"Low Salinity,Low-salinity Water","Wang, Yamin; Yu, Muhan; Bo, Zhenkai; Bedrikovetsky, Pavel; Le-Hussain, Furqan",Effect of temperature on mineral reactions and fines migration during low-salinity water injection into Berea sandstone,Temperature; Ion exchange reaction; Permeability decrease; Fines migration; Low-salinity water injection; Water disposal,OIL-RECOVERY; ION-EXCHANGE; MATHEMATICAL-MODEL; BRINE COMPOSITION; RESERVOIR ROCKS; SLOW MIGRATION; 2-PHASE FLOW; CRUDE-OIL; DISSOLUTION; PERMEABILITY,"Recent experiments on sandstone rocks found more fines migration at higher temperature. They attributed this to temperature-dependent zeta potential. However, temperature also affects mineral reactions. The present study investigates the effect of temperature on both fines migration and mineral reactions. Two sets of single-phase injection experiments are performed using Berea sandstone sister plugs. In one set of experiments, solutions of NaCl brine are injected at a constant temperature of 25 ?C, 50 ?C, or 70 ?C. In the other set, solutions of CaCl2 brine are injected at a constant temperature of 25 ?C or 50 ?C. All plugs are subjected to five sequential injections of the designated brine at salinities 0.684 mol/L, 0.171 mol/L, 0.043 mol/L, 0.0085 mol/L, and 0 mol/L. Permeability at each injection stage is calculated from pressure difference across the core. When NaCl brine is used, the percentage of permeability decrease is found to be 99% at 25 ?C, 90% at 50 ?C, and 40% at 70 ?C. The lower permeability decrease at high temperature is found to be accompanied by a smaller concentration of produced fines. Comparison of scanning electron microscope images taken before and at the end of each experiment shows pore enlargement due to mineral reaction at high temperature, which further explains the lower permeability decrease. Ionic concentrations of Ca2+ and Mg2+ in the produced water are found to be greater at higher temperature, due to higher reaction rate. With CaCl2 brine, a 7% permeability decrease is observed at 25 ?C, whereas a 20% permeability increase is observed at 50 ?C. The observed fines concentration and increase in Ca2+ ion production are found to be lower than with NaCl brine, which is attributed to ion exchange between Na+ and Ca2+ with NaCl brine. Temperature affects both (1) permeability increase due to pore enlargement caused by mineral reactions, and (2) permeability decrease due to fines migration.",5,5,1
Crude Oil,"Low Salinity,Low-salinity Water","Kondori, Javad; Miah, Mohammad Islam; Zendehboudi, Sohrab; Khan, Faisal; Heagle, Dru",Hybrid connectionist models to assess recovery performance of low salinity water injection,Low salinity water injection; Recovery factor; Smart tools; Statistical analysis; Variable ranking,ENHANCED OIL-RECOVERY; ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINES; REAL-TIME PREDICTION; WETTABILITY ALTERATION; COMPRESSIVE STRENGTH; POROUS-MEDIA; CRUDE-OIL; REGRESSION; RESERVOIRS,"The low salinity water injection (LSWI) is one of the emerging enhanced oil recovery techniques to improve both microscopic and macroscopic displacement efficiencies by creating a new streamline in petroleum reservoirs. While experimental studies are tedious, costly, and time-consuming, the smart connectionist tools are more reliable and cost-effective approaches to predict oil recovery factor (RF) without considerations of governing equations and physics behind production mechanisms in oil reservoirs. The main objective of this study is to investigate the data-driven model performance and variable contribution while predicting RF of LSWI processes. We introduce connectionist models using hybridized least squares support vector machine (LSSVM) with global optimization technique of coupled simulated annealing (CSA), and adaptive network-based fuzzy inference system (ANFIS). The extremely randomized tree or extra tree (ET) tool is also applied to forecast the RF and investigate the parameter contribution in the employed model. The model performance is examined using statistical parameters, including coefficient of determination, relative error, mean absolute percentage error, and mean squared error. According to the results, the ET and hybridized LSSVM-CSA models perform better than the ANFIS model in estimating RF. Utilizing the ET smart model, the total dissolved salts (TDS, ppm) is the most influential parameter, while the fluid injection rate has the minimum importance in the determination of RF. The current research confirms that LSSVM-CSA and ET techniques are able to obtain RF of LSWI with high accuracy and reliability, which can be used by researchers and engineers for better management of oil reservoirs under LSWI.",4,4,3
Crude Oil,"Low Salinity,Low-salinity Water","Rafiei, Arsalan; Khamehchi, Ehsan",Design of smart water composition based on scale minimization and its effect on wettability alteration in the presence of nanoparticles and mineral scales,Smart water; Nanoparticles; Wettability alteration; Scale deposition,LOW-SALINITY WATER; BRINE COMPOSITION; FINES MIGRATION; OIL-RECOVERY; CRUDE-OIL; IONS,"Smart Water (SW) injection is one of the most popular and inexpensive methods of FOR in sandstone and carbonate reservoirs. By modifying water chemistry with changes in salinity and composition optimization, we can obtain the appropriate smart water composition. So finding the optimal composition of smart water is one of the essential parts of its operations in reservoirs. On the other hand, due to the numerous applications of nanoparticles in the petroleum industry, the most critical part of nanofluids is the dispersion and stabilization of nanoparticles in the fluid. In this paper, a comprehensive study has been conducted on optimizing the composition of smart water based on scale formation and obtaining the optimum composition of the ions. Numerous experiments have been carried out to stabilize the nanoparticles in the optimized water composition under reservoir temperature, and the effect of each parameter has been determined. Also, the impact of optimized smart water on wettability alteration compared with other compositions has been reported. The effect of dispersed nanoparticles on wettability alteration in different Smart Water compositions was also shown. According to the results of this paper, the incompatibility of smart water and formation water can affect the purpose of injecting smart water, such that water containing the least scale due to incompatibility has the most significant effect on wettability alteration. Also, smart water composition that was incompatible with formation water has reduced the wettability alteration. Moreover, the presence of nanoparticles can slow down the process of wettability alteration. Thus, the presence of nanoparticles in injected water has reduced the hydrophilicity of rock.",4,4,0
Crude Oil,"Low Salinity,Low-salinity Water","Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Crude Oil,"Low Salinity,Low-salinity Water","Mahmoudvand, Mohsen; Javadi, Aliyar; Pourafshary, Peyman; Vatanparast, Hamid; Bahramian, Alireza",Effects of cation salinity on the dynamic interfacial tension and viscoelasticity of a water-oil system,Crude oil; Brine; Dynamic interfacial tension; Salinity concentration; Asphaltene; Monolayer; Viscoelasticity; Low salinity water; Smart water; Enhanced oil recovery,SALTING-OUT; ADSORPTION-KINETICS; SMART WATER; OIL/WATER INTERFACE; SURFACE-TENSION; ASPHALTENES; RECOVERY; INJECTION; DISSOLUTION; ASSOCIATION,"This experimental study aims to obtain insights into the effect of brine salinity on the dynamic interfacial tension (IFT) and interfacial behavior of a water-oil system. The effects of monovalent and divalent cations (Na+, Ca2+, and Mg2+) in a salinity range of 0.01-0.1 mol/l on the equilibrium and dynamic interfacial tension of the wateroil system are studied using pendant drop experiments. To understand the adsorbed layer of surface active components (asphaltene and resin) at the interface, surface dilational elasticity is also studied. The results reveal that the types of the ions, salinity concentration, and type of the surface-active components in the crude oil, are dominant parameters that affect the interfacial properties. Divalent cations especially Mg2+ show a much stronger interaction with surface-active components at the brine-oil interface while monovalent cations have a negligible effect. The IFT of the water-oil system decreases in the presence of salts up to a minimum point and a further increase in the salinity leads to an increment in the IFT. The effect of salinity on the formation of asphaltene and resin components at the drop surface is studied by employing surface area compression experiments. When asphaltene components are at the interface, the drop profile shows a sharp increase in standard deviation from Laplacian form at the closely-packed state, while for maltene (deasphalted oil), no rise is observed in the standard deviation values. The closely-packed state and the asphaltene layer collapse happen at an earlier time with increasing salt concentration up to an optimum point due to the presence of the higher amount of complexes at the interface.",3,3,2
Crude Oil,Surfactant,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Crude Oil,Surfactant,"Saadat, Marzieh; Yang, Junyi; Dudek, Marcin; Oye, Gisle; Tsai, Peichun Amy",Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability,Wettability alteration; Microfluidics; Surfactant flooding; Oil recovery; Enhanced oil recovery; Low salinity water flooding,LOW-SALINITY WATER; CRUDE-OIL; FINES MIGRATION; PHASE-BEHAVIOR; SURFACTANT; WET; DISPLACEMENT; EOR; ADSORPTION; SULFONATE,"Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.",8,9,11
Crude Oil,Surfactant,"Onaizi, Sagheer A.; Alsulaimani, Mohammed; Al-Sakkaf, Mohammed K.; Bahadi, Salem A.; Mahmoud, Mohamed; Alshami, Ali",Crude oil/water nanoemulsions stabilized by biosurfactant: Stability and pH-Switchability,Crude oil/water nanoemulsions; Emulsion stability; Rhamnolipid biosurfactant; pH-responsive; Demulsification; Droplet size,OIL-IN-WATER; INTERFACIAL-TENSION; POROUS-MEDIA; SURFACTIN BIOSURFACTANT; SILICA NANOPARTICLES; RECOVERY; EMULSIONS; EMULSIFICATION; COMBINATION; BACTERIA,"Emulsification is one of the proposed mechanisms for enhancing crude oil recovery in chemical flooding. The replacement of chemical surfactants in enhanced oil recovery (EOR) applications with biosurfactants is an attractive alternative; yet, there is a lack of studies on the crude oil emulsification using biosurfactants. Particularly, the formulation of crude oil/water (crude O/W) nanoemulsions with an extreme stability and a pH-responsiveness behavior is still not documented in the literature, to the best of our knowledge. Accordingly, we report in this study the preparation of both light and heavy crude oil/water emulsions using different concentrations of the rhamnolipid biosurfactant. The emulsions were prepared in a two-step process: stirring overnight to create coarse emulsions followed by sonication. All the prepared emulsions have a nanoscale size (e.g., about 50% of the formed droplets at 0.1 wt% rhamnolipid are < 200 nm in size), which decreases with increasing the biosurfactant concentration. The zeta potential values of the formed crude O/W nanoemulsions were highly negative (<=-39.3). Increasing the biosurfactant concentration resulted in a more negative zeta potential. The formulated crude O/W nanoemulsions were extremely stable with 0% oil or water separation even after a month of storage. Despite the extreme stability of these crude O/W nanoemulsions, they could be easily switched off (i. e., demulsified) within 1 h by pH-swing via the addition of 50 mM sulfuric acid (H2SO4) regardless of the bioemulsifier (i.e., rhamnolipid) concentration. It was also possible to switch on/off the crude O/W nanoemulsions a number of times (at least five times) through this pH-swing mechanism. We also demonstrated that the crude O/W nanoemulsions can be completely switched off through the addition of NaOH, particularly, when these crude O/W nanoemulsions are stabilized by low rhamnolipid dosages (<= 0.5 wt%); such an observation is very unusual. The findings reported in this study clearly demonstrate the ability of creating extremely stable crude O/W nanoemulsions, which is desirable in EOR; however, the emulsified crude oil can be easily and economically recovered via a simple and an economic process (i.e., pH-switch) with the ability to switch off/on the emulsion several times.",7,7,6
Crude Oil,Surfactant,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Crude Oil,Surfactant,"Elmobarak, Wamda F.; Almomani, Fares",Application of magnetic nanoparticles for the removal of oil from oil-in-water emulsion: Regeneration/reuse of spent particles,Oil-in-water emulsion (O-in-W-Emu); Fe3O4 magnetic nanoparticles; Demulsification efficiency; Oil removal,IRON-OXIDE NANOPARTICLES; SOLUTION-COMBUSTION SYNTHESIS; WASTE-WATER; FE3O4 NANOPARTICLES; HYDROTHERMAL SYNTHESIS; EFFICIENT SEPARATION; EPITAXIAL-FILMS; CRUDE-OIL; ADSORPTION; FACILE,"The recovery of oil from produced water (PW) is integral for minimizing energy resource loses and creating an appropriate treatment method for a sustainable environment. In this study, Fe3O4 magnetic nanoparticles (Fe-MNP) were synthesized using the combustion synthesis method (CSM) in the temperature range of 150 to 350 degrees C. The Fe-MNP were characterized using various analytical techniques and were used to recover oil from oil-inwater emulsion (O-in-W-emu) at various concentrations. The effects of the process parameters including, pH, oil concentration (C-oil), Fe-MNP dose (D-MNP), the surfactant concentration (C-sur) on the demulsification efficiency (%(eta dem)), and the percentage oil removal (%R-oil) were studied. Further, the re-usability of the assynthetized Fe-MNP were examined and reported. The as-synthetized Fe-MNP achieved a %(eta dem) >= 98% for C-oil in the range of 200-660 mg/L. Up to 98.6% of the %(eta dem) was attained for C-oil in the range from 0 to 800 mg/L using only a DMNP of 10 mg/L. A lower D-MNP of 5 mg/L recovered up to 55.6% of the oil, while increasing the D-MNP > 50 mg/L did not significantly affect the %(eta dem) nor the %(eta dem). The observed %(eta dem) at a pH of 4 and C-sur of 0.05 g/L was observed to be > 90 + 0.1% and decreased by either rising the pH to 7 or increasing the C-sur to 0.1 g/L. This change is due to the decrease in the emulsion stability and the formation of fine oil droplets. Stability and re-usability tests of the as-synthetized Fe-MNP exhibited an effective oil recovery of up to 90% after 7 cycles. The as-synthesized Fe-MNP demulsifier exhibited an excellent adsorption capacity of 51 mg/g and best fit the Langmuir and Freundlich models. The kinetics of the oil recovery process are properly adapted to fit the pseudosecond-order model for the C-oil and D-MNP. The tests indicated that the fastest and highest adsorption capacity was achieved at a D-MNP (100 mg/L). As such, the results indicate that the developed Fe-MNP are an effective and reusable demulsifier, which are suitable for the oil recovery of produced water (PW).",5,5,7
Crude Oil,Surfactant,"Chen, Weidong; Schechter, David S.",Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs,,WETTABILITY ALTERATION; ADSORPTION; WET,"Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures. Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure. The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition. In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants. The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.",5,5,3
Crude Oil,Surfactant,"Ge, Meng-Ru; Miao, Si-Jia; Liu, Jin-Feng; Gang, Hong-Ze; Yang, Shi-Zhong; Mu, Bo-Zhong",Laboratory studies on a novel salt-tolerant and alkali-free flooding system composed of a biopolymer and a bio-based surfactant for oil recovery,Biopolymer/surfactant formula; Ultra-low interfacial tension; Enhanced oil recovery; Salt-tolerant; Alkali-free,HIGH-TEMPERATURE; WELAN GUM; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; NONIONIC SURFACTANT; ASSOCIATING POLYMER; AQUEOUS WELAN; XANTHAN GUM; STRAIN; POLYSACCHARIDES,"Alkali/surfactant/polymer (ASP) flooding is one of the most effective tertiary oil recovery technologies. However, the formation of an alkali scale potentially results in the reduction of the formation permeability and pipeline corrosion, which affect its industrial application. Recently, the surfactant/polymer (SP) flooding system in the absence of alkali has received increasing attention. Here, we screened a high-yielding strain, which is capable of producing salt-tolerant biopolymer. The results of rheological properties evaluation showed that this biopolymer possessed a stable viscosity at high salinities (up to 200 g/L NaCl, 100 g/L Ca2+, and 100 g/L Mg2+) and a wide range of pH (4-11), indicating its superior salt and pH resistance. Based on these properties, a novel salt-tolerant and alkali-free binary flooding system was constructed with this biopolymer and bio-based surfactant newly synthesized in our lab. The ultra-low interfacial tension (IFT) between crude oil and the binary system containing 0.5 wt % biopolymer and 1.00 g/L surfactant could be achieved in the presence of 100 g/L NaCl or 400 mg/L Ca2+. Moreover, it exhibited good resistance to oil sands adsorption, excellent anti-dilution, and ageing stability. These results indicate that the biopolymer produced by the Kosakonia oryzae strain possessed great potential in the construction of an alkali-free SP system for enhanced oil recovery (EOR) in high salinity and high temperature oil reservoirs.",4,4,5
Crude Oil,Surfactant,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Crude Oil,Surfactant,"Cao, Guangsheng; Du, Tong; Bai, Yujie; Yang, Tingyuan; Zuo, Jize",Effects of surfactant molecular structure on the stability of water in oil emulsion,Water-in-oil emulsifier; Surfactant; Molecular structure; Interfacial film; Hydrophobic group,CRUDE-OIL; HYDROCARBON EMULSIONS; INTERFACIAL RHEOLOGY; STABILIZATION; ASPHALTENES; BEHAVIOR,"The stability of a water-in-oil emulsion is the key to the water control technology for active crude oil, and different surfactants have direct influence on the emulsion properties. Thus, it is necessary to investigate the relationship between the molecular structure of surfactants and the stability of the crude oil emulsion. This study used emulsification experiments to investigate emulsion stability. In particular, the effects of the number of saturated alkyl carbon atoms on the lipophilic end, saturation of the alkyl chains and the number of hydrophobic branched-chains on the emulsion were analyzed with a viscometer, microscope and tensiometer. The results showed that longer hydrophobic monoalkyl chains produced more effective emulsifiers; however, unsaturated bonds on the hydrophobic alkyl chain or highly branched alkyl chains reduced the emulsifying effect.",3,3,5
Crude Oil,Surfactant,"Akhlaghi, Naser; Riahi, Siavash; Parvaneh, Ronak","Interfacial tension behavior of a nonionic surfactant in oil/water system; salinity, pH, temperature, and ionic strength effects",Triton X-100; IFT; CMC; Enhanced oil recovery; PH; Salinity,ENHANCED OIL-RECOVERY; ASSISTED GRAVITY DRAINAGE; ACIDIC CRUDE-OIL; WATER; IFT; WETTABILITY; BRINE; PERFORMANCE; ASPHALTENE; COMPONENTS,"Since most of the world's oil reservoirs are in the second half lifetime, the use of Enhanced Oil Recovery (EOR) methods is inevitable. Interfacial Tension (IFT) is one of the effective parameters on EOR can be changed by surfactants. But surfactant injection is one of the costly methods and chemistry of the surfactant solutions such as salinity (one and two valence ions) and pH should be engineered. Furthermore, the temperature is an effective parameter affecting on IFT. In this study, the effect of salinity, especially hard salinity, temperature and pH on IFT between Triton X-100 surfactant and an Iranian oil sample has been investigated. In order to, evaluate the effect of salinity, different concentrations of NaCl, CaCl2, MgCl2, and Na2SO4 salts (0, 0.1, 0.5, and 1 wt%) were used in different concentrations of surfactant. IFT results showed that magnesium and calcium divalent cations had a greater effect on IFT reduction than monovalent sodium cation. Also, all the studied cations were more effective than sulfate as a divalent anion. The ionic strength of the solutions was inversely proportional to the IFT amounts. Less value of IFT in the presence of magnesium ions than calcium ions was due to the higher ionic strength of solutions containing magnesium compared with calcium. IFT results at three temperatures (20, 40, and 60 degrees C) proved that by increasing temperature IFT increased. Also, the effect of pH on IFT in three pHs including acidic, almost neutral and alkaline in the presence of surfactant was studied. Results indicated that IFT decreased with increasing pH, especially in concentrations lower than critical micelle concentration (CMC).",3,3,4
Crude Oil,Surfactant,"Seetharaman, Gomathi Rajalakshmi; Jadhav, Rohan M.; Sangwai, Jitendra S.",Effect of monovalent and divalent alkali [NaOH and Ca(OH)(2)] on the interfacial tension of pure hydrocarbon-water systems relevant for enhanced oil recovery,Alkali; Hydrocarbons; Hydroxide ions; Interfacial tension; Temperature,SURFACE-TENSION; WETTABILITY ALTERATION; IONIC LIQUIDS; ASP; HYDROXIDE; IMIDAZOLIUM; SALINITY; BEHAVIOR; SALTS,"Although various efficient enhanced oil recovery (EOR) techniques have been proposed, the use of chemicals such as alkali, surfactants, and polymer in the field of EOR makes chemical EOR a promising method. The residual oil left behind after the secondary recovery process can be successfully displaced by decreasing the interfacial tension (IFT) between the liquid-liquid systems. Moreover, understanding the IFT between the liquid-liquid systems are essential in formulating and controlling the multiphase and multicomponent processes. As crude oil is a complex mixture of organic, inorganic compounds and heteroatoms, understanding the IFT of the pure hydrocarbon-water system is vital to develop robust models. In this study, the IFT between pure hydrocarbon-water systems in the presence of alkali has been explored. The IFT measurements were performed using a dynamic contact angle tensiometer using a Wilhelmy plate. Different hydrocarbon liquids such as hexane, heptane, decane and aromatics such as benzene and toluene were used. The monovalent NaOH and divalent alkali Ca(OH)(2) in the concentration range of 0-37.5 mM are used to understand the effect of alkali on the IFT of the oil-water system. This paper also elaborates on the effect of temperature at 298.15 K, 323.15 K and 348.15 K on the IFT of hydrocarbon-water systems. The experimental results show that the increase in the concentration of alkali continuously decreased the IFT of hydrocarbon-water systems. Moreover, it has been found that the type of alkali also has a reasonable impact on the IFT of the hydrocarbon-water system. The divalent alkali [Ca(OH)(2)] is found to be more efficient in reducing the IFT of both alkane-water and aromatic-water systems than the moderately performed monovalent alkali (NaOH). The possible mechanism for the continuous reduction in IFT has been proposed using surface adsorption of hydroxide ions at the interface of the oil-water system.",3,3,3
Crude Oil,Surfactant,"Mejia, Miguel; Parra, Jose E.; Mejia, Lucas; Pope, Gary A.; Balhoff, Matthew T.",Experiments and numerical simulations of chemical enhanced oil recovery in fractured carbonate rocks,Surfactant FOR; Fractured carbonates; Microemulsion phase behavior; Numerical simulation,SURFACTANT IMBIBITION; PERMEABILITY; SALINITY; DRAINAGE; PHASE; FLOW,"Secondary oil recovery from naturally fractured, oil wet carbonate reservoirs is challenging due to high permeability fractures and unfavorable capillary forces. A series of new tertiary surfactant coreflood experiments in fractured oil wet limestone cores were performed in which surfactants lowered the IFT and formed viscous microemulsions upon mixing with crude oil and brine. The viscous microemulsions cause favorable transverse pressure gradients that result in increased oil recovery. The effects of surfactant slug size, salinity and injection rate were investigated experimentally. In all cases, the injected surfactant solutions recovered significantly more oil than waterflooding. Numerical simulations were used to interpret the experimental results. The experimental oil recovery and pressure drop data were matched by reducing the fluid mobility in the fracture. A new experiment verified that a viscous phase formed in the fracture, which resulted in a significant improvement in oil recovery.",3,3,2
Crude Oil,Viscosity,"Mohammadi, Mohammad-Reza; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Husein, Maen M.; Ranjbar, Mohammad",Application of cascade forward neural network and group method of data handling to modeling crude oil pyrolysis during thermal enhanced oil recovery,In-situ combustion; EOR; Pyrolysis; TGA; Artificial neural networks; Group method of data handling,IN-SITU COMBUSTION; MINIMUM MISCIBILITY PRESSURE; GENERALIZED REGRESSION; COMPRESSIBILITY FACTOR; KINETICS; PREDICTION; VISCOSITY; HYBRID; ASPHALTENES; OXIDATION,"Oil recovery during in situ combustion is majorly controlled by hydrocarbon oxidation and pyrolysis reactions, which govern fuel formation and heat evolution. Fuel deposition, in turn, can be accurately predicted in part through crude oil pyrolysis using thermogravimetry analysis (TGA). The theoretical models based on TGA runs, however, may be limited to crude oil samples at hand. In this study, we develop more general models to predict the residual mass during crude oil pyrolysis based on multi-layer perceptron (MLP), cascade forward (CFNN), generalized regression (GRNN), and radial basis function (RBF) neural networks. More than 2000 experimental data spanning wide range of weight percentages of asphaltenes and resins as well as oAPI gravities, heating rates, and temperatures are used. Moreover, six optimization algorithms; including Bayesian regularization (BR), scaled conjugate gradient (SCG), Levenberg-Marquardt (LM), conjugate gradient backpropagation with FletcherReeves updates (CGF), resilient backpropagation (RB), and conjugate gradient backpropagation with PolakRibie ' re updates (CGP) are used to improve the performance and prediction ability of the MLP and CFNN neural networks. The CFNN model optimized with the LM algorithm best fits all the experimental data with a mean absolute percent relative error of 1.04%. Lastly, a mathematical correlation is developed utilizing the group method of data handling (GMDH) to estimate the residual mass of crude oil pyrolysis in TGA. Despite its simplicity, the correlation also provides very good estimates. Sensitivity analysis showed that temperature followed by asphaltenes and resin content showed the highest effect on mass loss during crude oil pyrolysis. Outliers estimation applying the Leverage approach suggested only 1% of the data points could be doubtful.",11,11,1
Crude Oil,Viscosity,"Strelets, Larisa A.; Ilyin, Sergey O.",Effect of enhanced oil recovery on the composition and rheological properties of heavy crude oil,Heavy crude oil; Enhanced oil recovery; Oil composition; Rheology; Viscosity; Viscoelasticity,GLASS-FORMING LIQUIDS; POLYMER; ASPHALTENE; AGGREGATION; BITUMEN; MEDIA; STATE,"The composition and rheological properties of ten samples of heavy crude oil from five different wells were investigated before and after integrated oilfield treatment with gel-forming and oil-displacing systems for increasing oil recovery. The study of the viscosity and viscoelastic properties of oil samples in a wide temperature range (from -30 to 70 degrees C) made it possible to determine their gelation and glass transition temperatures and also to establish the effect of enhanced oil recovery treatment on these characteristics. It was found that the treatment can either increase or decrease the viscosity of oil, and the same applies to the gelation and glass transition temperatures as well as to the contents of saturates, resins, and asphaltenes. The rheological properties of oil samples were closely related to their group composition, while the changes in the latter as a result of oilfield treatment were dependent on the relative position of the injection and production wells. The work allowed finding universal correlations between the group composition of heavy oil, its viscosity, and test temperature.",10,10,4
Crude Oil,Viscosity,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Crude Oil,Viscosity,"Volkov, Vladimir Y.; Al-Muntaser, Ameen A.; Varfolomeev, Mikhail A.; Khasanova, Nailia M.; Sakharov, Boris, V; Suwaid, Muneer A.; Djimasbe, Richard; Galeev, Ranel, I; Nurgaliev, Danis K.",Low-field NMR-relaxometry as fast and simple technique for in-situ determination of SARA-composition of crude oils,Low field NMR relaxation; SARA analysis; Heavy oil; Light oil; Group composition,LIQUID-CHROMATOGRAPHY; HEAVY OIL; FRACTIONS; ASPHALTENES; SEPARATION; PHASE; LIGHT; HPLC; PRECIPITATION; SPECTROSCOPY,"In this study a new, fast and simple method based on low field NMR-relaxometry for in-situ determination of SARA (saturates, aromatics, resins and asphaltenes) composition of crude oils was proposed. This method was tested on 22 samples of crude oils with a wide range of SARA-composition and API gravity values (4.6-42.0 degrees), including extra-heavy, heavy, medium and light crude oils. Results obtained by low-field nuclear magnetic resonance (LF-NMR) were compared with conventional SARA analysis method (ASTM D 4124). Comparison shows good coincidence between SARA values determined by LF-NMR and conventional method data for heavy fractions of asphaltenes and resins (R-2 is equal to 0.98 and 0.91, respectively) and for the sum of light fractions including saturates and aromatics (R-2 = 0.96). However, comparison for saturated and aromatic compounds separately gave low correlation coefficients (R-2 <= 0.61 and 0.27, respectively) and relatively soaring standard deviation for individual correlations for saturates and aromatics (8.18 and 9.20). Consequently, LF- NMR relaxation as an alternative method for studying the composition of crude oil allows the determination of asphaltenes, resins and the sum of light fractions (saturates and aromatics) without their extraction (in-situ), which greatly simplifies and accelerates conventional chromatographic analysis. This method can be successfully applied for different types of crude oils with a wide range of API gravity and viscosity values.",7,7,3
Crude Oil,Viscosity,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Crude Oil,Viscosity,"Ge, Meng-Ru; Miao, Si-Jia; Liu, Jin-Feng; Gang, Hong-Ze; Yang, Shi-Zhong; Mu, Bo-Zhong",Laboratory studies on a novel salt-tolerant and alkali-free flooding system composed of a biopolymer and a bio-based surfactant for oil recovery,Biopolymer/surfactant formula; Ultra-low interfacial tension; Enhanced oil recovery; Salt-tolerant; Alkali-free,HIGH-TEMPERATURE; WELAN GUM; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; NONIONIC SURFACTANT; ASSOCIATING POLYMER; AQUEOUS WELAN; XANTHAN GUM; STRAIN; POLYSACCHARIDES,"Alkali/surfactant/polymer (ASP) flooding is one of the most effective tertiary oil recovery technologies. However, the formation of an alkali scale potentially results in the reduction of the formation permeability and pipeline corrosion, which affect its industrial application. Recently, the surfactant/polymer (SP) flooding system in the absence of alkali has received increasing attention. Here, we screened a high-yielding strain, which is capable of producing salt-tolerant biopolymer. The results of rheological properties evaluation showed that this biopolymer possessed a stable viscosity at high salinities (up to 200 g/L NaCl, 100 g/L Ca2+, and 100 g/L Mg2+) and a wide range of pH (4-11), indicating its superior salt and pH resistance. Based on these properties, a novel salt-tolerant and alkali-free binary flooding system was constructed with this biopolymer and bio-based surfactant newly synthesized in our lab. The ultra-low interfacial tension (IFT) between crude oil and the binary system containing 0.5 wt % biopolymer and 1.00 g/L surfactant could be achieved in the presence of 100 g/L NaCl or 400 mg/L Ca2+. Moreover, it exhibited good resistance to oil sands adsorption, excellent anti-dilution, and ageing stability. These results indicate that the biopolymer produced by the Kosakonia oryzae strain possessed great potential in the construction of an alkali-free SP system for enhanced oil recovery (EOR) in high salinity and high temperature oil reservoirs.",4,4,5
Crude Oil,Viscosity,"Yusuff, Afeez Oluwatobi; Yahya, Noorhana; Zakariya, Mohd Azman; Sikiru, Surajudeen",Investigations of graphene impact on oil mobility and physicochemical interaction with sandstone surface,Enhanced oil recovery; Graphene; Physicochemical interaction; Viscosity; Diffusion coefficient; Molecular dynamic simulation,SHEAR VISCOSITY; NANOPARTICLES; DIFFUSION; RECOVERY; AGGREGATION; PERFORMANCE; SIMULATION; MECHANISM; MEDIA; MODEL,"Enhanced oil recovery (EOR) is the recovery of oil trapped in the reservoir after primary and secondary recovery processes through novel techniques. Viscosity is primarily a major cause of the high proportion of hydrocarbon fluid entrapped. Recently, emergence of nanotechnology has gained attention in oil industry. The major factor hindering the efficiency of nanoparticles is poor transport inside the reservoir due to high adsorption energy to grains surfaces, leading to their retention. Some studies have reported the effectiveness of nanoparticles on oil viscosity. However, report on the use of pristine graphene has been missing along with requisite transportation behaviour on sandstone surface. This work investigates the applicability of graphene in EOR. The effects of graphene concentrations (0.01, 0.05 & 0.1 wt%) on flowability of oil (50 cP and 0.85 cP), and its adsorption energy are reported. Experimentally, viscosity of the more viscous crude oil was reduced by 43-65%. Using molecular simulation, diffusion coefficient estimation indicate improvement in diffusivity of light decane by 112%. Furthermore, the adsorption energy of graphene is surprisingly found to be low (-9.11 kcal/mol). This study concluded that graphene is applicable, the oil sample is Newtonian and viscosity well reduced.",4,4,4
Crude Oil,Viscosity,"Zhao, Feng; Zhu, Hongbin; Cui, Qingfeng; Wang, Bingxin; Su, Han; Zhang, Ying",Anaerobic production of surfactin by a new Bacillus subtilis isolate and the in situ emulsification and viscosity reduction effect towards enhanced oil recovery applications,Microbial enhanced oil recovery; Anaerobic conditions; Bacillus subtilis; Surfactin; Emulsifying activity; Viscosity reduction,,"Emulsification and viscosity reduction effect of biosurfactants to crude oil are significant for enhanced oil recovery. Although biosurfactants for enhanced oil recovery were extensively studied, information on the anaerobic production of biosurfactants and its in situ effect to crude oil are still limited. Bacillus subtilis AnPL-1 was isolated from oil reservoirs production water and produced 150 mg/l of biosurfactants under anaerobic conditions. Sucrose and nitrate were favorable for anaerobic production of biosurfactants by strain AnPL-1. Strain AnPL-1 anaerobically produced biosurfactants at temperatures (20 degrees C-50 degrees C), pH values (6-9) and 0-7% of NaCl. FTIR and HPLC-MS analysis showed that the anaerobically produced biosurfactants was a mixture of C-13-, C-14- and C-15-surfactin congeners. Anaerobically produced surfactin decreased water surface tension to 28.5 mN/m with a critical micelle concentration of 30 mg/l. It can also emulsify crude oil with an emulsion index (EI24) of 70.5%. Strain AnPL-1 also produced 115 mg/l biosurfactants under simulated oil reservoirs conditions (anaerobic and 10 MPa conditions). Furthermore, strain AnPL-1 anaerobically grew well in the presence of crude oil. Strain AnPL-1 reduced the crude oil viscosity by 40.6% through in situ emulsification effect of produced biosurfactants. In core flooding tests, in situ biosurfactants production by strain AnPL-1 enhanced oil recovery of 9.98%. Although B. subtilis is a facultative anaerobe, anaerobic production of biosurfactants by B. subtilis for MEOR applications has been firstly studied. Without air injection, anaerobic production of surfactin by B. subtilis AnPL-1 is promising for in situ MEOR applications.",4,4,2
Crude Oil,Viscosity,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Crude Oil,Viscosity,"Li, Hanyong; Gao, Hang; Zhao, Xiaonan; Xia, Zijie; Yu, Bo; Sun, Dongliang",Experimental study on viscosity reduction of heavy oil with water content by synergistic effect of microwave and nano-catalyst,Viscosity reduction; Microwave heating; Nano-catalyst; Heavy oil; Water content,CRUDE-OIL; ASPHALTENES; DEMULSIFICATION; NANOPARTICLES; EMULSIONS; RECOVERY,"With the depleting of conventional oil and gas resources, viscosity reduction of heavy oil became more and more important as a research focus. As a new method of viscosity reduction, the mechanism of microwave-assisted with nano-catalysts is still unclear. In this paper, the viscosity reduction of nano-catalyst and microwave treatment of heavy oil in different water content was studied. The experimental results showed that the maximum viscosity reduction was 96.81 % when the water content was 50 wt% under the conditions of microwave heating power of 614w, microwave heating temperature of 68 degrees C and nickel nano-catalyst concentration of 0.8 wt%. The oil samples before and after three treatments were analyzed by infrared spectroscopy, element analysis, four-component separation, and two-dimensional gas chromatography-mass spectrometry. By analyzing the changes of functional group, element composition, and component content, the effects of microwave and nano-catalyst were studied. The results showed that the resin and asphaltene content decreased by 17.3 wt%, and the hydrogen to carbon ratio was 2.14 when the water content was 30 wt% under the conditions of microwave heating power of 666w, microwave heating temperature of 65 degrees C and nickel nano-catalyst concentration of 2.3 wt%, which proved that microwave treatment assisted with nano-catalysts could increase the cracking capacity of macromolecules and the production of coke.",3,3,10
Crude Oil,Viscosity,"Yang, Fei; Zhu, Haoran; Li, Chuanxian; Yao, Bo; Wang, Feng; Chen, Jinxiu; Sun, Guangyu",Investigation on the mechanism of wax deposition inhibition induced by asphaltenes and wax inhibitors,Wax deposition; Inhibition; Asphaltenes; Wax inhibitor; Mechanism,VINYL ACETATE COPOLYMER; POUR POINT DEPRESSANT; CRUDE-OIL; SYNERGISTICALLY IMPROVE; PERFORMANCE IMPROVEMENT; RHEOLOGICAL PROPERTIES; FLOW BEHAVIOR; MODEL; EVA; MIXTURES,"This study is specifically concerned with the effect and mechanism of asphaltenes and wax inhibitors on the wax deposition characteristics of model waxy oil. According to the rheological and wax deposition test, the pure model waxy oil has a pour point higher than the pipe wall temperature, and the formed wax deposit exhibits the slowest aging rate and homogeneous wax deposit structure. Based on the DSC and rheological experiments, the solubility of wax crystals is hardly influenced by asphaltenes or wax inhibitors, but the decrease of oil viscosity and the weakened low-temperature gel structure induced by asphaltenes and wax inhibitors would increase the wax molecular diffusion coefficient and wax content in the wax deposit, which ultimately leads to a thinner and harder wax deposit. Moreover, based on the molecular dynamic simulation, the EVA molecules can be adsorbed on the asphaltene surface thus forming EVA-asphaltene composite particles, which can change the crystallization habit of wax molecules and the wax crystal micromorphology, thereby dramatically improving the crude oil rheology at low temperatures and inhibiting wax deposition. This work provides a comprehensive understanding of the wax deposition mechanism induced by asphaltenes and wax inhibitors, which helps to the well or pipeline operation safety and efficiency.",3,3,9
Crude Oil,Viscosity,"Abdullah, Mahmood M. S.; Al-Lohedan, Hamad A.",Synthesis and characterization of tannic acid esters and their performances as asphaltenes dispersants,Tannic acid; Asphaltene; Dispersants; Esters,IONIC LIQUIDS; NATURAL-PRODUCTS; HEAVY; INHIBITION; PRECIPITATION; DEMULSIFIER; CARDANOL; IMIDAZOLIUM; DEPOSITION; MODIFIERS,"Asphaltene aggregation and flocculation in upstream and downstream industries cause severe problems due to phase separation and asphaltene particle growth. This work aims to esterify tannic acid (TA) at different molar ratios of heptanoyl chloride (HC) 1:3, 1:6, and 1:9, producing species TA-HC3, TA-HC6, and TA-HC9, respectively. The synthesized esters were characterized by Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance (H-1-NMR), and thermal analyses. Their performances as asphaltene dispersants of Arabian heavy crude oil were assessed by dynamic light scattering (DLS), ultraviolet-visible (UV-Vis) spectroscopy, and viscosity measurements. All specimens (TA-HC3, TA-HC6, and TA-HC9) dispersed asphaltene, and their dispersal abilities increased with increasing number of alkyl chains (i.e., TA-HC3 > TA-HC6 > TA-HC9).",3,3,6
Crude Oil,Viscosity,"Ali, Hassan; Soleimani, Hassan; Yahya, Noorhana; Khodapanah, Leila; Kozlowski, Gregory; Sabet, Maziyar; Demiral, Birol M. R.; Adebayo, Lawal Lanre; Hussain, Tanvir",Experimental investigation and two-phase flow simulation of oil and nanofluids on micro CT images of sandstone for wettability alteration of the system,Capillary pressure; Oil reservoir; Porous media; Permeability; Oil saturation,PORE NETWORK MODEL; POROUS-MEDIA; PERMEABILITY; TRANSPORT; WATER; MIGRATION; BRINE,"This work provides an analysis of the effect of nanofluids on the wettability of sandstone for the application of enhanced oil recovery. The wettability of sandstone with brine and nanofluids of ZnO, BiFeO3, and SrFeO3 is studied experimentally using contact angle calculations. Also, the direct simulations for the displacement of oil with brine and nanofluids are carried out on a micro-CT scanned porous sandstone structure for the measurement of capillary pressure and relative permeability. Fluid properties such as viscosity and density of the nanofluids, brine, and oil to be used in simulations were obtained using viscometer and densimeter. The experimental results show that the contact angle of crude oil on the sandstone surface has a higher value for nanofluids as 125.89 degrees for ZnO, 122.88 degrees for BiFeO3, and 104.98 for SrFeO3 as compared to brine 28.66 degrees, which means the wettability of the system changes from oil-wet to water-wet by the addition of nanofluids. The simulation results indicate that BiFeO3 nanofluid has a greater tendency to change the wettability of porous medium as compared to brine, ZnO, and SrFeO3 nanofluids, as it shows better values of relative permeability and capillary pressure.",3,3,5
Crude Oil,Deposition,"Mohammadi, Mohammad-Reza; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Husein, Maen M.; Ranjbar, Mohammad",Application of cascade forward neural network and group method of data handling to modeling crude oil pyrolysis during thermal enhanced oil recovery,In-situ combustion; EOR; Pyrolysis; TGA; Artificial neural networks; Group method of data handling,IN-SITU COMBUSTION; MINIMUM MISCIBILITY PRESSURE; GENERALIZED REGRESSION; COMPRESSIBILITY FACTOR; KINETICS; PREDICTION; VISCOSITY; HYBRID; ASPHALTENES; OXIDATION,"Oil recovery during in situ combustion is majorly controlled by hydrocarbon oxidation and pyrolysis reactions, which govern fuel formation and heat evolution. Fuel deposition, in turn, can be accurately predicted in part through crude oil pyrolysis using thermogravimetry analysis (TGA). The theoretical models based on TGA runs, however, may be limited to crude oil samples at hand. In this study, we develop more general models to predict the residual mass during crude oil pyrolysis based on multi-layer perceptron (MLP), cascade forward (CFNN), generalized regression (GRNN), and radial basis function (RBF) neural networks. More than 2000 experimental data spanning wide range of weight percentages of asphaltenes and resins as well as oAPI gravities, heating rates, and temperatures are used. Moreover, six optimization algorithms; including Bayesian regularization (BR), scaled conjugate gradient (SCG), Levenberg-Marquardt (LM), conjugate gradient backpropagation with FletcherReeves updates (CGF), resilient backpropagation (RB), and conjugate gradient backpropagation with PolakRibie ' re updates (CGP) are used to improve the performance and prediction ability of the MLP and CFNN neural networks. The CFNN model optimized with the LM algorithm best fits all the experimental data with a mean absolute percent relative error of 1.04%. Lastly, a mathematical correlation is developed utilizing the group method of data handling (GMDH) to estimate the residual mass of crude oil pyrolysis in TGA. Despite its simplicity, the correlation also provides very good estimates. Sensitivity analysis showed that temperature followed by asphaltenes and resin content showed the highest effect on mass loss during crude oil pyrolysis. Outliers estimation applying the Leverage approach suggested only 1% of the data points could be doubtful.",11,11,1
Crude Oil,Deposition,"Al-Khafaji, Amer Jassim; Hakimi, Mohammed Hail; Mohialdeen, Ibrahim M. J.; Idan, Rami M.; Afify, Wafaa E.; Lashin, Aref A.","Geochemical characteristics of crude oils and basin modelling of the probable source rocks in the Southern Mesopotamian Basin, South Iraq",Oil-oil correlation; Cretaceous reservoirs; Carbon isotope; Biomarker ratios; Basin modeling; Mesopotamian basin; South Iraq,PETROLEUM SYSTEM-ANALYSIS; ZAGROS FOLD BELT; DEPOSITIONAL-ENVIRONMENTS; HYDROCARBON GENERATION; SARGELU FORMATION; ORGANIC-MATTER; SHOUSHAN BASIN; WESTERN DESERT; NORTH; MIGRATION,"Bulk property and geochemical analyses were performed on 15 crude oil samples collected from the Early Cretaceous clastic reservoirs in the oilfields of the southern Mesopotamian Basin, South Iraq. Specific gravities ranging between 25.4 and 31.6 API and relatively high sulfur concentrations of up to 1.97 wt % suggest that the samples were generated from kerogen Type IBS at relatively low maturity level. Biomarker ratios and parameters as well as carbon isotope ratios, indicate that the oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions during the Jurassic to Early Cretaceous. Furthermore, biomarker maturity suggests two maturity subgroups for the samples based on their sulfur concentrations and specific gravity values. Sub-group (A) is characterized by oils generated from low-mature source rocks from the Late Jurassic-Early Cretaceous Sulaiy Formation; while the relatively high mature oils of sub-group (B) were generated from organic-rich intervals in the Jurassic Sargelu and Najmah formations. Basin model results revealed that these formations reached a peak oil-generation window at different times, expelling various quantities of oil. The basin model results further suggest that the organic-rich interval in the Sulaiy Formation began to expel little amounts of oil, corresponding to transformation ratio (TR) between 50 and 63% since the Late Miocene to present-day, while the organic-rich intervals in the Sargelu and Najmah formations were the earliest to expel significant amounts of oil, with relatively high TR values of 50-90% during the end of the Late Cretaceous to Early Eocene and continued to the present-day. These generated oils subsequently migrated to the shallow stratigraphic reservoir intervals through the vertical pathway of faults, and are currently extracted for use in the oil industry.",10,10,1
Crude Oil,Deposition,"Varfolomeev, Mikhail A.; Yuan, Chengdong; V. Bolotov, Alexander; Minkhanov, Ilgiz F.; Mehrabi-Kalajahi, Seyedsaeed; Saifullin, Emil R.; Marvanov, Marat M.; Baygildin, Emil R.; Sabiryanov, Raushan M.; Rojas, Allan; Emelianov, Dmitrii A.; Al-Muntaser, Ameen A.; Ganiev, Bulat G.; Zaripov, Azat T.; Beregovoi, Anton N.; Shaihutdinov, Damir K.",Effect of copper stearate as catalysts on the performance of in-situ combustion process for heavy oil recovery and upgrading,In-situ combustion; In-situ upgrading; Heavy oil; Copper stearate; Oil-soluble catalyst; Catalytic combustion,LIGHT CRUDE-OIL; OXIDATION BEHAVIOR; NANOPARTICLES; ASPHALTENES; KINETICS; DECOMPOSITION; ADSORPTION; PYROLYSIS,"Using copper stearate as catalysts, catalytic in-situ combustion (ISC) of heavy oil was studied by porous medium thermo-effect cell (PMTEC) and combustion tube experiments. Significant acceleration of combustion was observed in porous media in PMTEC when copper stearate was added. Copper stearate promoted fuel deposition and its combustion and made them occur easier in low temperature, thus shifting both low-temperature oxidation (LTO) and high-temperature oxidation (HTO) into lower temperatures, and even totally merge HTO into LTO in some conditions. We found that the promotion on fuel deposition by catalysts might be related to the change of H/C ratio in fuel. The improvement in the performance of ISC by copper stearate in combustion tube experiments mainly manifests in lower ignition temperature, lower H/C ratio, increased air/fuel ratio, higher oil recovery, and higher level of in-situ oil upgrading, which makes copper stearate a good candidate for catalyzing ISC in field application.",9,9,6
Crude Oil,Deposition,"Zhang, Kun; Liu, Rong; Liu, Zhaojun","Sedimentary sequence evolution and organic matter accumulation characteristics of the Chang 8-Chang 7 members in the Upper Triassic Yanchang Formation, southwest Ordos Basin, central China",Sedimentary environment; Paleoclimate; Organic matter accumulation; Yanchang formation; Ordos basin,SILURIAN LONGMAXI FORMATION; DEVONIAN DUVERNAY FORMATION; TIGHT SANDSTONE RESERVOIRS; GEOCHEMICAL CHARACTERISTICS; DEPOSITIONAL ENVIRONMENT; BLACK SHALES; OIL-SHALE; STRATIGRAPHIC ANALYSIS; ELEMENT GEOCHEMISTRY; MARCELLUS FORMATION,"Lacustrine organic-rich shales are widely developed in the Chang 7 member of the Yanchang Formation in the Ordos Basin. These shales have been proven to be the source rocks for crude oil and shale oil. The study of sedimentary evolution and the characteristics of organic matter (OM) accumulation is an important factor for the exploration and development of oil and gas resources. Based on the lithological assemblages, lithofacies, mineral contents, log curves and geochemical data, the sequence stratigraphic framework of the Chang 8-Chang 7 members of the Yanchang Formation in the southern margin of the Ordos Basin were established. A complete third-order sequence was identified, and it included four systems tracts: a lowstand systems tract (LST), a transgressive systems tract (TST), a highstand systems tract (HST) and a regressive systems tract (RST). By using organic petrology, organic geochemistry and elemental geochemistry, the abundance and source of OM, paleoclimate, paleowater conditions, paleoproductivity, and deposition rates of the different systems tracts of the Chang 8-Chang 7 are studied in detail. Various factors controlled the accumulation of OM in the different systems tracts. The abundance of OM in the LST is low, the kerogen type is mainly type III (including vitrinite); the abundance of OM increased gradually in the TST, the kerogen types are III and II2 (including vitrinite and sporophyte); the OM is mainly concentrated in the HST, and the kerogen type is mainly type ID (including alginite), biomarker compounds show that OM has a mixed source of land plant and planktonic material; the abundance of OM in the RST is relatively high, the kerogen type is mainly type II2 and III (including vitrinite and alginite). The main controlling factor for OM accumulation was paleoclimate, which affected the primary productivity of lake and the chemical properties of the water column (redox and paleosalinity), leading to differences in OM accumulation under different climatic conditions. Hydrothermal activities contributed to anoxia and a salinity increase in lake bottom waters, with volcanic ash providing large amounts of essential nutrients for algal blooms. Based on the V/Cr, Sr/Ba, P/Ti and (La/Yb)(N) ratios with TOC values, the abundance of OM is positively correlated with paleoproductivity and water column reducibility, and negatively correlated with paleosalinity. The abundance of OM first increases and then decreases with increasing sedimentation rate. In general, the accumulation of OM was promoted under warm and humid climates, anoxic fresh to brackish water and adequate paleoproductivity.",8,8,9
Crude Oil,Deposition,"Fan, Kaifeng; Li, Si; Li, Rongbin",Development of wax molecular diffusivity correlation suitable for crude oil in wax deposition: Experiments with a cold-finger apparatus,Wax deposition; Molecular diffusion; Partial saturated; Saturated solution; Concentration gradient; Diffusivity correlation,CRITICAL CARBON NUMBER; FLOW; FIELD; TEMPERATURE; PIPELINES,"Wax deposition is a hot and difficult topic in waxy crude oil transportation. Wax molecular diffusion is recognized to play a crucial role in wax deposition. Empirical correlations of Hayduk-Minhas and Wilke-Chang are widely used to calculate the wax molecular diffusivity. However, they are developed based on binary solutions and underestimate the diffusion coefficient of wax components. To address this issue, wax deposition experiments with different crude oils were conducted in cold-finger apparatus. The temperature distribution was obtained by computational fluid dynamics software of Fluent and the characteristics of wax deposit were investigated. In addition, the wax molecular diffusion process under saturated and partial saturated conditions were theoretically elucidated. It was found that the bulk temperature, deposition duration and carbon number distribution of wax molecules can significantly influence the total wax content and wax precipitation properties of wax deposits. Moreover, the wax molecular diffusivity experimentally calculated based on the Fick's first law were found larger than that obtained by correlations of Hayduk-Minhas and Wilke-Chang. A new correlation calculating the wax diffusion in crude oil was developed and verified with experiments. Good agreement between predicted and experimental values was observed with maximum relative deviation being 12.52% and mean absolute error being 8.90%. This new correlation is suitable in wax molecular diffusivity calculation for crude oils.",5,5,6
Crude Oil,Deposition,"You, Jiyuan; Liu, Yiqun; Song, Shanshan; Zhou, Dingwu; Yang, Yiyao",Characteristics and controlling factors of LORS from the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin,LORS; Redox conditions; Paleoproductivity; Volcanic and hydrothermal activities; Yanchang formation; Ordos basin,GEOCHEMICAL CHARACTERISTICS; SEQUENCE STRATIGRAPHY; CHINA IMPLICATIONS; BARNETT SHALE; TRACE-METALS; DEEP-SEA; EVOLUTION; ACCUMULATION; PRODUCTIVITY; MORPHOLOGY,"Lacustrine organic-rich shale (LORS) developed in the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin. LORS has been proven to be a source of crude oil and tight oil, as well as a source and reservoir for shale oil in the basin. A total of 35 LORS samples were collected from Well Z233 and analysed by mineralogy and element geochemistry to reveal the characteristics and controlling factors of LORS. The following results were obtained: In the oil shale, the organic matter is composed of type I and type II kerogen, with a pre- dominance of type II. The organic matter is mature and reaches high levels of abundance. (2)Through further analysis. The values of w(U)/w(Th), w(V)/w(Cr), w(Ni)/w(Co), the size and morphology of pyrite, indicates that the lake water of the LORS deposition period in the study area is anoxic or suboxic state. the TOC of the samples was found to have significant positive correlations with the w(Mo) and w(Ba-bio) contents. Paleoproductivity can be inferred to be the key factor controlling organic matter enrichment in the LORS. (3)Volcanic and hydrothermal activities promote the development of LORS, provide nutrients needed by organisms, promote the growth of organisms, and improve paleoproductivity. Hydrothermal activity leads to the formation of an anoxic environment at the bottom of the lake, and tuff will cover the sediments, which promotes LORS preservation. This study reveals in detail paleoproductivity is the main factor in the formation of LORS during the evolution of the basin. Volcanic and hydrothermal activities promoted the increase of paleoproductivity, and finally the oil shale layers with the richest organic matter have been formed. And thereby deepens our theoretical understanding of organic matter enrichment.",5,5,4
Crude Oil,Deposition,"Mirkhoshhal, Seyed Mehdi; Mahani, Hassan; Ayatollahi, Shahab; Shirazi, Maysam Mohammadzadeh",Pore-scale insights into sludge formation damage during acid stimulation and its underlying mechanisms,Acid stimulation; Formation damage; Pore-scale mechanism; Acid sludge; Acid-oil emulsion; Microfluidics,ASPHALTENE PRECIPITATION; OIL; WATER; VISUALIZATION; SALINITY; PREVENTION; MICROMODEL; DEPOSITION; ROCK,"Acid-oil emulsion and sludge formation are known as two major formation damage mechanisms and the reason for failure of some acid treatments. The published studies in this area focus primarily on core- to well/reservoir-scale and it is fairly unclear how acid-oil interaction at the pore-scale leads to the formation damage observed at the macro- or core-scale. In this paper, dynamic, micro-scale experiments were designed and executed to investigate the acid-induced formation damage using microfluidic approach. In addition, a series of so-called static (microscope) tests were performed in which acid-crude oil compatibility tests were conducted on a glass slide followed by microscopic observation to better analyze the micromodel results. The results show that sludge precipitation occurred right at the interface of the crude oil and acid; either with the residual oil film on the pore wall, at the acid-oil displacement menisci or acid-oil interfaces in the emulsion. Although, it is theoretically assumed that the reaction between acid and crude oil is fast, the results highlight that the damage is intensified by increasing the exposure time up to 8 hours. Besides, the acid type and concentration showed to have considerable impact on the acid-sludge and emulsion formation. The dynamic results indicate that increasing live acid concentration from 15 wt% to 28 wt% caused about 27.5% more permeability impairment due to sever pore-bridging, while spent acid did not result in any acid-sludge deposit. Furthermore, the role of ferric ion, as a transfer catalyst facilitating the two-phase contact, was visually confirmed through static tests. The dynamic tests also indicated 13% more permeability reduction when 3000 ppm ferric ion was present during 28 wt% HCl injection compared with the free-iron case. Emulsion analysis at the pore-scale showed that acid emulsion critically plugs the pore throats and intensify acid-sludge depositions. Size of acid-oil emulsion droplets was found to be distance-dependent such that as the acid permeated deeper into the porous medium the emulsions became finer and denser causing increased damage. Mitigating formation damage requires underpinning the mechanisms, the microfluidic approach can assist in identifying whether sludge precipitation or emulsion formation are the chief mechanisms and can serve as a fast, intermediate step before conducting the time intensive acidizing experiments at core-scale.",4,4,1
Crude Oil,Deposition,"Alkhafaji, Mohamed W.","Biomarker assessment of oil biodegradation, water washing, and source rock characteristics of oil seeps from the Foothill Zone along the Tigris River, Northern Iraq",Source rock depositional environment; Biomarkers; Oil seeps; Biodegradation; Water washing; Hammam Al-Alil; Qaiyarah; Fat'ha; Northern Iraq,TRIASSIC SHUBLIK FORMATION; LOWER FARS FORMATION; IN-SOURCE ROCKS; CRUDE OILS; DEPOSITIONAL ENVIRONMENT; PETROLEUM GENERATION; THERMAL MATURITY; FOLD BELT; IDENTIFICATION; MARKERS,"Oil seep samples from the Foothill Zone of northern Iraq were geochemically characterized to determine the level of biodegradation and water washing of the seeps and to determine the depositional environment (including sedimentary facies, oxicity, and organic matter type) of correlative source rocks. Eight samples from three seeps sites (Hammam Al-Alil, Qaiyarah, and Fat'ha) were investigated. Detailed saturated and aromatic biomarkers were analyzed using GC-FID and GC-MS, in addition to measurement of carbon isotopes and the sulphur content. Qaiyarah samples range from non-biodegraded to moderately biodegraded; whereas Hammam Al-Alil and Fat'ha samples are moderately biodegraded. The Hammam Al-Alil and Fat'ha samples are also affected by water washing. Biomarker, carbon isotope, and sulphur data suggest that these oil seeps contain oil expelled during the early oil window from carbonate source rocks of Jurassic age. Correlative source rocks were deposited in an anoxic marine environment. The most likely source rock candidates include the Sargelu, Naoklekan, and Chia Gara formations.",4,4,1
Crude Oil,Deposition,"Rafiei, Arsalan; Khamehchi, Ehsan",Design of smart water composition based on scale minimization and its effect on wettability alteration in the presence of nanoparticles and mineral scales,Smart water; Nanoparticles; Wettability alteration; Scale deposition,LOW-SALINITY WATER; BRINE COMPOSITION; FINES MIGRATION; OIL-RECOVERY; CRUDE-OIL; IONS,"Smart Water (SW) injection is one of the most popular and inexpensive methods of FOR in sandstone and carbonate reservoirs. By modifying water chemistry with changes in salinity and composition optimization, we can obtain the appropriate smart water composition. So finding the optimal composition of smart water is one of the essential parts of its operations in reservoirs. On the other hand, due to the numerous applications of nanoparticles in the petroleum industry, the most critical part of nanofluids is the dispersion and stabilization of nanoparticles in the fluid. In this paper, a comprehensive study has been conducted on optimizing the composition of smart water based on scale formation and obtaining the optimum composition of the ions. Numerous experiments have been carried out to stabilize the nanoparticles in the optimized water composition under reservoir temperature, and the effect of each parameter has been determined. Also, the impact of optimized smart water on wettability alteration compared with other compositions has been reported. The effect of dispersed nanoparticles on wettability alteration in different Smart Water compositions was also shown. According to the results of this paper, the incompatibility of smart water and formation water can affect the purpose of injecting smart water, such that water containing the least scale due to incompatibility has the most significant effect on wettability alteration. Also, smart water composition that was incompatible with formation water has reduced the wettability alteration. Moreover, the presence of nanoparticles can slow down the process of wettability alteration. Thus, the presence of nanoparticles in injected water has reduced the hydrophilicity of rock.",4,4,0
Crude Oil,Deposition,"Yang, Fei; Zhu, Haoran; Li, Chuanxian; Yao, Bo; Wang, Feng; Chen, Jinxiu; Sun, Guangyu",Investigation on the mechanism of wax deposition inhibition induced by asphaltenes and wax inhibitors,Wax deposition; Inhibition; Asphaltenes; Wax inhibitor; Mechanism,VINYL ACETATE COPOLYMER; POUR POINT DEPRESSANT; CRUDE-OIL; SYNERGISTICALLY IMPROVE; PERFORMANCE IMPROVEMENT; RHEOLOGICAL PROPERTIES; FLOW BEHAVIOR; MODEL; EVA; MIXTURES,"This study is specifically concerned with the effect and mechanism of asphaltenes and wax inhibitors on the wax deposition characteristics of model waxy oil. According to the rheological and wax deposition test, the pure model waxy oil has a pour point higher than the pipe wall temperature, and the formed wax deposit exhibits the slowest aging rate and homogeneous wax deposit structure. Based on the DSC and rheological experiments, the solubility of wax crystals is hardly influenced by asphaltenes or wax inhibitors, but the decrease of oil viscosity and the weakened low-temperature gel structure induced by asphaltenes and wax inhibitors would increase the wax molecular diffusion coefficient and wax content in the wax deposit, which ultimately leads to a thinner and harder wax deposit. Moreover, based on the molecular dynamic simulation, the EVA molecules can be adsorbed on the asphaltene surface thus forming EVA-asphaltene composite particles, which can change the crystallization habit of wax molecules and the wax crystal micromorphology, thereby dramatically improving the crude oil rheology at low temperatures and inhibiting wax deposition. This work provides a comprehensive understanding of the wax deposition mechanism induced by asphaltenes and wax inhibitors, which helps to the well or pipeline operation safety and efficiency.",3,3,9
Crude Oil,Deposition,"Abdullah, Mahmood M. S.; Al-Lohedan, Hamad A.",Synthesis and characterization of tannic acid esters and their performances as asphaltenes dispersants,Tannic acid; Asphaltene; Dispersants; Esters,IONIC LIQUIDS; NATURAL-PRODUCTS; HEAVY; INHIBITION; PRECIPITATION; DEMULSIFIER; CARDANOL; IMIDAZOLIUM; DEPOSITION; MODIFIERS,"Asphaltene aggregation and flocculation in upstream and downstream industries cause severe problems due to phase separation and asphaltene particle growth. This work aims to esterify tannic acid (TA) at different molar ratios of heptanoyl chloride (HC) 1:3, 1:6, and 1:9, producing species TA-HC3, TA-HC6, and TA-HC9, respectively. The synthesized esters were characterized by Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance (H-1-NMR), and thermal analyses. Their performances as asphaltene dispersants of Arabian heavy crude oil were assessed by dynamic light scattering (DLS), ultraviolet-visible (UV-Vis) spectroscopy, and viscosity measurements. All specimens (TA-HC3, TA-HC6, and TA-HC9) dispersed asphaltene, and their dispersal abilities increased with increasing number of alkyl chains (i.e., TA-HC3 > TA-HC6 > TA-HC9).",3,3,6
Crude Oil,Contact Angle,"Siadatifar, Seyed Emad; Fatemi, Mobeen; Masihi, Mohsen",Pore scale visualization of fluid-fluid and rock-fluid interactions during low-salinity waterflooding in carbonate and sandstone representing micromodels,Low salinity waterflooding (LSWF); Microfluidics; Fluid/fluid interactions; Rock/fluid interactions; Visco-elastic interface,OIL-RECOVERY; WATER; MECHANISMS; SURFACE; DIFFUSION; OIL/WATER; WET,"Low Salinity Waterflooding (LSWF) has become a popular tertiary injection EOR method recently. Both fluid-fluid and fluid-rock interactions are suggested as the contributing mechanisms on the effectiveness of LSWF. Considering the contradictory remarks in the literature, the dominating mechanisms and necessary conditions for Low Salinity Effect (LSE) varies for different crude oil-brine-rock (CBR) systems. The aim of the present study is to investigate LSE for an oil field in the Middle East that is composed of separate sandstone and limestone layers. Contact angles and Interfacial Tension (IFT) are measured to have more insight on the CBR under investigation. Visual experiments were conducted in micromodels to determine the dominating mechanisms of LSE. Experiments were conducted under water-wet and oil-wet conditions for both sandstone and limestone representing micromodels. Several secondary and tertiary injection scenarios were performed with different levels of salinities. Consecutive injection of high-salinity and low-salinity water illustrated that LSE occurs under certain conditions. For both rock types, during the secondary high salinity injection, the oil trapping mechanism was mostly snap-off under water-wet condition, while fingering/bypassing was dominant under oil-wet conditions. LSWF causes diminutive changes of saturation redistribution in water-wet micromodels. Even in rare occasions that oil ganglia started to reshape or redistribute, it became trapped again in the downstream pores of the model, and not produced effectively. Contrary to this, LSWF was very effective under oil-wetting conditions. Continuous oil films, which exist in oil-wet condition, are beneficial for the effectiveness of LSE. Measured IFT and contact angles cannot justify the observed LSE. Additionally in the designed micromodels, any contribution of clay or fine migration to the LSE is ruled out. Spontaneous formation of the micro-emulsion was a very weak mechanism in our experiments and did not contribute to pushing oil out of the dead end pores or divert the flow path to the un-swept areas. Visual investigations suggested that formation of the visco-elastic interface can be the dominating mechanism for LSE in the investigated CBRs which is more effective in the case of oil-wet system due to the lack of snap-off trapping mechanism.",10,10,3
Crude Oil,Contact Angle,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
Crude Oil,Contact Angle,"Saadat, Marzieh; Yang, Junyi; Dudek, Marcin; Oye, Gisle; Tsai, Peichun Amy",Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability,Wettability alteration; Microfluidics; Surfactant flooding; Oil recovery; Enhanced oil recovery; Low salinity water flooding,LOW-SALINITY WATER; CRUDE-OIL; FINES MIGRATION; PHASE-BEHAVIOR; SURFACTANT; WET; DISPLACEMENT; EOR; ADSORPTION; SULFONATE,"Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.",8,9,11
Crude Oil,Contact Angle,"Farhadi, Hamed; Fatemi, Mobeen; Ayatollahi, Shahab",Experimental investigation on the dominating fluid-fluid and rock-fluid interactions during low salinity water flooding in water-wet and oil-wet calcites,Low salinity water flooding; Enhanced oil recovery; Carbonate rock wettability alteration; Dynamic interfacial tension; Dynamic contact angle; Surface electric charges,INTERFACIAL INTERACTIONS; TENSION; RESERVOIR,"Low salinity water flooding (LSWF) has the potential to enhance the oil recovery by affecting the fluid-fluid and rock-fluid interactions. Therefore, a systematic investigation on the effect of initial wetting state (water-wet or oil-wet) of pure calcite is conducted to study the importance of these interactions on the effectiveness of LSWF. In the case of initially water-wet cores, more oil recovery efficiency is observed for more saline water cases. To shed light on the possible involved mechanisms, dynamic IFT, dynamic contact angle (CA), oil/brine and rock/brine surfaces zeta potentials, and effluent pH are measured. It is shown that the short-term effect of IFT reduction and long-term effect of wettability alteration toward neutral-wetness (due to change in the electric charge of the crude-oil/brine and calcite/brine) are the dominating recovery mechanisms. However, the oil recovery behavior of oil-wet cores is in the opposite direction of that of water-wet cores, which demonstrates the wettability dependency of the involved mechanisms. CA measurement shows that diluted sea water (dSW) has more ability to change wettability toward water-wetness. The zeta potential results show that as brine salinity reduces, both crude-oil and rock surfaces become more negatively charged. Therefore, the observed wettability alteration behavior with salinity reduction is attributed to larger repulsion between these surfaces at lower salinity. pH results suggest CO32- ions are responsible to make calcite surface more negative with diluting SW brine. The oil recovery behavior is also a strong function of the initial wetting state. SW brine, recovered less oil and experienced an earlier breakthrough in an initially oil-wet core compared to an initially water-wet core. Unlike the previous case, dSW experienced higher ultimate oil recovery and almost the same breakthrough time in an initially oil-wet core compared to an initially water-wet core. The superior performance of the low salinity water in an oil-wet core is a result of the wettability alteration toward more water-wetness which triggers more piston-like advancement.",7,7,3
Crude Oil,Contact Angle,"Chen, Weidong; Schechter, David S.",Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs,,WETTABILITY ALTERATION; ADSORPTION; WET,"Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures. Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure. The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition. In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants. The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.",5,5,3
Crude Oil,Contact Angle,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Crude Oil,Contact Angle,"Ali, Muhammad; Jha, Nilesh Kumar; Al-Yaseri, Ahmed; Zhang, Yihuai; Iglauer, Stefan; Sarmadivaleh, Mohammad",Hydrogen wettability of quartz substrates exposed to organic acids; Implications for hydrogen geo-storage in sandstone reservoirs,Hydrogen geo-storage; Hydrogen storage capacity; Hydrogen wettability; Sandstone aquifer,SUPERCRITICAL CO2; CARBON-DIOXIDE; WET CARBONATE; HIGH-PRESSURE; CRUDE-OIL; TEMPERATURE; CO2-WETTABILITY; SURFACES; ADSORPTION; NANOFLUID,"Hydrogen is presently evaluated as a clean fuel to mitigate anthropogenic CO2 emissions and reduce the greenhouse gas effect. However, one of the major challenges for implementing a full hydrogen economy is hydrogen storage (as hydrogen is highly volatile and compressible). The solution to this problem is storing hydrogen into geological formations (as they are abundant and have large storing quantities). One of the key factors in this process is the wettability of the formation, which determines fluid dynamics, containment security, withdrawal rates, and storage capacities. To do this, we have determined the wettability of sandstone rock representative substrate through an extensive set of experiments in the presence of hydrogen. Whereas, almost all of these formations contains organic acids (hexanoic C6, lauric C12, and lignoceric C24 acids, respectively), even in minute concentrations, ranging from C4 to C26. Therefore, to fully comprehend the H2 wettability in a realistic scenario, we have aged quartz substrates in organic acids and conducted contact angle measurements under assorted storage conditions (temperature of 323 K, pressure of 0.1, 15, and 25 MPa). Our results show that pure quartz was inherently strongly water-wet (where 0a is 40.8 degrees and 0r is 35.1 degrees) and turned to intermediate water-wet (0a is 91.3 degrees and 0r is 82.7 degrees) in presence of H2 (at 323 K and 25 MPa) when the rock substrate was aged with organic acids having longer alkyl chain (10-2 Molarity (M) of lignoceric acid). This study, thus, provides crucial information for the implementation of the future hydrogen economy.",3,3,12
Crude Oil,Contact Angle,"Ali, Hassan; Soleimani, Hassan; Yahya, Noorhana; Khodapanah, Leila; Kozlowski, Gregory; Sabet, Maziyar; Demiral, Birol M. R.; Adebayo, Lawal Lanre; Hussain, Tanvir",Experimental investigation and two-phase flow simulation of oil and nanofluids on micro CT images of sandstone for wettability alteration of the system,Capillary pressure; Oil reservoir; Porous media; Permeability; Oil saturation,PORE NETWORK MODEL; POROUS-MEDIA; PERMEABILITY; TRANSPORT; WATER; MIGRATION; BRINE,"This work provides an analysis of the effect of nanofluids on the wettability of sandstone for the application of enhanced oil recovery. The wettability of sandstone with brine and nanofluids of ZnO, BiFeO3, and SrFeO3 is studied experimentally using contact angle calculations. Also, the direct simulations for the displacement of oil with brine and nanofluids are carried out on a micro-CT scanned porous sandstone structure for the measurement of capillary pressure and relative permeability. Fluid properties such as viscosity and density of the nanofluids, brine, and oil to be used in simulations were obtained using viscometer and densimeter. The experimental results show that the contact angle of crude oil on the sandstone surface has a higher value for nanofluids as 125.89 degrees for ZnO, 122.88 degrees for BiFeO3, and 104.98 for SrFeO3 as compared to brine 28.66 degrees, which means the wettability of the system changes from oil-wet to water-wet by the addition of nanofluids. The simulation results indicate that BiFeO3 nanofluid has a greater tendency to change the wettability of porous medium as compared to brine, ZnO, and SrFeO3 nanofluids, as it shows better values of relative permeability and capillary pressure.",3,3,5
Crude Oil,Contact Angle,"Seetharaman, Gomathi Rajalakshmi; Jadhav, Rohan M.; Sangwai, Jitendra S.",Effect of monovalent and divalent alkali [NaOH and Ca(OH)(2)] on the interfacial tension of pure hydrocarbon-water systems relevant for enhanced oil recovery,Alkali; Hydrocarbons; Hydroxide ions; Interfacial tension; Temperature,SURFACE-TENSION; WETTABILITY ALTERATION; IONIC LIQUIDS; ASP; HYDROXIDE; IMIDAZOLIUM; SALINITY; BEHAVIOR; SALTS,"Although various efficient enhanced oil recovery (EOR) techniques have been proposed, the use of chemicals such as alkali, surfactants, and polymer in the field of EOR makes chemical EOR a promising method. The residual oil left behind after the secondary recovery process can be successfully displaced by decreasing the interfacial tension (IFT) between the liquid-liquid systems. Moreover, understanding the IFT between the liquid-liquid systems are essential in formulating and controlling the multiphase and multicomponent processes. As crude oil is a complex mixture of organic, inorganic compounds and heteroatoms, understanding the IFT of the pure hydrocarbon-water system is vital to develop robust models. In this study, the IFT between pure hydrocarbon-water systems in the presence of alkali has been explored. The IFT measurements were performed using a dynamic contact angle tensiometer using a Wilhelmy plate. Different hydrocarbon liquids such as hexane, heptane, decane and aromatics such as benzene and toluene were used. The monovalent NaOH and divalent alkali Ca(OH)(2) in the concentration range of 0-37.5 mM are used to understand the effect of alkali on the IFT of the oil-water system. This paper also elaborates on the effect of temperature at 298.15 K, 323.15 K and 348.15 K on the IFT of hydrocarbon-water systems. The experimental results show that the increase in the concentration of alkali continuously decreased the IFT of hydrocarbon-water systems. Moreover, it has been found that the type of alkali also has a reasonable impact on the IFT of the hydrocarbon-water system. The divalent alkali [Ca(OH)(2)] is found to be more efficient in reducing the IFT of both alkane-water and aromatic-water systems than the moderately performed monovalent alkali (NaOH). The possible mechanism for the continuous reduction in IFT has been proposed using surface adsorption of hydroxide ions at the interface of the oil-water system.",3,3,3
Crude Oil,Heavy Oil,"Strelets, Larisa A.; Ilyin, Sergey O.",Effect of enhanced oil recovery on the composition and rheological properties of heavy crude oil,Heavy crude oil; Enhanced oil recovery; Oil composition; Rheology; Viscosity; Viscoelasticity,GLASS-FORMING LIQUIDS; POLYMER; ASPHALTENE; AGGREGATION; BITUMEN; MEDIA; STATE,"The composition and rheological properties of ten samples of heavy crude oil from five different wells were investigated before and after integrated oilfield treatment with gel-forming and oil-displacing systems for increasing oil recovery. The study of the viscosity and viscoelastic properties of oil samples in a wide temperature range (from -30 to 70 degrees C) made it possible to determine their gelation and glass transition temperatures and also to establish the effect of enhanced oil recovery treatment on these characteristics. It was found that the treatment can either increase or decrease the viscosity of oil, and the same applies to the gelation and glass transition temperatures as well as to the contents of saturates, resins, and asphaltenes. The rheological properties of oil samples were closely related to their group composition, while the changes in the latter as a result of oilfield treatment were dependent on the relative position of the injection and production wells. The work allowed finding universal correlations between the group composition of heavy oil, its viscosity, and test temperature.",10,10,4
Crude Oil,Heavy Oil,"Varfolomeev, Mikhail A.; Yuan, Chengdong; V. Bolotov, Alexander; Minkhanov, Ilgiz F.; Mehrabi-Kalajahi, Seyedsaeed; Saifullin, Emil R.; Marvanov, Marat M.; Baygildin, Emil R.; Sabiryanov, Raushan M.; Rojas, Allan; Emelianov, Dmitrii A.; Al-Muntaser, Ameen A.; Ganiev, Bulat G.; Zaripov, Azat T.; Beregovoi, Anton N.; Shaihutdinov, Damir K.",Effect of copper stearate as catalysts on the performance of in-situ combustion process for heavy oil recovery and upgrading,In-situ combustion; In-situ upgrading; Heavy oil; Copper stearate; Oil-soluble catalyst; Catalytic combustion,LIGHT CRUDE-OIL; OXIDATION BEHAVIOR; NANOPARTICLES; ASPHALTENES; KINETICS; DECOMPOSITION; ADSORPTION; PYROLYSIS,"Using copper stearate as catalysts, catalytic in-situ combustion (ISC) of heavy oil was studied by porous medium thermo-effect cell (PMTEC) and combustion tube experiments. Significant acceleration of combustion was observed in porous media in PMTEC when copper stearate was added. Copper stearate promoted fuel deposition and its combustion and made them occur easier in low temperature, thus shifting both low-temperature oxidation (LTO) and high-temperature oxidation (HTO) into lower temperatures, and even totally merge HTO into LTO in some conditions. We found that the promotion on fuel deposition by catalysts might be related to the change of H/C ratio in fuel. The improvement in the performance of ISC by copper stearate in combustion tube experiments mainly manifests in lower ignition temperature, lower H/C ratio, increased air/fuel ratio, higher oil recovery, and higher level of in-situ oil upgrading, which makes copper stearate a good candidate for catalyzing ISC in field application.",9,9,6
Crude Oil,Heavy Oil,"Onaizi, Sagheer A.; Alsulaimani, Mohammed; Al-Sakkaf, Mohammed K.; Bahadi, Salem A.; Mahmoud, Mohamed; Alshami, Ali",Crude oil/water nanoemulsions stabilized by biosurfactant: Stability and pH-Switchability,Crude oil/water nanoemulsions; Emulsion stability; Rhamnolipid biosurfactant; pH-responsive; Demulsification; Droplet size,OIL-IN-WATER; INTERFACIAL-TENSION; POROUS-MEDIA; SURFACTIN BIOSURFACTANT; SILICA NANOPARTICLES; RECOVERY; EMULSIONS; EMULSIFICATION; COMBINATION; BACTERIA,"Emulsification is one of the proposed mechanisms for enhancing crude oil recovery in chemical flooding. The replacement of chemical surfactants in enhanced oil recovery (EOR) applications with biosurfactants is an attractive alternative; yet, there is a lack of studies on the crude oil emulsification using biosurfactants. Particularly, the formulation of crude oil/water (crude O/W) nanoemulsions with an extreme stability and a pH-responsiveness behavior is still not documented in the literature, to the best of our knowledge. Accordingly, we report in this study the preparation of both light and heavy crude oil/water emulsions using different concentrations of the rhamnolipid biosurfactant. The emulsions were prepared in a two-step process: stirring overnight to create coarse emulsions followed by sonication. All the prepared emulsions have a nanoscale size (e.g., about 50% of the formed droplets at 0.1 wt% rhamnolipid are < 200 nm in size), which decreases with increasing the biosurfactant concentration. The zeta potential values of the formed crude O/W nanoemulsions were highly negative (<=-39.3). Increasing the biosurfactant concentration resulted in a more negative zeta potential. The formulated crude O/W nanoemulsions were extremely stable with 0% oil or water separation even after a month of storage. Despite the extreme stability of these crude O/W nanoemulsions, they could be easily switched off (i. e., demulsified) within 1 h by pH-swing via the addition of 50 mM sulfuric acid (H2SO4) regardless of the bioemulsifier (i.e., rhamnolipid) concentration. It was also possible to switch on/off the crude O/W nanoemulsions a number of times (at least five times) through this pH-swing mechanism. We also demonstrated that the crude O/W nanoemulsions can be completely switched off through the addition of NaOH, particularly, when these crude O/W nanoemulsions are stabilized by low rhamnolipid dosages (<= 0.5 wt%); such an observation is very unusual. The findings reported in this study clearly demonstrate the ability of creating extremely stable crude O/W nanoemulsions, which is desirable in EOR; however, the emulsified crude oil can be easily and economically recovered via a simple and an economic process (i.e., pH-switch) with the ability to switch off/on the emulsion several times.",7,7,6
Crude Oil,Heavy Oil,"Volkov, Vladimir Y.; Al-Muntaser, Ameen A.; Varfolomeev, Mikhail A.; Khasanova, Nailia M.; Sakharov, Boris, V; Suwaid, Muneer A.; Djimasbe, Richard; Galeev, Ranel, I; Nurgaliev, Danis K.",Low-field NMR-relaxometry as fast and simple technique for in-situ determination of SARA-composition of crude oils,Low field NMR relaxation; SARA analysis; Heavy oil; Light oil; Group composition,LIQUID-CHROMATOGRAPHY; HEAVY OIL; FRACTIONS; ASPHALTENES; SEPARATION; PHASE; LIGHT; HPLC; PRECIPITATION; SPECTROSCOPY,"In this study a new, fast and simple method based on low field NMR-relaxometry for in-situ determination of SARA (saturates, aromatics, resins and asphaltenes) composition of crude oils was proposed. This method was tested on 22 samples of crude oils with a wide range of SARA-composition and API gravity values (4.6-42.0 degrees), including extra-heavy, heavy, medium and light crude oils. Results obtained by low-field nuclear magnetic resonance (LF-NMR) were compared with conventional SARA analysis method (ASTM D 4124). Comparison shows good coincidence between SARA values determined by LF-NMR and conventional method data for heavy fractions of asphaltenes and resins (R-2 is equal to 0.98 and 0.91, respectively) and for the sum of light fractions including saturates and aromatics (R-2 = 0.96). However, comparison for saturated and aromatic compounds separately gave low correlation coefficients (R-2 <= 0.61 and 0.27, respectively) and relatively soaring standard deviation for individual correlations for saturates and aromatics (8.18 and 9.20). Consequently, LF- NMR relaxation as an alternative method for studying the composition of crude oil allows the determination of asphaltenes, resins and the sum of light fractions (saturates and aromatics) without their extraction (in-situ), which greatly simplifies and accelerates conventional chromatographic analysis. This method can be successfully applied for different types of crude oils with a wide range of API gravity and viscosity values.",7,7,3
Crude Oil,Heavy Oil,"Pham, Hung Hai; Kim, Kwang Ho; Go, Kang Seok; Nho, Nam Sun; Kim, Woohyun; Kwon, Eun Hee; Jung, Ryu Ho; Lim, Young-il; Lim, Suk Hyun; Pham, Dung Anh",Hydrocracking and hydrotreating reaction kinetics of heavy oil in CSTR using a dispersed catalyst,Reaction kinetics; Hydrocracking; Hydrotreating; H-2 consumption; Heavy oil; Dispersed catalyst,SLURRY-PHASE HYDROCRACKING; MAYA CRUDE-OIL; MODERATE HYDROCRACKING; REACTION TEMPERATURE; VACUUM RESIDUE; HYDROCONVERSION; LIQUID; MODEL; TIME,"A kinetic model for the slurry phase hydrocracking of vacuum residue was proposed under conditions of: 410-450 degrees C, 0.25 1 hr(-1), 160 bar, 1500 Nm(3)/m(3) of H-2 to oil ratio, and 500 ppm catalyst (Mo-octoate). A five-lump model with ten reaction pathways was adopted to describe the hydrocracking kinetics, while the hydrotreating reactions were modeled by the power-law approach. The kinetic parameters were estimated considering the change in liquid density with reaction time. The kinetic model predicted product yields and concentrations with an average error of less than 10%. As for the hydrocracking reaction, it was demonstrated that the secondary cracking of VGO mainly produced MD at high temperature and the high conversion of RES. As for hydrotreating, it was confirmed that asphaltene conversion proceeded to increase the removal level of other impurities. Finally, a hydrogen consumption rate model was proposed based on HCK and HDT, which provides consistent information for further uses in reactor modeling and process modeling.",6,6,2
Crude Oil,Heavy Oil,"Keykhosravi, Amin; Vanani, Mozhdeh Bagheri; Aghayari, Chia",TiO2 nanoparticle-induced Xanthan Gum Polymer for EOR: Assessing the underlying mechanisms in oil-wet carbonates,Enhanced oil recovery; Xanthan gum polymer; Anatase titanium dioxide nanoparticles; Wettability alteration; Shear viscosity,HEAVY CRUDE-OIL; SILICA NANOPARTICLE; SPONTANEOUS IMBIBITION; INTERFACIAL PROPERTIES; WETTABILITY ALTERATION; RECOVERY; SURFACTANT; NANOFLUIDS; SALINITY; TEMPERATURE,"This work systematically investigates the potential of Anatase TiO2 nanoparticles-induced Xanthan-gum polymer as a Nano-polymer suspension for enhanced oil recovery (EOR) in carbonates. For this purpose, initially, viscosity of Xanthan gum polymer with and without the nanoparticles (NPs) was examined at different conditions. The stability of the suspensions was determined qualitatively and quantitatively. The capability of the Nano-polymer suspensions for wettability alteration was explored using contact angle measurement aided by a mathematical approach. Interfacial tension measurement was performed. Finally, oil displacement experiments were conducted to examine EOR efficiency of the Nano-polymer suspension. We found that while increasing temperature and adding salt to polymeric solutions caused a reduction in shear viscosity, the addition of NPs to the solutions could relatively recover the viscosity. The presence of polymers in the nanofluids improved dispersion stability of NPs. Also, the Nano-polymer suspensions could extend the ability of the NPs for wettability alteration and faster equilibrium states obtained than the polymer-free nanofluids. The mathematical model derived based on the equation of kinetic adsorption could describe the wettability alteration process well and successfully captured contact angle profiles. Results of the oil displacement tests revealed that whereas TiO2 nanofluid and polymer solution showed additional oil recovery values of 12 and 19% of OOIP, respectively, 25% additional oil was produced using Anatase TiO2-induced Xanthan gum polymer flooding.",3,3,16
Crude Oil,Heavy Oil,"Li, Hanyong; Gao, Hang; Zhao, Xiaonan; Xia, Zijie; Yu, Bo; Sun, Dongliang",Experimental study on viscosity reduction of heavy oil with water content by synergistic effect of microwave and nano-catalyst,Viscosity reduction; Microwave heating; Nano-catalyst; Heavy oil; Water content,CRUDE-OIL; ASPHALTENES; DEMULSIFICATION; NANOPARTICLES; EMULSIONS; RECOVERY,"With the depleting of conventional oil and gas resources, viscosity reduction of heavy oil became more and more important as a research focus. As a new method of viscosity reduction, the mechanism of microwave-assisted with nano-catalysts is still unclear. In this paper, the viscosity reduction of nano-catalyst and microwave treatment of heavy oil in different water content was studied. The experimental results showed that the maximum viscosity reduction was 96.81 % when the water content was 50 wt% under the conditions of microwave heating power of 614w, microwave heating temperature of 68 degrees C and nickel nano-catalyst concentration of 0.8 wt%. The oil samples before and after three treatments were analyzed by infrared spectroscopy, element analysis, four-component separation, and two-dimensional gas chromatography-mass spectrometry. By analyzing the changes of functional group, element composition, and component content, the effects of microwave and nano-catalyst were studied. The results showed that the resin and asphaltene content decreased by 17.3 wt%, and the hydrogen to carbon ratio was 2.14 when the water content was 30 wt% under the conditions of microwave heating power of 666w, microwave heating temperature of 65 degrees C and nickel nano-catalyst concentration of 2.3 wt%, which proved that microwave treatment assisted with nano-catalysts could increase the cracking capacity of macromolecules and the production of coke.",3,3,10
Crude Oil,Heavy Oil,"Abdullah, Mahmood M. S.; Al-Lohedan, Hamad A.",Synthesis and characterization of tannic acid esters and their performances as asphaltenes dispersants,Tannic acid; Asphaltene; Dispersants; Esters,IONIC LIQUIDS; NATURAL-PRODUCTS; HEAVY; INHIBITION; PRECIPITATION; DEMULSIFIER; CARDANOL; IMIDAZOLIUM; DEPOSITION; MODIFIERS,"Asphaltene aggregation and flocculation in upstream and downstream industries cause severe problems due to phase separation and asphaltene particle growth. This work aims to esterify tannic acid (TA) at different molar ratios of heptanoyl chloride (HC) 1:3, 1:6, and 1:9, producing species TA-HC3, TA-HC6, and TA-HC9, respectively. The synthesized esters were characterized by Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance (H-1-NMR), and thermal analyses. Their performances as asphaltene dispersants of Arabian heavy crude oil were assessed by dynamic light scattering (DLS), ultraviolet-visible (UV-Vis) spectroscopy, and viscosity measurements. All specimens (TA-HC3, TA-HC6, and TA-HC9) dispersed asphaltene, and their dispersal abilities increased with increasing number of alkyl chains (i.e., TA-HC3 > TA-HC6 > TA-HC9).",3,3,6
Crude Oil,Degrees C.,"Strelets, Larisa A.; Ilyin, Sergey O.",Effect of enhanced oil recovery on the composition and rheological properties of heavy crude oil,Heavy crude oil; Enhanced oil recovery; Oil composition; Rheology; Viscosity; Viscoelasticity,GLASS-FORMING LIQUIDS; POLYMER; ASPHALTENE; AGGREGATION; BITUMEN; MEDIA; STATE,"The composition and rheological properties of ten samples of heavy crude oil from five different wells were investigated before and after integrated oilfield treatment with gel-forming and oil-displacing systems for increasing oil recovery. The study of the viscosity and viscoelastic properties of oil samples in a wide temperature range (from -30 to 70 degrees C) made it possible to determine their gelation and glass transition temperatures and also to establish the effect of enhanced oil recovery treatment on these characteristics. It was found that the treatment can either increase or decrease the viscosity of oil, and the same applies to the gelation and glass transition temperatures as well as to the contents of saturates, resins, and asphaltenes. The rheological properties of oil samples were closely related to their group composition, while the changes in the latter as a result of oilfield treatment were dependent on the relative position of the injection and production wells. The work allowed finding universal correlations between the group composition of heavy oil, its viscosity, and test temperature.",10,10,4
Crude Oil,Degrees C.,"Pham, Hung Hai; Kim, Kwang Ho; Go, Kang Seok; Nho, Nam Sun; Kim, Woohyun; Kwon, Eun Hee; Jung, Ryu Ho; Lim, Young-il; Lim, Suk Hyun; Pham, Dung Anh",Hydrocracking and hydrotreating reaction kinetics of heavy oil in CSTR using a dispersed catalyst,Reaction kinetics; Hydrocracking; Hydrotreating; H-2 consumption; Heavy oil; Dispersed catalyst,SLURRY-PHASE HYDROCRACKING; MAYA CRUDE-OIL; MODERATE HYDROCRACKING; REACTION TEMPERATURE; VACUUM RESIDUE; HYDROCONVERSION; LIQUID; MODEL; TIME,"A kinetic model for the slurry phase hydrocracking of vacuum residue was proposed under conditions of: 410-450 degrees C, 0.25 1 hr(-1), 160 bar, 1500 Nm(3)/m(3) of H-2 to oil ratio, and 500 ppm catalyst (Mo-octoate). A five-lump model with ten reaction pathways was adopted to describe the hydrocracking kinetics, while the hydrotreating reactions were modeled by the power-law approach. The kinetic parameters were estimated considering the change in liquid density with reaction time. The kinetic model predicted product yields and concentrations with an average error of less than 10%. As for the hydrocracking reaction, it was demonstrated that the secondary cracking of VGO mainly produced MD at high temperature and the high conversion of RES. As for hydrotreating, it was confirmed that asphaltene conversion proceeded to increase the removal level of other impurities. Finally, a hydrogen consumption rate model was proposed based on HCK and HDT, which provides consistent information for further uses in reactor modeling and process modeling.",6,6,2
Crude Oil,Degrees C.,"Elmobarak, Wamda F.; Almomani, Fares",Application of magnetic nanoparticles for the removal of oil from oil-in-water emulsion: Regeneration/reuse of spent particles,Oil-in-water emulsion (O-in-W-Emu); Fe3O4 magnetic nanoparticles; Demulsification efficiency; Oil removal,IRON-OXIDE NANOPARTICLES; SOLUTION-COMBUSTION SYNTHESIS; WASTE-WATER; FE3O4 NANOPARTICLES; HYDROTHERMAL SYNTHESIS; EFFICIENT SEPARATION; EPITAXIAL-FILMS; CRUDE-OIL; ADSORPTION; FACILE,"The recovery of oil from produced water (PW) is integral for minimizing energy resource loses and creating an appropriate treatment method for a sustainable environment. In this study, Fe3O4 magnetic nanoparticles (Fe-MNP) were synthesized using the combustion synthesis method (CSM) in the temperature range of 150 to 350 degrees C. The Fe-MNP were characterized using various analytical techniques and were used to recover oil from oil-inwater emulsion (O-in-W-emu) at various concentrations. The effects of the process parameters including, pH, oil concentration (C-oil), Fe-MNP dose (D-MNP), the surfactant concentration (C-sur) on the demulsification efficiency (%(eta dem)), and the percentage oil removal (%R-oil) were studied. Further, the re-usability of the assynthetized Fe-MNP were examined and reported. The as-synthetized Fe-MNP achieved a %(eta dem) >= 98% for C-oil in the range of 200-660 mg/L. Up to 98.6% of the %(eta dem) was attained for C-oil in the range from 0 to 800 mg/L using only a DMNP of 10 mg/L. A lower D-MNP of 5 mg/L recovered up to 55.6% of the oil, while increasing the D-MNP > 50 mg/L did not significantly affect the %(eta dem) nor the %(eta dem). The observed %(eta dem) at a pH of 4 and C-sur of 0.05 g/L was observed to be > 90 + 0.1% and decreased by either rising the pH to 7 or increasing the C-sur to 0.1 g/L. This change is due to the decrease in the emulsion stability and the formation of fine oil droplets. Stability and re-usability tests of the as-synthetized Fe-MNP exhibited an effective oil recovery of up to 90% after 7 cycles. The as-synthesized Fe-MNP demulsifier exhibited an excellent adsorption capacity of 51 mg/g and best fit the Langmuir and Freundlich models. The kinetics of the oil recovery process are properly adapted to fit the pseudosecond-order model for the C-oil and D-MNP. The tests indicated that the fastest and highest adsorption capacity was achieved at a D-MNP (100 mg/L). As such, the results indicate that the developed Fe-MNP are an effective and reusable demulsifier, which are suitable for the oil recovery of produced water (PW).",5,5,7
Crude Oil,Degrees C.,"Zhao, Feng; Zhu, Hongbin; Cui, Qingfeng; Wang, Bingxin; Su, Han; Zhang, Ying",Anaerobic production of surfactin by a new Bacillus subtilis isolate and the in situ emulsification and viscosity reduction effect towards enhanced oil recovery applications,Microbial enhanced oil recovery; Anaerobic conditions; Bacillus subtilis; Surfactin; Emulsifying activity; Viscosity reduction,,"Emulsification and viscosity reduction effect of biosurfactants to crude oil are significant for enhanced oil recovery. Although biosurfactants for enhanced oil recovery were extensively studied, information on the anaerobic production of biosurfactants and its in situ effect to crude oil are still limited. Bacillus subtilis AnPL-1 was isolated from oil reservoirs production water and produced 150 mg/l of biosurfactants under anaerobic conditions. Sucrose and nitrate were favorable for anaerobic production of biosurfactants by strain AnPL-1. Strain AnPL-1 anaerobically produced biosurfactants at temperatures (20 degrees C-50 degrees C), pH values (6-9) and 0-7% of NaCl. FTIR and HPLC-MS analysis showed that the anaerobically produced biosurfactants was a mixture of C-13-, C-14- and C-15-surfactin congeners. Anaerobically produced surfactin decreased water surface tension to 28.5 mN/m with a critical micelle concentration of 30 mg/l. It can also emulsify crude oil with an emulsion index (EI24) of 70.5%. Strain AnPL-1 also produced 115 mg/l biosurfactants under simulated oil reservoirs conditions (anaerobic and 10 MPa conditions). Furthermore, strain AnPL-1 anaerobically grew well in the presence of crude oil. Strain AnPL-1 reduced the crude oil viscosity by 40.6% through in situ emulsification effect of produced biosurfactants. In core flooding tests, in situ biosurfactants production by strain AnPL-1 enhanced oil recovery of 9.98%. Although B. subtilis is a facultative anaerobe, anaerobic production of biosurfactants by B. subtilis for MEOR applications has been firstly studied. Without air injection, anaerobic production of surfactin by B. subtilis AnPL-1 is promising for in situ MEOR applications.",4,4,2
Crude Oil,Degrees C.,"Li, Hanyong; Gao, Hang; Zhao, Xiaonan; Xia, Zijie; Yu, Bo; Sun, Dongliang",Experimental study on viscosity reduction of heavy oil with water content by synergistic effect of microwave and nano-catalyst,Viscosity reduction; Microwave heating; Nano-catalyst; Heavy oil; Water content,CRUDE-OIL; ASPHALTENES; DEMULSIFICATION; NANOPARTICLES; EMULSIONS; RECOVERY,"With the depleting of conventional oil and gas resources, viscosity reduction of heavy oil became more and more important as a research focus. As a new method of viscosity reduction, the mechanism of microwave-assisted with nano-catalysts is still unclear. In this paper, the viscosity reduction of nano-catalyst and microwave treatment of heavy oil in different water content was studied. The experimental results showed that the maximum viscosity reduction was 96.81 % when the water content was 50 wt% under the conditions of microwave heating power of 614w, microwave heating temperature of 68 degrees C and nickel nano-catalyst concentration of 0.8 wt%. The oil samples before and after three treatments were analyzed by infrared spectroscopy, element analysis, four-component separation, and two-dimensional gas chromatography-mass spectrometry. By analyzing the changes of functional group, element composition, and component content, the effects of microwave and nano-catalyst were studied. The results showed that the resin and asphaltene content decreased by 17.3 wt%, and the hydrogen to carbon ratio was 2.14 when the water content was 30 wt% under the conditions of microwave heating power of 666w, microwave heating temperature of 65 degrees C and nickel nano-catalyst concentration of 2.3 wt%, which proved that microwave treatment assisted with nano-catalysts could increase the cracking capacity of macromolecules and the production of coke.",3,3,10
Crude Oil,Degrees C.,"Akhlaghi, Naser; Riahi, Siavash; Parvaneh, Ronak","Interfacial tension behavior of a nonionic surfactant in oil/water system; salinity, pH, temperature, and ionic strength effects",Triton X-100; IFT; CMC; Enhanced oil recovery; PH; Salinity,ENHANCED OIL-RECOVERY; ASSISTED GRAVITY DRAINAGE; ACIDIC CRUDE-OIL; WATER; IFT; WETTABILITY; BRINE; PERFORMANCE; ASPHALTENE; COMPONENTS,"Since most of the world's oil reservoirs are in the second half lifetime, the use of Enhanced Oil Recovery (EOR) methods is inevitable. Interfacial Tension (IFT) is one of the effective parameters on EOR can be changed by surfactants. But surfactant injection is one of the costly methods and chemistry of the surfactant solutions such as salinity (one and two valence ions) and pH should be engineered. Furthermore, the temperature is an effective parameter affecting on IFT. In this study, the effect of salinity, especially hard salinity, temperature and pH on IFT between Triton X-100 surfactant and an Iranian oil sample has been investigated. In order to, evaluate the effect of salinity, different concentrations of NaCl, CaCl2, MgCl2, and Na2SO4 salts (0, 0.1, 0.5, and 1 wt%) were used in different concentrations of surfactant. IFT results showed that magnesium and calcium divalent cations had a greater effect on IFT reduction than monovalent sodium cation. Also, all the studied cations were more effective than sulfate as a divalent anion. The ionic strength of the solutions was inversely proportional to the IFT amounts. Less value of IFT in the presence of magnesium ions than calcium ions was due to the higher ionic strength of solutions containing magnesium compared with calcium. IFT results at three temperatures (20, 40, and 60 degrees C) proved that by increasing temperature IFT increased. Also, the effect of pH on IFT in three pHs including acidic, almost neutral and alkaline in the presence of surfactant was studied. Results indicated that IFT decreased with increasing pH, especially in concentrations lower than critical micelle concentration (CMC).",3,3,4
Crude Oil,Degrees C.,"Wang, Wenqiang; Wang, Tieguan; Li, Meijun; Mao, Fengjun; Liu, Jiguo; Xiao, Hong; Lai, Hongfei; Ai, Xinyu",The origins of biodegraded oils in sandstone reservoirs in the Termit Basin,Geochemical characteristics; Biodegraded oil; Termit basin; Geological condition,HIGH ACIDITY OILS; CRUDE-OIL; SOURCE ROCKS; GEOCHEMICAL CHARACTERISTICS; COMPOSITIONAL CHANGES; DEEP SUBSURFACE; CENTRAL-AFRICA; RIFT BASINS; TARIM BASIN; PETROLEUM,"Systematic geochemical analysis of 39 crude oils from the Termit Basin, Niger, all belonging to the same oil family, reveals distinct differences in bulk properties and molecular compositions, which were undoubtedly caused by differences in the extent of biodegradation. Various degrees of microbial alteration were identified in crude oils, which were classified as non-, slightly, moderately, or heavily degraded oils, according to their physical properties, bulk chemical compositions, and certain molecular biomarker characteristics. Examination of the possible origins and geological backgrounds of the biodegraded oils shows that reservoirs with deeper burial depths (greater than 1800 m), thicker caprocks (>100 m), relatively higher stratigraphic temperatures (>80 degrees C), and which have been subject to the influence of silent faults had not suffered significant biodegradation. The burial depth of reservoirs is therefore considered to be the main factor controlling the biodegradation process, and may offset other factors if the depth is sufficient. The Paleogene reservoirs in the Dinga Step-Fault Zone (DSFZ) that meet all of these conditions are therefore dominated by normal oils. Degraded oils of varying degrees are widely distributed in other tectonic units where at least one of these factors is absent. This study may have practical application for further petroleum exploration, prediction of petroleum properties, and the reduction of production risk.",3,3,3
Crude Oil,Reaction,"Mohammadi, Mohammad-Reza; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Husein, Maen M.; Ranjbar, Mohammad",Application of cascade forward neural network and group method of data handling to modeling crude oil pyrolysis during thermal enhanced oil recovery,In-situ combustion; EOR; Pyrolysis; TGA; Artificial neural networks; Group method of data handling,IN-SITU COMBUSTION; MINIMUM MISCIBILITY PRESSURE; GENERALIZED REGRESSION; COMPRESSIBILITY FACTOR; KINETICS; PREDICTION; VISCOSITY; HYBRID; ASPHALTENES; OXIDATION,"Oil recovery during in situ combustion is majorly controlled by hydrocarbon oxidation and pyrolysis reactions, which govern fuel formation and heat evolution. Fuel deposition, in turn, can be accurately predicted in part through crude oil pyrolysis using thermogravimetry analysis (TGA). The theoretical models based on TGA runs, however, may be limited to crude oil samples at hand. In this study, we develop more general models to predict the residual mass during crude oil pyrolysis based on multi-layer perceptron (MLP), cascade forward (CFNN), generalized regression (GRNN), and radial basis function (RBF) neural networks. More than 2000 experimental data spanning wide range of weight percentages of asphaltenes and resins as well as oAPI gravities, heating rates, and temperatures are used. Moreover, six optimization algorithms; including Bayesian regularization (BR), scaled conjugate gradient (SCG), Levenberg-Marquardt (LM), conjugate gradient backpropagation with FletcherReeves updates (CGF), resilient backpropagation (RB), and conjugate gradient backpropagation with PolakRibie ' re updates (CGP) are used to improve the performance and prediction ability of the MLP and CFNN neural networks. The CFNN model optimized with the LM algorithm best fits all the experimental data with a mean absolute percent relative error of 1.04%. Lastly, a mathematical correlation is developed utilizing the group method of data handling (GMDH) to estimate the residual mass of crude oil pyrolysis in TGA. Despite its simplicity, the correlation also provides very good estimates. Sensitivity analysis showed that temperature followed by asphaltenes and resin content showed the highest effect on mass loss during crude oil pyrolysis. Outliers estimation applying the Leverage approach suggested only 1% of the data points could be doubtful.",11,11,1
Crude Oil,Reaction,"Kok, Mustafa Versan; Varfolomeev, Mikhail A.; Nurgaliev, Danis K.","TGA and DSC investigation of different clay mineral effects on the combustion behavior and kinetics of crude oil from Kazan region, Russia",Clay; Combustion; Crude oil; Kinetic analysis; Thermogravimetry; Differential scanning calorimeter,,"In this research, the effect of different clay minerals (bentonite, illite and kaolinite) on the combustion behavior and kinetics of crude oils from Kazan region (Russia) was studied using thermogravimetry (TGA) and differential scanning calorimeter (DSC). The ramped temperature experiments were performed at constant heating rates (10, 20 and 30 degrees C/min) under air atmosphere. In both TGA and DSC experiments, two reaction zones were identified known as low temperature oxidation (LTO) and high temperature oxidation (HTO). The reaction regions, burnout temperatures, mass loss, heat of reaction and peak temperatures were determined. It was observed that the reaction intervals and the peak temperatures were also affected in the presence of different clay minerals. Kinetic parameters were calculated by Ozawa-Flynn-Wall (OFW), Kissenger-Akahira-Sunouse (KAS) kinetic methods. The addition of different clay minerals reduced the mass loss percentages of the crude oil samples due to the surface area effect. In addition, all clay samples show a good catalytic effect by a significant reduction in activation energy.",6,6,5
Crude Oil,Reaction,"Pham, Hung Hai; Kim, Kwang Ho; Go, Kang Seok; Nho, Nam Sun; Kim, Woohyun; Kwon, Eun Hee; Jung, Ryu Ho; Lim, Young-il; Lim, Suk Hyun; Pham, Dung Anh",Hydrocracking and hydrotreating reaction kinetics of heavy oil in CSTR using a dispersed catalyst,Reaction kinetics; Hydrocracking; Hydrotreating; H-2 consumption; Heavy oil; Dispersed catalyst,SLURRY-PHASE HYDROCRACKING; MAYA CRUDE-OIL; MODERATE HYDROCRACKING; REACTION TEMPERATURE; VACUUM RESIDUE; HYDROCONVERSION; LIQUID; MODEL; TIME,"A kinetic model for the slurry phase hydrocracking of vacuum residue was proposed under conditions of: 410-450 degrees C, 0.25 1 hr(-1), 160 bar, 1500 Nm(3)/m(3) of H-2 to oil ratio, and 500 ppm catalyst (Mo-octoate). A five-lump model with ten reaction pathways was adopted to describe the hydrocracking kinetics, while the hydrotreating reactions were modeled by the power-law approach. The kinetic parameters were estimated considering the change in liquid density with reaction time. The kinetic model predicted product yields and concentrations with an average error of less than 10%. As for the hydrocracking reaction, it was demonstrated that the secondary cracking of VGO mainly produced MD at high temperature and the high conversion of RES. As for hydrotreating, it was confirmed that asphaltene conversion proceeded to increase the removal level of other impurities. Finally, a hydrogen consumption rate model was proposed based on HCK and HDT, which provides consistent information for further uses in reactor modeling and process modeling.",6,6,2
Crude Oil,Reaction,"Wang, Yamin; Yu, Muhan; Bo, Zhenkai; Bedrikovetsky, Pavel; Le-Hussain, Furqan",Effect of temperature on mineral reactions and fines migration during low-salinity water injection into Berea sandstone,Temperature; Ion exchange reaction; Permeability decrease; Fines migration; Low-salinity water injection; Water disposal,OIL-RECOVERY; ION-EXCHANGE; MATHEMATICAL-MODEL; BRINE COMPOSITION; RESERVOIR ROCKS; SLOW MIGRATION; 2-PHASE FLOW; CRUDE-OIL; DISSOLUTION; PERMEABILITY,"Recent experiments on sandstone rocks found more fines migration at higher temperature. They attributed this to temperature-dependent zeta potential. However, temperature also affects mineral reactions. The present study investigates the effect of temperature on both fines migration and mineral reactions. Two sets of single-phase injection experiments are performed using Berea sandstone sister plugs. In one set of experiments, solutions of NaCl brine are injected at a constant temperature of 25 ?C, 50 ?C, or 70 ?C. In the other set, solutions of CaCl2 brine are injected at a constant temperature of 25 ?C or 50 ?C. All plugs are subjected to five sequential injections of the designated brine at salinities 0.684 mol/L, 0.171 mol/L, 0.043 mol/L, 0.0085 mol/L, and 0 mol/L. Permeability at each injection stage is calculated from pressure difference across the core. When NaCl brine is used, the percentage of permeability decrease is found to be 99% at 25 ?C, 90% at 50 ?C, and 40% at 70 ?C. The lower permeability decrease at high temperature is found to be accompanied by a smaller concentration of produced fines. Comparison of scanning electron microscope images taken before and at the end of each experiment shows pore enlargement due to mineral reaction at high temperature, which further explains the lower permeability decrease. Ionic concentrations of Ca2+ and Mg2+ in the produced water are found to be greater at higher temperature, due to higher reaction rate. With CaCl2 brine, a 7% permeability decrease is observed at 25 ?C, whereas a 20% permeability increase is observed at 50 ?C. The observed fines concentration and increase in Ca2+ ion production are found to be lower than with NaCl brine, which is attributed to ion exchange between Na+ and Ca2+ with NaCl brine. Temperature affects both (1) permeability increase due to pore enlargement caused by mineral reactions, and (2) permeability decrease due to fines migration.",5,5,1
Crude Oil,Reaction,"Mirkhoshhal, Seyed Mehdi; Mahani, Hassan; Ayatollahi, Shahab; Shirazi, Maysam Mohammadzadeh",Pore-scale insights into sludge formation damage during acid stimulation and its underlying mechanisms,Acid stimulation; Formation damage; Pore-scale mechanism; Acid sludge; Acid-oil emulsion; Microfluidics,ASPHALTENE PRECIPITATION; OIL; WATER; VISUALIZATION; SALINITY; PREVENTION; MICROMODEL; DEPOSITION; ROCK,"Acid-oil emulsion and sludge formation are known as two major formation damage mechanisms and the reason for failure of some acid treatments. The published studies in this area focus primarily on core- to well/reservoir-scale and it is fairly unclear how acid-oil interaction at the pore-scale leads to the formation damage observed at the macro- or core-scale. In this paper, dynamic, micro-scale experiments were designed and executed to investigate the acid-induced formation damage using microfluidic approach. In addition, a series of so-called static (microscope) tests were performed in which acid-crude oil compatibility tests were conducted on a glass slide followed by microscopic observation to better analyze the micromodel results. The results show that sludge precipitation occurred right at the interface of the crude oil and acid; either with the residual oil film on the pore wall, at the acid-oil displacement menisci or acid-oil interfaces in the emulsion. Although, it is theoretically assumed that the reaction between acid and crude oil is fast, the results highlight that the damage is intensified by increasing the exposure time up to 8 hours. Besides, the acid type and concentration showed to have considerable impact on the acid-sludge and emulsion formation. The dynamic results indicate that increasing live acid concentration from 15 wt% to 28 wt% caused about 27.5% more permeability impairment due to sever pore-bridging, while spent acid did not result in any acid-sludge deposit. Furthermore, the role of ferric ion, as a transfer catalyst facilitating the two-phase contact, was visually confirmed through static tests. The dynamic tests also indicated 13% more permeability reduction when 3000 ppm ferric ion was present during 28 wt% HCl injection compared with the free-iron case. Emulsion analysis at the pore-scale showed that acid emulsion critically plugs the pore throats and intensify acid-sludge depositions. Size of acid-oil emulsion droplets was found to be distance-dependent such that as the acid permeated deeper into the porous medium the emulsions became finer and denser causing increased damage. Mitigating formation damage requires underpinning the mechanisms, the microfluidic approach can assist in identifying whether sludge precipitation or emulsion formation are the chief mechanisms and can serve as a fast, intermediate step before conducting the time intensive acidizing experiments at core-scale.",4,4,1
Crude Oil,Reaction,"Mokhtari, Rasoul; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.",Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs,Enhanced oil recovery; Low salinity water; Core-flooding; Chalk; Ion chromatography,DETERMINING IONS CA2+; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; DISSOLUTION KINETICS; CALCITE DISSOLUTION; BRINE CHEMISTRY; NORTH-SEA; RECOVERY; IMPACT; CARBONATES,"Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.",3,3,5
Crude Oil,Source Rocks,"Al-Khafaji, Amer Jassim; Hakimi, Mohammed Hail; Mohialdeen, Ibrahim M. J.; Idan, Rami M.; Afify, Wafaa E.; Lashin, Aref A.","Geochemical characteristics of crude oils and basin modelling of the probable source rocks in the Southern Mesopotamian Basin, South Iraq",Oil-oil correlation; Cretaceous reservoirs; Carbon isotope; Biomarker ratios; Basin modeling; Mesopotamian basin; South Iraq,PETROLEUM SYSTEM-ANALYSIS; ZAGROS FOLD BELT; DEPOSITIONAL-ENVIRONMENTS; HYDROCARBON GENERATION; SARGELU FORMATION; ORGANIC-MATTER; SHOUSHAN BASIN; WESTERN DESERT; NORTH; MIGRATION,"Bulk property and geochemical analyses were performed on 15 crude oil samples collected from the Early Cretaceous clastic reservoirs in the oilfields of the southern Mesopotamian Basin, South Iraq. Specific gravities ranging between 25.4 and 31.6 API and relatively high sulfur concentrations of up to 1.97 wt % suggest that the samples were generated from kerogen Type IBS at relatively low maturity level. Biomarker ratios and parameters as well as carbon isotope ratios, indicate that the oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions during the Jurassic to Early Cretaceous. Furthermore, biomarker maturity suggests two maturity subgroups for the samples based on their sulfur concentrations and specific gravity values. Sub-group (A) is characterized by oils generated from low-mature source rocks from the Late Jurassic-Early Cretaceous Sulaiy Formation; while the relatively high mature oils of sub-group (B) were generated from organic-rich intervals in the Jurassic Sargelu and Najmah formations. Basin model results revealed that these formations reached a peak oil-generation window at different times, expelling various quantities of oil. The basin model results further suggest that the organic-rich interval in the Sulaiy Formation began to expel little amounts of oil, corresponding to transformation ratio (TR) between 50 and 63% since the Late Miocene to present-day, while the organic-rich intervals in the Sargelu and Najmah formations were the earliest to expel significant amounts of oil, with relatively high TR values of 50-90% during the end of the Late Cretaceous to Early Eocene and continued to the present-day. These generated oils subsequently migrated to the shallow stratigraphic reservoir intervals through the vertical pathway of faults, and are currently extracted for use in the oil industry.",10,10,1
Crude Oil,Source Rocks,"Zhang, Kun; Liu, Rong; Liu, Zhaojun","Sedimentary sequence evolution and organic matter accumulation characteristics of the Chang 8-Chang 7 members in the Upper Triassic Yanchang Formation, southwest Ordos Basin, central China",Sedimentary environment; Paleoclimate; Organic matter accumulation; Yanchang formation; Ordos basin,SILURIAN LONGMAXI FORMATION; DEVONIAN DUVERNAY FORMATION; TIGHT SANDSTONE RESERVOIRS; GEOCHEMICAL CHARACTERISTICS; DEPOSITIONAL ENVIRONMENT; BLACK SHALES; OIL-SHALE; STRATIGRAPHIC ANALYSIS; ELEMENT GEOCHEMISTRY; MARCELLUS FORMATION,"Lacustrine organic-rich shales are widely developed in the Chang 7 member of the Yanchang Formation in the Ordos Basin. These shales have been proven to be the source rocks for crude oil and shale oil. The study of sedimentary evolution and the characteristics of organic matter (OM) accumulation is an important factor for the exploration and development of oil and gas resources. Based on the lithological assemblages, lithofacies, mineral contents, log curves and geochemical data, the sequence stratigraphic framework of the Chang 8-Chang 7 members of the Yanchang Formation in the southern margin of the Ordos Basin were established. A complete third-order sequence was identified, and it included four systems tracts: a lowstand systems tract (LST), a transgressive systems tract (TST), a highstand systems tract (HST) and a regressive systems tract (RST). By using organic petrology, organic geochemistry and elemental geochemistry, the abundance and source of OM, paleoclimate, paleowater conditions, paleoproductivity, and deposition rates of the different systems tracts of the Chang 8-Chang 7 are studied in detail. Various factors controlled the accumulation of OM in the different systems tracts. The abundance of OM in the LST is low, the kerogen type is mainly type III (including vitrinite); the abundance of OM increased gradually in the TST, the kerogen types are III and II2 (including vitrinite and sporophyte); the OM is mainly concentrated in the HST, and the kerogen type is mainly type ID (including alginite), biomarker compounds show that OM has a mixed source of land plant and planktonic material; the abundance of OM in the RST is relatively high, the kerogen type is mainly type II2 and III (including vitrinite and alginite). The main controlling factor for OM accumulation was paleoclimate, which affected the primary productivity of lake and the chemical properties of the water column (redox and paleosalinity), leading to differences in OM accumulation under different climatic conditions. Hydrothermal activities contributed to anoxia and a salinity increase in lake bottom waters, with volcanic ash providing large amounts of essential nutrients for algal blooms. Based on the V/Cr, Sr/Ba, P/Ti and (La/Yb)(N) ratios with TOC values, the abundance of OM is positively correlated with paleoproductivity and water column reducibility, and negatively correlated with paleosalinity. The abundance of OM first increases and then decreases with increasing sedimentation rate. In general, the accumulation of OM was promoted under warm and humid climates, anoxic fresh to brackish water and adequate paleoproductivity.",8,8,9
Crude Oil,Source Rocks,"Alkhafaji, Mohamed W.","Biomarker assessment of oil biodegradation, water washing, and source rock characteristics of oil seeps from the Foothill Zone along the Tigris River, Northern Iraq",Source rock depositional environment; Biomarkers; Oil seeps; Biodegradation; Water washing; Hammam Al-Alil; Qaiyarah; Fat'ha; Northern Iraq,TRIASSIC SHUBLIK FORMATION; LOWER FARS FORMATION; IN-SOURCE ROCKS; CRUDE OILS; DEPOSITIONAL ENVIRONMENT; PETROLEUM GENERATION; THERMAL MATURITY; FOLD BELT; IDENTIFICATION; MARKERS,"Oil seep samples from the Foothill Zone of northern Iraq were geochemically characterized to determine the level of biodegradation and water washing of the seeps and to determine the depositional environment (including sedimentary facies, oxicity, and organic matter type) of correlative source rocks. Eight samples from three seeps sites (Hammam Al-Alil, Qaiyarah, and Fat'ha) were investigated. Detailed saturated and aromatic biomarkers were analyzed using GC-FID and GC-MS, in addition to measurement of carbon isotopes and the sulphur content. Qaiyarah samples range from non-biodegraded to moderately biodegraded; whereas Hammam Al-Alil and Fat'ha samples are moderately biodegraded. The Hammam Al-Alil and Fat'ha samples are also affected by water washing. Biomarker, carbon isotope, and sulphur data suggest that these oil seeps contain oil expelled during the early oil window from carbonate source rocks of Jurassic age. Correlative source rocks were deposited in an anoxic marine environment. The most likely source rock candidates include the Sargelu, Naoklekan, and Chia Gara formations.",4,4,1
Crude Oil,Source Rocks,"Wang, Wenqiang; Wang, Tieguan; Li, Meijun; Mao, Fengjun; Liu, Jiguo; Xiao, Hong; Lai, Hongfei; Ai, Xinyu",The origins of biodegraded oils in sandstone reservoirs in the Termit Basin,Geochemical characteristics; Biodegraded oil; Termit basin; Geological condition,HIGH ACIDITY OILS; CRUDE-OIL; SOURCE ROCKS; GEOCHEMICAL CHARACTERISTICS; COMPOSITIONAL CHANGES; DEEP SUBSURFACE; CENTRAL-AFRICA; RIFT BASINS; TARIM BASIN; PETROLEUM,"Systematic geochemical analysis of 39 crude oils from the Termit Basin, Niger, all belonging to the same oil family, reveals distinct differences in bulk properties and molecular compositions, which were undoubtedly caused by differences in the extent of biodegradation. Various degrees of microbial alteration were identified in crude oils, which were classified as non-, slightly, moderately, or heavily degraded oils, according to their physical properties, bulk chemical compositions, and certain molecular biomarker characteristics. Examination of the possible origins and geological backgrounds of the biodegraded oils shows that reservoirs with deeper burial depths (greater than 1800 m), thicker caprocks (>100 m), relatively higher stratigraphic temperatures (>80 degrees C), and which have been subject to the influence of silent faults had not suffered significant biodegradation. The burial depth of reservoirs is therefore considered to be the main factor controlling the biodegradation process, and may offset other factors if the depth is sufficient. The Paleogene reservoirs in the Dinga Step-Fault Zone (DSFZ) that meet all of these conditions are therefore dominated by normal oils. Degraded oils of varying degrees are widely distributed in other tectonic units where at least one of these factors is absent. This study may have practical application for further petroleum exploration, prediction of petroleum properties, and the reduction of production risk.",3,3,3
Crude Oil,Rheological Properties,"Strelets, Larisa A.; Ilyin, Sergey O.",Effect of enhanced oil recovery on the composition and rheological properties of heavy crude oil,Heavy crude oil; Enhanced oil recovery; Oil composition; Rheology; Viscosity; Viscoelasticity,GLASS-FORMING LIQUIDS; POLYMER; ASPHALTENE; AGGREGATION; BITUMEN; MEDIA; STATE,"The composition and rheological properties of ten samples of heavy crude oil from five different wells were investigated before and after integrated oilfield treatment with gel-forming and oil-displacing systems for increasing oil recovery. The study of the viscosity and viscoelastic properties of oil samples in a wide temperature range (from -30 to 70 degrees C) made it possible to determine their gelation and glass transition temperatures and also to establish the effect of enhanced oil recovery treatment on these characteristics. It was found that the treatment can either increase or decrease the viscosity of oil, and the same applies to the gelation and glass transition temperatures as well as to the contents of saturates, resins, and asphaltenes. The rheological properties of oil samples were closely related to their group composition, while the changes in the latter as a result of oilfield treatment were dependent on the relative position of the injection and production wells. The work allowed finding universal correlations between the group composition of heavy oil, its viscosity, and test temperature.",10,10,4
Crude Oil,Rheological Properties,"Ge, Meng-Ru; Miao, Si-Jia; Liu, Jin-Feng; Gang, Hong-Ze; Yang, Shi-Zhong; Mu, Bo-Zhong",Laboratory studies on a novel salt-tolerant and alkali-free flooding system composed of a biopolymer and a bio-based surfactant for oil recovery,Biopolymer/surfactant formula; Ultra-low interfacial tension; Enhanced oil recovery; Salt-tolerant; Alkali-free,HIGH-TEMPERATURE; WELAN GUM; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; NONIONIC SURFACTANT; ASSOCIATING POLYMER; AQUEOUS WELAN; XANTHAN GUM; STRAIN; POLYSACCHARIDES,"Alkali/surfactant/polymer (ASP) flooding is one of the most effective tertiary oil recovery technologies. However, the formation of an alkali scale potentially results in the reduction of the formation permeability and pipeline corrosion, which affect its industrial application. Recently, the surfactant/polymer (SP) flooding system in the absence of alkali has received increasing attention. Here, we screened a high-yielding strain, which is capable of producing salt-tolerant biopolymer. The results of rheological properties evaluation showed that this biopolymer possessed a stable viscosity at high salinities (up to 200 g/L NaCl, 100 g/L Ca2+, and 100 g/L Mg2+) and a wide range of pH (4-11), indicating its superior salt and pH resistance. Based on these properties, a novel salt-tolerant and alkali-free binary flooding system was constructed with this biopolymer and bio-based surfactant newly synthesized in our lab. The ultra-low interfacial tension (IFT) between crude oil and the binary system containing 0.5 wt % biopolymer and 1.00 g/L surfactant could be achieved in the presence of 100 g/L NaCl or 400 mg/L Ca2+. Moreover, it exhibited good resistance to oil sands adsorption, excellent anti-dilution, and ageing stability. These results indicate that the biopolymer produced by the Kosakonia oryzae strain possessed great potential in the construction of an alkali-free SP system for enhanced oil recovery (EOR) in high salinity and high temperature oil reservoirs.",4,4,5
Crude Oil,Rheological Properties,"Yang, Fei; Zhu, Haoran; Li, Chuanxian; Yao, Bo; Wang, Feng; Chen, Jinxiu; Sun, Guangyu",Investigation on the mechanism of wax deposition inhibition induced by asphaltenes and wax inhibitors,Wax deposition; Inhibition; Asphaltenes; Wax inhibitor; Mechanism,VINYL ACETATE COPOLYMER; POUR POINT DEPRESSANT; CRUDE-OIL; SYNERGISTICALLY IMPROVE; PERFORMANCE IMPROVEMENT; RHEOLOGICAL PROPERTIES; FLOW BEHAVIOR; MODEL; EVA; MIXTURES,"This study is specifically concerned with the effect and mechanism of asphaltenes and wax inhibitors on the wax deposition characteristics of model waxy oil. According to the rheological and wax deposition test, the pure model waxy oil has a pour point higher than the pipe wall temperature, and the formed wax deposit exhibits the slowest aging rate and homogeneous wax deposit structure. Based on the DSC and rheological experiments, the solubility of wax crystals is hardly influenced by asphaltenes or wax inhibitors, but the decrease of oil viscosity and the weakened low-temperature gel structure induced by asphaltenes and wax inhibitors would increase the wax molecular diffusion coefficient and wax content in the wax deposit, which ultimately leads to a thinner and harder wax deposit. Moreover, based on the molecular dynamic simulation, the EVA molecules can be adsorbed on the asphaltene surface thus forming EVA-asphaltene composite particles, which can change the crystallization habit of wax molecules and the wax crystal micromorphology, thereby dramatically improving the crude oil rheology at low temperatures and inhibiting wax deposition. This work provides a comprehensive understanding of the wax deposition mechanism induced by asphaltenes and wax inhibitors, which helps to the well or pipeline operation safety and efficiency.",3,3,9
Crude Oil,Rheological Properties,"Cao, Guangsheng; Du, Tong; Bai, Yujie; Yang, Tingyuan; Zuo, Jize",Effects of surfactant molecular structure on the stability of water in oil emulsion,Water-in-oil emulsifier; Surfactant; Molecular structure; Interfacial film; Hydrophobic group,CRUDE-OIL; HYDROCARBON EMULSIONS; INTERFACIAL RHEOLOGY; STABILIZATION; ASPHALTENES; BEHAVIOR,"The stability of a water-in-oil emulsion is the key to the water control technology for active crude oil, and different surfactants have direct influence on the emulsion properties. Thus, it is necessary to investigate the relationship between the molecular structure of surfactants and the stability of the crude oil emulsion. This study used emulsification experiments to investigate emulsion stability. In particular, the effects of the number of saturated alkyl carbon atoms on the lipophilic end, saturation of the alkyl chains and the number of hydrophobic branched-chains on the emulsion were analyzed with a viscometer, microscope and tensiometer. The results showed that longer hydrophobic monoalkyl chains produced more effective emulsifiers; however, unsaturated bonds on the hydrophobic alkyl chain or highly branched alkyl chains reduced the emulsifying effect.",3,3,5
Crude Oil,Ordos Basin,"Zhang, Kun; Liu, Rong; Liu, Zhaojun","Sedimentary sequence evolution and organic matter accumulation characteristics of the Chang 8-Chang 7 members in the Upper Triassic Yanchang Formation, southwest Ordos Basin, central China",Sedimentary environment; Paleoclimate; Organic matter accumulation; Yanchang formation; Ordos basin,SILURIAN LONGMAXI FORMATION; DEVONIAN DUVERNAY FORMATION; TIGHT SANDSTONE RESERVOIRS; GEOCHEMICAL CHARACTERISTICS; DEPOSITIONAL ENVIRONMENT; BLACK SHALES; OIL-SHALE; STRATIGRAPHIC ANALYSIS; ELEMENT GEOCHEMISTRY; MARCELLUS FORMATION,"Lacustrine organic-rich shales are widely developed in the Chang 7 member of the Yanchang Formation in the Ordos Basin. These shales have been proven to be the source rocks for crude oil and shale oil. The study of sedimentary evolution and the characteristics of organic matter (OM) accumulation is an important factor for the exploration and development of oil and gas resources. Based on the lithological assemblages, lithofacies, mineral contents, log curves and geochemical data, the sequence stratigraphic framework of the Chang 8-Chang 7 members of the Yanchang Formation in the southern margin of the Ordos Basin were established. A complete third-order sequence was identified, and it included four systems tracts: a lowstand systems tract (LST), a transgressive systems tract (TST), a highstand systems tract (HST) and a regressive systems tract (RST). By using organic petrology, organic geochemistry and elemental geochemistry, the abundance and source of OM, paleoclimate, paleowater conditions, paleoproductivity, and deposition rates of the different systems tracts of the Chang 8-Chang 7 are studied in detail. Various factors controlled the accumulation of OM in the different systems tracts. The abundance of OM in the LST is low, the kerogen type is mainly type III (including vitrinite); the abundance of OM increased gradually in the TST, the kerogen types are III and II2 (including vitrinite and sporophyte); the OM is mainly concentrated in the HST, and the kerogen type is mainly type ID (including alginite), biomarker compounds show that OM has a mixed source of land plant and planktonic material; the abundance of OM in the RST is relatively high, the kerogen type is mainly type II2 and III (including vitrinite and alginite). The main controlling factor for OM accumulation was paleoclimate, which affected the primary productivity of lake and the chemical properties of the water column (redox and paleosalinity), leading to differences in OM accumulation under different climatic conditions. Hydrothermal activities contributed to anoxia and a salinity increase in lake bottom waters, with volcanic ash providing large amounts of essential nutrients for algal blooms. Based on the V/Cr, Sr/Ba, P/Ti and (La/Yb)(N) ratios with TOC values, the abundance of OM is positively correlated with paleoproductivity and water column reducibility, and negatively correlated with paleosalinity. The abundance of OM first increases and then decreases with increasing sedimentation rate. In general, the accumulation of OM was promoted under warm and humid climates, anoxic fresh to brackish water and adequate paleoproductivity.",8,8,9
Crude Oil,Ordos Basin,"You, Jiyuan; Liu, Yiqun; Song, Shanshan; Zhou, Dingwu; Yang, Yiyao",Characteristics and controlling factors of LORS from the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin,LORS; Redox conditions; Paleoproductivity; Volcanic and hydrothermal activities; Yanchang formation; Ordos basin,GEOCHEMICAL CHARACTERISTICS; SEQUENCE STRATIGRAPHY; CHINA IMPLICATIONS; BARNETT SHALE; TRACE-METALS; DEEP-SEA; EVOLUTION; ACCUMULATION; PRODUCTIVITY; MORPHOLOGY,"Lacustrine organic-rich shale (LORS) developed in the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin. LORS has been proven to be a source of crude oil and tight oil, as well as a source and reservoir for shale oil in the basin. A total of 35 LORS samples were collected from Well Z233 and analysed by mineralogy and element geochemistry to reveal the characteristics and controlling factors of LORS. The following results were obtained: In the oil shale, the organic matter is composed of type I and type II kerogen, with a pre- dominance of type II. The organic matter is mature and reaches high levels of abundance. (2)Through further analysis. The values of w(U)/w(Th), w(V)/w(Cr), w(Ni)/w(Co), the size and morphology of pyrite, indicates that the lake water of the LORS deposition period in the study area is anoxic or suboxic state. the TOC of the samples was found to have significant positive correlations with the w(Mo) and w(Ba-bio) contents. Paleoproductivity can be inferred to be the key factor controlling organic matter enrichment in the LORS. (3)Volcanic and hydrothermal activities promote the development of LORS, provide nutrients needed by organisms, promote the growth of organisms, and improve paleoproductivity. Hydrothermal activity leads to the formation of an anoxic environment at the bottom of the lake, and tuff will cover the sediments, which promotes LORS preservation. This study reveals in detail paleoproductivity is the main factor in the formation of LORS during the evolution of the basin. Volcanic and hydrothermal activities promoted the increase of paleoproductivity, and finally the oil shale layers with the richest organic matter have been formed. And thereby deepens our theoretical understanding of organic matter enrichment.",5,5,4
Crude Oil,Ordos Basin,"Wang, Yuxia; Shang, Qinghua; Zhou, Lifa; Jiao, Zunsheng",Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin,Permeability heterogeneity; CO2 flooding; EOR; Tight sandstone reservoir; Ordos Basin,OIL-RECOVERY; CARBON-DIOXIDE; INJECTION,"Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200-1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with elastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO 2 -EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high-low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high-low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.",3,3,6
Crude Oil,Support Vector Machine,"Rashidi, Sina; Mehrad, Mohammad; Ghorbani, Hamzeh; Wood, David A.; Mohamadian, Nima; Moghadasi, Jamshid; Davoodi, Shadfar",Determination of bubble point pressure & oil formation volume factor of crude oils applying multiple hidden layers extreme learning machine algorithms,Oil formation volume factor; Bubble point pressure; Multi-layer extreme learning machine; Hybrid machine learning algorithms; Least squares support vector machine,SUPPORT VECTOR MACHINE; SHEAR-WAVE VELOCITY; PVT PROPERTIES; CORRELATION-COEFFICIENTS; RELATIVE PERMEABILITY; RESERVOIR; PREDICTION; MODEL; SYSTEMS; PERFORMANCE,"An important requirement of reservoir management is to understand the properties of reservoir fluids and dependent phase behaviors. This makes it possible to determine the properties of reservoir fluids in laboratory pressure-volume-temperature (PVT) tests. Such laboratory tests are costly and time consuming, and reservoir data are sometimes not available. When estimating the in-place fluid volumes and/or designing enhanced recovery processes information on bubble point pressure (BPP) and oil formation volume factor (OFVF) is required. Predicting these two parameters is therefore one of the priorities of reservoir engineers. It is becoming increasingly beneficial to be able to predict BPP and OFVF with efficient machine-learning algorithms based on underlying variables that are more easily measured directly in the field. In this study, a dataset of 638 data records of published crude oil fluid samples from around the world is evaluated. After filtering the dataset for outliers, 591 data records for BPP and 599 datasets for OFVF are evaluated with efficient hybrid machinelearning algorithms (multi-layer extreme learning machine ?MELM? and least squares support vector machine ? LSSVM) optimized using a genetic algorithm ?GA? and a particle swarm optimizer ?PSO? to improve their prediction performance. Four underlying variables are considered for each data record: temperature (T), solution gas oil ratio (Rs), gas specific gravity (?g) and oil gravity (API). The PSO- MELM-PSO hybrid algorithm achieved the highest prediction accuracy measured in terms of root mean square errors (RMSE) of 33.5 psi for BPP and 0.0199 for OFVF. The four-hybrid machine-learning-optimization algorithms evaluated all outperform the empirical relationships used for many decades in the oil industry to predict BPP and OFVF.",11,11,1
Crude Oil,Support Vector Machine,"Kondori, Javad; Miah, Mohammad Islam; Zendehboudi, Sohrab; Khan, Faisal; Heagle, Dru",Hybrid connectionist models to assess recovery performance of low salinity water injection,Low salinity water injection; Recovery factor; Smart tools; Statistical analysis; Variable ranking,ENHANCED OIL-RECOVERY; ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINES; REAL-TIME PREDICTION; WETTABILITY ALTERATION; COMPRESSIVE STRENGTH; POROUS-MEDIA; CRUDE-OIL; REGRESSION; RESERVOIRS,"The low salinity water injection (LSWI) is one of the emerging enhanced oil recovery techniques to improve both microscopic and macroscopic displacement efficiencies by creating a new streamline in petroleum reservoirs. While experimental studies are tedious, costly, and time-consuming, the smart connectionist tools are more reliable and cost-effective approaches to predict oil recovery factor (RF) without considerations of governing equations and physics behind production mechanisms in oil reservoirs. The main objective of this study is to investigate the data-driven model performance and variable contribution while predicting RF of LSWI processes. We introduce connectionist models using hybridized least squares support vector machine (LSSVM) with global optimization technique of coupled simulated annealing (CSA), and adaptive network-based fuzzy inference system (ANFIS). The extremely randomized tree or extra tree (ET) tool is also applied to forecast the RF and investigate the parameter contribution in the employed model. The model performance is examined using statistical parameters, including coefficient of determination, relative error, mean absolute percentage error, and mean squared error. According to the results, the ET and hybridized LSSVM-CSA models perform better than the ANFIS model in estimating RF. Utilizing the ET smart model, the total dissolved salts (TDS, ppm) is the most influential parameter, while the fluid injection rate has the minimum importance in the determination of RF. The current research confirms that LSSVM-CSA and ET techniques are able to obtain RF of LSWI with high accuracy and reliability, which can be used by researchers and engineers for better management of oil reservoirs under LSWI.",4,4,3
Numerical Simulation,Gas Production,"Wu, Yonghui; Cheng, Linsong; Ma, Liqiang; Huang, Shijun; Fang, Sidong; Killough, John; Jia, Pin; Wang, Suran",A transient two-phase flow model for production prediction of tight gas wells with fracturing fluid-induced formation damage,Fracturing fluid-induced formation damage; Two-phase flow; Tight gas; Production prediction; Multi-fractured horizontal well,,"A major concern with hydraulic fracturing in tight formation is the fracturing fluid-induced formation damage (FFIFD) for the high capillary pressure and the presence of water-sensitive clays. Analytical and semi-analytical models are good choices for formation damage evaluation comparing to computationally expensive numerical simulations, particularly in early times when there is limited information about the formation properties. However, the effects of FFIFD and two-phase flow are not addressed in many analytical models. This paper presents a semi-analytical model for this problem with the consideration of both FFIFD and two-phase flow. First, the physical model and mathematical fundamentals of the model are presented. The triple-porosity model is modified to capture the formation damage caused by fracturing fluid. A low permeability fracturing fluid invasion layer (FFIL) is used to characterize leakoff caused clay swelling and polymer adsorption in the matrix pores, and two-phase flow is assumed in the fractures to capture the choking effects. The analytical solution is obtained in the Laplace domain, and a successive iteration is used to update the dynamic parameters by coupling the flowing material balance equations. Then, the commercial numerical simulator Eclipse is used to validate the precision of the semi-analytical model, and several synthetical cases are presented to study the effects of two-phase flow, and the permeability and width of FFIL on gas production rate. Finally, a field case is provided to test the application of the proposed model. The main contribution of this paper is the provision of a simple yet versatile semi-analytical model for production prediction and analysis with the consideration of fracture networks, FFIFD, and two-phase flow. It serves as a good tool for making production prediction and production data analysis for hydraulically fractured tight gas wells.",37,37,15
Numerical Simulation,Gas Production,"Shi, Guoyun; Song, Shangfei; Shi, Bohui; Gong, Jing; Chen, Dongliang",A new transient model for hydrate slurry flow in oil-dominated flowlines,Multiphase flow; Natural gas hydrates; Hydrate formation; Flow assurance; Transient flow simulation,NATURAL-GAS HYDRATE; NUMERICAL-SIMULATION; INTRINSIC KINETICS; SHELL-MODEL; LIQUID FLOW; MASS; AGGLOMERATION; METHANE; SYSTEMS; DISSOCIATION,"A transient simulation tool for the gas hydrate slurry flow is crucial for hydrate flow assurance in the petroleum industry. In this work, we propose a new transient model for gas hydrate slurry flow in oil-dominated flowlines. A two-fluid model and a temperature equation are used to describe the gas-slurry two-phase flow. For the modeling of particulate phase flow, number density conservation equation and diameter conservation equation of the hydrate particles are established by Eulerian approach, a momentum conservation equation is established by Lagrangian approach. Furthermore, combining with the hydrate formation model, the transient gas hydrate slurry flow in oil-dominated flowlines can be numerically simulated. This model is verified by experimental data and field data, respectively. Afterwards, it is applied to analyze the transient behavior of the gas-hydrate slurry multiphase flow upon reduced gas well production. Finally, the sensitivity analysis of effects of flowrate, initial average size of water droplets and drag force on the hydrate slurry multiphase flow is performed. These results are of great practical value to give a deeper understanding of hydrate slurry multiphase flow, and contribute to better hydrate management in the petroleum industry by using hydrate slurry flow technology.",6,6,8
Numerical Simulation,Gas Production,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Numerical Simulation,Gas Production,"Liu, Zizhong; Emami-Meybodi, Hamid",Rate transient analysis of infinite-acting linear flow by use of piecewise constant diffusivity coefficients,Rate-transient analysis; Infinite-acting; Linear flow; Piecewise constant diffusivity coefficients; Pressure-dependent,GAS-WELLS; UNCONVENTIONAL GAS; TIGHT OIL; PERMEABILITY; RESERVOIRS,"Rate transient analysis (RTA) techniques are developed based on the analytical solutions to the hydraulic diffusivity equation. The diffusivity equation is subject to nonlinearity caused by the dependency of the rock and fluid properties to pressure. In this study, first, we develop a semi-analytical model to solve a nonlinear diffusivity equation for transient linear flow under the constant bottom-hole pressure condition. We use piecewise constant diffusivity coefficients to linearize the diffusivity equation. The domain under consideration is divided into an arbitrary number of subdomains. Each subdomain is assigned with a constant hydraulic diffusivity coefficient. As a result, the nonlinear diffusivity equation is reduced into a set of piecewise linear equations. Further, we propose a new RTA approach using the developed semi-analytical model. We then validate both the semi-analytical model and the RTA approach against direct numerical simulation. The comparison reveals the high accuracy of the developed model in the estimation of reservoir properties, pressure profiles, and flow rates, including the cases with highly pressure-dependent properties. Finally, we apply the proposed RTA approach to the flowback and long-term production data obtained from two horizontal wells to determine the reservoir properties, such as the cross-sectional area to flow and initial permeability. The field applications demonstrate that the proposed RTA approach provides a rigorous avenue for production data analysis of pressure-sensitive formations during transient linear flow.",5,5,2
Numerical Simulation,Gas Production,"Pinto, Helen; Wang, Xin; Gates, Ian",On the ratio of energy produced to energy injected in SAGD: Long-term consequences of early stage operational decisions,Steam-assisted gravity drainage; Energy efficiency; Thermal recovery; Energy produced versus energy injected (EPEI); Time-limited operator influence,,"Steam-Assisted Gravity Drainage (SAGD) is a recovery process used to extract bitumen from underground reservoirs. The efficiency of SAGD is determined by the volume of steam injected (reflecting cost and greenhouse gas emissions) relative to the volume of oil recovered (revenue). Another way to look at this relationship is as a ratio of cumulative energy produced to energy injected (EPEI). First described in this study, EPEI ratios offer a novel perspective on SAGD because they reduce the inter-well comparison bias caused by operational choices such as steam temperature, steam quality and well length. There are numerous studies on SAGD from an experimental, analytical or numerical simulation perspective, but all require assumptions and constraints specified in advance, and can only return an approximation of field performance. Studies that work exclusively with field data have typically been used for prediction modeling only. In contrast, this study employs a novel methodology by working within the existing constraints and operational choices of SAGD field wells to infer the number of steam-oil performance relationships present, and how long they last. One by one, we eliminate parameters that cannot cause the performance differences seen in the field using only deductive reasoning and multi-parameter sensitivity analysis, and arrive at possible reasons for the performance relationships found. 1520 SAGD well pairs in Alberta, Canada are used, which is more than 90% of the wells in Alberta over the last 20 years, and to the best of our knowledge, the largest field well set of any SAGD study to date. This comprehensive data set ensures that findings are applicable across the industry. Results reveal a new and surprising finding that the EPEI ratio is set during the first few months on production, and is very difficult to change thereafter. Hence, operators have a short, time-limited opportunity to influence each well's recovery ratio (and therefore its profitability and greenhouse gas emissions). This reflects the importance of process start-up and the first few months after start-up when the near well region of the reservoir is conditioned. Finally, the stability of the EPEI ratio permits a simple, new model capable of predicting cumulative recovery months in advance.",4,4,0
Numerical Simulation,Gas Production,"Wang, Zhenzhi; Fu, Xuehai; Hao, Ming; Li, Guofu; Pan, Jienan; Niu, Qinghe; Zhou, He",Experimental insights into the adsorption-desorption of CH4/N-2 and induced strain for medium-rank coals,N-2-ECBM; Binary mixed gases; Adsorption strain characteristics; Medium-rank coal; Anisotropic characteristics,GAS-ADSORPTION; COMPETITIVE ADSORPTION; METHANE ADSORPTION; PERMEABILITY; DEFORMATION; SIMULATION; DIFFUSION; EVOLUTION; NITROGEN; SORPTION,"To support the understanding of the effect of N-2-enhanced coalbed methane (N-2-ECBM) application on medium-rank coals, four coal samples from Shanxi Province were selected to test the porosity, mechanical properties and strain induced by binary gas adsorption-desorption. The results show that the desorption hysteresis is weakened with increasing N-2 fraction and is strengthened with increasing CH4 fraction, indicating that increasing the N-2 fraction can reduce the selectivity of coal to CH4. The critical desorption pressure of a mixed gas increases in a high N-2 fraction environment, promoting the desorption of CH4 and enhancing its recovery. This research clarifies the anisotropic strain characteristics induced by the adsorption-desorption of CH4/N-2 and provides reliable data for anisotropic permeability numerical simulations in the N-2-ECBM process. Swelling and shrinkage volume strain are negative-exponentially related to the N-2 fraction, and the volume shrinkage strain is close to the volume swelling strain given a N-2 fraction of 50%. There exists a polynomial relationship between the volume swelling/shrinking strain and adsorption capacity, which has a potential predictive effect on the volume strain variation in coal during N-2-ECBM. The analysis of the adsorption volume swelling strain rate and desorption volume shrinkage strain rate indicates that the N-2 fraction and micropore volume are the main factors controlling volume deformation. The volume strain decreases with increasing elastic modulus, but nitrogen injection weakens the effect of the elastic modulus on the strain. In this study, the desorption percentage increased and the volume swelling strain decreased with increasing nitrogen fraction. Nitrogen injection and sealing have a positive effect on methane desorption and the optimal N-2 fraction should be greater than 50%. This work provides a reference for improving coalbed methane production.",3,3,12
Numerical Simulation,Gas Production,"Wang, Jiaqi; He, Jiale; Lv, Xin; Ge, Kun; Cheng, Chuanxiao; Dong, Hongsheng",Numerical analysis of the gas recovery performance in hydrate reservoirs with various parameters by stepwise depressurization,Natural gas hydrate; Stepwise depressurization; Reservoir characteristics; Sensitivity analysis,METHANE HYDRATE; THERMAL-STIMULATION; DISSOCIATION; ENERGY; HEAT; PERMEABILITY,"Natural gas hydrates have drawn worldwide attention as a significant clean energy source in the 21st century. Depressurization is known to be the most effective method for hydrate exploitation owing to its feasibility and economic benefits. Recently, stepwise depressurization has received extensive attention owing to its advantages of effective prevention of ice generation and hydrate reformation during gas recovery. In this work, we optimized the 2-D simulator to model the evolution of temperature, pressure, hydrate saturation, and gas production behavior in hydrate sediments during decomposition process via stepwise depressurization. The effect of various reservoir characteristics on gas production was analyzed by introducing the sensitivity factor. The results demonstrated that higher specific heat capacity of the reservoir would promote gas production in the early stage of the reaction; however, this effect is reversed in the later stage. A higher thermal conductivity of the hydrate cores can dramatically enhance the gas production rate; however, this advantage is weakened with increasing thermal conductivity. Reducing the gas relative permeability hinders the hydrate decomposition process, and the water relative permeability has minimal effect on gas production. Based on the sensitivity analysis, the thermal conductivity and gas relative permeability are the main factors affecting hydrate decomposition.",3,3,9
Numerical Simulation,Gas Production,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Numerical Simulation,Gas Production,"Heng, Shuai; Li, Xianzhong; Zhang, Xiaodong; Li, Zhen",Mechanisms for the control of the complex propagation behaviour of hydraulic fractures in shale,Hydraulic fracture; Complex propagation behaviour; Bedding plane; Cementing strength; Fracture deviation; Shale,,"The complex propagation behaviours of hydraulic fracture (HF) at bedding planes (BPs) and the produced complicated fracture geometry are essential to enhance the production of shale gas reservoirs. To better understand the complex propagation behaviour of HF at BPs with different bond strengths, the propagation behaviour, including arrest, crossing, and deviation, was identified first from post-fracturing shale specimens. The discontinuous stress and displacement fields on both sides of a BP ahead of an HF were then determined using the numerical simulation method. Finally, three mechanisms-principal stress jump, Cook-Gordon debonding or Poisson effect, and elastic dissimilarity-were explored in detail to interpret the complex propagation behaviour. The results revealed that HF is arrested/deviated only at extremely weakly cemented or fully opened BPs, whereas HF crosses strongly cemented BPs. The high heterogeneity of the BPs in cementing strength is responsible for the complex propagation behaviour of HF. The principal stress jump at a BP is caused by the difference in stiffness between the BP and the rock matrix. The maximum tensile principal stress ahead of the HF cannot be transmitted across the weakly cemented or fully opened BPs, suggesting that the HF cannot cross BPs. The principal stresses may rotate at a weakly cemented BP, and the rotated principal stresses tend to terminate or deviate an HF. Because of Cook-Gordon debonding and the Poisson effect, if a weakly cemented BP is present and is roughly normal to an advancing HF, the BP may break at some distance ahead of the fracture tip and induce a secondary fracture along the BP. The HF then reaches the opened BP and deviates towards the BP. The propagation process of L- or T-shaped fractures can be interpreted both by the Cook-Gordon debonding and Poisson effect from the viewpoints of stress and displacement. The three mechanisms often operate together when an HF deviates towards a weak BP; while for a special case, there may be only one dominant mechanism.",3,3,7
Numerical Simulation,Gas Production,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Numerical Simulation,Gas Production,"Fu, Qinwen; Cudjoe, Sherifa; Ghahfarokhi, Reza Barati; Tsau, Jyun-Syung; Li, Xiaoli; Peltier, K.; Mohrbacher, D.; Baldwin, A.; Nicoud, B.; Bradford, K.",Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection-an Eagle Ford study,Molecular diffusion; Hydrocarbon gas huff-n-puff; Dual-permeability; Rock-fluid property; Gas injection; Eagle Ford shale; Unconventional reservoirs; EOR; IOR,OIL,"Fracture complexity, variation in fluid properties, variations in rock types and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research has been conducted to define diffusion coefficients coupled with rock tortuosity resulting in calculation of effective diffusion. The objective of this work is to conduct a comprehensive experimental and simulation study on lower Eagle Ford rock samples to measure diffusion coefficients for different injection cycles in three representative rock samples from the main flow unit. Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and effluent oil and gas compositions were measured. NMR measurement was repeated at the end. Three compositional simulation models were set up for three different samples using tortuosity values from FIB-SEM analysis to simulate experimental diffusion and production. For history matching, relative permeability curves, fracture properties, and tortuosity were tuned to match pressure and production results for three representative samples. Pressure profiles vary significantly between different cycles caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Effective diffusion coefficients were calculated using representative tortuosity values. Diffusion was represented by pressure drop during soaking time. This pressure drop varies across different lithofacies and for different rock samples. For produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate components increased. Gas huff-n-puff injection into shale oil reservoirs were being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments, conducted using a constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, show favorable results. Recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively.",3,3,4
Numerical Simulation,Gas Production,"Shi, Juntai; Jia, Yanran; Wu, Jiayi; Xu, Fengyin; Sun, Zheng; Liu, Chengyuan; Meng, Ye; Xiong, Xianyue; Liu, Cheng",Dynamic performance prediction of coalbed methane wells under the control of bottom-hole pressure and casing pressure,Coalbed methane; Dynamic performance analysis; Bottom-hole pressure; Casing pressure; Liquid level; Low permeability,PRODUCTIVITY MODEL; LOW PERMEABILITY; FRACTURED WELL; ORDOS BASIN; GAS; RESERVOIRS; EQUATIONS; FLOW; PROPAGATION; TRANSPORT,"In the early production stage of coalbed methane (CBM) wells, especially in low permeability reservoirs, the method of shutting in casing annulus is usually adopted. However, the current commercial numerical simulation software fails to predict the dynamic performance of CBM wells under the control of both bottom-hole pressure and casing pressure. In this work, the calculation models of wellbore-pressure distribution and formation pressure distribution are derived firstly. Then, the above two models are coupled with several CBM dynamic performance analysis (CBMDPA) models developed in our previous researches, including pressure propagation model, water/gas productivity equations, dynamic permeability model, and material balance equation. A new CBMDPA program is developed with the coupling model, which can simulate the dynamic production performance of CBM wells after inputting the basic reservoir and fluid parameters, casing pressure, and bottom-hole pressure. Next, the newly developed CBMDPA program is validated against four field cases in China, and excellent agreements are obtained. The inputs of our CBMDPA program include casing pressure, bottom-hole pressure, and some deterministic and uncertain reservoir and fluid parameters. By adjusting the uncertain parameters, the gas production history can be fitted, and the uncertainty on the determination of reservoir properties can be addressed. On this basis, the future gas production is predicted using the determined parameters and the scheduled bottom-hole pressure and casing pressure. Finally, the influence of casing pressure on gas production is studied. Results show that high casing pressure has detrimental impact on the maximum daily gas production, while, it plays a positive role to achieve great desorption area, which will further prolong the stable gas production period. Under the high casing pressure of 2.5 MPa, the maximum daily production is decreased by about 54%, but the stable production stage is prolonged to more than 3000 days. It indicates that an appropriate range for casing pressure is favorable, considering both the accumulative gas production and the desorption area. For the case with representative properties from Muai block, the casing pressure is suggested to be 1-2 MPa, and the range between 1 MPa and 1.5 MPa is recommended for Hancheng block.",3,3,4
Numerical Simulation,Gas Production,"Gao, Qi; Cheng, Yuanfang; Han, Songcai; Yan, Chuanliang; Li, Yang; Han, Zhongying",Effect of shale matrix heterogeneity on gas transport during production: A microscopic investigation,Shale gas; Matrix heterogeneity; Organic matter; Inorganic matter; Apparent permeability,,"Shale gas is playing increasingly important roles in transforming the global energy markets due to the huge demand for cleaner energy in the future. To extract shale gas at the commercial rate, formations must be hydraulically fractured to provide more contact area between the wellbores and reservoirs. Although the properties of hydraulic fractures are the key to gas production in the early stage, it is the matrix properties that determine the long-term production performance of the wells. However, understanding the gas transport behaviours in shale matrix is still a challenge at present. In this paper, to analyze shale gas flow at the microscale, an improved numerical model is developed, which is able to simultaneously capture the mechanical deformation of organic matter (OM) and inorganic matter (iOM), gas flow in OM and iOM, and fluid and solid interaction between the OM and iOM. The modelling results show that due to the coexistence of OM and iOM, the gas transport and shale matrix deformation behaviours exhibit regional differences. Specifically, during the gas production process, pore pressure in OM declines slower, gas density and Knudsen number in OM own larger values, and the apparent permeability and volumetric strain of OM are smaller. Therefore, taking matrix heterogeneity into consideration is necessary for accurately describing shale gas flow. In addition, numerical simulations are carried out to investigate the effect of a multitude of parameters on the modelling results. These parameters include nanopore compressibility, nanopore radius, matrix porosity, Langmuir volume and Langmuir pressure, and total organic carbon (TOC). The sensitivity of apparent permeability evolution in OM and iOM on each parameter is reported and discussed. The obtained results provide new insights for understanding gas transport in shale reservoirs from a microscopic perspective.",3,3,2
Numerical Simulation,Porous Media,"Wang, Jinyuan; Xu, Yi-Peng; Qahiti, Raed; Jafaryar, M.; Alazwari, Mashhour A.; Abu-Hamdeh, Nidal H.; Issakhov, Alibek; Selim, Mahmoud M.",Simulation of hybrid nanofluid flow within a microchannel heat sink considering porous media analyzing CPU stability,Processor cooling; Microchannel heat sink; Aluminium foam; Porous media; Hybrid nanoparticle; CPU stability And lifetime,THERMAL PERFORMANCE; FORCED-CONVECTION; PRESSURE-DROP; FLUID-FLOW; CONCAVITY; BOUNDS,"Current article aims to numerically scrutinize and compare the forced convection in three different configurations of a 3D heat sink. Two models of porous were designed aiming to evaluate the effects of nanomaterial and metallic foam to the conventional solid heat sink on thermal performance. In these two models, porous material with the same volume fraction was located in two different positions to have different contact areas with the solid. MWCNT-Fe3O4 hybrid nanofluid has been utilized as coolant working fluid. Validations were carried out in the critical case of 47 W for pure water through comparison with previous experimental work in which the whole surface of the CPU is covered with porous media. According to the results, at the constant Reynolds number, the heat sinks, which are consist of metallic foam, have better cooling performance and are able to decrease the surface temperature of heat sink more.",14,14,9
Numerical Simulation,Porous Media,"Alizadeh, MohammadReza; Fatemi, Mobeen; Mousavi, Mohammad",Direct numerical simulation of the effects of fluid/fluid and fluid/rock interactions on the oil displacement by low salinity and high salinity water: Pore-scale occupancy and displacement mechanisms,Direct numerical simulation; Computational fluid dynamics; Dynamic contact angle; Dynamic interfacial tension; Low salinity water flooding,INTERFACIAL-TENSION IFT; WETTABILITY ALTERATION; SPECIES TRANSFER; POROUS-MEDIA; SMART WATER; INJECTION; RECOVERY; BRINE; FLOW; VOLUME,"Laboratory experiments have shown that performance of waterflooding in oil reservoirs could be significantly increased by lowering the ionic strength and/or manipulation of its composition, which is generally known as low salinity waterflooding (LSWF). The involved mechanisms in additional oil production can be generally categorized in two categories, fluid/fluid and fluid/rock interactions. The distribution of the phases and the involved displacement mechanisms would be strongly affected by the inter-relations between capillary and viscous forces. Although there have been recent advances in the simulation of the LSWF at core scale and beyond and some models are included in commercial core-scale/field-scale simulators, there are very few works that modelled and simulated this process at the pore scale. As a result the effects of wettability alteration and/or interfacial tension (IFT) change on the distribution of the phases at pore scale as well as dynamics of the displacement are not thoroughly investigated and not well understood, even in spite of many micromodel experiments. The aim of the present study is to investigate the fluids distribution, redistribution and dynamic of the displacement mechanisms at the true pore scale (inside a pore), by modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Simulation results show that in addition to the fluid/rock interactions, fluid/fluid interactions are also important in the effectiveness of LSWF and shall be considered in simulation studies. This is especially true in the case of non-water-wet systems. Our simulations provide new physical insights into LSWF and the dynamics of two-phase flow under wettability alteration as well as IFT changes induced by the LSWF, which cannot be easily captured by laboratory experiments. The results are also used to better explain some of the observed discrepancies in larger scales such as micromodel or coreflood experiments.",7,7,1
Numerical Simulation,Porous Media,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Numerical Simulation,Porous Media,"Zhao, Wen; Jia, Chengzao; Jiang, Lin; Zhang, Tao; He, Minxia; Zhang, Fan; Jiang, Zhenxue; Li, Xiangfang; Wu, Keliu","Fluid charging and hydrocarbon accumulation in the sweet spot, Ordos Basin, China",Tight gas reservoir; Fluid charging; Hydrocarbon accumulation; Sweet spot; Lattice Boltzmann,,"Although significant progress has been made in the tight gas exploration and development, there is still a limited understanding of the fluid charging and hydrocarbon accumulation in the sweet spot. In this study, a novel method is proposed to generate the stochastically constructed porous media which represents the transition region between tight surrounding sandstone and sweet spot. Based on the constructed porous media, the fluid charging and hydrocarbon accumulation processes of the tight reservoir are simulated by the lattice Boltzmann method (LBM). The numerical simulation results show that, although a piston-like pattern can be observed in field-scale simulation or laboratory experiments, at the micro-scale, due to the inherent heterogeneity of the porous media, the fluid charging pattern tends to be fingering-like. The existence of the transition region between tight surrounding sandstone and sweet spot becomes a water-bearing gas layer or even gas-bearing water layer at the top/bottom of the gas layers (sweet spot). The existence of fractures is favorable for hydrocarbon charging into the reservoir rocks, but not for the hydrocarbon accumulation due to the gas escaping through the fractures. Combined with well logging interpretation results, three typical water bodies (isolated water body, water body at the top, or bottom of the gas layer) are identified from the view of fluid charging and hydrocarbon accumulation.",6,6,3
Numerical Simulation,Porous Media,"Jia, Cunqi; Huang, Zhaoqin; Sepehrnoori, Kamy; Yao, Jun",Modification of two-scale continuum model and numerical studies for carbonate matrix acidizing,Two-scale continuum model; Matrix acidizing; Reactive flow; Numerical simulation; Carbonate reservoir,WORMHOLE FORMATION; REACTIVE DISSOLUTION; POROUS-MEDIA; SIMULATION; TRANSPORT; FLOW; STIMULATION; PROPAGATION; FLUID; BEHAVIOR,"Matrix acidizing is one of the most effective stimulation techniques to achieve industrial development of carbonate reservoirs. In this work, a two-scale continuum model is modified to consider mass conversion between liquid and solid phases. The results show that the mass conversion between liquid and solid phases is very important and nonnegligible. Compared to modified model, original model overestimates amount of acid required for core breakthrough. A series of numerical cases based on modified model are presented for sensitivity studies on acid injection conditions, core geometries, acid, and rock properties. The modified model can well capture optimum acid injection velocity and typical dissolution patterns observed in experimental studies. Pore volume to breakthrough (PVBT) is very sensitive to acid injection concentration and acid surface reaction rate. Increasing injected acid concentration substantially reduces the amount of solute required but acid injection mass does not change significantly. Strong acid can effectively reduce least pore volume to breakthrough (PVBT) but meanwhile optimum acid injection velocity obviously increases. The simulation results are compared with available experimental and numerical data and found to attain a consistent match.",6,6,2
Numerical Simulation,Porous Media,"Cui, Yingzhi; Shikhov, Igor; Li, Rupeng; Liu, Shitao; Arns, Christoph H.",A numerical study of field strength and clay morphology impact on NMR transverse relaxation in sandstones,Kaolinite model; NMR transverse relaxation; Relaxation regime,PORE-SIZE DISTRIBUTIONS; MAGNETIC-FIELD; NUCLEAR MAGNETIZATION; POROUS-MEDIA; DIFFUSION; GRADIENTS; DECAY; PERMEABILITY; IMAGE; TIMES,"Nuclear magnetic resonance (NMR) relaxometry is a common technique for the petrophysical characterization of sedimentary rocks. The standard interpretation of NMR transverse relaxation responses is based on the assumptions of the fast diffusion limit, dominant surface relaxation, and weak coupling between pores, allowing an interpretation of the NMR response as pore size distribution. In general, three asymptotic relaxation regimes can be defined by comparing dephasing, structural and diffusion length scales. The shortest length scale defines the dominating relaxation regime, which is either the free diffusion, motional averaging, or localization regime. Complex mineralogy and morphology of rocks, especially due to clay minerals, may lead to the co-existence and coupling of multiple relaxation regimes in the presence of surface relaxivity heterogeneity and internal gradient effects. In this work the relationship between morphology of rocks, strength of applied magnetic field, resulting relaxation regimes and observed NMR relaxation responses is studied numerically. Limitations in the discretization of clays typical for micro-CT images are addressed by introducing a fine-scale kaolinite model based on SEM images. The model is utilized to evaluate the field-dependent mean transverse relaxation time and effective diffusion coefficient of clay regions. These effective parameters are incorporated into random-walk simulations on micro-CT images. Relaxation regimes are analysed spatially for three different types of sandstone as function of external magnetic field strength. Increase of paramagnetic clay content, field strength and echo-time increases the fraction of spins relaxing in the localization regime within macro-pores, typically being localised in the regions neighbouring clay pockets and grain surfaces. We demonstrate that a significant contribution of the localization regime to relaxation may lead to incorrect predictions of pore-size distributions and fluid typing. The prefactor of permeability correlations varies significantly due to clay effects. Accounting for these effects should enable more robust petrophysical interpretations.",5,5,6
Numerical Simulation,Porous Media,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Numerical Simulation,Porous Media,"Li, Longlong; Voskov, Denis",A novel hybrid model for multiphase flow in complex multi-scale fractured systems,Reservoir simulation; Multi-level discrete fracture model; Fractured reservoir; Local-global upscaling,NUMERICAL-SIMULATION; POROUS-MEDIA; RESERVOIR SIMULATION; TRANSPORT; FLUID; PERMEABILITY; RECOVERY; WATER,"We present a multi-level discrete fracture model (MLDFM) to guarantee a robust and efficient solution for naturally fractured reservoir simulation. In MLDFM, we apply a triple continuum model using structured grid for forward simulation where large-scale fractures are represented with numerical embedded discrete fracture model (EDFM) and the secondary fractures are upscaled as third continuum. What makes the triple continuum model different from the previous work is that both the numerical EDFM and the third continuum are treated in a dynamic approach by considering the effect of flow direction on the complex local-scale flow response. For that purpose, we construct a finer unstructured discrete fracture matrix (DFM) grid which represents all fractures explicitly and is conformal to the boundary of coarse structured grid. During a simulation run, we apply a basis function to generate the local boundary conditions at fine scale using the global solution. Benefit from that, we can use a more accurate flow-based approach in the extended local upscaling to re-compute the transmissibility in triple continuum model. Moreover, we apply a local-global upscaling formalism to guarantee dynamically updated local boundary conditions for upscaling. Besides, we present several cases using synthetic and realistic fractured networks to demonstrate the performance of MLDFM. The results prove that the proposed MLDFM approach more accurately captures the flow in complex fractured systems than EDFM solutions by comparing against fine-scale DFM. At the same time, MLDFM is more computationally efficient in comparison with fine scale DFM.",4,4,2
Numerical Simulation,Porous Media,"Li, Haoting; Wang, Shuyan; Wang, Ruichen; Liu, Yang; Shao, Baoli; Yuan, Zihan; Chen, Yujia; Ma, Yimei",Simulation on flow behavior of particles and its effect on heat transfer in porous media,Porous media; Discrete element method (DEM); Heat transfer; Migration and deposition; Numerical simulation,THERMAL-CONDUCTIVITY; DEPOSITION; CONVECTION; TRANSPORT; MODEL,"Mastering flow and heat transfer of fluids in porous media is significant in the development of oilfield. A three-dimensional porous model with anisotropic pore structure is developed, and flow and heat transfer behaviors of particles are simulated using CFD-DEM method incorporating with the coupled convective-conductive heat flow model. The interphase forces including drag force, lubricating force and thermophoretic force are considered comprehensively. Comparisons of the predicted results are also made and in a good agreement with the classical experimental results by Rimon. Simulation results show that the temperature in porous media rises along with the mixing and contact between particles and liquid. The migration of moving particles is restricted in pore spacing, and thus narrows the apertures of fluid channel, increases the local instantaneous liquid velocity. Moving particles are preferred to decelerate and deposit at a low porosity. The velocities of particles and frequency of collision increase while contact force and granular temperature decrease with an increase of porosity. With the increase of particle temperature, the temperature gradient around hot particles enlarges and the number of trapped particles goes up affected by thermophoretic force. The intensity of convection heat decreases at lower liquid velocity, and the heat conduction between particles is regarded as the main heat transfer mechanism.",3,4,4
Numerical Simulation,Porous Media,"Pinilla, Andres; Asuaje, Miguel; Hurtado, Camila; Hoyos, Angela; Ramirez, Luis; Padron, Aaron; Ratkovich, Nicolas",3D CFD simulation of a horizontal well at pore scale for heavy oil fields,Viscous fingering; Pore-scale; Horizontal well; CFD; Heavy oil; Recovery factor,POROUS-MEDIA; CO2 DISPLACEMENT; FLOW; CAPILLARY; PRESSURE; WATER; FRACTURE; DRAINAGE,"Water production in the oil industry has become so common that colloquial expressions such as ""oil companies no longer produce oil, but water"" have been unconsciously accepted in this industry. Nevertheless, water production is a serious issue in heavy oil fields with strong aquifers or fields under waterflooding for two reasons: It increases the costs affecting the economic viability of a project, and it has a serious environmental impact due to increasing energy consumption and CO2 emissions. The root cause behind this problem is a phenomenon called Viscous Fingering, which appears mainly by the viscosity ratio between the phases. This study aims to understand better the Viscous Fingering phenomenon associated with a horizontal well in 3D. For the first time, a scaled horizontal well in a numerical constructed porous media was studied using a full 3D Computational Fluid Dynamics (CFD) model. The horizontal well was scaled using the Reynolds law of similarity from a real section of a horizontal well. While the porous media was made with the DEM physical model using spherical 7mmparticles, which allows reproducing rock properties such as permeability and porosity. This phenomenon was studied at three different scaled production rates, 1000, 1500, and 2000 bbl/d. Finally, three different oils were considered to study the influence of the viscosity ratio in the CFD modeling of the fingering. It was determined that CM was capable of simulating Viscous Fingering for horizontal wells at the pore scale. Also, it could give information such as production and water cut-profiles, location and time of breakthrough, and specific locations of unrecoverable oil along the reservoir. The information given by the CFD approach could be useful for the development and improvement of completion and enhanced recovery techniques.",3,3,4
Numerical Simulation,Enhanced Oil-recovery,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Numerical Simulation,Enhanced Oil-recovery,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Numerical Simulation,Enhanced Oil-recovery,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Numerical Simulation,Enhanced Oil-recovery,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Numerical Simulation,Enhanced Oil-recovery,"Jia, Bao; Chen, Zeliang; Xian, Chenggang",Investigations of CO2 storage capacity and flow behavior in shale formation,Shale; CO2; Adsorption; Molecular diffusion,ENHANCED OIL-RECOVERY; CARBON-DIOXIDE; ADSORPTION; PRESSURE; RESERVOIRS; METHANE; INJECTION; NETWORKS; SORPTION; EOR,"CO2 storage, CO2 stimulation, CO2-enhanced oil recovery (EOR), and CO2-enhanced gas recovery (EGR) in shale reservoirs have recently attracted attention. Thorough investigations mimicking high pressure and high-temperature subsurface conditions are necessary to understand the interaction between CO2 and organic-rich shales, advance the fundamental understating of flow mechanisms in unconventional reservoirs, and successfully implement a field project. Most of the previous work focused on one aspect of adsorption, flow behavior, and reservoir numerical simulation. We suggest that a single approach investigation may lead to incomplete conclusions of CO2 injection in shales. This work comprehensively evaluates CO2 storage potential and injectivity in the Bakken Formation through various approaches. Samples are tested from the Lower Bakken Shale (LBS), the Middle Bakken (MB), and the Upper Bakken Shale (UBS). In terms of absolute and Gibbs/excess, adsorption isotherms of these two types are both measured, and the adsorbate density is estimated. We differentiate two adsorption isotherms and emphasize the correct use of the isotherm in the current commercial reservoir simulator, which is relatively obscure in the existing literature body. Nuclear magnetic resonance (NMR) confirms a portion of bitumen/absorption mobilization because of CO2 exposure. In the compositional simulations of CO2 injection in shales, several novel conclusions are obtained regarding analyzing main control factors; the most important one is that adsorption outweighs molecular diffusion in determining CO2 injection rate.",4,4,19
Numerical Simulation,Enhanced Oil-recovery,"Jing, Wenlong; Fu, Shuaishi; Zhang, Lei; Li, Aifen; Ren, Xiaoxia; Xu, Chao; Gao, Ziheng",Pore scale experimental and numerical study of surfactant flooding for enhanced oil recovery,Surfactant flooding; Glass etching model; Enhanced oil recovery; Numerical simulation,PERMEABILITY; MECHANISMS,"Surfactant flooding is a traditional method to enhance oil recovery. The surfactant flooding experiment based on glass etching model allows researchers to observe directly how the remaining oil is displaced by surfactant through microscope, so as to explore the mechanism of surfactant enhanced oil recovery. However, microscopic experiments mostly stay at the level of physical experiments, and the operation of physical experiments is too complex and cumbersome. This study is the first to combine surfactant flooding experiment with numerical simulation in glass etching model. Firstly, based on the real pore and throat structure of the real low permeability reservoir core, the glass etching model was developed, and the micro-oil-water displacement experiment was carried out. Through microscopic observation and analysis, combined with testing and image processing technology, the effect of water flooding was quantitatively investigated. Then the surfactant flooding was carried out. Three surfactants were used for displacement. It was found that residual oil in pore network was greatly reduced. The recovery factor has been greatly improved. Finally, numerical simulation of water flooding and surfactant flooding based on micro-physical experiment was carried out. The results of numerical simulation were compared with the experimental results. It is found that the recovery factor and the form of residual oil are basically the same. By analyzing the results of numerical simulation of oil recovery, it is found that the extent of surfactant enhancing oil recovery is different under different interfacial tension. The results showed that the surfactant with interfacial tension of 0.22 mN/m has the highest ability to enhance oil recovery. This work provides a reference for surfactant selection in oilfield development. It can select the best surfactant according to the factors of time, efficiency and cost.",4,4,13
Numerical Simulation,Enhanced Oil-recovery,"Cui, Jiangfeng; Si, Guangyao",Equivalent anisotropic permeability of shale rocks: Effect of micro-fractures,Shale; Equivalent permeability; Bedding fracture; Structural fracture; Numerical simulation,MICROFRACTURES; NANOPORES; TRANSPORT; OIL,"The extensive opening-mode micro-fractures, including horizontal bedding fractures and vertical structural fractures, are prevalent in shale rocks. Because of a huge difference with many orders of magnitude in permeability from the nearly impermeable shale matrix and those highly conductive micro-fractures, the microfractures are believed to contribute substantially to the macro-scale anisotropic flow properties of shale. Nevertheless, up to the present day, there has been no comprehensive research on this topic. Previous works simply employed a fixed pattern of micro-fractures and did their simulations. In this work, the finite difference method is employed to perform steady-state numerical simulation. The impact of micro-fractures on the flow capacity of shale rocks is characterized by the concept of normalized equivalent permeability. The concepts of bedding thickness, filling spacing and filling ratio are utilized to characterize the distribution pattern of horizontal bedding fractures. The length and number of vertical structural fractures are also considered. The validation of several simplistic scenarios against known results guarantees the correctness and accuracy of the numerical code. Comprehensive sensitivity analysis using realistic ranges of parameters based on literature is conducted for the two scenarios: (i) horizontal bedding fractures only, and (ii) horizontal bedding fractures and vertical structural fractures, moreover, both uniform and random distributions are discussed and then compared. Effects of bedding thickness, filling spacing and filling ratio of horizontal bedding fractures, the length and number of vertical structural fractures, the connectivity between horizontal bedding and vertical structural fractures, and the random distribution attribute of fractures on the anisotropic permeability of shale, including horizontal and vertical components, are discussed. This is the very first work that comprehensively investigates the effect of micro-fractures on the anisotropic permeability of shale rocks, which can help improve the understanding of the flow capacity of shale rocks and even the hydraulic properties of similar kinds of fractured material. Also, it is very useful for modeling the fluid flow to enhance oil/gas recovery in shale reservoirs.",3,3,8
Numerical Simulation,Enhanced Oil-recovery,"Pinilla, Andres; Asuaje, Miguel; Hurtado, Camila; Hoyos, Angela; Ramirez, Luis; Padron, Aaron; Ratkovich, Nicolas",3D CFD simulation of a horizontal well at pore scale for heavy oil fields,Viscous fingering; Pore-scale; Horizontal well; CFD; Heavy oil; Recovery factor,POROUS-MEDIA; CO2 DISPLACEMENT; FLOW; CAPILLARY; PRESSURE; WATER; FRACTURE; DRAINAGE,"Water production in the oil industry has become so common that colloquial expressions such as ""oil companies no longer produce oil, but water"" have been unconsciously accepted in this industry. Nevertheless, water production is a serious issue in heavy oil fields with strong aquifers or fields under waterflooding for two reasons: It increases the costs affecting the economic viability of a project, and it has a serious environmental impact due to increasing energy consumption and CO2 emissions. The root cause behind this problem is a phenomenon called Viscous Fingering, which appears mainly by the viscosity ratio between the phases. This study aims to understand better the Viscous Fingering phenomenon associated with a horizontal well in 3D. For the first time, a scaled horizontal well in a numerical constructed porous media was studied using a full 3D Computational Fluid Dynamics (CFD) model. The horizontal well was scaled using the Reynolds law of similarity from a real section of a horizontal well. While the porous media was made with the DEM physical model using spherical 7mmparticles, which allows reproducing rock properties such as permeability and porosity. This phenomenon was studied at three different scaled production rates, 1000, 1500, and 2000 bbl/d. Finally, three different oils were considered to study the influence of the viscosity ratio in the CFD modeling of the fingering. It was determined that CM was capable of simulating Viscous Fingering for horizontal wells at the pore scale. Also, it could give information such as production and water cut-profiles, location and time of breakthrough, and specific locations of unrecoverable oil along the reservoir. The information given by the CFD approach could be useful for the development and improvement of completion and enhanced recovery techniques.",3,3,4
Numerical Simulation,Enhanced Oil-recovery,"Mejia, Miguel; Parra, Jose E.; Mejia, Lucas; Pope, Gary A.; Balhoff, Matthew T.",Experiments and numerical simulations of chemical enhanced oil recovery in fractured carbonate rocks,Surfactant FOR; Fractured carbonates; Microemulsion phase behavior; Numerical simulation,SURFACTANT IMBIBITION; PERMEABILITY; SALINITY; DRAINAGE; PHASE; FLOW,"Secondary oil recovery from naturally fractured, oil wet carbonate reservoirs is challenging due to high permeability fractures and unfavorable capillary forces. A series of new tertiary surfactant coreflood experiments in fractured oil wet limestone cores were performed in which surfactants lowered the IFT and formed viscous microemulsions upon mixing with crude oil and brine. The viscous microemulsions cause favorable transverse pressure gradients that result in increased oil recovery. The effects of surfactant slug size, salinity and injection rate were investigated experimentally. In all cases, the injected surfactant solutions recovered significantly more oil than waterflooding. Numerical simulations were used to interpret the experimental results. The experimental oil recovery and pressure drop data were matched by reducing the fluid mobility in the fracture. A new experiment verified that a viscous phase formed in the fracture, which resulted in a significant improvement in oil recovery.",3,3,2
Numerical Simulation,Horizontal Wells,"Wu, Yonghui; Cheng, Linsong; Ma, Liqiang; Huang, Shijun; Fang, Sidong; Killough, John; Jia, Pin; Wang, Suran",A transient two-phase flow model for production prediction of tight gas wells with fracturing fluid-induced formation damage,Fracturing fluid-induced formation damage; Two-phase flow; Tight gas; Production prediction; Multi-fractured horizontal well,,"A major concern with hydraulic fracturing in tight formation is the fracturing fluid-induced formation damage (FFIFD) for the high capillary pressure and the presence of water-sensitive clays. Analytical and semi-analytical models are good choices for formation damage evaluation comparing to computationally expensive numerical simulations, particularly in early times when there is limited information about the formation properties. However, the effects of FFIFD and two-phase flow are not addressed in many analytical models. This paper presents a semi-analytical model for this problem with the consideration of both FFIFD and two-phase flow. First, the physical model and mathematical fundamentals of the model are presented. The triple-porosity model is modified to capture the formation damage caused by fracturing fluid. A low permeability fracturing fluid invasion layer (FFIL) is used to characterize leakoff caused clay swelling and polymer adsorption in the matrix pores, and two-phase flow is assumed in the fractures to capture the choking effects. The analytical solution is obtained in the Laplace domain, and a successive iteration is used to update the dynamic parameters by coupling the flowing material balance equations. Then, the commercial numerical simulator Eclipse is used to validate the precision of the semi-analytical model, and several synthetical cases are presented to study the effects of two-phase flow, and the permeability and width of FFIL on gas production rate. Finally, a field case is provided to test the application of the proposed model. The main contribution of this paper is the provision of a simple yet versatile semi-analytical model for production prediction and analysis with the consideration of fracture networks, FFIFD, and two-phase flow. It serves as a good tool for making production prediction and production data analysis for hydraulically fractured tight gas wells.",37,37,15
Numerical Simulation,Horizontal Wells,"Wang, Haitao; Kou, Zuhao; Guo, Jingjing; Chen, Zhuoting",A semi-analytical model for the transient pressure behaviors of a multiple fractured well in a coal seam gas reservoir,Coalbed methane; Multiple transportation mechanisms; Radial hydraulic fractures; Stimulated reservoir volume; Well test,HORIZONTAL WELLS; SHALE GAS; VERTICAL WELL; FLOW-RATE; PERMEABILITY; PERFORMANCE; ADSORPTION,"Multiple radial fractures can be generated in unconventional gas reservoirs after stimulation treatments such as hydraulic refracturing, high-energy gas fracturing, and explosive fracturing. This study presents a semi-analytical model to simulate the bottom-hole pressure (BHP) performances of a fractured well with multiple radial hydraulic fractures (MRHF) in a stress-sensitive coal seam gas reservoir. The adsorption-desorption and diffusion for fluid in reservoirs are considered. The continuous line-source function associated with discretization method in a composite coalbed gas reservoir is applied in Laplace domain. By means of Stehfest numerical inversion algorithm and Gauss elimination, the transient pressure responses in the well bottom are obtained and discussed. The results demonstrate that, from type curves, the main flow regimes for the proposed model in the coalbed gas reservoir are bilinear flow between adjacent radial hydraulic fractures, linear flow between adjacent radial hydraulic fractures, pseudo radial flow in stimulated region, and radial flow in un-stimulated region. Moreover, an obvious ""hump"" appears between the bilinear flow regime and the linear flow regime in stimulated region, which represents the interference between adjacent radial hydraulic fractures. The impacts of the ratio of permeability in stimulated region to that in un-stimulated region, the radius of stimulated reservoir volume (SRV), the permeability modulus, and the properties of hydraulic fractures on the transient pressure responses in well bottom are analyzed. The findings obtained in this study can pave the way for the quantitative understanding of the transient performances of multiple fractured vertical wells in unconventional reservoirs.",15,15,16
Numerical Simulation,Horizontal Wells,"Rao, Xiang; Xin, Liyuan; He, Yanxiang; Fang, Xiaoyu; Gong, Ruxiang; Wang, Fei; Zhao, Hui; Shi, Junjie; Xu, Yunfeng; Dai, Weixin",Numerical simulation of two-phase heat and mass transfer in fractured reservoirs based on projection-based embedded discrete fracture model (pEDFM),Projection-based embedded discrete fracture model; Heat and mass transfer; Fractured reservoir,SINGLE-PHASE FLOW; TRANSPORT; OIL,"pEDFM is a newly developed numerical simulation framework for mass transfer in fractured reservoirs, and this paper aims to study the application of the pEDFM framework to numerical simulation of two-phase heat and mass transfer in fractured reservoirs. Firstly, the finite volume method is used to discretize the mass and energy conservative equations. Then, all the connections between control volumes including two types of fracture-matrix (f-m), three types of fracture-fracture (f-f) and one type of matrix-matrix (m-m) connections are constructed, and corresponding transmissibility formulas of mass and heat transfer in finite-volume discrete schemes for these connections are given, and Newton iteration method is used to solve the fully implicit coupled discrete equations to obtain cell temperature, pressure and water saturation. Finally, two numerical examples including multiphase flow across high-conductivity fractures and flow barriers are implemented to show that pEDFM can eliminate the errors in EDFM for the calculated temperature profiles. An application case that applies water-flooding to a fractured reservoir model with a fractured horizontal well, four water injection wells, natural fractures and a fault is considered to show that, compared with EDFM, pEDFM can more accurately and effectively handle the numerical simulation of mass and heat transfer in realistic fractured reservoirs with complex geological conditions.",11,11,10
Numerical Simulation,Horizontal Wells,"Liu, Zizhong; Emami-Meybodi, Hamid",Rate transient analysis of infinite-acting linear flow by use of piecewise constant diffusivity coefficients,Rate-transient analysis; Infinite-acting; Linear flow; Piecewise constant diffusivity coefficients; Pressure-dependent,GAS-WELLS; UNCONVENTIONAL GAS; TIGHT OIL; PERMEABILITY; RESERVOIRS,"Rate transient analysis (RTA) techniques are developed based on the analytical solutions to the hydraulic diffusivity equation. The diffusivity equation is subject to nonlinearity caused by the dependency of the rock and fluid properties to pressure. In this study, first, we develop a semi-analytical model to solve a nonlinear diffusivity equation for transient linear flow under the constant bottom-hole pressure condition. We use piecewise constant diffusivity coefficients to linearize the diffusivity equation. The domain under consideration is divided into an arbitrary number of subdomains. Each subdomain is assigned with a constant hydraulic diffusivity coefficient. As a result, the nonlinear diffusivity equation is reduced into a set of piecewise linear equations. Further, we propose a new RTA approach using the developed semi-analytical model. We then validate both the semi-analytical model and the RTA approach against direct numerical simulation. The comparison reveals the high accuracy of the developed model in the estimation of reservoir properties, pressure profiles, and flow rates, including the cases with highly pressure-dependent properties. Finally, we apply the proposed RTA approach to the flowback and long-term production data obtained from two horizontal wells to determine the reservoir properties, such as the cross-sectional area to flow and initial permeability. The field applications demonstrate that the proposed RTA approach provides a rigorous avenue for production data analysis of pressure-sensitive formations during transient linear flow.",5,5,2
Numerical Simulation,Horizontal Wells,"Han, Bo; Cui, Guodong; Wang, Yanqing; Zhang, Jichao; Zhai, Zhiwei; Shi, Yue; Yan, Fangping; Li, Wei",Effect of fracture network on water injection huff-puff for volume stimulation horizontal wells in tight oil reservoir: Field test and numerical simulation study,Horizontal wells; Volume fracturing stimulation; Water injection huff-puff; Fracture network; Reservoir numerical simulation,OPTIMIZATION; RESOURCES,"Horizontal wells with volume fracturing stimulation technique is an effective technique to improve the single well oil production in tight oil reservoir, in which contact area of wellbore and formation is enlarged and large scale fracture network to improve the conductivity is formed. However, water injection is commonly avoided for fractured reservoirs because of the water channeling problem, which leads to the rapid decline of oil production. Water injection huff-puff is proved to be an effective method to improve the formation pressure and oil production. In the previous studies, researchers pay more attention on the huff-puff well, and the production of adjacent wells and its influencing factors are not taken seriously. Herein, the water injection huff-puff test is carried out in Huanjiang oilfield. Performance of both huff-puff well and adjacent wells are improved with oil production increased by 168.29 m3 and 876.82 m3, respectively. Two effect modes for adjacent wells are summarized considering the fracture network, well position and water breakthrough type. Moreover, reservoir numerical simulation is performed to investigate the influence of fracture network on the performance of water injection huff-puff technique. Two kinds of fracture network models of main fracture-connected model and main fracture-disconnected model are established. The results indicate that fracture network influences the performance of water injection huff-puff. For fracture connected model, shutting down adjacent wells during water injection period is an effective method to improve oil production in the whole field due to the fact that water channeling will occur leading to low formation pressure replenishing efficiency and sharp water cut rising of adjacent wells. For fracture disconnected model, formation pressure near the huff-puff well is significantly improved and so as the oil production. Water displacement effect is obvious for adjacent wells. The oil production of adjacent wells increases obviously without water cut rising sharply. In this model, shutting down adjacent wells during water injection is not recommended considering the long well occupation time.",4,4,3
Numerical Simulation,Horizontal Wells,"Wang, Shuyan; Wang, Yulin; Wang, Ruichen; Yuan, Zihan; Chen, Yujia; Shao, Baoli; Ma, Yimei",Simulation study on cutting transport in a horizontal well with hydraulic pulsed jet technology,Hydraulic pulsed jet technology; Cuttings migration; Horizontal well; Numerical simulation,DRILL PIPE ROTATION; NUMERICAL-ANALYSIS; STRING VIBRATION; PENETRATION RATE; KINETIC-THEORY; FLOW-FIELD; CFD; MODEL; FLUID; EFFICIENCY,"The hydraulic pulse jet is a high-efficiency drilling technology to improve the efficiency of bottom-hole cuttings removal by enhancing the down-hole flow of cuttings. In this paper, an Eulerian-Eulerian two-fluid model on the basis of the kinetic theory of granular flow is applied to simulate the flow behavior of cuttings and drilling fluid in a horizontal well with hydraulic pulsed jet technology. The influences of pulse jet velocity, amplitude, and frequency on hydrodynamic characteristics are analyzed. Increasing the pulse jet velocity can generate higher pressure and crossflow velocity in the bottom-hole area, quickly carry the cuttings out of the bottom-hole area, and form the cuttings bed near the outlet. The improvement of the amplitude of the pulsed jet can form a remarkable and deep jet penetration in the bottom-hole area, which has a positive effect on the cuttings migration at the bottom-hole area and destruction of the cuttings bed in the annulus. For a given average jet velocity in this paper, the optimal value of amplitude is a half of the average jet velocity. The pulse jet frequency has little effect on cuttings migration in the bottom-hole area, while a higher pulse jet frequency can effectively reduce the height of the cuttings bed in the annulus.",3,3,7
Numerical Simulation,Horizontal Wells,"Pinilla, Andres; Asuaje, Miguel; Hurtado, Camila; Hoyos, Angela; Ramirez, Luis; Padron, Aaron; Ratkovich, Nicolas",3D CFD simulation of a horizontal well at pore scale for heavy oil fields,Viscous fingering; Pore-scale; Horizontal well; CFD; Heavy oil; Recovery factor,POROUS-MEDIA; CO2 DISPLACEMENT; FLOW; CAPILLARY; PRESSURE; WATER; FRACTURE; DRAINAGE,"Water production in the oil industry has become so common that colloquial expressions such as ""oil companies no longer produce oil, but water"" have been unconsciously accepted in this industry. Nevertheless, water production is a serious issue in heavy oil fields with strong aquifers or fields under waterflooding for two reasons: It increases the costs affecting the economic viability of a project, and it has a serious environmental impact due to increasing energy consumption and CO2 emissions. The root cause behind this problem is a phenomenon called Viscous Fingering, which appears mainly by the viscosity ratio between the phases. This study aims to understand better the Viscous Fingering phenomenon associated with a horizontal well in 3D. For the first time, a scaled horizontal well in a numerical constructed porous media was studied using a full 3D Computational Fluid Dynamics (CFD) model. The horizontal well was scaled using the Reynolds law of similarity from a real section of a horizontal well. While the porous media was made with the DEM physical model using spherical 7mmparticles, which allows reproducing rock properties such as permeability and porosity. This phenomenon was studied at three different scaled production rates, 1000, 1500, and 2000 bbl/d. Finally, three different oils were considered to study the influence of the viscosity ratio in the CFD modeling of the fingering. It was determined that CM was capable of simulating Viscous Fingering for horizontal wells at the pore scale. Also, it could give information such as production and water cut-profiles, location and time of breakthrough, and specific locations of unrecoverable oil along the reservoir. The information given by the CFD approach could be useful for the development and improvement of completion and enhanced recovery techniques.",3,3,4
Numerical Simulation,Relative Permeability,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Numerical Simulation,Relative Permeability,"Khalilinezhad, Seyed Shahram; Mohammadi, Amir H.; Hashemi, Abdolnabi; Ghasemi, Mojtaba",Rheological characteristics and flow dynamics of polymer nanohybrids in enhancing oil recovery from low permeable carbonate oil reservoirs,Oil recovery; Sweep efficiency; Hydrophilic nanoparticles; Rheology; Wettability reversal; Low-permeable rock,PARTIALLY HYDROLYZED POLYACRYLAMIDE; SILICA NANOPARTICLES; WETTABILITY ALTERATION; POROUS-MEDIA; SURFACTANT; BEHAVIOR; CLAY; DISPLACEMENT; PERFORMANCE; MECHANISMS,"As the chemical flooding has proved to be one of the most efficient methods to unlock the trapped oil in porous media, studies on any further improvements in the rheological, phase, and flow behaviors of the common Chemical Enhanced Oil Recovery (CEOR) agents through the use of nanostructured-based materials have gathered significant importance in the field of petroleum engineering. Despite the extensive research in this area, the role of physical properties of polymers including molecular weight (MW) in the improvement of the flow characteristics of the resultant hybrid in a low-permeable carbonate rock has been scrutinized neither experimentally nor numerically so far. The purpose of this study was to clarify the effect of dispersed Hydrophilic Silica-Nanoparticles (HSNPs) in the polymer solution on the improvement of oil recovery during polymer flooding. Thus, rheological studies were performed to scrutinize the impacts of salinity, polymer content, and polymer MW on the viscoelastic behavior of the hybrid. An understanding of how the hybrid behaves when flowing through a relatively low-permeable carbonate rock was acquired by conducting core flood experiments. To monitor the mechanisms of the fluid flow and determine the influencing factors in the fluid distribution through complex pore systems, microfluidic models were utilized. The viscoelastic behavior of the hybrid shows that dispersing HSNPs in a polymer solution consisting of a polymer with lower MW can improve the viscosifying ability and non-Newtonian behavior of the solution. This trend becomes more noticeable by increasing polymer content. However, the employed Nanoparticles (NPs) have a distinct impact on the non-Newtonian behavior of the polymers with higher MW. The results from core flooding experiments reveal that the oil recovery factor is nearly 60% of Original Oil In-Place (OOIP) for the hybrid flooding, which displays pronounced enhancement in ultimate oil recovery, due to the proper mobility ratio of the displacement process. Pore-scale observations and the outputs of numerical simulations exhibit that wettability reversal and polymer adsorption reduction are also responsible for the improvement of oil recovery. The findings of this study not only present the underlying mechanisms of oil recovery during the hybrid flooding of low-permeable carbonate rocks but also provide a new reference for formulating a novel CEOR agent.",5,5,2
Numerical Simulation,Relative Permeability,"Wang, Zhenzhi; Fu, Xuehai; Hao, Ming; Li, Guofu; Pan, Jienan; Niu, Qinghe; Zhou, He",Experimental insights into the adsorption-desorption of CH4/N-2 and induced strain for medium-rank coals,N-2-ECBM; Binary mixed gases; Adsorption strain characteristics; Medium-rank coal; Anisotropic characteristics,GAS-ADSORPTION; COMPETITIVE ADSORPTION; METHANE ADSORPTION; PERMEABILITY; DEFORMATION; SIMULATION; DIFFUSION; EVOLUTION; NITROGEN; SORPTION,"To support the understanding of the effect of N-2-enhanced coalbed methane (N-2-ECBM) application on medium-rank coals, four coal samples from Shanxi Province were selected to test the porosity, mechanical properties and strain induced by binary gas adsorption-desorption. The results show that the desorption hysteresis is weakened with increasing N-2 fraction and is strengthened with increasing CH4 fraction, indicating that increasing the N-2 fraction can reduce the selectivity of coal to CH4. The critical desorption pressure of a mixed gas increases in a high N-2 fraction environment, promoting the desorption of CH4 and enhancing its recovery. This research clarifies the anisotropic strain characteristics induced by the adsorption-desorption of CH4/N-2 and provides reliable data for anisotropic permeability numerical simulations in the N-2-ECBM process. Swelling and shrinkage volume strain are negative-exponentially related to the N-2 fraction, and the volume shrinkage strain is close to the volume swelling strain given a N-2 fraction of 50%. There exists a polynomial relationship between the volume swelling/shrinking strain and adsorption capacity, which has a potential predictive effect on the volume strain variation in coal during N-2-ECBM. The analysis of the adsorption volume swelling strain rate and desorption volume shrinkage strain rate indicates that the N-2 fraction and micropore volume are the main factors controlling volume deformation. The volume strain decreases with increasing elastic modulus, but nitrogen injection weakens the effect of the elastic modulus on the strain. In this study, the desorption percentage increased and the volume swelling strain decreased with increasing nitrogen fraction. Nitrogen injection and sealing have a positive effect on methane desorption and the optimal N-2 fraction should be greater than 50%. This work provides a reference for improving coalbed methane production.",3,3,12
Numerical Simulation,Relative Permeability,"Wang, Jiaqi; He, Jiale; Lv, Xin; Ge, Kun; Cheng, Chuanxiao; Dong, Hongsheng",Numerical analysis of the gas recovery performance in hydrate reservoirs with various parameters by stepwise depressurization,Natural gas hydrate; Stepwise depressurization; Reservoir characteristics; Sensitivity analysis,METHANE HYDRATE; THERMAL-STIMULATION; DISSOCIATION; ENERGY; HEAT; PERMEABILITY,"Natural gas hydrates have drawn worldwide attention as a significant clean energy source in the 21st century. Depressurization is known to be the most effective method for hydrate exploitation owing to its feasibility and economic benefits. Recently, stepwise depressurization has received extensive attention owing to its advantages of effective prevention of ice generation and hydrate reformation during gas recovery. In this work, we optimized the 2-D simulator to model the evolution of temperature, pressure, hydrate saturation, and gas production behavior in hydrate sediments during decomposition process via stepwise depressurization. The effect of various reservoir characteristics on gas production was analyzed by introducing the sensitivity factor. The results demonstrated that higher specific heat capacity of the reservoir would promote gas production in the early stage of the reaction; however, this effect is reversed in the later stage. A higher thermal conductivity of the hydrate cores can dramatically enhance the gas production rate; however, this advantage is weakened with increasing thermal conductivity. Reducing the gas relative permeability hinders the hydrate decomposition process, and the water relative permeability has minimal effect on gas production. Based on the sensitivity analysis, the thermal conductivity and gas relative permeability are the main factors affecting hydrate decomposition.",3,3,9
Numerical Simulation,Relative Permeability,"Arianfar, Ali; Ramezanzadeh, Ahmad; Khalili, Mohammad",Numerical study of nonlinear fluid flow behavior in natural fractures adjacent to porous medium,Fractured reservoirs; Fracture; Roughness; Porous medium; Permeability; Forchheimer equation,,"It is essential to understand the hydraulic aperture behavior of rock fractures where fluid passes through the rock mass. The geometric parameters of fracture, such as wall roughness and fracture aperture, have a significant effect on its hydro-mechanical behavior. This issue has been addressed in many papers, but the fluid passage through the permeable zone adjacent to the fracture has rarely been studied. Therefore, this paper numerically simulated the fluid behavior in the porous fractured medium. For preparing the model geometry, the 3D scanning of fracture walls was used for the samples taken from one of the oil wells in southern Iran. The geometry of fractures was prepared using ICEM CFD software, and the fluid flow in rock fracture and porous matrix was simulated with Ansys FluentTM software. Given that the two fracture surfaces are connected in reality, the geometry of the model was constructed when the fractures are mated and the connection is established at a certain level (the connection between the two surfaces equal to 15, 30, 45, 60, 75, and 90% of the total area). The results of this simulation showed that the Forchheimer macroscopic relation well describes the nonlinear fluid flow in the rock fracture even considering the permeable matrix. However, the higher the permeability value of the matrix adjacent to the fracture, the higher the fracture permeability value. The results indicated an exponential relationship between the increased permeability and the decreased Forchheimer coefficients, which confirms the easier passage of fluid through the fracture enclosed by a zone of higher permeability. Also, the values of linear and nonlinear coefficients of Forchheimer equation were estimated for each of the geometric models, which showed that the changes in Forchheimer coefficients are exponentially related to the change in the connected surface area.",3,3,9
Numerical Simulation,Relative Permeability,"Su, Yuliang; Li, Zongfa; Zhan, Shiyuan; Li, Dongsheng; Sheng, Guanglong",Correction for capillary pressure influence on relative permeability by combining modified black oil model and Genetic Algorithm,Capillary pressure; Relative permeability; Numerical simulation; Genetic algorithm,TIGHT FORMATIONS; IMMISCIBLE FLOW; PORE-NETWORK; TEMPERATURE; DISTRIBUTIONS; SIMULATION; IMBIBITION; CURVES,"The substantial interference of the tight reservoir's capillary pressure on relative permeability measurement can significantly diminish the prediction accuracy of the oilfield production. This study established an innovative method to eliminate the capillary pressure effect on relative permeability calculation by combining the modified numerical simulation model and the Genetic Algorithm. Steady-state measurements were conducted on tight core sample (0.0321mD) to obtain the initial relative permeability curves using Darcy's law. A modified numerical simulation model that considers equivalent phase pressure for water and oil at outlet surface and directly simulates fixed injection-rate boundary conditions without using wells has been proposed. After analysis of water saturation distribution and pressure distribution along the core, absolute permeability, residual water saturation, and the two-phase relative permeability at corresponding saturation need to be optimized by the Genetic Algorithm based on the initial relative permeability curves to match the experimental results. The outcomes show that the optimized absolute permeability is 19.63% higher than the experimentally measured value, and the optimized residual water saturation is 17.46% lower than the experimental residual water saturation. For the other saturations, the differences between the optimized relative permeability and the experimental results range from 25.93% to 10.57%. The whole divergence of the experiment results and the simulation results about average water saturation and inlet pressure using optimized Kr curves is 1.57%, far less than 69.72% of the unoptimized Kr curves. This research is of great significance for accurately obtaining the relative permeability curves of the tight oil reservoir with intense capillary pressure.",3,3,5
Numerical Simulation,Relative Permeability,"Fu, Qinwen; Cudjoe, Sherifa; Ghahfarokhi, Reza Barati; Tsau, Jyun-Syung; Li, Xiaoli; Peltier, K.; Mohrbacher, D.; Baldwin, A.; Nicoud, B.; Bradford, K.",Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection-an Eagle Ford study,Molecular diffusion; Hydrocarbon gas huff-n-puff; Dual-permeability; Rock-fluid property; Gas injection; Eagle Ford shale; Unconventional reservoirs; EOR; IOR,OIL,"Fracture complexity, variation in fluid properties, variations in rock types and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research has been conducted to define diffusion coefficients coupled with rock tortuosity resulting in calculation of effective diffusion. The objective of this work is to conduct a comprehensive experimental and simulation study on lower Eagle Ford rock samples to measure diffusion coefficients for different injection cycles in three representative rock samples from the main flow unit. Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and effluent oil and gas compositions were measured. NMR measurement was repeated at the end. Three compositional simulation models were set up for three different samples using tortuosity values from FIB-SEM analysis to simulate experimental diffusion and production. For history matching, relative permeability curves, fracture properties, and tortuosity were tuned to match pressure and production results for three representative samples. Pressure profiles vary significantly between different cycles caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Effective diffusion coefficients were calculated using representative tortuosity values. Diffusion was represented by pressure drop during soaking time. This pressure drop varies across different lithofacies and for different rock samples. For produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate components increased. Gas huff-n-puff injection into shale oil reservoirs were being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments, conducted using a constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, show favorable results. Recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively.",3,3,4
Numerical Simulation,Particles,"Shi, Guoyun; Song, Shangfei; Shi, Bohui; Gong, Jing; Chen, Dongliang",A new transient model for hydrate slurry flow in oil-dominated flowlines,Multiphase flow; Natural gas hydrates; Hydrate formation; Flow assurance; Transient flow simulation,NATURAL-GAS HYDRATE; NUMERICAL-SIMULATION; INTRINSIC KINETICS; SHELL-MODEL; LIQUID FLOW; MASS; AGGLOMERATION; METHANE; SYSTEMS; DISSOCIATION,"A transient simulation tool for the gas hydrate slurry flow is crucial for hydrate flow assurance in the petroleum industry. In this work, we propose a new transient model for gas hydrate slurry flow in oil-dominated flowlines. A two-fluid model and a temperature equation are used to describe the gas-slurry two-phase flow. For the modeling of particulate phase flow, number density conservation equation and diameter conservation equation of the hydrate particles are established by Eulerian approach, a momentum conservation equation is established by Lagrangian approach. Furthermore, combining with the hydrate formation model, the transient gas hydrate slurry flow in oil-dominated flowlines can be numerically simulated. This model is verified by experimental data and field data, respectively. Afterwards, it is applied to analyze the transient behavior of the gas-hydrate slurry multiphase flow upon reduced gas well production. Finally, the sensitivity analysis of effects of flowrate, initial average size of water droplets and drag force on the hydrate slurry multiphase flow is performed. These results are of great practical value to give a deeper understanding of hydrate slurry multiphase flow, and contribute to better hydrate management in the petroleum industry by using hydrate slurry flow technology.",6,6,8
Numerical Simulation,Particles,"Wang, Zhiming; Hurter, Suzanne; You, Zhenjiang; Honari, Vahab; Sun, Yuning; Zhang, Shuo",Influences of negative pressure on air-leakage of coalseam gas extraction: Laboratory and CFD-DEM simulations,Coal seam gas; Negative pressure; Air-leakage; Fracture; Blockage; CFD-DEM simulation,FINES MIGRATION; METHANE EXTRACTION; 2-PHASE FLOW; MODEL; PARTICLES; DRAINAGE; RATIO,"Comprehensive understandings of the influences of negative pressure on air-leakage and its driving mechanism are critical for controlling methane concentration during coal seam gas extraction. Laboratory experiments were conducted using an integrated apparatus to study the air-leakage process of coal seam gas extraction under different negative pressures. In addition, a coupled computational fluid dynamics-discrete element approach was used to simulate the process of air flow and particle transport in a natural coal fracture to understand the influential mechanism of negative pressure on air-leakage at the mesoscale. Experimental results show that with an increase in the absolute value of negative pressure, the air-leakage experiences three stages of increase, decrease and increase at Stage I, Stage II and Stage III, respectively. It is reported for the first time and in good agreement with field test data. From experimental and numerical results, at Stage I the air-leakage increases with the absolute value of negative pressure because there is no blockage in fractures around borehole. At Stage II, the further increased absolute value of negative pressure contributes to particles motion in fractures. It gradually leads to the formation of blockage structure composed of aggregated particles in fractures, and the decrease of fracture conductivity and air velocity. With the absolute value of negative pressure rising continuously, the contact forces between the aggregated particles increase. Therefore, the balance of the blockage structure tends to be broken, which helps to understand the air-leakage increase with the absolute value of negative pressure at Stage III. Between Stage II and Stage III, there is a valley point corresponding to the minimum air-leakage, which is important to the improvement of gas extraction performance. The contact forces on the aggregated soft particles are larger than those on the aggregated hard particles under the same negative pressure. Therefore, the blockage structure consisting of soft particles is much easier to be broken than that formed by hard particles. This explains why the absolute value of negative pressure corresponding to the valley point for hard coal model is larger than that for the soft coal model.",5,5,12
Numerical Simulation,Particles,"Wang, Tongtao; Chai, Guoxing; Cen, Xueqi; Yang, Jie; Daemen, J. J. K.",Safe distance between debrining tubing inlet and sediment in a gas storage salt cavern,Natural gas; Salt cavern gas storage; Debrining; Mathematical model; Insoluble particle; Optimization design,SIMULATION; RISK,"The proper determination of the distance between the debrining inner tubing (DIT) inlet and sediment during the debrining of an underground gas storage (UGS) salt cavern both can increase the expelled brine volume and decrease the risk of blocking the DIT caused either by brine crystallization or by sucking in of large chunks of insoluble solids. Based on the fluid distribution and the force applied to the insoluble particles around the DIT inlet, a mathematical model is built to describe the movement of insoluble particles in a cavern. The equations are deduced for the forces applied to the particles, the critical fluid rate of the brine, and the critical diameter of particles being sucked in. An equation is given to determine the critical distance between DIT inlet and sediment. Based on the diameter distribution of the insoluble particles, the critical distance is proposed between DIT inlet and sediment under different DIT sizes and debrining rates. Results show that increasing the DIT size can decrease the distance between DIT inlet and sediment greatly, as well as the risk of sucking in insoluble particles. Increasing the diameter of the particles permitted to be sucked in has a slight effect on increasing the debrining volume but notably increases the risk of blocking the DIT. Not permitting insoluble particles being sucked in is proposed as the criterion to determine the distance between the DIT inlet and sediment for an actual debrining. Numerical simulation and field testing results show that the proposed mathematical model has a high accuracy and can effectively guide the field debrining operation.",5,5,0
Numerical Simulation,Particles,"Movahedi, Hamed; Jamshidi, Saeid",Experimental and CFD simulation of slurry flow in the annular flow path using two-fluid model,Granular flow; Turbulence model; Annular space; CFD; Flow loop; Experimental analyses,CIRCULATING FLUIDIZED-BED; GAS-SOLID FLOW; NUMERICAL-SIMULATION; BEHAVIOR; TRANSPORT; DEPOSITION; DYNAMICS,"The current study is allocated to experimental evaluation of the multiphase flow of fine solid particles (FSPs) as well as comprehensive numerical study in an annular space under static, laminar, and turbulent flow conditions with consideration of the inner pipe eccentricity and rotation. The experimental investigation was carried out using an annular pipe flow loop. The numerical modeling and simulation of the multiphase flow in the annular space have been performed using the Euler-Euler approach. The unsteady-state multiphase model based on the kinetic theory of granular flow (KTGF) is developed to investigate the particulate flow characteristics in the annular space. Moreover, Standard and Realizable k-epsilon turbulence models used to predict turbulence in this study. The Realizable Per-Phase turbulence model with new corrected coefficients (C-2 = 4.2, C-3 = 1.3, C-T = 0.0131, sigma(kappa) = 1, sigma(epsilon) = 1.2) is calibrated to predict the pressure drop along the annular pipe for solid-liquid multiphase flow. Comparison between numerical and experimental analyses showed that under both flowing and static conditions, the simulation results are in good agreement with experimental data. Based on the error estimation model, the CFD model's accuracy for pressure drop and FSPs concentration prediction is 99% and 95%, respectively. The trends of the variation in particle concentration along the annular pipe were investigated for different flow velocities (0.05-2.5 m/s) and different inner pipe rotations of 500, 1000, and 1500 rpm. The results also showed that the higher particle settling occurred at the critical inclination angles of 45-60 degrees.",4,4,4
Numerical Simulation,Particles,"Li, Haoting; Wang, Shuyan; Wang, Ruichen; Liu, Yang; Shao, Baoli; Yuan, Zihan; Chen, Yujia; Ma, Yimei",Simulation on flow behavior of particles and its effect on heat transfer in porous media,Porous media; Discrete element method (DEM); Heat transfer; Migration and deposition; Numerical simulation,THERMAL-CONDUCTIVITY; DEPOSITION; CONVECTION; TRANSPORT; MODEL,"Mastering flow and heat transfer of fluids in porous media is significant in the development of oilfield. A three-dimensional porous model with anisotropic pore structure is developed, and flow and heat transfer behaviors of particles are simulated using CFD-DEM method incorporating with the coupled convective-conductive heat flow model. The interphase forces including drag force, lubricating force and thermophoretic force are considered comprehensively. Comparisons of the predicted results are also made and in a good agreement with the classical experimental results by Rimon. Simulation results show that the temperature in porous media rises along with the mixing and contact between particles and liquid. The migration of moving particles is restricted in pore spacing, and thus narrows the apertures of fluid channel, increases the local instantaneous liquid velocity. Moving particles are preferred to decelerate and deposit at a low porosity. The velocities of particles and frequency of collision increase while contact force and granular temperature decrease with an increase of porosity. With the increase of particle temperature, the temperature gradient around hot particles enlarges and the number of trapped particles goes up affected by thermophoretic force. The intensity of convection heat decreases at lower liquid velocity, and the heat conduction between particles is regarded as the main heat transfer mechanism.",3,4,4
Numerical Simulation,Rock Typing,"Tan, Maojin; Su, Mengning; Liu, Weihua; Song, Xiaodong; Wang, Siyu",Digital core construction of fractured carbonate rocks and pore-scale analysis of acoustic properties,Fractured carbonate rock; Digital core; Rock physics; Acoustic properties; Pore-scale simulation,LINEAR ELASTIC PROPERTIES; WAVE-PROPAGATION; COMPOSITES,"Fractures in carbonate rocks make the reservoir and its elastic properties complex, which creates challenges in the geophysical exploration of oil and gas resources. To study the elastic properties of fractured carbonate rocks, pore-scale numerical simulations and microscopic analyses are necessary for theoretically comprehensive analysis. First, a digital core of carbonate rock was established from X-ray CT scan using medium filtering and threshold segmentation method technologies. Then, some carbonate rock digital cores with different types of fractures were constructed by inserting fractures into scanning slices. Based on the theory of elastic mechanics, the elastic properties of carbonate rock cores with fractures were calculated using the finite-element method, and the effects of the microscopic factors on the rock elastic properties were studied in detail. The calculated stiffness-matrix elements of the digital core are consistent with the Gassmann fluid-substitution theory in isotropic rock. For the digital cores with coin-shaped and penetrating fractures, the influence of fracture density, fracture opening, and fracture length on the stiffness-matrix elements and the wave velocity were studied in detail through pore-scale simulations. This work provides a new perspective for carbonate rock physics and lays a foundation for multi-scale analysis of acoustic properties in carbonate rock reservoirs.",6,6,6
Numerical Simulation,Rock Typing,"Cui, Yingzhi; Shikhov, Igor; Li, Rupeng; Liu, Shitao; Arns, Christoph H.",A numerical study of field strength and clay morphology impact on NMR transverse relaxation in sandstones,Kaolinite model; NMR transverse relaxation; Relaxation regime,PORE-SIZE DISTRIBUTIONS; MAGNETIC-FIELD; NUCLEAR MAGNETIZATION; POROUS-MEDIA; DIFFUSION; GRADIENTS; DECAY; PERMEABILITY; IMAGE; TIMES,"Nuclear magnetic resonance (NMR) relaxometry is a common technique for the petrophysical characterization of sedimentary rocks. The standard interpretation of NMR transverse relaxation responses is based on the assumptions of the fast diffusion limit, dominant surface relaxation, and weak coupling between pores, allowing an interpretation of the NMR response as pore size distribution. In general, three asymptotic relaxation regimes can be defined by comparing dephasing, structural and diffusion length scales. The shortest length scale defines the dominating relaxation regime, which is either the free diffusion, motional averaging, or localization regime. Complex mineralogy and morphology of rocks, especially due to clay minerals, may lead to the co-existence and coupling of multiple relaxation regimes in the presence of surface relaxivity heterogeneity and internal gradient effects. In this work the relationship between morphology of rocks, strength of applied magnetic field, resulting relaxation regimes and observed NMR relaxation responses is studied numerically. Limitations in the discretization of clays typical for micro-CT images are addressed by introducing a fine-scale kaolinite model based on SEM images. The model is utilized to evaluate the field-dependent mean transverse relaxation time and effective diffusion coefficient of clay regions. These effective parameters are incorporated into random-walk simulations on micro-CT images. Relaxation regimes are analysed spatially for three different types of sandstone as function of external magnetic field strength. Increase of paramagnetic clay content, field strength and echo-time increases the fraction of spins relaxing in the localization regime within macro-pores, typically being localised in the regions neighbouring clay pockets and grain surfaces. We demonstrate that a significant contribution of the localization regime to relaxation may lead to incorrect predictions of pore-size distributions and fluid typing. The prefactor of permeability correlations varies significantly due to clay effects. Accounting for these effects should enable more robust petrophysical interpretations.",5,5,6
Numerical Simulation,Rock Typing,"Fu, Qinwen; Cudjoe, Sherifa; Ghahfarokhi, Reza Barati; Tsau, Jyun-Syung; Li, Xiaoli; Peltier, K.; Mohrbacher, D.; Baldwin, A.; Nicoud, B.; Bradford, K.",Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection-an Eagle Ford study,Molecular diffusion; Hydrocarbon gas huff-n-puff; Dual-permeability; Rock-fluid property; Gas injection; Eagle Ford shale; Unconventional reservoirs; EOR; IOR,OIL,"Fracture complexity, variation in fluid properties, variations in rock types and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research has been conducted to define diffusion coefficients coupled with rock tortuosity resulting in calculation of effective diffusion. The objective of this work is to conduct a comprehensive experimental and simulation study on lower Eagle Ford rock samples to measure diffusion coefficients for different injection cycles in three representative rock samples from the main flow unit. Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and effluent oil and gas compositions were measured. NMR measurement was repeated at the end. Three compositional simulation models were set up for three different samples using tortuosity values from FIB-SEM analysis to simulate experimental diffusion and production. For history matching, relative permeability curves, fracture properties, and tortuosity were tuned to match pressure and production results for three representative samples. Pressure profiles vary significantly between different cycles caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Effective diffusion coefficients were calculated using representative tortuosity values. Diffusion was represented by pressure drop during soaking time. This pressure drop varies across different lithofacies and for different rock samples. For produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate components increased. Gas huff-n-puff injection into shale oil reservoirs were being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments, conducted using a constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, show favorable results. Recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively.",3,3,4
Numerical Simulation,Rock Typing,"Kolah-kaj, Parvin; Kord, Shahin; Soleymanzadeh, Aboozar","The effect of pressure on electrical rock typing, formation resistivity factor, and cementation factor",Electrical quality index (EQI); Electrical rock typing; Cementation factor; Fluid saturation,OVERBURDEN PRESSURE; FZI-ASTERISK; FLOW UNITS; POROSITY; SATURATION,"As a key parameter in the calculation of fluid saturation, cementation factor (m) is routinely approximated using the Archie's equation. Numerous correlations and several techniques have been proposed to determine cementation factor, one of which is electrical rock typing. Besides hydraulic rock typing, which plays a significant role in modeling and numerical simulation of reservoirs, electrical rock typing refers to categorizing rocks into distinct groups based on similarity in electrical properties of the rocks. The current study focuses on the effective pressure impact on electrical rock typing. In addition, the effect of change in effective pressure due to production on petrophysical properties, and consequently rock capacity for transmitting electricity was studied. In this paper, 39 limestone samples were studied to analyze the effect of pressure on porosity (0), formation resistivity factor (F), and m. Performance of the Archie's equation under different effective pressures was further examined. Considering the fact that an increase in effective pressure causes pore and throat deformation, the pressure impact on the rock quality for transmitting electricity was scrutinized. Then, the influence of effective pressure on electrical rock typing was studied. It was discovered that due to an increase in effective pressure, F and m increase while 0 decreases. The rock quality for transmitting electricity and the effective pressure were found to be correlated through a second-order polynomial equation. It was further concluded that the electrical rock typing was affected by the changes in electrical efficiency, and the number of electrical rock types and the presence of samples in them were influenced by variations of the effective pressure. This was a noticeable point because different rock types require the adoption of different correlations for determining the parameters of the Archie's equation; therefore, realizing that each sample belongs to which rock type is essential. The findings of this study contributed to a better understanding of the impact of the effective pressure on Archie's parameters and petrophysical properties, leading to a method for determining fluid saturation under different effective pressures during the reservoir lifespan.",3,3,3
Numerical Simulation,Theoretical Model,"Kumar, Narendra; Pal, Nilanjan; Mandal, Ajay","Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match",Nanoemulsion flooding; Numerical simulation; Relative permeability; CMG-STARS; History matching; Enhanced oil recovery,ELEMENTARY-VOLUME ANALYSIS; FULLY IMPLICIT; CHEMICAL EOR; SURFACTANT; OPTIMIZATION; STABILITY; INJECTION; EMULSIONS; PARALLEL; FOAM,"In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23?28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.",6,6,8
Numerical Simulation,Theoretical Model,"Song, Hengyu; Shi, Huaizhong; Li, Gensheng; Chen, Zhenliang; Li, Xiaojing",Numerical simulation of the energy transfer efficiency and rock damage in axial-torsional coupled percussive drilling,Axial percussion; Torsional percussion; Coupled percussive drilling; Energy transfer efficiency; Rock damage,MODEL; BIT; PLASTICITY,"Axial-torsional coupled percussive drilling helps improve the breaking efficiency of hard rock. This paper adopted the simulation method to study the energy transfer efficiency (ETE), and rock damage in axial-torsional coupled percussive drilling with a multiple-button bit. The axial-torsional coupled percussive system model was first built in the finite element calculation platform. And then the temperature-dependent model parameter values for rock were selected. Finally, we simulated axial-torsional coupled percussive process, and analyzed the effects of various parameters. The main simulation results are as follows. In axial-torsional coupled percussive process, axial percussion has a significant influence on the ETE of torsional percussion, while torsional percussion has little influence on the ETE of axial percussion. As the impact velocity of axial percussive hammer increases, the ETE of axial percussion, the ETE of torsional percussion, and the total ETE all augment. When the impact velocity is increased from 4 m/s to 16 m/s, the total ETE is increased by 62.8%. Both the ETE of torsional percussion and the total ETE decline with the pulse torque amplitude increasing. When the pulse torque amplitude is increased from 4000 N m to 28000 N m, the total ETE is reduced by 18.3%. For convenience, we abbreviate the ratio of the torsional input energy to the total input energy as RTT. An increase in RTT, or an increase in rock temperature will reduce the ETE of axial percussion, the ETE of torsional percussion, and the total ETE. When the RTT is increased from 2.3% to 84.4%, the total ETE is reduced by 34.5%. As the axial impact velocity increases, the rock damaged areas gradually expand. With the increase of the pulse torque amplitude, the rock damaged areas sharply expand. As the RTT increases, the number of narrow tensile damaged zones extending outwardly decrease, while the connectivity between the tensile damaged areas caused by buttons augments. As the rock temperature rises, the total damaged area of rock gradually shrinks. This study provides a theoretical basis for the efficient rock breaking in axial-torsional coupled percussive drilling.",4,5,4
Numerical Simulation,Theoretical Model,"Liu, Yong; Guo, Xinhui; Wei, Jianping; Zhang, Huidong",Application of supercritical carbon dioxide jet: A parametric study using numerical simulation model,Coal bed methane; Coal breakage; Drilling; Supercritical carbon dioxide jets; Impact pressure,,"Defining the structure of a supercritical carbon dioxide (SC-CO2) jet flow field is a critical component of establishing a theoretical basis for its application. This study investigates the influence of pressure ratio on the wave features of an SC-CO2 jet flow field using a new numerical simulation model and flow field visualization experiments. To assess the characteristics of the SC-CO2 flow field and predict the distribution of temperature and pressure, a computational model based on constant pressure specific heat capacity and thermal conductivity of SC-CO2 was established, and the user-defined function (UDF) feature available in ANSYS Fluent software was used. The results demonstrated that the temperature and pressure of the SC-CO2 jet flow field could be accurately predicted by the numerical simulation model proposed in this research, and the wave features of the flow field could be visualized by both the numerical simulation contours and the experiments. The wave features, which resulted from different pressure ratios, were found be a function of the structure of the Laval nozzle at a constant inlet pressure. The pressure ratio could be controlled by the nozzle structure and accurately describe the wave features of the SC-CO2 jet flow field. In this study, an optimal pressure ratio of 1.31 was used and the flow field structure corresponding to the maximum jet impact force could be satisfactorily described by the optimal pressure ratio.",3,3,13
Numerical Simulation,Theoretical Model,"Shaohu, Liu; Hao, Zhou; Hong, Zhong; Yang, Liu; Zhen, Wang",Experimental and numerical simulation study on fatigue life of coiled tubing with typical defects,CT; Fatigue life; Defect; Fatigue failure; Pit defects; Defect depth; Theoretical model,MODEL,"Coiled tubing (CT) technology is widely used in oil and gas development. In operation process, defects are common and accelerate the fatigue failure of CT. Therefore, it is necessary to predict the fatigue life of CT with defects. In this paper, the combining method of finite element analysis and experimental analysis is used to analyze the parameters of affecting the fatigue life of CT, such as the depth, length, width and distribution of the defects. Experimental results show that the most important defect parameter is the defect depth. Considering the effect of these significant parameters, based on the elastic-plastic mechanics and Brown-Miller fatigue life theoretical model, a theoretical model of the fatigue life of CT with pit defects was established, and it was modified according to the experimental results for obtaining more accurate theoretical model of the fatigue life of CT. The theoretical model is suitable for CT with ellipsoidal defects, and the defects are volume reduction defects caused by mechanical damage.",3,3,5
Numerical Simulation,Mathematical Model,"Wu, Yonghui; Cheng, Linsong; Ma, Liqiang; Huang, Shijun; Fang, Sidong; Killough, John; Jia, Pin; Wang, Suran",A transient two-phase flow model for production prediction of tight gas wells with fracturing fluid-induced formation damage,Fracturing fluid-induced formation damage; Two-phase flow; Tight gas; Production prediction; Multi-fractured horizontal well,,"A major concern with hydraulic fracturing in tight formation is the fracturing fluid-induced formation damage (FFIFD) for the high capillary pressure and the presence of water-sensitive clays. Analytical and semi-analytical models are good choices for formation damage evaluation comparing to computationally expensive numerical simulations, particularly in early times when there is limited information about the formation properties. However, the effects of FFIFD and two-phase flow are not addressed in many analytical models. This paper presents a semi-analytical model for this problem with the consideration of both FFIFD and two-phase flow. First, the physical model and mathematical fundamentals of the model are presented. The triple-porosity model is modified to capture the formation damage caused by fracturing fluid. A low permeability fracturing fluid invasion layer (FFIL) is used to characterize leakoff caused clay swelling and polymer adsorption in the matrix pores, and two-phase flow is assumed in the fractures to capture the choking effects. The analytical solution is obtained in the Laplace domain, and a successive iteration is used to update the dynamic parameters by coupling the flowing material balance equations. Then, the commercial numerical simulator Eclipse is used to validate the precision of the semi-analytical model, and several synthetical cases are presented to study the effects of two-phase flow, and the permeability and width of FFIL on gas production rate. Finally, a field case is provided to test the application of the proposed model. The main contribution of this paper is the provision of a simple yet versatile semi-analytical model for production prediction and analysis with the consideration of fracture networks, FFIFD, and two-phase flow. It serves as a good tool for making production prediction and production data analysis for hydraulically fractured tight gas wells.",37,37,15
Numerical Simulation,Mathematical Model,"Wang, Tongtao; Chai, Guoxing; Cen, Xueqi; Yang, Jie; Daemen, J. J. K.",Safe distance between debrining tubing inlet and sediment in a gas storage salt cavern,Natural gas; Salt cavern gas storage; Debrining; Mathematical model; Insoluble particle; Optimization design,SIMULATION; RISK,"The proper determination of the distance between the debrining inner tubing (DIT) inlet and sediment during the debrining of an underground gas storage (UGS) salt cavern both can increase the expelled brine volume and decrease the risk of blocking the DIT caused either by brine crystallization or by sucking in of large chunks of insoluble solids. Based on the fluid distribution and the force applied to the insoluble particles around the DIT inlet, a mathematical model is built to describe the movement of insoluble particles in a cavern. The equations are deduced for the forces applied to the particles, the critical fluid rate of the brine, and the critical diameter of particles being sucked in. An equation is given to determine the critical distance between DIT inlet and sediment. Based on the diameter distribution of the insoluble particles, the critical distance is proposed between DIT inlet and sediment under different DIT sizes and debrining rates. Results show that increasing the DIT size can decrease the distance between DIT inlet and sediment greatly, as well as the risk of sucking in insoluble particles. Increasing the diameter of the particles permitted to be sucked in has a slight effect on increasing the debrining volume but notably increases the risk of blocking the DIT. Not permitting insoluble particles being sucked in is proposed as the criterion to determine the distance between the DIT inlet and sediment for an actual debrining. Numerical simulation and field testing results show that the proposed mathematical model has a high accuracy and can effectively guide the field debrining operation.",5,5,0
Numerical Simulation,Mathematical Model,"Fu, Hao; Wang, Sai; Ling, Kegang",Detection of two-point leakages in a pipeline based on lab investigation and numerical simulation,Pipeline leakages; Pressure distribution; Mathematical model; Multi-rate testing,MODEL,"The pipeline is an efficient tool to transmit fluid in a long distance. However, due to different reasons such as pipe aging or natural disaster, multiple leaks can occur to the broken pipeline system. Therefore, it is very crucial to find an accurate, quick, and low-cost method to detect the leakages in the pipeline. In this study, pressure distribution analysis was proposed to diagnose the location of the leakages via experimental study and Computational Fluid Dynamics (CFD) simulation. Different dimensionless variables, which are the dimensionless leak location, dimensionless leak rate, and dimensionless pressure drop, were applied in our analysis. Through the mathematical modeling which was built on the dimensionless variables, the locations of the leakages can be detected. Multiple flowrate testing was conducted to detect the locations of two leakages. The proposed method can be used to monitor the severity of the pipeline during the operation. Different from former researchers, our work combined the experimental study, CFD simulation, and dimensionless variable analysis to solve the problem of two-point leak detection. This new method can be applied to detect the leakages under different flow rates. For the detection of multiple leaks, a trial-and-error approach was investigated. When the pressure and flow rate at the inlet and outlet of the leaking pipe are known, not only does the method supply an inexpensive way to identify the leaks but also it shortens the time interval between an accident occurring and finding the leak points.",3,3,6
Numerical Simulation,Spontaneous Imbibition,"Liu, Dengke; Ren, Dazhong; Du, Kun; Qi, Yiru; Ye, Feng",Impacts of mineral composition and pore structure on spontaneous imbibition in tight sandstone,Spontaneous imbibition; Mineral composition; Pore structure; Tight sandstone,DIRECT NUMERICAL-SIMULATION; TRIASSIC YANCHANG FORMATION; ORDOS BASIN; NITROGEN ADSORPTION; OIL; RESERVOIR; SALINITY; TRANSPORT,"Spontaneous imbibition is a fundamental mechanism to figure out the rock-fluid interplay during waterflooding and hydraulic fracturing. Mineral composition and pore structure play significant roles in imbibition efficiency, but how these parameters influence the oil production efficiency still is a myth. This research conducted the spontaneous imbibition experiments combined with low-temperature adsorption and nuclear magnetic resonance to (1) study how minerals and pore structures impact fluid movement features for tight sandstones; (2) systematically investigate the contribution to oil recovery of different pores' types and the impact of pore connectivity on spontaneous imbibition. The results show that the brine is inclined to attach hydrophilic minerals because of the wettability, increasing the imbibition efficiency. Additionally, with the tiny pores' development, the oil is more easily replaced by the brine due to strong capillary pressure. Last, as the mainstream imbibition area grows, the oil is preferentially displaced by the brine. The research provides insights into how mineral compositions and pore structures can influence spontaneous imbibition efficiency and improves the understanding of the complicated interaction between fluid and minerals in tight sandstones.",17,15,9
Numerical Simulation,Spontaneous Imbibition,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Numerical Simulation,Proxy Model,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Numerical Simulation,Proxy Model,"Deng, Lichi; Pan, Yuewei",Data-driven proxy model for waterflood performance prediction and optimization using Echo State Network with Teacher Forcing in mature fields,Data-driven proxy model; Echo state network; Teacher forcing; Machine learning; Waterflood; Optimization,,"Waterflood has been widely applied across the world as the most important secondary recovery process to improve reservoir performance. The schemes applied to waterflood projects involve key decision-making which aims to maximize the net present value (NPV) for a given period, improve recovery and sweep efficiency, maintain reservoir pressure, reduce water production, and avoid water recycling. Traditionally, the preferred approach to estimate the future performance of any given waterflood project is through the numerical reservoir simulation. However, despite the great power and intuition associated with the simulation models, sometimes this potential is unachievable due to massive computational requirements. Also, in some other cases, there may exist no simulation model to begin with. To tackle these problems, data-driven proxy models are proposed. In this research, we propose a novel machine-learning-based proxy model for waterflood performance prediction and further apply it for production optimization purpose to obtain the optimal future well control. The data-driven model is realized using the Echo State Network (ESN) under the paradigm of ""Reservoir Computing"" (RC). Compared with traditional ESNs, this specific methodology includes a feedback loop from the output into the high dimensional ""reservoir"" to achieve improved prediction results for separated phase production rates. Teacher Forcing (TF) technique is used for easier incorporation of the feedback information without introducing additional recurrent loops during the training process. Furthermore, training ESN proxy models utilizes Ridge Regression, thus all calculations within have analytical solutions that guarantee much improved speed when evaluating forward model-runs, which further lowers the computational demand during the optimization process. The proposed workflow is typically more suitable for mature fields since reliable production data after breakthrough from each producer could greatly improve the training process, and it can be used under the circumstance where no reservoir model has been established. In this research, we present two test examples where we apply ESN to learn the reservoir simulation results of waterflood and further perform open-loop optimization on each of them.",5,5,2
Numerical Simulation,Jet,"Liu, Yong; Guo, Xinhui; Wei, Jianping; Zhang, Huidong",Application of supercritical carbon dioxide jet: A parametric study using numerical simulation model,Coal bed methane; Coal breakage; Drilling; Supercritical carbon dioxide jets; Impact pressure,,"Defining the structure of a supercritical carbon dioxide (SC-CO2) jet flow field is a critical component of establishing a theoretical basis for its application. This study investigates the influence of pressure ratio on the wave features of an SC-CO2 jet flow field using a new numerical simulation model and flow field visualization experiments. To assess the characteristics of the SC-CO2 flow field and predict the distribution of temperature and pressure, a computational model based on constant pressure specific heat capacity and thermal conductivity of SC-CO2 was established, and the user-defined function (UDF) feature available in ANSYS Fluent software was used. The results demonstrated that the temperature and pressure of the SC-CO2 jet flow field could be accurately predicted by the numerical simulation model proposed in this research, and the wave features of the flow field could be visualized by both the numerical simulation contours and the experiments. The wave features, which resulted from different pressure ratios, were found be a function of the structure of the Laval nozzle at a constant inlet pressure. The pressure ratio could be controlled by the nozzle structure and accurately describe the wave features of the SC-CO2 jet flow field. In this study, an optimal pressure ratio of 1.31 was used and the flow field structure corresponding to the maximum jet impact force could be satisfactorily described by the optimal pressure ratio.",3,3,13
Numerical Simulation,Jet,"Wang, Shuyan; Wang, Yulin; Wang, Ruichen; Yuan, Zihan; Chen, Yujia; Shao, Baoli; Ma, Yimei",Simulation study on cutting transport in a horizontal well with hydraulic pulsed jet technology,Hydraulic pulsed jet technology; Cuttings migration; Horizontal well; Numerical simulation,DRILL PIPE ROTATION; NUMERICAL-ANALYSIS; STRING VIBRATION; PENETRATION RATE; KINETIC-THEORY; FLOW-FIELD; CFD; MODEL; FLUID; EFFICIENCY,"The hydraulic pulse jet is a high-efficiency drilling technology to improve the efficiency of bottom-hole cuttings removal by enhancing the down-hole flow of cuttings. In this paper, an Eulerian-Eulerian two-fluid model on the basis of the kinetic theory of granular flow is applied to simulate the flow behavior of cuttings and drilling fluid in a horizontal well with hydraulic pulsed jet technology. The influences of pulse jet velocity, amplitude, and frequency on hydrodynamic characteristics are analyzed. Increasing the pulse jet velocity can generate higher pressure and crossflow velocity in the bottom-hole area, quickly carry the cuttings out of the bottom-hole area, and form the cuttings bed near the outlet. The improvement of the amplitude of the pulsed jet can form a remarkable and deep jet penetration in the bottom-hole area, which has a positive effect on the cuttings migration at the bottom-hole area and destruction of the cuttings bed in the annulus. For a given average jet velocity in this paper, the optimal value of amplitude is a half of the average jet velocity. The pulse jet frequency has little effect on cuttings migration in the bottom-hole area, while a higher pulse jet frequency can effectively reduce the height of the cuttings bed in the annulus.",3,3,7
Numerical Simulation,Coal Seam Gas,"Wang, Haitao; Kou, Zuhao; Guo, Jingjing; Chen, Zhuoting",A semi-analytical model for the transient pressure behaviors of a multiple fractured well in a coal seam gas reservoir,Coalbed methane; Multiple transportation mechanisms; Radial hydraulic fractures; Stimulated reservoir volume; Well test,HORIZONTAL WELLS; SHALE GAS; VERTICAL WELL; FLOW-RATE; PERMEABILITY; PERFORMANCE; ADSORPTION,"Multiple radial fractures can be generated in unconventional gas reservoirs after stimulation treatments such as hydraulic refracturing, high-energy gas fracturing, and explosive fracturing. This study presents a semi-analytical model to simulate the bottom-hole pressure (BHP) performances of a fractured well with multiple radial hydraulic fractures (MRHF) in a stress-sensitive coal seam gas reservoir. The adsorption-desorption and diffusion for fluid in reservoirs are considered. The continuous line-source function associated with discretization method in a composite coalbed gas reservoir is applied in Laplace domain. By means of Stehfest numerical inversion algorithm and Gauss elimination, the transient pressure responses in the well bottom are obtained and discussed. The results demonstrate that, from type curves, the main flow regimes for the proposed model in the coalbed gas reservoir are bilinear flow between adjacent radial hydraulic fractures, linear flow between adjacent radial hydraulic fractures, pseudo radial flow in stimulated region, and radial flow in un-stimulated region. Moreover, an obvious ""hump"" appears between the bilinear flow regime and the linear flow regime in stimulated region, which represents the interference between adjacent radial hydraulic fractures. The impacts of the ratio of permeability in stimulated region to that in un-stimulated region, the radius of stimulated reservoir volume (SRV), the permeability modulus, and the properties of hydraulic fractures on the transient pressure responses in well bottom are analyzed. The findings obtained in this study can pave the way for the quantitative understanding of the transient performances of multiple fractured vertical wells in unconventional reservoirs.",15,15,16
Numerical Simulation,Coal Seam Gas,"Wang, Zhiming; Hurter, Suzanne; You, Zhenjiang; Honari, Vahab; Sun, Yuning; Zhang, Shuo",Influences of negative pressure on air-leakage of coalseam gas extraction: Laboratory and CFD-DEM simulations,Coal seam gas; Negative pressure; Air-leakage; Fracture; Blockage; CFD-DEM simulation,FINES MIGRATION; METHANE EXTRACTION; 2-PHASE FLOW; MODEL; PARTICLES; DRAINAGE; RATIO,"Comprehensive understandings of the influences of negative pressure on air-leakage and its driving mechanism are critical for controlling methane concentration during coal seam gas extraction. Laboratory experiments were conducted using an integrated apparatus to study the air-leakage process of coal seam gas extraction under different negative pressures. In addition, a coupled computational fluid dynamics-discrete element approach was used to simulate the process of air flow and particle transport in a natural coal fracture to understand the influential mechanism of negative pressure on air-leakage at the mesoscale. Experimental results show that with an increase in the absolute value of negative pressure, the air-leakage experiences three stages of increase, decrease and increase at Stage I, Stage II and Stage III, respectively. It is reported for the first time and in good agreement with field test data. From experimental and numerical results, at Stage I the air-leakage increases with the absolute value of negative pressure because there is no blockage in fractures around borehole. At Stage II, the further increased absolute value of negative pressure contributes to particles motion in fractures. It gradually leads to the formation of blockage structure composed of aggregated particles in fractures, and the decrease of fracture conductivity and air velocity. With the absolute value of negative pressure rising continuously, the contact forces between the aggregated particles increase. Therefore, the balance of the blockage structure tends to be broken, which helps to understand the air-leakage increase with the absolute value of negative pressure at Stage III. Between Stage II and Stage III, there is a valley point corresponding to the minimum air-leakage, which is important to the improvement of gas extraction performance. The contact forces on the aggregated soft particles are larger than those on the aggregated hard particles under the same negative pressure. Therefore, the blockage structure consisting of soft particles is much easier to be broken than that formed by hard particles. This explains why the absolute value of negative pressure corresponding to the valley point for hard coal model is larger than that for the soft coal model.",5,5,12
Numerical Simulation,Machine-learning Algorithms,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Numerical Simulation,Machine-learning Algorithms,"Guo, Qi; Zhuang, Tianlin; Li, Zhen; He, Shumei",Prediction of reservoir saturation field in high water cut stage by bore-ground electromagnetic method based on machine learning,Bore-ground electromagnetic method; Learning curve; Cross validation; Saturation field prediction; Machine learning algorithm; Numerical simulation,OPTIMIZATION; ALGORITHM,"The prediction of oil saturation by bore-ground electromagnetic method provides a new expression for reservoir fluid. However, due to the complexity of the internal environment of reservoir and the influence of construction cost, the signal excitation point often cannot cover the whole vertical reservoir range. In this paper, based on the results of single-layer saturation field distribution collected and processed by bore-ground electromagnetic method, six machine learning algorithms, decision-tree, random-forest, k-nearest neighbor, AdaBoost-decision tree, AdaBoost-random forest and AdaBoost-k-nearest neighbor, are established by using machine learning algorithm to introduce inter layer reservoir flow correlation parameters. The fitting of prediction model is detected by learning curve in machine learning algorithm, and the hyper-parameters of the model are optimized by grid search, finally a machine learning algorithm suitable for predicting the saturation distribution by bore-ground electromagnetic method is evaluated and the remaining oil saturation of other layers in the vertical direction is predicted. The results show that the new method can effectively overcome the defects of the bore-ground electromagnetic method, the vertical saturation field of each layer can be reasonably predicted, and the prediction accuracy is more than 90% when it is applied to the prediction of saturation field in block 2 of Gangdong oilfield. The oil saturation distribution results are more similar to the actual reservoir.",4,4,0
Hydraulic Fracture,Fracture Network,"Wu, Yonghui; Cheng, Linsong; Ma, Liqiang; Huang, Shijun; Fang, Sidong; Killough, John; Jia, Pin; Wang, Suran",A transient two-phase flow model for production prediction of tight gas wells with fracturing fluid-induced formation damage,Fracturing fluid-induced formation damage; Two-phase flow; Tight gas; Production prediction; Multi-fractured horizontal well,,"A major concern with hydraulic fracturing in tight formation is the fracturing fluid-induced formation damage (FFIFD) for the high capillary pressure and the presence of water-sensitive clays. Analytical and semi-analytical models are good choices for formation damage evaluation comparing to computationally expensive numerical simulations, particularly in early times when there is limited information about the formation properties. However, the effects of FFIFD and two-phase flow are not addressed in many analytical models. This paper presents a semi-analytical model for this problem with the consideration of both FFIFD and two-phase flow. First, the physical model and mathematical fundamentals of the model are presented. The triple-porosity model is modified to capture the formation damage caused by fracturing fluid. A low permeability fracturing fluid invasion layer (FFIL) is used to characterize leakoff caused clay swelling and polymer adsorption in the matrix pores, and two-phase flow is assumed in the fractures to capture the choking effects. The analytical solution is obtained in the Laplace domain, and a successive iteration is used to update the dynamic parameters by coupling the flowing material balance equations. Then, the commercial numerical simulator Eclipse is used to validate the precision of the semi-analytical model, and several synthetical cases are presented to study the effects of two-phase flow, and the permeability and width of FFIL on gas production rate. Finally, a field case is provided to test the application of the proposed model. The main contribution of this paper is the provision of a simple yet versatile semi-analytical model for production prediction and analysis with the consideration of fracture networks, FFIFD, and two-phase flow. It serves as a good tool for making production prediction and production data analysis for hydraulically fractured tight gas wells.",37,37,15
Hydraulic Fracture,Fracture Network,"Wu, Yonghui; Cheng, Linsong; Killough, John; Huang, Shijun; Fang, Sidong; Jia, Pin; Cao, Renyi; Xue, Yongchao","Integrated characterization of the fracture network in fractured shale gas Reservoirs-Stochastic fracture modeling, simulation and assisted history matching",Fracture characterization; Integrated workflow; Complex fracture networks; Discrete fracture models; Green element method; History matching,HORIZONTAL WELLS; SEMIANALYTICAL APPROACH; FINITE-DIFFERENCE; MULTIPHASE FLOW; BLACK-OIL; BEHAVIOR; ELEMENT; PERFORMANCE; TRANSPORT; FLUID,"The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. It is of significance to make the most of multiple data in fracture characterization, including the measurements of hydraulic fracturing treatment, core, microseismic, production data, etc. Besides, handling the complex fracture networks (CFNs) explicitly is demanded in large-scale field case studies. This paper presents an efficient method to characterize the complex fracture networks (CFNs) and reduce the uncertainties by integrating stochastic CFNs modeling, reservoir simulation, and assisted history matching. In CFNs modeling, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data, and a stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities. To efficiently simulate the discrete fractures in field cases, the edge-based Green Element Method (eGEM) is modified by applying a steady-state fundamental solution and the technique of local grid refinement (LGR). Assisted-history-matching based on EnKF is implemented to calibrate the CFNs models and further quantify the uncertainties. The proposed method is applied to a field case from a multi-fractured horizontal shale gas well. The results show that the computation of the modified eGEM is much cheaper than the original eGEM when the steady-state fundamental solution and the technique of LGR are applied. Besides, acceptable precision can be obtained with relative coarse grids, for example, 50 m primary grids and 25 m refined grids near the fractures can be used in the test case. These advantages make the modified eGEM quite efficient in assisted history matching of large-scale field applications. The history matching results and EUR distributions show that the uncertainties are significantly reduced after 5 steps assimilation, and good results can be obtained after 10 steps assimilation. The distribution ranges of the matrix permeability and porosity are significantly narrowed down after history matching, while the matrix compressibility is hard to be determined because the rock compressibility is so small comparing to gas compressibility that gas production is not sensitive to it. The results also show that only part of the fractures are well-propped because only the fractures in a certain range of the wellbore are with good properties, that is high initial fracture conductivities and low conductivity moduli.",32,32,19
Hydraulic Fracture,Fracture Network,"Chen, Shida; Tang, Dazhen; Tao, Shu; Liu, Pengcheng; Mathews, Jonathan P.","Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China",In situ stress; Permeability; Gas distribution; Productivity; Hydraulic fracture; Depth,DEPENDENT PERMEABILITY; LABORATORY MEASUREMENT; SEDIMENTARY CONTROL; HORIZONTAL STRESS; CBM DEVELOPMENT; BEARING SYSTEM; PORE PRESSURE; ORDOS BASIN; RESERVOIR; PROVINCE,"With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m3/t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500-800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.471.71 MPa/100 m). Overall, the stress release zone at depths of 500-800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production.",22,22,26
Hydraulic Fracture,Fracture Network,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Hydraulic Fracture,Fracture Network,"Jiang, Liwu; Liu, Jinju; Liu, Tongjing; Yang, Daoyong",Semi-analytical modeling of transient pressure behaviour for fractured horizontal wells in a tight formation with fractal-like discrete fracture network,,STIMULATED RESERVOIR VOLUME; TRANSFORM FINITE-DIFFERENCE; FLOW BEHAVIOR; SECONDARY FRACTURES; MULTIPLE; PERFORMANCE; INTEGRATION; CURVES; SYSTEM,"In this work, theoretical models have been formulated, validated, and applied to evaluate transient pressure behaviour of a horizontal well with fractal-like multistage fractures in a tight formation. A coupled matrix-fracture flow model is proposed based on the superposition principle. More specifically, a slab source function was developed to describe the transient fluid flow behaviour from matrix to fracture, while a numerical solution was derived to describe the fluid flow behaviour in the complex fracture network. Then, a semi-analytical method is applied to solve such coupled models by discretizing hydraulic fracture into small segments. Furthermore, type curves are generated to examine the effect of the fractal fracture network. Sensitivity analysis of some major parameters (e.g., iteration number, deviation angle, and branch number) has been conducted to investigate their effects on the transient pressure responses. It is found that the fractal fracture network will greatly affect the transient pressure behaviour. The deviation of the pressure derivative curve from the case with the traditional bi-wing fracture can be used to quantify the complexity and the conductivity of the fracture network, while the existence of the complex fracture network will greatly improve the well performance in the intermediate time period.",7,7,3
Hydraulic Fracture,Fracture Network,"Zhu, Zhaopeng; Song, Xianzhi; Li, Gensheng; Xu, Zhengming; Zhu, Shuo; Yao, Xuezhe; Jing, Silin",Prediction of the settling velocity of the rod-shaped proppant in vertical fracture using artificial neural network,Rod-shaped proppant; Settling orientation; Settling velocity; Vertical fracture; Neural network,,"As a new technology proppant, rod-shaped proppant is receiving more and more attention because it can greatly improve the performance of hydraulic fracturing. With special shape, the rod-shaped proppant is subject to greater flow resistance, resulting in complex migration in fractures. Accurate prediction of the settling velocity of rod proppant in fracture is important for predicting the transport distance and bed height of rod proppant in hydraulic fractures to improve the fracture performance. In this study, high-speed photography and transparent parallel plates were used to simulate and record the settling process of proppant in vertical fractures. A total of 588 effective tests were conducted to reveal the influence of proppant shape, fracturing fluid properties, and the wall effect of fracture on the settling characteristics involving the range of proppant aspect ratio and Reynolds number are 1.5-5.0 and 0.001-172.54, respectively. It was found that the rod proppant settled vertically at the low Reynolds number and horizontally at the high Reynolds number. First, an artificial neural network model of settling orientation with the prediction accuracy of 100% is established as the basis for predicting settlement velocity. The topological structure of the neural network is further extended to establish the prediction model of settling velocity with mean relative error of 1.21%. The relative importance of each input factor to the settling velocity was analyzed by the connection weights algorithm, and the weight and bias of the neural network are provided for the application and generalization of the model. Finally, the neural network model is evaluated objectively by comparing with the mathematical model. This study is a successful exploration of artificial intelligence in particle migration and will provide guidance for improving the performance of rod proppant in hydraulic fracturing.",6,6,5
Hydraulic Fracture,Fracture Network,"Gou, Bo; Zhan, Li; Guo, Jianchun; Zhang, Ran; Zhou, Changlin; Wu, Lin; Ye, Jiexiao; Zeng, Ji",Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan,Fractured carbonate rock; True tri-axial experiment; Reactive fluid; Nonreactive fluid; Fracture propagation; CT scan,LIMESTONE FORMATION; CRITERION; SHALE; ACID,"Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm x 200 mm x 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.",5,5,13
Hydraulic Fracture,Fracture Network,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Hydraulic Fracture,Fracture Network,"Xiao, Hui; Li, Zhenming; He, Siyuan; Lu, Xinqian; Liu, Pingli; Li, Jun",Experimental study on proppant diversion transportation and multi-size proppant distribution in complex fracture networks,Experimental study; Multistage fracture networks; Proppant diversion transportation; Proppant separation; Proppant distribution,,"Proppant transportation in fracture networks is significant for hydraulic fracture design and evaluation. Previous studies on proppant placement in complex fracture networks had shortcomings in terms of proppant diversion transportation, proppant distribution in a secondary fracture, and proppant distribution with different particle sizes. This experimental study was conducted on proppant diversion transportation and distribution in complex fracture networks based on the visualization proppant placement model. The findings revealed that the critical proppant diversion time rapidly decreased with the increase in the pumping rate. When the pumping rate was lower than 2.5 m(3)/h, no proppant diversion transportation was found in the second- and third-branch fractures. The smaller-sized proppant particles (100 mesh) were distributed mainly in the fracture located far away from the wellbore or the major fracture. More smaller-sized proppant particles were distributed in the deeper fracture when the difference between the proppant particle sizes was large. Increasing the pumping times increased the transport of proppant particles to deeper fractures. However, the increase in the amplitude was larger in 100-mesh proppant particles than in 30/50-mesh proppant particles. Smaller-sized proppant particles were more easily transported to branch fractures, thus increasing the proppant placement efficiency. The experimental findings can be used to optimize the parameters of the stimulated reservoir volume fracturing to improve the effectiveness of fracture networks.",4,4,13
Hydraulic Fracture,Fracture Network,"Lu, Yuejian; Liu, Dameng; Cai, Yidong; Li, Qian; Zhou, Yingfang",Spontaneous imbibition in coal with in-situ dynamic micro-CT imaging,Coalbed methane; Spontaneous imbibition; X-ray; Relative permeability,PORE-FRACTURE NETWORKS; MERCURY INTRUSION POROSIMETRY; RELATIVE PERMEABILITY; WATER IMBIBITION; POROUS-MEDIA; LOW-RANK; GAS; SHALE; SORPTION; METHANE,"The gas/fluid flowing behavior and fluid distribution under capillary forces in porous media are essential for evaluating the pore-fracture characteristics of coal. Capillary force is crucial for flow-back efficiency after hydraulic fracturing during enhanced coalbed methane (CBM) production. In this work, in situ dynamic X-ray micro-computed tomography (X-ray mu-CT), field emission scanning electron microscopy (FE-SEM) combined with mercury intrusion porosimetry (MIP) were used on two coal samples of different wettability to explore the behavior of spontaneous imbibition. The results show that both pore-fracture and mineral content could affect the imbibition behavior of coal, which the former has played a major role. The spontaneous imbibition process can be divided into 4 stages to reveal fluid flow characteristics by the fluid distribution at different time steps. The gas relative permeability of coal attenuates exponentially with imbibition time result for capillary force based on fractal theory (the gas relative permeability reduces its value from 0.72 mD to 0.01 mD for WD, 0.5 mD to 0.08 mD for WZX). A low flow-back rate of fracturing fluid would lead to severe permeability damage. The longer the return drainage time, the more severe the permeability damage.",3,3,37
Hydraulic Fracture,Fracture Network,"Zhang, C. P.; Cheng, P.; Ma, Z. Y.; Ranjith, P. G.; Zhou, J. P.",Comparison of fracturing unconventional gas reservoirs using CO2 and water: An experimental study,CO2-based fracturing; Hydraulic fracturing; Breakdown pressure; Fracture aperture; Fracture morphology,CARBON-DIOXIDE; HYDRAULIC CONDUCTIVITY; TIGHT SANDSTONE; FLOW BEHAVIOR; SHALE GAS; PROPAGATION; INITIATION; PERMEABILITY; WELLBORE,"CO2-based fracturing (CBF) has been regarded as the most promising alternative to water-based fracturing (WBF) in water-sensitive unconventional gas reservoirs, and the fracture initiation and propagation at different in-site stresses created by CBF is crucial to the flow conductivity of fracture network. The main aim of this study is to compare the fracturing efficiency of WBF and CBF by conducting a series of fracturing tests on siltstone samples. According to the experimental results, the breakdown pressure linearly increases with the confining pressure, and the slope is 1.3928 and 1.6422 for CBF and WBF, respectively, and the much lower breakdown pressure for CBF is because of the fast penetration of CO2 through the rock matrix, which significantly reduces the effective stress around the borehole. Importantly, the observed fracture aperture for CBF is much greater than that for WBF, the maximum fracture aperture for CBF is around 2 to 5 times greater than that for WBF under the same test conditions. The difference in fracture aperture depends on the presence of discrete blocks and particles, and CBF can create greater and more loose particles in both mechanically-created method and hydraulically-created method to keep the created fractures open after the release of the injection pressure. The greater fracture aperture of CBF is favourable for the flow capacity of the fractures and therefore reservoir productivity, which is verified by the permeability tests with 190.43 times of permeability than that of WBF. Interestingly, the greater fracture width expansion for CBF perpendicular to the major principal pressure promotes the generation of horizontal fractures, even when the injection pressure is smaller than the major principal pressure, and the probability of horizontal fracture for CBF is 4-5 times of that for WBF, which reflect its great potential to create complex fracture network in unconventional gas reservoirs. The test results reveal that CBF is superior to the WBF since it is capable to create much more complex and efficient fracture networks. The findings are beneficial to understand the difference of fracturing behaviours at different in-site stresses between WBF and CBF, and provide experimental guidance for the exploitation of water-sensitive unconventional gas reservoirs by CBF.",3,3,4
Hydraulic Fracture,Fracture Network,"Chaikine, Ilia A.; Gates, Ian D.",A machine learning model for predicting multi-stage horizontal well production,Horizontal multistage fracture; Machine learning; Production; Unconventional reservoirs; Hydraulic fracturing; Predictive models,,"In this study, a hybrid convolutional-recurrent neural network (c-RNN) is evaluated for making predictions of the five-year cumulative production profiles in multistage hydraulically fractured wells. The model was trained by using a combinations of completion parameters, rock mechanical properties, and well spacing and completion order for each stage of 74 wells in the Montney Formation in Alberta. The prediction accuracy of the various combinations was measured by using the mean average percent error and mean absolute error generated through the leave-one-out method. The best combination of inputs was found to be the rock mechanical properties surrounding each perforation cluster, the proppant amount used for every stage, and the spacing and completion order of neighboring wells. The novelty of this study is that the input variables used are at the stage level rather than the average of the entire well. The accuracy of the model was found to increase exponentially as the production of multiple wells was aggregated. The approach yields insights for planning new well drills in fields with existing development since it provides the ability to run multiple field development scenarios without having to spend capital.",3,3,3
Hydraulic Fracture,Proppant,"Chen, Shida; Tang, Dazhen; Tao, Shu; Liu, Pengcheng; Mathews, Jonathan P.","Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China",In situ stress; Permeability; Gas distribution; Productivity; Hydraulic fracture; Depth,DEPENDENT PERMEABILITY; LABORATORY MEASUREMENT; SEDIMENTARY CONTROL; HORIZONTAL STRESS; CBM DEVELOPMENT; BEARING SYSTEM; PORE PRESSURE; ORDOS BASIN; RESERVOIR; PROVINCE,"With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m3/t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500-800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.471.71 MPa/100 m). Overall, the stress release zone at depths of 500-800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production.",22,22,26
Hydraulic Fracture,Proppant,"Li, Jun; Liu, Pingli; Kuang, Shibo; Yu, Aibing",Visual lab tests: Proppant transportation in a 3D printed vertical hydraulic fracture with two-sided rough surfaces,Shale gas; Hydraulic fracture; Proppant placement; 3D printing technology; Two-sided rough fracture model; Particle wormhole,SINGLE FRACTURE; SEDIMENT,"An effective proppant placement in a hydraulic fracture system is the key to increasing the gas production of unconventional reservoirs. The fracture surfaces are generally rough, however, assumed to be smooth or rough only on one side for visualization in existing experimental fracture models, which may generate unrealistic results. This paper presents a two-sided rough fracture model for studying the proppant placement. This was realized by combining the digitalization of rough surface and 3D printing technology. Using this new fracture model, some distinct piling-up and transportation mechanisms of proppants in a vertical fracture with two-sided rough surfaces were demonstrated against the counterpart of the fracture that considers only one-sided rough surface or smooth surfaces. Particularly, a finger-like piling of proppants resulting from the collective effect of proppant gliding, aggregation and saltation was present in the two-sided rough fracture. Meanwhile, high-speed channel, particle wormhole, cavity and isolated pillars also occurred locally. To quantify these mesostructures, the concept of channel ratio was introduced and correlated with fluid viscosity. All the results suggest that the new fracture model is useful not only to better understand the proppant placement but also to optimally design and control hydraulic fracture systems.",9,9,7
Hydraulic Fracture,Proppant,"Zhu, Zhaopeng; Song, Xianzhi; Li, Gensheng; Xu, Zhengming; Zhu, Shuo; Yao, Xuezhe; Jing, Silin",Prediction of the settling velocity of the rod-shaped proppant in vertical fracture using artificial neural network,Rod-shaped proppant; Settling orientation; Settling velocity; Vertical fracture; Neural network,,"As a new technology proppant, rod-shaped proppant is receiving more and more attention because it can greatly improve the performance of hydraulic fracturing. With special shape, the rod-shaped proppant is subject to greater flow resistance, resulting in complex migration in fractures. Accurate prediction of the settling velocity of rod proppant in fracture is important for predicting the transport distance and bed height of rod proppant in hydraulic fractures to improve the fracture performance. In this study, high-speed photography and transparent parallel plates were used to simulate and record the settling process of proppant in vertical fractures. A total of 588 effective tests were conducted to reveal the influence of proppant shape, fracturing fluid properties, and the wall effect of fracture on the settling characteristics involving the range of proppant aspect ratio and Reynolds number are 1.5-5.0 and 0.001-172.54, respectively. It was found that the rod proppant settled vertically at the low Reynolds number and horizontally at the high Reynolds number. First, an artificial neural network model of settling orientation with the prediction accuracy of 100% is established as the basis for predicting settlement velocity. The topological structure of the neural network is further extended to establish the prediction model of settling velocity with mean relative error of 1.21%. The relative importance of each input factor to the settling velocity was analyzed by the connection weights algorithm, and the weight and bias of the neural network are provided for the application and generalization of the model. Finally, the neural network model is evaluated objectively by comparing with the mathematical model. This study is a successful exploration of artificial intelligence in particle migration and will provide guidance for improving the performance of rod proppant in hydraulic fracturing.",6,6,5
Hydraulic Fracture,Proppant,"Xiao, Hui; Li, Zhenming; He, Siyuan; Lu, Xinqian; Liu, Pingli; Li, Jun",Experimental study on proppant diversion transportation and multi-size proppant distribution in complex fracture networks,Experimental study; Multistage fracture networks; Proppant diversion transportation; Proppant separation; Proppant distribution,,"Proppant transportation in fracture networks is significant for hydraulic fracture design and evaluation. Previous studies on proppant placement in complex fracture networks had shortcomings in terms of proppant diversion transportation, proppant distribution in a secondary fracture, and proppant distribution with different particle sizes. This experimental study was conducted on proppant diversion transportation and distribution in complex fracture networks based on the visualization proppant placement model. The findings revealed that the critical proppant diversion time rapidly decreased with the increase in the pumping rate. When the pumping rate was lower than 2.5 m(3)/h, no proppant diversion transportation was found in the second- and third-branch fractures. The smaller-sized proppant particles (100 mesh) were distributed mainly in the fracture located far away from the wellbore or the major fracture. More smaller-sized proppant particles were distributed in the deeper fracture when the difference between the proppant particle sizes was large. Increasing the pumping times increased the transport of proppant particles to deeper fractures. However, the increase in the amplitude was larger in 100-mesh proppant particles than in 30/50-mesh proppant particles. Smaller-sized proppant particles were more easily transported to branch fractures, thus increasing the proppant placement efficiency. The experimental findings can be used to optimize the parameters of the stimulated reservoir volume fracturing to improve the effectiveness of fracture networks.",4,4,13
Hydraulic Fracture,Proppant,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Hydraulic Fracture,Proppant,"Zhu, Haiwen; Zhu, Jianjun; Lin, Zimo; Zhao, Qingqi; Rutter, Risa; Zhang, Hong-Quan",Performance degradation and wearing of Electrical Submersible Pump (ESP) with gas-liquid-solid flow: Experiments and mechanistic modeling,,,"Electrical Submersible Pump (ESP), one of the most profitable artificial lift methods in the petroleum industry, is sensitive to flow conditions, especially under solid-particle flow. Compared to the sand produced from the unconsolidated sandstone, the proppant backflow in hydraulic fractured wells is more erosive to ESPs due to its higher hardness and larger diameter. As a result, the pump geometry is jeopardized, and the boosting pressure is affected. Therefore, the sand-water-air tests were conducted in this study to investigate the performance degradation and wearing damage in ESPs. For the first time, a semi-mechanistic model based on Achard law was proposed to predict the abrasion damage in the second flow passage of an ESP. A new mechanistic model was established to predict pump boosting pressure and describe the pump leakage effect under gas-liquid flow conditions. Considering the rotational effect, the leakage flow rate was calculated in three stage seal clearances, skirt ring, balance ring, and inter-stage. The change of the clearance calculated by the proposed abrasion equation agrees well with the experimental measurement. With the original and eroded pump geometries, the predicted ESP two-phase boosting pressure matches the measured pump curves, while the flow pattern transition from bubbly flow to intermittent flow is also captured.",3,3,4
Hydraulic Fracture,Proppant,"Chaikine, Ilia A.; Gates, Ian D.",A machine learning model for predicting multi-stage horizontal well production,Horizontal multistage fracture; Machine learning; Production; Unconventional reservoirs; Hydraulic fracturing; Predictive models,,"In this study, a hybrid convolutional-recurrent neural network (c-RNN) is evaluated for making predictions of the five-year cumulative production profiles in multistage hydraulically fractured wells. The model was trained by using a combinations of completion parameters, rock mechanical properties, and well spacing and completion order for each stage of 74 wells in the Montney Formation in Alberta. The prediction accuracy of the various combinations was measured by using the mean average percent error and mean absolute error generated through the leave-one-out method. The best combination of inputs was found to be the rock mechanical properties surrounding each perforation cluster, the proppant amount used for every stage, and the spacing and completion order of neighboring wells. The novelty of this study is that the input variables used are at the stage level rather than the average of the entire well. The accuracy of the model was found to increase exponentially as the production of multiple wells was aggregated. The approach yields insights for planning new well drills in fields with existing development since it provides the ability to run multiple field development scenarios without having to spend capital.",3,3,3
Hydraulic Fracture,Proppant,"Krishnan, Mohan Raj; Aldawsari, Yazeed; Michael, Feven Mattews; Li, Wengang; Alsharaeh, Edreese H.",Mechanically reinforced polystyrene-polymethyl methacrylate copolymer-graphene and Epoxy-Graphene composites dual-coated sand proppants for hydraulic fracture operations,Proppants; Sand; Polystyrene-polymethyl methacrylate; Epoxy; Mechanical and thermal stability; Stress resistance,,"Herein, we report mechanically reinforced dual-coated sand proppants for hydraulic fracturing operations. The dual-coated sand proppants were prepared by sequential surface modifications. The sand particles were firstly coated with polystyrene-polymethyl methacrylate copolymer (PS-PMMA) composite with commercial graphene (CG) (first composite layer) and subsequently coated with epoxy-CG composite (second composite layer). The copolymer-CG coating onto sand particles was carried out by mixing 1:1 styrene (S) and methyl methacrylate (MMA) monomers with the initiator AIBN along with CG followed by adding the mixture to sand particles with vigorous stirring and subsequent polymerization at 70 degrees C. The PS-PMMA-CG coated sand particles were then mixed with epoxy resin and a cure in a ratio of 4:1 along with CG and cured at 150 degrees C for 5 min. Chemical, mechanical, thermal, and morphological characterizations for the composite layers and dual-coated sand proppants were investigated in detail by Fourier transform-infrared spectroscopy (FT-IR), nano-indentation, thermogravimetric (TGA), optical, and scanning electron microscopic (SEM) techniques. The FT-IR results revealed that the successful formation of PS-PMMA-CG copolymer composite and cross-linked epoxy-CG composites. The XRD results indicated that the successful surface coverage of the dual composites coating onto the sand. The optical and SEM results revealed that the roundness and sphericity of the reinforced proppant particles were greater than 0.6. Interestingly, elasticity (E), and hardness (H) of the coating shells have reached a maximum of 3.97 GPa and 0.144 GPa, respectively. The thermal stability of the (PS-PMMA-CG)-(epoxy-CG) dual composite shell has reached as high as 363 degrees C. Furthermore, the stress resistance of the optimized dual-coated sand proppant (Sand-(PS-PMMA-CG)-(epoxy-CG)) reached as high as 10000 psi with a fine production of <10 wt%. The mechanically reinforced dual-coated sand including the most desirable characteristics of roundness and sphericity to be greater than 0.6, high-stress resistance with excellent thermal and mechanical stabilities confirmed its great potential to be applied as successful proppants in oil and gas upstream applications.",3,3,3
Hydraulic Fracture,Proppant,"Chuprakov, Dimitry; Iuldasheva, Aliia; Alekseev, Alexey",Criterion of proppant pack mobilization by filtrating fluids: Theory and experiments,Proppant flowback; Dense granular suspension; Sand mobilization; Hydraulic fracture; Bridging,FRACTURES; FLOW,"The goal of hydraulic fracturing is placing a granular material, proppant, in the created fracture to sustain its conductivity and attain economical production rates. After fracture closure on the placed proppant and subsequent pressure drawdown in a well, the consolidated proppant can be dragged by the producing fluids and undesirably be produced back to the well. Rough estimations or accurate simulations of this phenomenon require a valid quantitative criterion of proppant mobilization in a fracture. In this work, we analytically derive such criterion from the fundamental principles. The criterion is expressed in terms of the minimum fluid filtration velocity that destabilizes the proppant. It is sensitive to such important factors as cohesion, thickness and permeability of a proppant pack, mean grain size, roughness and softness of fracture walls, and filtrating fluid viscosity. The developed theory considers the existing unloaded edge of a proppant pack, its granular structure, and related finite cohesion of particles holding each other in a pack. These key properties are shown to play a dominant role for mobilization of a proppant in hydraulic fractures. On the other hand, we conduct an extensive series of laboratory experiments mimicking subterranean fracture closure on proppant, fluid filtration through it, and registering proppant flowback. In the experiments, we try a wide range of commercial proppants, less- and more-viscous fluids, and stiff and soft fracture walls. We associated proppant flowback onset with the change of proppant pack height. We also show how proppant bridging depends on the particle embedment into soft walls and illustrate various geometries of proppant washing out, giving clues to various scenarios of proppant flowback evolution. Finally, we observe a good correspondence of our theory and experimental observations. Theoretical hypotheses of unstressed edge and finite cohesion of a granular solids serve as the only means to explain the observed range of filtration velocity magnitudes for proppant mobilization and their independence from the value of confining stress. The reciprocity between the cohesion and critical velocity revealed by the theory is confirmed by experiments. It allows measuring only one of them to estimate another.",3,3,2
Hydraulic Fracture,Oil,"Abdelghany, Wael K.; Radwan, Ahmed E.; Elkhawaga, Mohamed A.; Wood, David A.; Sen, Souvik; Kassem, Ahmed A.",Geomechanical modeling using the depth-of-damage approach to achieve successful underbalanced drilling in the Gulf of Suez rift basin,Sub-surface stress regime; Depth of damage; Wellbore breakout; Over-pressured formations; Underbalanced drilling; High-pressure formations; Wellbore stability,HYDRAULIC FRACTURE INITIATION; BOREHOLE STABILITY ANALYSIS; CONSOLIDATED ROCK STRATA; PRESENT-DAY STATE; WELLBORE-STABILITY; BADRI FIELD; BELAYIM FORMATION; EFFECTIVE STRESS; TECTONIC STRESS; PORE PRESSURE,"Typical oil and gas reservoirs producing in the Gulf of Suez are now extensively depleted in terms of recovery of conventional resources and display declining production levels and heterogeneous pore pressure regimes. To continue production on a commercially viable basis and enhance the recovery of remaining oil and gas from the mature reservoirs currently in production, drilling decision-makers can no longer rely on traditional balanced or overbalanced drilling methods. Hence, underbalanced drilling is an essential requirement for such reservoirs. However, inducing underbalanced conditions increases the risk of the borehole instability. In the studied area, three previous wellbore stability studies were performed associated with the Hilal-X platform wells using the breakout-width-failure concept. Nevertheless, several wellbore instability issues were recorded there due to that method determining a mud-weight window that was too conservative. New wellbore stability analysis has been performed using a depth-of-damage approach. This analysis has helped to deliver excellent results during underbalanced drilling, after many attempts in previously drilled wells in overbalanced conditions that resulted in borehole instability and/or formation damage. This study documents how successful underbalanced drilling has been achieved in this basin for the first time by mud weights being guided by depth-of-damage analysis, highlight the requirements of that method using a case study for a specific well. In-situ stresses and an 1D-geomechanical earth model were generated using well log data from offset wells. The modified Lade method was used as a failure criterion, while the depth-of-damage approach was used for wellbore stability analysis in HilalX4 well. The study reveals that: 1) the Hilal field reservoirs have variable pore pressure regimes, 2) the breakoutwidth-failure concept provides misleading results in the studied reservoir formation, 3) the depth-of-damage approach reflects reservoir conditions more effectively and allows for successful underbalanced drilling without any instability events, 4) a new casing design for the Hilal Field wells has led to enhanced production performance, and 5) underbalanced drilling, when downhole pressures are carefully managed, is a safe and reliable technique for the mature fields of the Gulf of Suez rift basin.",25,25,10
Hydraulic Fracture,Oil,"Liu, Dengke; Ren, Dazhong; Du, Kun; Qi, Yiru; Ye, Feng",Impacts of mineral composition and pore structure on spontaneous imbibition in tight sandstone,Spontaneous imbibition; Mineral composition; Pore structure; Tight sandstone,DIRECT NUMERICAL-SIMULATION; TRIASSIC YANCHANG FORMATION; ORDOS BASIN; NITROGEN ADSORPTION; OIL; RESERVOIR; SALINITY; TRANSPORT,"Spontaneous imbibition is a fundamental mechanism to figure out the rock-fluid interplay during waterflooding and hydraulic fracturing. Mineral composition and pore structure play significant roles in imbibition efficiency, but how these parameters influence the oil production efficiency still is a myth. This research conducted the spontaneous imbibition experiments combined with low-temperature adsorption and nuclear magnetic resonance to (1) study how minerals and pore structures impact fluid movement features for tight sandstones; (2) systematically investigate the contribution to oil recovery of different pores' types and the impact of pore connectivity on spontaneous imbibition. The results show that the brine is inclined to attach hydrophilic minerals because of the wettability, increasing the imbibition efficiency. Additionally, with the tiny pores' development, the oil is more easily replaced by the brine due to strong capillary pressure. Last, as the mainstream imbibition area grows, the oil is preferentially displaced by the brine. The research provides insights into how mineral compositions and pore structures can influence spontaneous imbibition efficiency and improves the understanding of the complicated interaction between fluid and minerals in tight sandstones.",17,15,9
Hydraulic Fracture,Oil,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Hydraulic Fracture,Oil,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Hydraulic Fracture,Oil,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Hydraulic Fracture,Oil,"Chen, Xiang; Zhao, Liqiang; Liu, Pingli; Du, Juan; Bai, Zongxian; Liu, Jinming; Zhang, Nanlin; Luo, Zhifeng; Xu, Kun; Li, Nianyin",Laboratory study and field verification of a thermo-responsive water shutoff agent,Thermo-responsive water shutoff agent; Working mechanism; Laboratory experiment; Field application verification; Changqing oilfield,,"For the low-pressure and low-permeability oil reservoirs, water injection development and hydraulic fracturing stimulation are essential. The ideal water flooding mode is piston-like displacement. However, due to the heterogeneity of reservoirs, most of the injected water flow to oil wells along the dominant channel (i.e., high permeability area, natural fractures, or artificial fractures), which causes the decrease of oil displacement efficiency, the premature water breakthrough of oil wells, and high water content. Hence, over a span of decades, a compelling body of work has focused on the development of water shutoff agents. According to its working mechanism, water shutoff agents were divided into selective and non-selective water shutoff agents. However, the water shutoff agents mentioned above have been tested in more than 350 wells of Changqing oilfield, and the success rate was unsatisfactory. Therefore, this study aimed to develop a thermo-responsive water shutoff agent (TRWSA) with high plugging strength and compact structure. Through a series of laboratory experiments, the key performances of TRWSA for field application were tested and evaluated. First, the initial viscosity of TRWSA was 34.5 mPa s, which could easily pass through any completion tool (e.g., screen pipe and gravel pack) and enter any size fracture. Second, the TRWSA was non-water soluble and its phase-transition characteristics were not affected by guar gum fracturing fluid. Third, the phase transformation position of TRWSA could be determined by adjusting the SA-DST dosage and the wellbore-reservoir temperature. Fourth, its plugging strength was greater than 19.1 MPa and the volume retention rate was up to 99.13%. In addition, the field application results showed that oil production increased from 0.08 m(3)/d to 5.37 m(3)/d, and water content decreased from 98.6% to 9.8%. The TRWSA was satisfactory and had a great application prospect.",4,4,22
Hydraulic Fracture,Oil,"Liu, Zhonghua; Bai, Baojun; Wang, Yanling; Qu, Hai; Xiao, Qianhua; Zeng, Shunpeng",Spontaneous imbibition characteristics of slickwater and its components in Longmaxi shale,Spontaneous imbibition; Slickwater; Gas shale; Imbibition capacity; Imbibition rate; Secondary microfracture,WATER IMBIBITION; GAS; DAMAGE; PERMEABILITY; OIL,"During and after multi-stage hydraulic fracturing, the spontaneous imbibition of water-base fracturing fluid in shale formation is considered as the main mechanism responsible for the retention of large amounts of fracturing fluid. Slickwater is widely applied in Fuling shale gas field, the largest shale gas field in China. To characterize the spontaneous imbibition of slickwater and its four major components, experiments were carried out by using modified imbibition cells. Results show that all of the imbibition curves can be divided into three stages: linear imbibition stage, transition stage and stable imbibition stage. Their imbibition capacities are in the order of cleanup additive, clay stabilizer, slickwater, defoamer and friction reducer from highest to lowest. We have found that the imbibed volume is larger than the initial pore volume. Nuclear Magnetic Resonance (NMR) tests, core images and porosity comparison before and after imbibition all indicate the secondary microfractures were created during the imbibition process. The calculated volume of secondary microfractures which is the difference between the pore volume before and after the imbibition is very close to the imbibed volume, indicating the imbibition mainly through the microfractures. We also found that the imbibition rate of slickwater and its components in the order from highest to lowest is cleanup additive (0.087 cc/d), slickwater (0.058 cc/d), clay stabilizer (0.035 cc/d), defoamer (0.022 cc/d) and friction reducer (0.014 cc/d), indicating the synergy effect of slickwater components on the imbibition process and the role to optimize the cleanup additives during slickwater design.",4,4,13
Hydraulic Fracture,Oil,"Arianfar, Ali; Ramezanzadeh, Ahmad; Khalili, Mohammad",Numerical study of nonlinear fluid flow behavior in natural fractures adjacent to porous medium,Fractured reservoirs; Fracture; Roughness; Porous medium; Permeability; Forchheimer equation,,"It is essential to understand the hydraulic aperture behavior of rock fractures where fluid passes through the rock mass. The geometric parameters of fracture, such as wall roughness and fracture aperture, have a significant effect on its hydro-mechanical behavior. This issue has been addressed in many papers, but the fluid passage through the permeable zone adjacent to the fracture has rarely been studied. Therefore, this paper numerically simulated the fluid behavior in the porous fractured medium. For preparing the model geometry, the 3D scanning of fracture walls was used for the samples taken from one of the oil wells in southern Iran. The geometry of fractures was prepared using ICEM CFD software, and the fluid flow in rock fracture and porous matrix was simulated with Ansys FluentTM software. Given that the two fracture surfaces are connected in reality, the geometry of the model was constructed when the fractures are mated and the connection is established at a certain level (the connection between the two surfaces equal to 15, 30, 45, 60, 75, and 90% of the total area). The results of this simulation showed that the Forchheimer macroscopic relation well describes the nonlinear fluid flow in the rock fracture even considering the permeable matrix. However, the higher the permeability value of the matrix adjacent to the fracture, the higher the fracture permeability value. The results indicated an exponential relationship between the increased permeability and the decreased Forchheimer coefficients, which confirms the easier passage of fluid through the fracture enclosed by a zone of higher permeability. Also, the values of linear and nonlinear coefficients of Forchheimer equation were estimated for each of the geometric models, which showed that the changes in Forchheimer coefficients are exponentially related to the change in the connected surface area.",3,3,9
Hydraulic Fracture,Oil,"Cui, Jiangfeng; Si, Guangyao",Equivalent anisotropic permeability of shale rocks: Effect of micro-fractures,Shale; Equivalent permeability; Bedding fracture; Structural fracture; Numerical simulation,MICROFRACTURES; NANOPORES; TRANSPORT; OIL,"The extensive opening-mode micro-fractures, including horizontal bedding fractures and vertical structural fractures, are prevalent in shale rocks. Because of a huge difference with many orders of magnitude in permeability from the nearly impermeable shale matrix and those highly conductive micro-fractures, the microfractures are believed to contribute substantially to the macro-scale anisotropic flow properties of shale. Nevertheless, up to the present day, there has been no comprehensive research on this topic. Previous works simply employed a fixed pattern of micro-fractures and did their simulations. In this work, the finite difference method is employed to perform steady-state numerical simulation. The impact of micro-fractures on the flow capacity of shale rocks is characterized by the concept of normalized equivalent permeability. The concepts of bedding thickness, filling spacing and filling ratio are utilized to characterize the distribution pattern of horizontal bedding fractures. The length and number of vertical structural fractures are also considered. The validation of several simplistic scenarios against known results guarantees the correctness and accuracy of the numerical code. Comprehensive sensitivity analysis using realistic ranges of parameters based on literature is conducted for the two scenarios: (i) horizontal bedding fractures only, and (ii) horizontal bedding fractures and vertical structural fractures, moreover, both uniform and random distributions are discussed and then compared. Effects of bedding thickness, filling spacing and filling ratio of horizontal bedding fractures, the length and number of vertical structural fractures, the connectivity between horizontal bedding and vertical structural fractures, and the random distribution attribute of fractures on the anisotropic permeability of shale, including horizontal and vertical components, are discussed. This is the very first work that comprehensively investigates the effect of micro-fractures on the anisotropic permeability of shale rocks, which can help improve the understanding of the flow capacity of shale rocks and even the hydraulic properties of similar kinds of fractured material. Also, it is very useful for modeling the fluid flow to enhance oil/gas recovery in shale reservoirs.",3,3,8
Hydraulic Fracture,Oil,"Iyare, U. C.; Blake, O. O.; Ramsook, R.",Brittleness evaluation of Naparima Hill mudstones,Brittleness; Elastic properties; Effective pressure; Water saturation; Unconventional reservoirs; Naparima hill formation (Trinidad),ELASTIC PROPERTIES; SEISMIC ANISOTROPY; SEDIMENTARY-ROCKS; SHALE; WAVES; SATURATION; FREQUENCY; STRENGTH; VELOCITY; INDEXES,"The brittleness of unconventional source rock reservoirs is an essential parameter that controls the effectiveness of hydraulic fracturing operation. Brittleness can vary with effective pressure (equivalent to burial depth) and can be influenced by fluid saturation. Therefore, a detailed evaluation of rock brittleness is necessary prior to field applications. The late Cretaceous Naparima Hill Formation is the primary source for most of the 4 billion barrels of oil and 10 trillion cubic feet of gas produced in the last hundred years from conventional reservoirs in Trinidad, West Indies. This Formation is now being considered an unconventional reservoir in order to prolong and increase current productions. However, despite being a prolific Formation, there are no available geomechanical data, including brittleness. Brittleness index (BI) is often used to measure rock brittleness. In this study, we determined elastic-based BI from P- and S-wave velocity measurements, at effective pressures up to 130 MPa, for dry and water saturated outcrop mudstones from four lithofacies within the Naparima Hill Formation. The experimental results show that the BI for all four lithofacies, is independent of effective pressures in both dry and water saturated conditions. All four lithofacies can be considered brittle under dry conditions. However, when saturated, the BI reduces, which proves significant for softer lithofacies (siliceous calcareous mudstones and siliceous mudstones). In this saturated state, the harder lithofacies (calcareous mudstone interbedded with black chert and carbonate rich mudstone with nodular chert) are considered marginally brittle and the softer ones, are considered ductile. The results highlight that porosity is the main factor that controls the magnitude of reduction in the BI when the mudstones are fully saturated.",3,3,5
Hydraulic Fracture,Oil,"Krishnan, Mohan Raj; Aldawsari, Yazeed; Michael, Feven Mattews; Li, Wengang; Alsharaeh, Edreese H.",Mechanically reinforced polystyrene-polymethyl methacrylate copolymer-graphene and Epoxy-Graphene composites dual-coated sand proppants for hydraulic fracture operations,Proppants; Sand; Polystyrene-polymethyl methacrylate; Epoxy; Mechanical and thermal stability; Stress resistance,,"Herein, we report mechanically reinforced dual-coated sand proppants for hydraulic fracturing operations. The dual-coated sand proppants were prepared by sequential surface modifications. The sand particles were firstly coated with polystyrene-polymethyl methacrylate copolymer (PS-PMMA) composite with commercial graphene (CG) (first composite layer) and subsequently coated with epoxy-CG composite (second composite layer). The copolymer-CG coating onto sand particles was carried out by mixing 1:1 styrene (S) and methyl methacrylate (MMA) monomers with the initiator AIBN along with CG followed by adding the mixture to sand particles with vigorous stirring and subsequent polymerization at 70 degrees C. The PS-PMMA-CG coated sand particles were then mixed with epoxy resin and a cure in a ratio of 4:1 along with CG and cured at 150 degrees C for 5 min. Chemical, mechanical, thermal, and morphological characterizations for the composite layers and dual-coated sand proppants were investigated in detail by Fourier transform-infrared spectroscopy (FT-IR), nano-indentation, thermogravimetric (TGA), optical, and scanning electron microscopic (SEM) techniques. The FT-IR results revealed that the successful formation of PS-PMMA-CG copolymer composite and cross-linked epoxy-CG composites. The XRD results indicated that the successful surface coverage of the dual composites coating onto the sand. The optical and SEM results revealed that the roundness and sphericity of the reinforced proppant particles were greater than 0.6. Interestingly, elasticity (E), and hardness (H) of the coating shells have reached a maximum of 3.97 GPa and 0.144 GPa, respectively. The thermal stability of the (PS-PMMA-CG)-(epoxy-CG) dual composite shell has reached as high as 363 degrees C. Furthermore, the stress resistance of the optimized dual-coated sand proppant (Sand-(PS-PMMA-CG)-(epoxy-CG)) reached as high as 10000 psi with a fine production of <10 wt%. The mechanically reinforced dual-coated sand including the most desirable characteristics of roundness and sphericity to be greater than 0.6, high-stress resistance with excellent thermal and mechanical stabilities confirmed its great potential to be applied as successful proppants in oil and gas upstream applications.",3,3,3
Hydraulic Fracture,Fracture Propagation,"Hui, Gang; Chen, Shengnan; Chen, Zhangxing; Gu, Fei",An integrated approach to characterize hydraulic fracturing-induced seismicity in shale reservoirs,Induced seismicity; Hydraulic fracturing; Coupled flow-geomechanics model; Coulomb failure stress; Mitigation strategy,COULOMB STRESS CHANGES; INDUCED EARTHQUAKES; CROOKED LAKE; FOX CREEK; POROELASTICITY; SEQUENCES,"There has been a remarkable increase in induced seismicity in Western Canada and the majority of these events can be related to hydraulic fracturing operations applied to develop unconventional reservoirs. The underlying mechanism of such induced seismicity is still unclear and needs to be investigated to mitigate risks of future events. In this paper, we propose a new integrated approach to characterize hydraulic fracturing-induced seismicity. Inferred faults in the target area were first identified by the ant-tracking approach and hydraulic fractures were characterized by simulating hydraulic fracturing processes. The coupled flow-geomechanics modeling was then performed to compute the Coulomb Failure Stress and determine the reactivation of pre-existing faults. A case study was finally utilized to demonstrate the applicability of the integrated method. Four north-south-oriented faults were interpreted and half-length of hydraulic fractures were calculated from 84 to 127 m. The calculated results of the flow-geomechanics model were in good agreement with the actual induced seismicity spatially and temporally. Three types of triggering mechanisms were accounted for HF-induced seismicity, including hydraulic fractures propagation, the connection between hydraulic fractures and a fault and connections of hydraulic fractures with the natural fractures around the fault. The injection rate could be decreased to mitigate risks of future seismic events.",7,8,2
Hydraulic Fracture,Fracture Propagation,"Gou, Bo; Zhan, Li; Guo, Jianchun; Zhang, Ran; Zhou, Changlin; Wu, Lin; Ye, Jiexiao; Zeng, Ji",Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan,Fractured carbonate rock; True tri-axial experiment; Reactive fluid; Nonreactive fluid; Fracture propagation; CT scan,LIMESTONE FORMATION; CRITERION; SHALE; ACID,"Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm x 200 mm x 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.",5,5,13
Hydraulic Fracture,Fracture Propagation,"Park, Jaeyoung; Iino, Atsushi; Datta-Gupta, Akhil; Bi, Jackson; Sankaran, Sathish",Novel hybrid Fast Marching Method-based simulation workflow for rapid history matching and completion design optimization of hydraulically fractured shale wells,Completion optimization; Rapid reservoir simulation technique; Hydraulic fracture modeling; Shale reservoir,FINITE-ELEMENT SIMULATION; RESERVOIR PROPERTIES; GAS-PRODUCTION; PERMEABILITY; STRESS; FLOW; DEFORMATION; STIMULATION; PROPAGATION; INTEGRATION,"This paper introduces a novel hybrid Fast Marching Method-based simulation (FMM-Sim) workflow for rapid history matching and completion design optimization of hydraulically fractured shale wells in unconventional reservoirs. The workflow incorporates fracture propagation to model the injection phase using a 3D finite difference (FD) simulation and seamlessly transitions to FMM-Sim for the subsequent production phase modeling. A simplified physical model for pressure-dependent fracture dilation/compaction was proposed and parameterized to emulate fracture propagation. The model was validated with ABAQUS, a fully coupled fluid flow and geomechanics simulator. In the workflow, the fracture parameters such as fracture geometry and permeability are obtained as a result of the injection phase modeling. Next, they are transferred into the subsequent production phase modeling with FMM-Sim which transforms 3D reservoir simulation model into 1D simulation model leading to orders of magnitude faster computation. The workflow was successfully applied to a field case in the Delaware Basin. The injection and production well data was first history-matched using a genetic algorithm. The calibrated models provide a range of estimated ultimate recovery (EUR) and net present value (NPV) of the history-matched well. After the history matching, the calibrated fracture dilation/compaction curves were used to investigate the optimum completion design for the well. The workflow has been proposed in practical and efficient way in the sense that the entire workflow, from the fracture propagation to the subsequent production, can be performed in any 3D FD simulator. This substantially saves computation resources and manpower compared to common industry workflows. The proposed workflow which connects completion design and hydrocarbon production with efficient computation would be beneficial for field development planning and economic decision making in unconventional reservoirs.",5,5,0
Hydraulic Fracture,Fracture Propagation,"Yan, Yan; Guan, Zhichuan; Zhang, Bo; Chen, Weiqing",Numerical investigation of debonding extent development of cementing interfaces during hydraulic fracturing through perforation cluster,Hydraulic fracturing; Perforation; Cohesive zone method; Cement debonding; Well integrity,PLASTIC-DAMAGE MODEL; SHEATH INTEGRITY; ZONAL ISOLATION; SIMULATION; PROPAGATION; STRENGTH; FAILURE; DRIVEN; WELLS,"The perforation will damage the sealing integrity of cement sheath/cementing interfaces around the hole more or less, especially the debonding of cementing interfaces may lead to the fluid channeling during hydraulic fracturing. In this work, a laboratory experiment were used to verify the cohesive zone method (CZM) for simulating the debonding extent of casing/cement interface from a single hole during hydraulic fracturing. Then the debonding degree of cementing interfaces through perforation cluster during fracturing was investigated by using CZM. The numerical analysis results showed that the axial debonding length of the cement/formation interface is longer than which of casing/cement interface under the same working conditions. When the debonding zone around the perforation holes connected to each other, the cement/formation interface debonded faster than that of the casing/cement interface under the pressure of fracturing. The parameter sensitivity analysis shows that it is beneficial to diminish the debonding extent of cementing interfaces by reducing the viscosity of fracturing fluid and the pump pressure. The reliability of CZM method was validated by means of the peak values of critical failure pressure and casing displacement during lab scale fracturing experiment. Improving interfacial bonding strength and reducing the elastic modulus of the cement sheath can effectively promote wellbore integrity during hydraulic fracturing. This work can be used to evaluate the sealing performance of the cement sheath under the hydraulic fracturing and to provide guidance for fracturing planning.",4,4,7
Hydraulic Fracture,Fracture Propagation,"Pan, Rui; Zhang, Guangqing; Li, Shiyuan; Zheng, Xuelin; Xu, Changzhuo; Fan, Zongyang",Influence of the fracture process zone on fracture propagation mode in layered rocks,Interbedded interfaces; Fracture process zone; Fracture propagation mode; Digital image correlation; Hydraulic fracturing,HYDRAULIC FRACTURE; TOUGHNESS DETERMINATION; TENSILE-STRENGTH; BRITTLE; ANISOTROPY,"During the hydraulic fracturing, fractures are often kinked, blunted, or offset owing to the alternating, interbedded interfaces of diverse properties that render fracturing performance unsatisfactory. In this study, two cases (the artificial fracture perpendicular to and parallel to the bedding interfaces) were examined through threepoint bending experiments on semi-circular bending (SCB) using shale specimens. The fracture process zone (FPZ) was studied based on the Digital Image Correlation (DIC) technique. The interbedded interfaces ahead of the artificial fracture tip affect the fracture propagation, with its extents are related to the bedding planes. In such conditions, the FPZ is composed of two parts: the FPZ ahead of the artificial fracture tip, and the zones of the deformed bedding interfaces distant from the artificial fracture tip. When the artificial fracture ran along the bedding interface, after peak loading, the interbedded interfaces on both sides of the main fracture undergone tensile failure. In turn, the deformation at the interbedded interfaces restricted the extension of the main fracture. The propagation mode of the hydraulic fracture accompanied by distant opening/slipping of interbedded interfaces is found remarkable in the layered reservoirs, and should be included in hydraulic fracturing designs or numerical fracturing modeling.",3,3,13
Hydraulic Fracture,Fracture Propagation,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Hydraulic Fracture,Fracture Propagation,"Heng, Shuai; Li, Xianzhong; Zhang, Xiaodong; Li, Zhen",Mechanisms for the control of the complex propagation behaviour of hydraulic fractures in shale,Hydraulic fracture; Complex propagation behaviour; Bedding plane; Cementing strength; Fracture deviation; Shale,,"The complex propagation behaviours of hydraulic fracture (HF) at bedding planes (BPs) and the produced complicated fracture geometry are essential to enhance the production of shale gas reservoirs. To better understand the complex propagation behaviour of HF at BPs with different bond strengths, the propagation behaviour, including arrest, crossing, and deviation, was identified first from post-fracturing shale specimens. The discontinuous stress and displacement fields on both sides of a BP ahead of an HF were then determined using the numerical simulation method. Finally, three mechanisms-principal stress jump, Cook-Gordon debonding or Poisson effect, and elastic dissimilarity-were explored in detail to interpret the complex propagation behaviour. The results revealed that HF is arrested/deviated only at extremely weakly cemented or fully opened BPs, whereas HF crosses strongly cemented BPs. The high heterogeneity of the BPs in cementing strength is responsible for the complex propagation behaviour of HF. The principal stress jump at a BP is caused by the difference in stiffness between the BP and the rock matrix. The maximum tensile principal stress ahead of the HF cannot be transmitted across the weakly cemented or fully opened BPs, suggesting that the HF cannot cross BPs. The principal stresses may rotate at a weakly cemented BP, and the rotated principal stresses tend to terminate or deviate an HF. Because of Cook-Gordon debonding and the Poisson effect, if a weakly cemented BP is present and is roughly normal to an advancing HF, the BP may break at some distance ahead of the fracture tip and induce a secondary fracture along the BP. The HF then reaches the opened BP and deviates towards the BP. The propagation process of L- or T-shaped fractures can be interpreted both by the Cook-Gordon debonding and Poisson effect from the viewpoints of stress and displacement. The three mechanisms often operate together when an HF deviates towards a weak BP; while for a special case, there may be only one dominant mechanism.",3,3,7
Hydraulic Fracture,Fracture Propagation,"Zhang, C. P.; Cheng, P.; Ma, Z. Y.; Ranjith, P. G.; Zhou, J. P.",Comparison of fracturing unconventional gas reservoirs using CO2 and water: An experimental study,CO2-based fracturing; Hydraulic fracturing; Breakdown pressure; Fracture aperture; Fracture morphology,CARBON-DIOXIDE; HYDRAULIC CONDUCTIVITY; TIGHT SANDSTONE; FLOW BEHAVIOR; SHALE GAS; PROPAGATION; INITIATION; PERMEABILITY; WELLBORE,"CO2-based fracturing (CBF) has been regarded as the most promising alternative to water-based fracturing (WBF) in water-sensitive unconventional gas reservoirs, and the fracture initiation and propagation at different in-site stresses created by CBF is crucial to the flow conductivity of fracture network. The main aim of this study is to compare the fracturing efficiency of WBF and CBF by conducting a series of fracturing tests on siltstone samples. According to the experimental results, the breakdown pressure linearly increases with the confining pressure, and the slope is 1.3928 and 1.6422 for CBF and WBF, respectively, and the much lower breakdown pressure for CBF is because of the fast penetration of CO2 through the rock matrix, which significantly reduces the effective stress around the borehole. Importantly, the observed fracture aperture for CBF is much greater than that for WBF, the maximum fracture aperture for CBF is around 2 to 5 times greater than that for WBF under the same test conditions. The difference in fracture aperture depends on the presence of discrete blocks and particles, and CBF can create greater and more loose particles in both mechanically-created method and hydraulically-created method to keep the created fractures open after the release of the injection pressure. The greater fracture aperture of CBF is favourable for the flow capacity of the fractures and therefore reservoir productivity, which is verified by the permeability tests with 190.43 times of permeability than that of WBF. Interestingly, the greater fracture width expansion for CBF perpendicular to the major principal pressure promotes the generation of horizontal fractures, even when the injection pressure is smaller than the major principal pressure, and the probability of horizontal fracture for CBF is 4-5 times of that for WBF, which reflect its great potential to create complex fracture network in unconventional gas reservoirs. The test results reveal that CBF is superior to the WBF since it is capable to create much more complex and efficient fracture networks. The findings are beneficial to understand the difference of fracturing behaviours at different in-site stresses between WBF and CBF, and provide experimental guidance for the exploitation of water-sensitive unconventional gas reservoirs by CBF.",3,3,4
Hydraulic Fracture,Fracture Initiation Pressure,"Xue, Yi; Liu, Jia; Ranjith, P. G.; Liang, Xin; Wang, Songhe",Investigation of the influence of gas fracturing on fracturing characteristics of coal mass and gas extraction efficiency based on a multi-physical field model,Gas fracturing; Hydro-mechanical coupling; Gas extraction efficiency; Fracture criterion; Non-uniform stress,OIL-RECOVERY; SHALE; PRESSURE; FLOW; CO2; RESERVOIRS; DIFFUSION; METHANE; PERMEABILITY; PRECIPITATION,"Coal seam gas recovery is a critical way to achieve clean energy development and reduce greenhouse gas emissions. Gas fracturing, as a necessary and advantageous stimulation measure, can effectively achieve gas extraction from deep coal seams and ensure safe production in deep coal mines. In this study, a hydro-mechanical coupling model is established to analyze the damage characteristics of coal seams during gas fracturing. The model focuses on three aspects: (a). the fracture criterion of type-I fracture under the action of multiple stress states in the fracturing process; (b). the characteristics of post-peak strain softening of coal and its influence on coal permeability; (c). the influence of non-uniform stress state on directional compression deformation and directional permeability of coal. The difference between gas fracturing (nitrogen, CO2) and hydraulic fracturing is studied based on this coupling model. The development of fractures in coal seam gas reservoirs after gas fracturing is investigated, and the influences of the coal parameters of the gas extraction process after fracturing are determined. Results show that because of the different compression coefficients, viscosities of water and gas and the slippage effect, there are obvious differences in the fracturing pressure of gas and water. Under the same parameters, the hydraulic fracturing method needs larger fracture initiation pressure than the gas fracturing method (nitrogen, CO2). For two kinds of media (nitrogen, CO2) in gas fracturing, in addition to the parameter difference of gas itself, the adsorption of CO2 is also the main factor affecting the fracturing pressure. The increase of coal permeability and Biot's coefficient will reduce the fracture initiation pressure, and the increase of confining pressure will increase the fracture initiation pressure.",39,39,25
Hydraulic Fracture,Fracture Initiation Pressure,"Abdelghany, Wael K.; Radwan, Ahmed E.; Elkhawaga, Mohamed A.; Wood, David A.; Sen, Souvik; Kassem, Ahmed A.",Geomechanical modeling using the depth-of-damage approach to achieve successful underbalanced drilling in the Gulf of Suez rift basin,Sub-surface stress regime; Depth of damage; Wellbore breakout; Over-pressured formations; Underbalanced drilling; High-pressure formations; Wellbore stability,HYDRAULIC FRACTURE INITIATION; BOREHOLE STABILITY ANALYSIS; CONSOLIDATED ROCK STRATA; PRESENT-DAY STATE; WELLBORE-STABILITY; BADRI FIELD; BELAYIM FORMATION; EFFECTIVE STRESS; TECTONIC STRESS; PORE PRESSURE,"Typical oil and gas reservoirs producing in the Gulf of Suez are now extensively depleted in terms of recovery of conventional resources and display declining production levels and heterogeneous pore pressure regimes. To continue production on a commercially viable basis and enhance the recovery of remaining oil and gas from the mature reservoirs currently in production, drilling decision-makers can no longer rely on traditional balanced or overbalanced drilling methods. Hence, underbalanced drilling is an essential requirement for such reservoirs. However, inducing underbalanced conditions increases the risk of the borehole instability. In the studied area, three previous wellbore stability studies were performed associated with the Hilal-X platform wells using the breakout-width-failure concept. Nevertheless, several wellbore instability issues were recorded there due to that method determining a mud-weight window that was too conservative. New wellbore stability analysis has been performed using a depth-of-damage approach. This analysis has helped to deliver excellent results during underbalanced drilling, after many attempts in previously drilled wells in overbalanced conditions that resulted in borehole instability and/or formation damage. This study documents how successful underbalanced drilling has been achieved in this basin for the first time by mud weights being guided by depth-of-damage analysis, highlight the requirements of that method using a case study for a specific well. In-situ stresses and an 1D-geomechanical earth model were generated using well log data from offset wells. The modified Lade method was used as a failure criterion, while the depth-of-damage approach was used for wellbore stability analysis in HilalX4 well. The study reveals that: 1) the Hilal field reservoirs have variable pore pressure regimes, 2) the breakoutwidth-failure concept provides misleading results in the studied reservoir formation, 3) the depth-of-damage approach reflects reservoir conditions more effectively and allows for successful underbalanced drilling without any instability events, 4) a new casing design for the Hilal Field wells has led to enhanced production performance, and 5) underbalanced drilling, when downhole pressures are carefully managed, is a safe and reliable technique for the mature fields of the Gulf of Suez rift basin.",25,25,10
Hydraulic Fracture,Fracture Initiation Pressure,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Hydraulic Fracture,Fracture Initiation Pressure,"Zhong, Jianyu; Ge, Zhaolong; Lu, Yiyu; Zhou, Zhe; Zheng, Jingwei",Prediction of fracture initiation pressure in multiple failure hydraulic fracturing modes: Three-dimensional stress model considering borehole deformation,Hydraulic fracturing; Fracture initiation pressure; Three-dimensional stress; Borehole deformation; Coal seam weak plane; Multiple failure modes,,"Hydraulic fracturing technology has been widely used as the main method of exploiting coalbed methane (CBM). The core of this technology is the accurate prediction of the fracture initiation pressure. As the exploitation depth increases, the influence of the in-situ stress obviously increases. Because the existing model of calculating the fracture initiation pressure ignores the influence of in-situ stress on the extraction borehole (CBM well) deformation, and the fracture initiation failure mode is single, the fracture initiation pressure of hydraulic fracturing cannot be accurately predicted in the field. In this study, a new model for predicting the fracture initiation pressure in hydraulic fracturing under a three-dimensional stress state was established. For the first time, the deformation of a circular borehole is related to the in-situ stress, and the size of the elliptical borehole can be accurately obtained after deformation. Eleven fracture initiation failure modes for the hydraulic fracturing of coal seams are proposed. The fracture initiation pressure of each failure mode was calculated in MATLAB, and the fracture initiation pressure of the shear failure of the rho z plane (a) was the smallest. The effects of the horizontal maximum principal stress, horizontal minimum principal stress, vertical intermediate principal stress, coal seam dip angle, horizontal azimuth of borehole, and gas pressure on the fracturing pressure were investigated using the proposed model. The coal seam dip angle exerted the greatest influence, and a new hydraulic fracturing construction procedure is proposed: the pump pressure should be gradually increased from the minimum initiation pressure according to the fracture initiation pressure gradient required by each failure mode. A field hydraulic fracturing test was conducted, and the experimental results are in good agreement with the theoretical calculation results. The maximum error was 5.5%, which validates the proposed theoretical model. The accuracy of the proposed theoretical model in the calculation of the fracture initiation pressure increased by 364.4% compared with the classical hydraulic fracturing theory. The results obtained by this study can provide more precise guidance to hydraulic fracturing projects.",6,6,14
Hydraulic Fracture,Fracture Initiation Pressure,"Wang, Yanbin; Liu, Kui; Gao, Deli",Investigation of the interface cracks on the cement sheath stress in shale gas wells during hydraulic fracturing,Shale gas wells; Hydraulic fracturing; Interface cracks; Mechanical properties; Wellbore integrity,CASING PRESSURE; FAILURE; DESIGN; INTEGRITY,"Wellbore integrity problem induced by insufficient seal ability of the cement sheath has become a technical challenge of shale gas wells during hydraulic fracturing. In this paper, a new model has been established to characteristic the mechanics of the casing-cement interface (CCI) and the cement-formation interface (CFI) of the shale gas wells. In this model, the radial stress and the stress intensity factor has been analyzed to predict the prolongation of the initial cracks caused by perforation through comparison of the stress intensity factor and the interfacial fracture toughness of the CCI and CFI. In addition, the influence of the casing and cement parameters on the interfacial stress and the crack width of the CCI and CFI has been discussed in detail, and the optimal design of these parameters has been proposed according to the field data. Finally, the conclusions and some realistic suggestions have been put forward based on the discussion.",4,4,5
Hydraulic Fracture,Fracture Initiation Pressure,"Zhang, Fengyuan; Emami-Meybodi, Hamid",Analysis of early-time production data from multi-fractured shale gas wells by considering multiple transport mechanisms through nanopores,Two-phase; Production data; Flowback fracture characterization; Shale; Diffusion; Desorption,APPARENT PERMEABILITY MODEL; RATE-TRANSIENT ANALYSIS; MATERIAL BALANCE EQUATION; 2-PHASE FLOWBACK; SEMIANALYTICAL METHOD; HORIZONTAL WELLS; WATER-FLOWBACK; RESERVOIRS; DRAINAGE; DEFORMATION,"Analysis of early-time production and flowback data from multi-fractured shale gas wells is of critical importance in the characterization of hydraulic fractures (HF). However, the accurate estimation of HF properties in the current models is challenged by the complexity in multiple transport mechanisms and two-phase flow of shale gas reservoir. This study presents a new semi-analytical method to estimate HF attributes for shale gas wells exhibiting two-phase flow based on straight line analysis. The proposed method considers two-phase infinite acting linear flow (IALF) and boundary dominated flow (BDF) for both HF and matrix domains. In addition, matrix flow considers desorption, diffusion, slip flow, continuum flow, stress dependence rock, and adsorbed water film in the nanopores. A modified material balance equation is proposed to calculate average pressure in the fracture and distance of investigation (DOI) in the matrix by considering gas desorption and diffusion in the matrix domain. The accuracy of the proposed method is tested against numerical results obtained from commercial software (IMEX-CMG). The validation results confirm that the developed method can closely estimate initial fracture volume, permeability, and permeability modulus from early-time production data exhibiting two-phase IALF and BDF regimes. Furthermore, the results indicate that the consideration of desorption, diffusion, and slip flow plays an important role in the modeling of gas transport in shale matrix. The impact of these transport mechanisms on production modeling as well as characterization of HF properties becomes significant when the matrix experiences substantial pressure drops. For the purpose of field application, the proposed method is used to analyze flowback data from a multi-fractured horizontal well. The field results reveal that the calculated fracture properties are consistent between the proposed method and the long-term production data analysis method.",3,3,5
Hydraulic Fracture,Fracture Initiation Pressure,"Zhang, C. P.; Cheng, P.; Ma, Z. Y.; Ranjith, P. G.; Zhou, J. P.",Comparison of fracturing unconventional gas reservoirs using CO2 and water: An experimental study,CO2-based fracturing; Hydraulic fracturing; Breakdown pressure; Fracture aperture; Fracture morphology,CARBON-DIOXIDE; HYDRAULIC CONDUCTIVITY; TIGHT SANDSTONE; FLOW BEHAVIOR; SHALE GAS; PROPAGATION; INITIATION; PERMEABILITY; WELLBORE,"CO2-based fracturing (CBF) has been regarded as the most promising alternative to water-based fracturing (WBF) in water-sensitive unconventional gas reservoirs, and the fracture initiation and propagation at different in-site stresses created by CBF is crucial to the flow conductivity of fracture network. The main aim of this study is to compare the fracturing efficiency of WBF and CBF by conducting a series of fracturing tests on siltstone samples. According to the experimental results, the breakdown pressure linearly increases with the confining pressure, and the slope is 1.3928 and 1.6422 for CBF and WBF, respectively, and the much lower breakdown pressure for CBF is because of the fast penetration of CO2 through the rock matrix, which significantly reduces the effective stress around the borehole. Importantly, the observed fracture aperture for CBF is much greater than that for WBF, the maximum fracture aperture for CBF is around 2 to 5 times greater than that for WBF under the same test conditions. The difference in fracture aperture depends on the presence of discrete blocks and particles, and CBF can create greater and more loose particles in both mechanically-created method and hydraulically-created method to keep the created fractures open after the release of the injection pressure. The greater fracture aperture of CBF is favourable for the flow capacity of the fractures and therefore reservoir productivity, which is verified by the permeability tests with 190.43 times of permeability than that of WBF. Interestingly, the greater fracture width expansion for CBF perpendicular to the major principal pressure promotes the generation of horizontal fractures, even when the injection pressure is smaller than the major principal pressure, and the probability of horizontal fracture for CBF is 4-5 times of that for WBF, which reflect its great potential to create complex fracture network in unconventional gas reservoirs. The test results reveal that CBF is superior to the WBF since it is capable to create much more complex and efficient fracture networks. The findings are beneficial to understand the difference of fracturing behaviours at different in-site stresses between WBF and CBF, and provide experimental guidance for the exploitation of water-sensitive unconventional gas reservoirs by CBF.",3,3,4
Hydraulic Fracture,Nature,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Hydraulic Fracture,Nature,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Hydraulic Fracture,Nature,"Hui, Gang; Chen, Shengnan; Chen, Zhangxing; Gu, Fei",An integrated approach to characterize hydraulic fracturing-induced seismicity in shale reservoirs,Induced seismicity; Hydraulic fracturing; Coupled flow-geomechanics model; Coulomb failure stress; Mitigation strategy,COULOMB STRESS CHANGES; INDUCED EARTHQUAKES; CROOKED LAKE; FOX CREEK; POROELASTICITY; SEQUENCES,"There has been a remarkable increase in induced seismicity in Western Canada and the majority of these events can be related to hydraulic fracturing operations applied to develop unconventional reservoirs. The underlying mechanism of such induced seismicity is still unclear and needs to be investigated to mitigate risks of future events. In this paper, we propose a new integrated approach to characterize hydraulic fracturing-induced seismicity. Inferred faults in the target area were first identified by the ant-tracking approach and hydraulic fractures were characterized by simulating hydraulic fracturing processes. The coupled flow-geomechanics modeling was then performed to compute the Coulomb Failure Stress and determine the reactivation of pre-existing faults. A case study was finally utilized to demonstrate the applicability of the integrated method. Four north-south-oriented faults were interpreted and half-length of hydraulic fractures were calculated from 84 to 127 m. The calculated results of the flow-geomechanics model were in good agreement with the actual induced seismicity spatially and temporally. Three types of triggering mechanisms were accounted for HF-induced seismicity, including hydraulic fractures propagation, the connection between hydraulic fractures and a fault and connections of hydraulic fractures with the natural fractures around the fault. The injection rate could be decreased to mitigate risks of future seismic events.",7,8,2
Hydraulic Fracture,Nature,"Gou, Bo; Zhan, Li; Guo, Jianchun; Zhang, Ran; Zhou, Changlin; Wu, Lin; Ye, Jiexiao; Zeng, Ji",Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan,Fractured carbonate rock; True tri-axial experiment; Reactive fluid; Nonreactive fluid; Fracture propagation; CT scan,LIMESTONE FORMATION; CRITERION; SHALE; ACID,"Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm x 200 mm x 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.",5,5,13
Hydraulic Fracture,Nature,"Chen, Xiang; Zhao, Liqiang; Liu, Pingli; Du, Juan; Bai, Zongxian; Liu, Jinming; Zhang, Nanlin; Luo, Zhifeng; Xu, Kun; Li, Nianyin",Laboratory study and field verification of a thermo-responsive water shutoff agent,Thermo-responsive water shutoff agent; Working mechanism; Laboratory experiment; Field application verification; Changqing oilfield,,"For the low-pressure and low-permeability oil reservoirs, water injection development and hydraulic fracturing stimulation are essential. The ideal water flooding mode is piston-like displacement. However, due to the heterogeneity of reservoirs, most of the injected water flow to oil wells along the dominant channel (i.e., high permeability area, natural fractures, or artificial fractures), which causes the decrease of oil displacement efficiency, the premature water breakthrough of oil wells, and high water content. Hence, over a span of decades, a compelling body of work has focused on the development of water shutoff agents. According to its working mechanism, water shutoff agents were divided into selective and non-selective water shutoff agents. However, the water shutoff agents mentioned above have been tested in more than 350 wells of Changqing oilfield, and the success rate was unsatisfactory. Therefore, this study aimed to develop a thermo-responsive water shutoff agent (TRWSA) with high plugging strength and compact structure. Through a series of laboratory experiments, the key performances of TRWSA for field application were tested and evaluated. First, the initial viscosity of TRWSA was 34.5 mPa s, which could easily pass through any completion tool (e.g., screen pipe and gravel pack) and enter any size fracture. Second, the TRWSA was non-water soluble and its phase-transition characteristics were not affected by guar gum fracturing fluid. Third, the phase transformation position of TRWSA could be determined by adjusting the SA-DST dosage and the wellbore-reservoir temperature. Fourth, its plugging strength was greater than 19.1 MPa and the volume retention rate was up to 99.13%. In addition, the field application results showed that oil production increased from 0.08 m(3)/d to 5.37 m(3)/d, and water content decreased from 98.6% to 9.8%. The TRWSA was satisfactory and had a great application prospect.",4,4,22
Hydraulic Fracture,Nature,"Arianfar, Ali; Ramezanzadeh, Ahmad; Khalili, Mohammad",Numerical study of nonlinear fluid flow behavior in natural fractures adjacent to porous medium,Fractured reservoirs; Fracture; Roughness; Porous medium; Permeability; Forchheimer equation,,"It is essential to understand the hydraulic aperture behavior of rock fractures where fluid passes through the rock mass. The geometric parameters of fracture, such as wall roughness and fracture aperture, have a significant effect on its hydro-mechanical behavior. This issue has been addressed in many papers, but the fluid passage through the permeable zone adjacent to the fracture has rarely been studied. Therefore, this paper numerically simulated the fluid behavior in the porous fractured medium. For preparing the model geometry, the 3D scanning of fracture walls was used for the samples taken from one of the oil wells in southern Iran. The geometry of fractures was prepared using ICEM CFD software, and the fluid flow in rock fracture and porous matrix was simulated with Ansys FluentTM software. Given that the two fracture surfaces are connected in reality, the geometry of the model was constructed when the fractures are mated and the connection is established at a certain level (the connection between the two surfaces equal to 15, 30, 45, 60, 75, and 90% of the total area). The results of this simulation showed that the Forchheimer macroscopic relation well describes the nonlinear fluid flow in the rock fracture even considering the permeable matrix. However, the higher the permeability value of the matrix adjacent to the fracture, the higher the fracture permeability value. The results indicated an exponential relationship between the increased permeability and the decreased Forchheimer coefficients, which confirms the easier passage of fluid through the fracture enclosed by a zone of higher permeability. Also, the values of linear and nonlinear coefficients of Forchheimer equation were estimated for each of the geometric models, which showed that the changes in Forchheimer coefficients are exponentially related to the change in the connected surface area.",3,3,9
Hydraulic Fracture,Nature,"Xu, Youjie; Li, Xiaoping; Liu, Qiguo; Yang, Sihan; Tan, Xiaohua",A semi-analytical solution of finite-conductivity multi-wing fractured well in naturally fractured reservoirs by boundary element method,Multi-wing fractured well (MWFW); Finite conductivity; Boundary element method (BEM); Pressure transient analysis,PRESSURE TRANSIENT ANALYSIS; SHALE GAS-RESERVOIRS; HORIZONTAL WELLS; VERTICAL WELLS; BEHAVIOR; MODEL,"Large-scale vertical well fracturing leads to formation of multi-wing fractures, which can effectively reduce fluid seepage resistance and increase single well production. As one of the post-fracture evaluation methods, pressure transient analysis is used widely in oil/gas field evaluation by engineers. It is of great significance for petroleum engineers to choose the correct and appropriate well test model for the accurate evaluation of formation parameters. Since oil/gas outer boundary is often rectangle or arbitrarily shape, a semi-analytical model of multiwing fractured well (MWFW) with arbitrarily shaped outer boundary gas reservoirs is presented. The reservoirs and hydraulic fracture mathematical models are established and solved. Coupling reservoirs and hydraulic fracture solution, and then discreting hydraulic fracture and outer boundary. The wellbore pressure solution with arbitrarily shaped outer boundary is obtained by pressure drop superposition, boundary element method (BEM) and Stehfest numerical inversion method. The bi-wing symmetrical hydraulic fracture and MWFW with finite conductivity are verified respectively by using numerical solution and comparison results reaches a good match, which certifies the correctness of the model and solving method. Typical curves of wellbore pressure and rate decline are discussed and influence of conductivity, hydraulic fracture number and hydraulic fracture distribution style et al. on wellbore pressure and rate decline is analyzes by combining with rate distribution of different time and segment. Influence of other parameters (Storativity ratio, interporosity coefficient and boundary shape size) on wellbore pressure and rate decline is also discussed in the end of paper.",3,3,8
Hydraulic Fracture,Nature,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Hydraulic Fracture,Spontaneous Imbibition,"Liu, Dengke; Ren, Dazhong; Du, Kun; Qi, Yiru; Ye, Feng",Impacts of mineral composition and pore structure on spontaneous imbibition in tight sandstone,Spontaneous imbibition; Mineral composition; Pore structure; Tight sandstone,DIRECT NUMERICAL-SIMULATION; TRIASSIC YANCHANG FORMATION; ORDOS BASIN; NITROGEN ADSORPTION; OIL; RESERVOIR; SALINITY; TRANSPORT,"Spontaneous imbibition is a fundamental mechanism to figure out the rock-fluid interplay during waterflooding and hydraulic fracturing. Mineral composition and pore structure play significant roles in imbibition efficiency, but how these parameters influence the oil production efficiency still is a myth. This research conducted the spontaneous imbibition experiments combined with low-temperature adsorption and nuclear magnetic resonance to (1) study how minerals and pore structures impact fluid movement features for tight sandstones; (2) systematically investigate the contribution to oil recovery of different pores' types and the impact of pore connectivity on spontaneous imbibition. The results show that the brine is inclined to attach hydrophilic minerals because of the wettability, increasing the imbibition efficiency. Additionally, with the tiny pores' development, the oil is more easily replaced by the brine due to strong capillary pressure. Last, as the mainstream imbibition area grows, the oil is preferentially displaced by the brine. The research provides insights into how mineral compositions and pore structures can influence spontaneous imbibition efficiency and improves the understanding of the complicated interaction between fluid and minerals in tight sandstones.",17,15,9
Hydraulic Fracture,Spontaneous Imbibition,"Liang, Tianbo; Zhao, Xurong; Yuan, Shuai; Zhu, Jiawei; Liang, Xingyuan; Li, Xiuhui; Zhou, Fujian",Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments,EOR; Tight oil reservoir; Diluted microemulsion; Wettability alteration; Dispersion of surfactant,WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; HYDROCARBON-PERMEABILITY; INTERFACIAL-TENSION; WATER BLOCKING; RECOVERY; WET; SHALE; MECHANISMS; ADSORPTION,"Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV-vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.",7,7,8
Hydraulic Fracture,Spontaneous Imbibition,"Eltahan, Esmail; Rego, Fabio Bordeaux; Yu, Wei; Sepehrnoori, Kamy",Impact of well shut-in after hydraulic-fracture treatments on productivity and recovery of tight oil reservoirs,Tight oil; Water blocking; Reservoir simulation,WATER; IMBIBITION; SALINITY; GAS; PERFORMANCE,"Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geomechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition countercurrent flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.",5,5,3
Hydraulic Fracture,Spontaneous Imbibition,"Liu, Zhonghua; Bai, Baojun; Wang, Yanling; Qu, Hai; Xiao, Qianhua; Zeng, Shunpeng",Spontaneous imbibition characteristics of slickwater and its components in Longmaxi shale,Spontaneous imbibition; Slickwater; Gas shale; Imbibition capacity; Imbibition rate; Secondary microfracture,WATER IMBIBITION; GAS; DAMAGE; PERMEABILITY; OIL,"During and after multi-stage hydraulic fracturing, the spontaneous imbibition of water-base fracturing fluid in shale formation is considered as the main mechanism responsible for the retention of large amounts of fracturing fluid. Slickwater is widely applied in Fuling shale gas field, the largest shale gas field in China. To characterize the spontaneous imbibition of slickwater and its four major components, experiments were carried out by using modified imbibition cells. Results show that all of the imbibition curves can be divided into three stages: linear imbibition stage, transition stage and stable imbibition stage. Their imbibition capacities are in the order of cleanup additive, clay stabilizer, slickwater, defoamer and friction reducer from highest to lowest. We have found that the imbibed volume is larger than the initial pore volume. Nuclear Magnetic Resonance (NMR) tests, core images and porosity comparison before and after imbibition all indicate the secondary microfractures were created during the imbibition process. The calculated volume of secondary microfractures which is the difference between the pore volume before and after the imbibition is very close to the imbibed volume, indicating the imbibition mainly through the microfractures. We also found that the imbibition rate of slickwater and its components in the order from highest to lowest is cleanup additive (0.087 cc/d), slickwater (0.058 cc/d), clay stabilizer (0.035 cc/d), defoamer (0.022 cc/d) and friction reducer (0.014 cc/d), indicating the synergy effect of slickwater components on the imbibition process and the role to optimize the cleanup additives during slickwater design.",4,4,13
Hydraulic Fracture,Spontaneous Imbibition,"Lu, Yuejian; Liu, Dameng; Cai, Yidong; Li, Qian; Zhou, Yingfang",Spontaneous imbibition in coal with in-situ dynamic micro-CT imaging,Coalbed methane; Spontaneous imbibition; X-ray; Relative permeability,PORE-FRACTURE NETWORKS; MERCURY INTRUSION POROSIMETRY; RELATIVE PERMEABILITY; WATER IMBIBITION; POROUS-MEDIA; LOW-RANK; GAS; SHALE; SORPTION; METHANE,"The gas/fluid flowing behavior and fluid distribution under capillary forces in porous media are essential for evaluating the pore-fracture characteristics of coal. Capillary force is crucial for flow-back efficiency after hydraulic fracturing during enhanced coalbed methane (CBM) production. In this work, in situ dynamic X-ray micro-computed tomography (X-ray mu-CT), field emission scanning electron microscopy (FE-SEM) combined with mercury intrusion porosimetry (MIP) were used on two coal samples of different wettability to explore the behavior of spontaneous imbibition. The results show that both pore-fracture and mineral content could affect the imbibition behavior of coal, which the former has played a major role. The spontaneous imbibition process can be divided into 4 stages to reveal fluid flow characteristics by the fluid distribution at different time steps. The gas relative permeability of coal attenuates exponentially with imbibition time result for capillary force based on fractal theory (the gas relative permeability reduces its value from 0.72 mD to 0.01 mD for WD, 0.5 mD to 0.08 mD for WZX). A low flow-back rate of fracturing fluid would lead to severe permeability damage. The longer the return drainage time, the more severe the permeability damage.",3,3,37
Hydraulic Fracture,Carbonate,"Huang, Qiming; Wu, Bing; Liu, Yu; Guo, Zhiguo; Wang, Gang; Sun, Lulu",Experimental and simulation investigations of the impact of polyacrylamide on CBM ad-/desorption,Slickwater; Coalbed methane; Polyacrylamide; Adsorption; Desorption,PORE STRUCTURE; FRACTURING FLUID; CO2 SORPTION; COAL; ADSORPTION; METHANE; CARBON; DIFFUSION; PRESSURE; NITROGEN,"Slickwater is commonly used during hydraulic fracturing in coalbed gas well, which is often prepared with polyacrylamide as the friction reducer. To investigate the impact of polyacrylamide on CBM ad-/desorption after a fracturing operation, slickwater with different concentrations of polyacrylamide were prepared and used to treat Illinois coal samples. Both isothermal ad-/desorption experiments and molecular simulations were conducted to investigate the impact of slickwater. Nuclear magnetic resonance measurements were performed to analyse the evolution of surface functional groups of coal during slickwater treatment. The results show that there is no significant chemical reaction between the coal component and polyacrylamide. Because of the porosity of the polyacrylamide coating adhered onto the surface of the pore, polyacrylamide has a significant sorption capacity of methane. The methane sorption amount of the 'coal-slickwater' system is higher than that of raw coal. However, with the increase of the amount of residue entering the pores, the porous structure of the polyacrylamide coating becomes denser, blocking some pores and the pore surface area is reduced; thus, the overall sorption capacity of the 'coal-polyacrylamide' system decreases.",16,16,17
Hydraulic Fracture,Carbonate,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Hydraulic Fracture,Carbonate,"Gou, Bo; Zhan, Li; Guo, Jianchun; Zhang, Ran; Zhou, Changlin; Wu, Lin; Ye, Jiexiao; Zeng, Ji",Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan,Fractured carbonate rock; True tri-axial experiment; Reactive fluid; Nonreactive fluid; Fracture propagation; CT scan,LIMESTONE FORMATION; CRITERION; SHALE; ACID,"Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm x 200 mm x 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.",5,5,13
Hydraulic Fracture,Carbonate,"Iyare, U. C.; Blake, O. O.; Ramsook, R.",Brittleness evaluation of Naparima Hill mudstones,Brittleness; Elastic properties; Effective pressure; Water saturation; Unconventional reservoirs; Naparima hill formation (Trinidad),ELASTIC PROPERTIES; SEISMIC ANISOTROPY; SEDIMENTARY-ROCKS; SHALE; WAVES; SATURATION; FREQUENCY; STRENGTH; VELOCITY; INDEXES,"The brittleness of unconventional source rock reservoirs is an essential parameter that controls the effectiveness of hydraulic fracturing operation. Brittleness can vary with effective pressure (equivalent to burial depth) and can be influenced by fluid saturation. Therefore, a detailed evaluation of rock brittleness is necessary prior to field applications. The late Cretaceous Naparima Hill Formation is the primary source for most of the 4 billion barrels of oil and 10 trillion cubic feet of gas produced in the last hundred years from conventional reservoirs in Trinidad, West Indies. This Formation is now being considered an unconventional reservoir in order to prolong and increase current productions. However, despite being a prolific Formation, there are no available geomechanical data, including brittleness. Brittleness index (BI) is often used to measure rock brittleness. In this study, we determined elastic-based BI from P- and S-wave velocity measurements, at effective pressures up to 130 MPa, for dry and water saturated outcrop mudstones from four lithofacies within the Naparima Hill Formation. The experimental results show that the BI for all four lithofacies, is independent of effective pressures in both dry and water saturated conditions. All four lithofacies can be considered brittle under dry conditions. However, when saturated, the BI reduces, which proves significant for softer lithofacies (siliceous calcareous mudstones and siliceous mudstones). In this saturated state, the harder lithofacies (calcareous mudstone interbedded with black chert and carbonate rich mudstone with nodular chert) are considered marginally brittle and the softer ones, are considered ductile. The results highlight that porosity is the main factor that controls the magnitude of reduction in the BI when the mudstones are fully saturated.",3,3,5
Hydraulic Fracture,Carbonate,"Gao, Qi; Cheng, Yuanfang; Han, Songcai; Yan, Chuanliang; Li, Yang; Han, Zhongying",Effect of shale matrix heterogeneity on gas transport during production: A microscopic investigation,Shale gas; Matrix heterogeneity; Organic matter; Inorganic matter; Apparent permeability,,"Shale gas is playing increasingly important roles in transforming the global energy markets due to the huge demand for cleaner energy in the future. To extract shale gas at the commercial rate, formations must be hydraulically fractured to provide more contact area between the wellbores and reservoirs. Although the properties of hydraulic fractures are the key to gas production in the early stage, it is the matrix properties that determine the long-term production performance of the wells. However, understanding the gas transport behaviours in shale matrix is still a challenge at present. In this paper, to analyze shale gas flow at the microscale, an improved numerical model is developed, which is able to simultaneously capture the mechanical deformation of organic matter (OM) and inorganic matter (iOM), gas flow in OM and iOM, and fluid and solid interaction between the OM and iOM. The modelling results show that due to the coexistence of OM and iOM, the gas transport and shale matrix deformation behaviours exhibit regional differences. Specifically, during the gas production process, pore pressure in OM declines slower, gas density and Knudsen number in OM own larger values, and the apparent permeability and volumetric strain of OM are smaller. Therefore, taking matrix heterogeneity into consideration is necessary for accurately describing shale gas flow. In addition, numerical simulations are carried out to investigate the effect of a multitude of parameters on the modelling results. These parameters include nanopore compressibility, nanopore radius, matrix porosity, Langmuir volume and Langmuir pressure, and total organic carbon (TOC). The sensitivity of apparent permeability evolution in OM and iOM on each parameter is reported and discussed. The obtained results provide new insights for understanding gas transport in shale reservoirs from a microscopic perspective.",3,3,2
Hydraulic Fracture,Coal Seam,"Xue, Yi; Liu, Jia; Ranjith, P. G.; Liang, Xin; Wang, Songhe",Investigation of the influence of gas fracturing on fracturing characteristics of coal mass and gas extraction efficiency based on a multi-physical field model,Gas fracturing; Hydro-mechanical coupling; Gas extraction efficiency; Fracture criterion; Non-uniform stress,OIL-RECOVERY; SHALE; PRESSURE; FLOW; CO2; RESERVOIRS; DIFFUSION; METHANE; PERMEABILITY; PRECIPITATION,"Coal seam gas recovery is a critical way to achieve clean energy development and reduce greenhouse gas emissions. Gas fracturing, as a necessary and advantageous stimulation measure, can effectively achieve gas extraction from deep coal seams and ensure safe production in deep coal mines. In this study, a hydro-mechanical coupling model is established to analyze the damage characteristics of coal seams during gas fracturing. The model focuses on three aspects: (a). the fracture criterion of type-I fracture under the action of multiple stress states in the fracturing process; (b). the characteristics of post-peak strain softening of coal and its influence on coal permeability; (c). the influence of non-uniform stress state on directional compression deformation and directional permeability of coal. The difference between gas fracturing (nitrogen, CO2) and hydraulic fracturing is studied based on this coupling model. The development of fractures in coal seam gas reservoirs after gas fracturing is investigated, and the influences of the coal parameters of the gas extraction process after fracturing are determined. Results show that because of the different compression coefficients, viscosities of water and gas and the slippage effect, there are obvious differences in the fracturing pressure of gas and water. Under the same parameters, the hydraulic fracturing method needs larger fracture initiation pressure than the gas fracturing method (nitrogen, CO2). For two kinds of media (nitrogen, CO2) in gas fracturing, in addition to the parameter difference of gas itself, the adsorption of CO2 is also the main factor affecting the fracturing pressure. The increase of coal permeability and Biot's coefficient will reduce the fracture initiation pressure, and the increase of confining pressure will increase the fracture initiation pressure.",39,39,25
Hydraulic Fracture,Coal Seam,"Chen, Shida; Tang, Dazhen; Tao, Shu; Liu, Pengcheng; Mathews, Jonathan P.","Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China",In situ stress; Permeability; Gas distribution; Productivity; Hydraulic fracture; Depth,DEPENDENT PERMEABILITY; LABORATORY MEASUREMENT; SEDIMENTARY CONTROL; HORIZONTAL STRESS; CBM DEVELOPMENT; BEARING SYSTEM; PORE PRESSURE; ORDOS BASIN; RESERVOIR; PROVINCE,"With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m3/t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500-800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.471.71 MPa/100 m). Overall, the stress release zone at depths of 500-800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production.",22,22,26
Hydraulic Fracture,Coal Seam,"Wang, Haitao; Kou, Zuhao; Guo, Jingjing; Chen, Zhuoting",A semi-analytical model for the transient pressure behaviors of a multiple fractured well in a coal seam gas reservoir,Coalbed methane; Multiple transportation mechanisms; Radial hydraulic fractures; Stimulated reservoir volume; Well test,HORIZONTAL WELLS; SHALE GAS; VERTICAL WELL; FLOW-RATE; PERMEABILITY; PERFORMANCE; ADSORPTION,"Multiple radial fractures can be generated in unconventional gas reservoirs after stimulation treatments such as hydraulic refracturing, high-energy gas fracturing, and explosive fracturing. This study presents a semi-analytical model to simulate the bottom-hole pressure (BHP) performances of a fractured well with multiple radial hydraulic fractures (MRHF) in a stress-sensitive coal seam gas reservoir. The adsorption-desorption and diffusion for fluid in reservoirs are considered. The continuous line-source function associated with discretization method in a composite coalbed gas reservoir is applied in Laplace domain. By means of Stehfest numerical inversion algorithm and Gauss elimination, the transient pressure responses in the well bottom are obtained and discussed. The results demonstrate that, from type curves, the main flow regimes for the proposed model in the coalbed gas reservoir are bilinear flow between adjacent radial hydraulic fractures, linear flow between adjacent radial hydraulic fractures, pseudo radial flow in stimulated region, and radial flow in un-stimulated region. Moreover, an obvious ""hump"" appears between the bilinear flow regime and the linear flow regime in stimulated region, which represents the interference between adjacent radial hydraulic fractures. The impacts of the ratio of permeability in stimulated region to that in un-stimulated region, the radius of stimulated reservoir volume (SRV), the permeability modulus, and the properties of hydraulic fractures on the transient pressure responses in well bottom are analyzed. The findings obtained in this study can pave the way for the quantitative understanding of the transient performances of multiple fractured vertical wells in unconventional reservoirs.",15,15,16
Hydraulic Fracture,Coal Seam,"Zhong, Jianyu; Ge, Zhaolong; Lu, Yiyu; Zhou, Zhe; Zheng, Jingwei",Prediction of fracture initiation pressure in multiple failure hydraulic fracturing modes: Three-dimensional stress model considering borehole deformation,Hydraulic fracturing; Fracture initiation pressure; Three-dimensional stress; Borehole deformation; Coal seam weak plane; Multiple failure modes,,"Hydraulic fracturing technology has been widely used as the main method of exploiting coalbed methane (CBM). The core of this technology is the accurate prediction of the fracture initiation pressure. As the exploitation depth increases, the influence of the in-situ stress obviously increases. Because the existing model of calculating the fracture initiation pressure ignores the influence of in-situ stress on the extraction borehole (CBM well) deformation, and the fracture initiation failure mode is single, the fracture initiation pressure of hydraulic fracturing cannot be accurately predicted in the field. In this study, a new model for predicting the fracture initiation pressure in hydraulic fracturing under a three-dimensional stress state was established. For the first time, the deformation of a circular borehole is related to the in-situ stress, and the size of the elliptical borehole can be accurately obtained after deformation. Eleven fracture initiation failure modes for the hydraulic fracturing of coal seams are proposed. The fracture initiation pressure of each failure mode was calculated in MATLAB, and the fracture initiation pressure of the shear failure of the rho z plane (a) was the smallest. The effects of the horizontal maximum principal stress, horizontal minimum principal stress, vertical intermediate principal stress, coal seam dip angle, horizontal azimuth of borehole, and gas pressure on the fracturing pressure were investigated using the proposed model. The coal seam dip angle exerted the greatest influence, and a new hydraulic fracturing construction procedure is proposed: the pump pressure should be gradually increased from the minimum initiation pressure according to the fracture initiation pressure gradient required by each failure mode. A field hydraulic fracturing test was conducted, and the experimental results are in good agreement with the theoretical calculation results. The maximum error was 5.5%, which validates the proposed theoretical model. The accuracy of the proposed theoretical model in the calculation of the fracture initiation pressure increased by 364.4% compared with the classical hydraulic fracturing theory. The results obtained by this study can provide more precise guidance to hydraulic fracturing projects.",6,6,14
Hydraulic Fracture,Pressure Gradient,"Chen, Shida; Tang, Dazhen; Tao, Shu; Liu, Pengcheng; Mathews, Jonathan P.","Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China",In situ stress; Permeability; Gas distribution; Productivity; Hydraulic fracture; Depth,DEPENDENT PERMEABILITY; LABORATORY MEASUREMENT; SEDIMENTARY CONTROL; HORIZONTAL STRESS; CBM DEVELOPMENT; BEARING SYSTEM; PORE PRESSURE; ORDOS BASIN; RESERVOIR; PROVINCE,"With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m3/t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500-800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.471.71 MPa/100 m). Overall, the stress release zone at depths of 500-800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production.",22,22,26
Hydraulic Fracture,Pressure Gradient,"Zhong, Jianyu; Ge, Zhaolong; Lu, Yiyu; Zhou, Zhe; Zheng, Jingwei",Prediction of fracture initiation pressure in multiple failure hydraulic fracturing modes: Three-dimensional stress model considering borehole deformation,Hydraulic fracturing; Fracture initiation pressure; Three-dimensional stress; Borehole deformation; Coal seam weak plane; Multiple failure modes,,"Hydraulic fracturing technology has been widely used as the main method of exploiting coalbed methane (CBM). The core of this technology is the accurate prediction of the fracture initiation pressure. As the exploitation depth increases, the influence of the in-situ stress obviously increases. Because the existing model of calculating the fracture initiation pressure ignores the influence of in-situ stress on the extraction borehole (CBM well) deformation, and the fracture initiation failure mode is single, the fracture initiation pressure of hydraulic fracturing cannot be accurately predicted in the field. In this study, a new model for predicting the fracture initiation pressure in hydraulic fracturing under a three-dimensional stress state was established. For the first time, the deformation of a circular borehole is related to the in-situ stress, and the size of the elliptical borehole can be accurately obtained after deformation. Eleven fracture initiation failure modes for the hydraulic fracturing of coal seams are proposed. The fracture initiation pressure of each failure mode was calculated in MATLAB, and the fracture initiation pressure of the shear failure of the rho z plane (a) was the smallest. The effects of the horizontal maximum principal stress, horizontal minimum principal stress, vertical intermediate principal stress, coal seam dip angle, horizontal azimuth of borehole, and gas pressure on the fracturing pressure were investigated using the proposed model. The coal seam dip angle exerted the greatest influence, and a new hydraulic fracturing construction procedure is proposed: the pump pressure should be gradually increased from the minimum initiation pressure according to the fracture initiation pressure gradient required by each failure mode. A field hydraulic fracturing test was conducted, and the experimental results are in good agreement with the theoretical calculation results. The maximum error was 5.5%, which validates the proposed theoretical model. The accuracy of the proposed theoretical model in the calculation of the fracture initiation pressure increased by 364.4% compared with the classical hydraulic fracturing theory. The results obtained by this study can provide more precise guidance to hydraulic fracturing projects.",6,6,14
Hydraulic Fracture,Pressure Gradient,"Zhang, Yao; Chai, Junrui; Cao, Cheng; Shang, Tao","Combined influences of shear displacement, roughness, and pressure gradient on nonlinear flow in self-affine fractures",Shear displacement; Roughness; Pressure gradient; Nonlinear flow; Weierstrass-Mandelbrot function,CONSERVATIVE SOLUTE TRANSPORT; FLUID-FLOW; HYDRAULIC CHARACTERISTICS; SURFACE-ROUGHNESS; WALLED FRACTURES; ROCK FRACTURE; CUBIC LAW; MODEL; CONDUCTIVITY; PERMEABILITY,"This study numerically investigated the nonlinear flow behaviors under the combined influences of shear displacement, roughness, and pressure gradient. Two-dimensional (2D) self-affine fractures with five fractal dimensions (1.1-1.5) were generated by the Weierstrass-Mandelbrot (W-M) function. Different conditions with six shear displacements (0.5-3.0 mm) and five pressure gradients (1-100 kPa/m) were applied to each model and the nonlinear flow behaviors were investigated based on microscopic descriptions and macroscopic characterizations. The results show that shear displacement coupled with the effect of high roughness can easily lead to heterogeneous void spaces and emergence of eddies. The flow rate of unmated rough fractures is always larger than that of mated rough fractures due to the effects of geometries and eddies, while this situation may be reversed in relatively smooth fractures. Rougher fractures correspond to lower flow rates under the same conditions and many eddies still exist although the fractures are mated. Increasing the pressure gradient can accelerate the development of eddies in rough fractures, while when the pressure gradient exceeds a certain value, its effect is restrained by apertures. In general, increasing the shear displacement and roughness can enhance the proportion of the quadratic term in Forchheimer's law. However, not all fractures were satisfied with these points. Increasing the shear displacement from 2.5 mm to 3.0 mm in the fracture with fractal dimension of 1.1 and increasing the fractal dimension from 1.4 to 1.5 at the shear displacement of 1.0 mm both decreased the proportion of the quadratic term. The ratio of the mechanical aperture to the hydraulic aperture (E/e) varies between 1.0 and 2.8, and its relationship with the Reynolds number (Re) can be described by a power function for the fractures with the fractal dimension of 1.1-1.4 (or JRC = 0.3-18). The relationship of E/e versus Re is strongly dependent on the fracture roughness, and for a given roughness the relationship is almost the same under different shear displacements and pressure gradients. However, this phenomenon is no longer valid as the fracture becomes rougher. The results of this study can deeply advance the understanding of nonlinear flow in rough fractures and its dependence on shear displacement, roughness, pressure gradient, and especially their combined influences under high Re.",4,5,7
Hydraulic Fracture,Brittleness,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Hydraulic Fracture,Brittleness,"Pan, Rui; Zhang, Guangqing; Li, Shiyuan; Zheng, Xuelin; Xu, Changzhuo; Fan, Zongyang",Influence of the fracture process zone on fracture propagation mode in layered rocks,Interbedded interfaces; Fracture process zone; Fracture propagation mode; Digital image correlation; Hydraulic fracturing,HYDRAULIC FRACTURE; TOUGHNESS DETERMINATION; TENSILE-STRENGTH; BRITTLE; ANISOTROPY,"During the hydraulic fracturing, fractures are often kinked, blunted, or offset owing to the alternating, interbedded interfaces of diverse properties that render fracturing performance unsatisfactory. In this study, two cases (the artificial fracture perpendicular to and parallel to the bedding interfaces) were examined through threepoint bending experiments on semi-circular bending (SCB) using shale specimens. The fracture process zone (FPZ) was studied based on the Digital Image Correlation (DIC) technique. The interbedded interfaces ahead of the artificial fracture tip affect the fracture propagation, with its extents are related to the bedding planes. In such conditions, the FPZ is composed of two parts: the FPZ ahead of the artificial fracture tip, and the zones of the deformed bedding interfaces distant from the artificial fracture tip. When the artificial fracture ran along the bedding interface, after peak loading, the interbedded interfaces on both sides of the main fracture undergone tensile failure. In turn, the deformation at the interbedded interfaces restricted the extension of the main fracture. The propagation mode of the hydraulic fracture accompanied by distant opening/slipping of interbedded interfaces is found remarkable in the layered reservoirs, and should be included in hydraulic fracturing designs or numerical fracturing modeling.",3,3,13
Hydraulic Fracture,Brittleness,"Iyare, U. C.; Blake, O. O.; Ramsook, R.",Brittleness evaluation of Naparima Hill mudstones,Brittleness; Elastic properties; Effective pressure; Water saturation; Unconventional reservoirs; Naparima hill formation (Trinidad),ELASTIC PROPERTIES; SEISMIC ANISOTROPY; SEDIMENTARY-ROCKS; SHALE; WAVES; SATURATION; FREQUENCY; STRENGTH; VELOCITY; INDEXES,"The brittleness of unconventional source rock reservoirs is an essential parameter that controls the effectiveness of hydraulic fracturing operation. Brittleness can vary with effective pressure (equivalent to burial depth) and can be influenced by fluid saturation. Therefore, a detailed evaluation of rock brittleness is necessary prior to field applications. The late Cretaceous Naparima Hill Formation is the primary source for most of the 4 billion barrels of oil and 10 trillion cubic feet of gas produced in the last hundred years from conventional reservoirs in Trinidad, West Indies. This Formation is now being considered an unconventional reservoir in order to prolong and increase current productions. However, despite being a prolific Formation, there are no available geomechanical data, including brittleness. Brittleness index (BI) is often used to measure rock brittleness. In this study, we determined elastic-based BI from P- and S-wave velocity measurements, at effective pressures up to 130 MPa, for dry and water saturated outcrop mudstones from four lithofacies within the Naparima Hill Formation. The experimental results show that the BI for all four lithofacies, is independent of effective pressures in both dry and water saturated conditions. All four lithofacies can be considered brittle under dry conditions. However, when saturated, the BI reduces, which proves significant for softer lithofacies (siliceous calcareous mudstones and siliceous mudstones). In this saturated state, the harder lithofacies (calcareous mudstone interbedded with black chert and carbonate rich mudstone with nodular chert) are considered marginally brittle and the softer ones, are considered ductile. The results highlight that porosity is the main factor that controls the magnitude of reduction in the BI when the mudstones are fully saturated.",3,3,5
Hydraulic Fracture,Wellbore Stability,"Abdelghany, Wael K.; Radwan, Ahmed E.; Elkhawaga, Mohamed A.; Wood, David A.; Sen, Souvik; Kassem, Ahmed A.",Geomechanical modeling using the depth-of-damage approach to achieve successful underbalanced drilling in the Gulf of Suez rift basin,Sub-surface stress regime; Depth of damage; Wellbore breakout; Over-pressured formations; Underbalanced drilling; High-pressure formations; Wellbore stability,HYDRAULIC FRACTURE INITIATION; BOREHOLE STABILITY ANALYSIS; CONSOLIDATED ROCK STRATA; PRESENT-DAY STATE; WELLBORE-STABILITY; BADRI FIELD; BELAYIM FORMATION; EFFECTIVE STRESS; TECTONIC STRESS; PORE PRESSURE,"Typical oil and gas reservoirs producing in the Gulf of Suez are now extensively depleted in terms of recovery of conventional resources and display declining production levels and heterogeneous pore pressure regimes. To continue production on a commercially viable basis and enhance the recovery of remaining oil and gas from the mature reservoirs currently in production, drilling decision-makers can no longer rely on traditional balanced or overbalanced drilling methods. Hence, underbalanced drilling is an essential requirement for such reservoirs. However, inducing underbalanced conditions increases the risk of the borehole instability. In the studied area, three previous wellbore stability studies were performed associated with the Hilal-X platform wells using the breakout-width-failure concept. Nevertheless, several wellbore instability issues were recorded there due to that method determining a mud-weight window that was too conservative. New wellbore stability analysis has been performed using a depth-of-damage approach. This analysis has helped to deliver excellent results during underbalanced drilling, after many attempts in previously drilled wells in overbalanced conditions that resulted in borehole instability and/or formation damage. This study documents how successful underbalanced drilling has been achieved in this basin for the first time by mud weights being guided by depth-of-damage analysis, highlight the requirements of that method using a case study for a specific well. In-situ stresses and an 1D-geomechanical earth model were generated using well log data from offset wells. The modified Lade method was used as a failure criterion, while the depth-of-damage approach was used for wellbore stability analysis in HilalX4 well. The study reveals that: 1) the Hilal field reservoirs have variable pore pressure regimes, 2) the breakoutwidth-failure concept provides misleading results in the studied reservoir formation, 3) the depth-of-damage approach reflects reservoir conditions more effectively and allows for successful underbalanced drilling without any instability events, 4) a new casing design for the Hilal Field wells has led to enhanced production performance, and 5) underbalanced drilling, when downhole pressures are carefully managed, is a safe and reliable technique for the mature fields of the Gulf of Suez rift basin.",25,25,10
Hydraulic Fracture,Wellbore Stability,"Meng, Meng; Baldino, Silvio; Miska, Stefan",Evaluation of failure criteria under dynamic loading of the wellbore with strain rates between 10(-6) and 10(0) /s,Failure criteria; Strain rates; Grid search algorithm; Mohr failure line; Triaxial compression tests,,"Dynamic loading is very common during drilling, mining, hydraulic fracturing, and tunnel excavation. This could compromise the long-term stability and integrity of the underground constructions. Under dynamic loading, rocks usually behave differently compared to static loading. Whether the static failure criteria can be used to evaluate structure failure under dynamic loading is a question that has not been answered yet. In this paper, the triaxial compression strength data under different strain rates (between 10(-6) and 10(0)/s) for four types of rock (Bedford limestone, Bukit Timah granite, Laurentian granite, and Dry silica sand) have been used to evaluate six different failure criteria. Two methods have been implemented to obtain rock cohesion and internal friction angle, which are the grid search algorithm and the Mohr failure line method. The results show that the grid search algorithm guarantees the best performance of the failure criteria, providing the best-fit rock parameters. The more practical method of the Mohr failure line can also generate reasonable predictions if a safety factor of 1.1 is considered. Both methods show that Modified Lade is the failure criterion that provides the best performance in predicting rock failure under dynamic loading. In the petroleum industry, most of the activities causing dynamic loading of the wellbore are characterized by a magnitude of strain rate lower than 10(0)/s (even lower than 10(-3)/s). Consequently, this work shows that it is reasonable to assume that the commonly used static failure criteria, especially Modified Lade, could be selected to analyze wellbore stability under dynamic loading conditions effectively.",5,5,5
Hydraulic Fracture,Cretaceous,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Hydraulic Fracture,Cretaceous,"Iyare, U. C.; Blake, O. O.; Ramsook, R.",Brittleness evaluation of Naparima Hill mudstones,Brittleness; Elastic properties; Effective pressure; Water saturation; Unconventional reservoirs; Naparima hill formation (Trinidad),ELASTIC PROPERTIES; SEISMIC ANISOTROPY; SEDIMENTARY-ROCKS; SHALE; WAVES; SATURATION; FREQUENCY; STRENGTH; VELOCITY; INDEXES,"The brittleness of unconventional source rock reservoirs is an essential parameter that controls the effectiveness of hydraulic fracturing operation. Brittleness can vary with effective pressure (equivalent to burial depth) and can be influenced by fluid saturation. Therefore, a detailed evaluation of rock brittleness is necessary prior to field applications. The late Cretaceous Naparima Hill Formation is the primary source for most of the 4 billion barrels of oil and 10 trillion cubic feet of gas produced in the last hundred years from conventional reservoirs in Trinidad, West Indies. This Formation is now being considered an unconventional reservoir in order to prolong and increase current productions. However, despite being a prolific Formation, there are no available geomechanical data, including brittleness. Brittleness index (BI) is often used to measure rock brittleness. In this study, we determined elastic-based BI from P- and S-wave velocity measurements, at effective pressures up to 130 MPa, for dry and water saturated outcrop mudstones from four lithofacies within the Naparima Hill Formation. The experimental results show that the BI for all four lithofacies, is independent of effective pressures in both dry and water saturated conditions. All four lithofacies can be considered brittle under dry conditions. However, when saturated, the BI reduces, which proves significant for softer lithofacies (siliceous calcareous mudstones and siliceous mudstones). In this saturated state, the harder lithofacies (calcareous mudstone interbedded with black chert and carbonate rich mudstone with nodular chert) are considered marginally brittle and the softer ones, are considered ductile. The results highlight that porosity is the main factor that controls the magnitude of reduction in the BI when the mudstones are fully saturated.",3,3,5
Machine Learning,Error,"Otchere, Daniel Asante; Ganat, Tarek Omar Arbi; Gholami, Raoof; Ridha, Syahrir",Application of supervised machine learning paradigms in the prediction of petroleum reservoir properties: Comparative analysis of ANN and SVM models,Artificial intelligence (AI); Supervised machine learning; Artificial neural network (ANN); Support vector machine (SVM); Relevance vector machine (RVM); Hybrid intelligent system,,"The advent of Artificial Intelligence (AI) in the petroleum industry has seen an increase in its use in exploration, development, production, reservoir engineering and management planning to accelerate decision making, reduce cost and time. Supervised machine learning has gained much popularity in establishing a relationship between complex non-linear datasets. This type of machine learning algorithm has showcased its superiority over petroleum engineering regression techniques in terms of prediction errors for high dimensional data, computational power and memory. This review focuses on the most widely used machine learning algorithm employed in the petroleum industry, the Artificial Neural Network (ANN) with different shallow models used in reservoir characterisation. The Support Vector Machine (SVM) and Relevant Vector Machine (RVM) has over the years emerged as competitive algorithms where in most cases based on this review it outperformed the ANN. This makes it preferable than the ANN when there are limited data sets. Finally, hybridisation of multiple algorithms methodologies also showed improved performance over singularly applied algorithms offering a pathway in improving reservoir characterisation based on supervised machine learning as future scope of work.",20,20,14
Machine Learning,Error,"Mahdaviara, Mehdi; Rostami, Alireza; Keivanimehr, Farhad; Shahbazi, Khalil",Accurate determination of permeability in carbonate reservoirs using Gaussian Process Regression,Permeability determination; Carbonate reservoir; Pore specific surface area; Gaussian process regression; Sensitivity analysis; Outliers detection,ABSOLUTE PERMEABILITY; BAYESIAN NETWORKS; PREDICTION; MODELS; ALGORITHM; OIL,"The knowledge of reservoir permeability determination is increasingly important in petroleum engineering. Understanding the alteration of the abovementioned parameter as a dynamic characteristic of formations helps the characterization of reservoir rock. The existing models available for permeability determination are mainly developed for sandstone reservoir; therefore, a great challenge is in the prediction of permeability in carbonate heterogeneous rock. The current study addresses the application of Gaussian Process Regression (GPR), a state-of-the-art machine learning algorithm, in estimating permeability of carbonate reservoirs. This Bayesian network offers various benefits including non-linearity and multi-dimensionality. A widespread source of data pertinent to four deposits of Vuktyl' skiy, central Asia, Kuybyhev, and Orenburg was adopted from literature. The data set includes water saturation, effective porosity, and pore specific surface area parameters in association with absolute rock permeability as the target. Four different Kernels of Matern, rational quadratic, exponential, and squared exponential are utilized as the covariance functions of the GPR network. A wide variety of the visualizations and statistical parameters are prepared to assess the potential of the established models in permeability estimation. Finally, it is demonstrated that the GPR (Matern) gives the highest precision with Mean Magnitude Relative Error (MMRE) and Adjusted R-squared equal to 38% and 0.98, respectively. Besides, the applied sensitivity analysis reveals that porosity and irreducible water saturation have the lowest and the highest absolute impact values on permeability estimation. The applicability and validity of the developed models are also demonstrated by means of the so-called Williams' method for outliers detection. At last, it is worthwhile mentioning that the created new methods in this study can be good nominees for permeability determination in characterizing the heterogeneous carbonate reservoirs.",14,14,10
Machine Learning,Error,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Machine Learning,Error,"Rashidi, Sina; Mehrad, Mohammad; Ghorbani, Hamzeh; Wood, David A.; Mohamadian, Nima; Moghadasi, Jamshid; Davoodi, Shadfar",Determination of bubble point pressure & oil formation volume factor of crude oils applying multiple hidden layers extreme learning machine algorithms,Oil formation volume factor; Bubble point pressure; Multi-layer extreme learning machine; Hybrid machine learning algorithms; Least squares support vector machine,SUPPORT VECTOR MACHINE; SHEAR-WAVE VELOCITY; PVT PROPERTIES; CORRELATION-COEFFICIENTS; RELATIVE PERMEABILITY; RESERVOIR; PREDICTION; MODEL; SYSTEMS; PERFORMANCE,"An important requirement of reservoir management is to understand the properties of reservoir fluids and dependent phase behaviors. This makes it possible to determine the properties of reservoir fluids in laboratory pressure-volume-temperature (PVT) tests. Such laboratory tests are costly and time consuming, and reservoir data are sometimes not available. When estimating the in-place fluid volumes and/or designing enhanced recovery processes information on bubble point pressure (BPP) and oil formation volume factor (OFVF) is required. Predicting these two parameters is therefore one of the priorities of reservoir engineers. It is becoming increasingly beneficial to be able to predict BPP and OFVF with efficient machine-learning algorithms based on underlying variables that are more easily measured directly in the field. In this study, a dataset of 638 data records of published crude oil fluid samples from around the world is evaluated. After filtering the dataset for outliers, 591 data records for BPP and 599 datasets for OFVF are evaluated with efficient hybrid machinelearning algorithms (multi-layer extreme learning machine ?MELM? and least squares support vector machine ? LSSVM) optimized using a genetic algorithm ?GA? and a particle swarm optimizer ?PSO? to improve their prediction performance. Four underlying variables are considered for each data record: temperature (T), solution gas oil ratio (Rs), gas specific gravity (?g) and oil gravity (API). The PSO- MELM-PSO hybrid algorithm achieved the highest prediction accuracy measured in terms of root mean square errors (RMSE) of 33.5 psi for BPP and 0.0199 for OFVF. The four-hybrid machine-learning-optimization algorithms evaluated all outperform the empirical relationships used for many decades in the oil industry to predict BPP and OFVF.",11,11,1
Machine Learning,Error,"Lu, Hongfang; Iseley, Tom; Matthews, John; Liao, Wei; Azimi, Mohammadamin",An ensemble model based on relevance vector machine and multi-objective salp swarm algorithm for predicting burst pressure of corroded pipelines,Corroded pipeline; Burst pressure; Prediction; Relevance vector machine; Multi-objective salp swarm algorithm; Machine learning,API X70 PIPE; FAILURE PRESSURE; PROBABILISTIC ANALYSIS; INTEGRITY ASSESSMENT; CORROSION DEFECTS; STRENGTH; STEEL; DEPTH; LOAD,"Burst pressure is the key to the design of pressure pipelines, and its accurate prediction is of considerable significance to pipeline safety and integrity management. Due to the different corrosion forms of different pipelines, the traditional empirical formula is difficult to predict the burst pressure with high accuracy. This paper proposes an ensemble data-driven model that can train the model based on existing pipeline parameters, corrosion characteristics, and burst pressure data. The trained model can be used to predict the burst pressure of pipelines with other pipeline parameters and corrosion characteristics. In the ensemble model design, a more advanced machine learning model, relevance vector machine, is used as the basic predictor. Multi-objective salp swarm algorithm is utilized to optimize the relevance vector machine, to improve the prediction accuracy and stability. The proposed model is applied to three datasets with different features and inputs. The results reveal that the average absolute percent errors of the proposed model in the three datasets are 3.724%, 1.788%, and 4.133%, respectively, and the standard deviations of the percentage errors are 9.07%, 2.36%, and 5.42%, respectively, which are all in a low level. The results indicate that the proposed model has high prediction accuracy and stability in different datasets, even when the data amount is small. Moreover, the Diebold-Mariano test implies that the proposed model's prediction performance is better than benchmark models, and much better than the model without the optimizer or with the single-objective optimizer.",9,9,5
Machine Learning,Error,"Lashari, Najeebullah; Ganat, Tarek; Otchere, Daniel; Kalam, Shams; Ali, Imtiaz",Navigating viscosity of GO-SiO2/HPAM composite using response surface methodology and supervised machine learning models,Chemical; Polymeric composite material; Nanoparticles; Response surface methodology; Rheology; Supervised machine learning,ENHANCED OIL-RECOVERY; POLYACRYLAMIDE; TEMPERATURE; RHEOLOGY; NETWORK; WATER; FIELD,"This paper presents the use of response surface methodology (RSM) and robust supervised machine learning approaches to model nano-polymeric viscosity. In the absence of studies in the previous research on using these two techniques, this study's key objective was to equate these strategies' efficiency with a nano-polymer solution's viscosity modelling. Synthesized nano-polymer composite is characterized by scanning electron microscope, transmission electron microscope, X-ray diffraction, and thermogravimetric analysis. The research used the Split-Plot Central Composite Design (SP-CCD) of RSM to model five independent parameters for nanopolymeric composite viscosity, namely shear rate, temperature, and concentration nanoparticles, sodium chloride, and calcium chloride. The findings indicate that the polymer solution's viscosity was not equally crucial to all parameters. Besides, a variance analysis (ANOVA) was conducted, and no evidence of inadequacy in the RSM model was provided. The comparative study of the conventional central composite design model and the supervised machine learning model was conducted. The split-plot central composite model gave R2 of 92% and adjusted R2 of 88%. Amongst all supervised machine learning models used, the XGBoost model recorded the highest R2 accuracy of 90% and lowest prediction errors in terms of mean absolute error and root mean square error. XGBoost when compared to other models in terms of akaike information criterion had the highest likelihood of fit making it the best option in analyzing rheological behavior for hybrid polymeric nanofluid.",6,6,5
Machine Learning,Error,"Mousazadeh, Fatemeh; Naeem, Mohammad Hossein Towfighi; Daneshfar, Reza; Soulgani, Bahram Soltani; Naseri, Maryam",Predicting the condensate viscosity near the wellbore by ELM and ANFIS-PSO strategies,Viscosity; Gas condensate; Extreme learning machine; Machine learning; Particle swarm optimization,EXTREME LEARNING-MACHINE; DEW-POINT PRESSURE; GAS; DENSITY; SYSTEMS; MIXTURES; METHANE; MODELS; DECANE; STATE,"By lowering the pressure beneath the dew point as the result of production in gas condensate (GC) reservoirs, liquid droplets are formed in the borehole zone. Accurate calculation of pressure decline and optimization operations in these reservoirs need to know and predict the specific properties such as liquid viscosity. Empirical models have already been developed to predict this parameter. Due to the peculiar behavior of fluids beneath the dew point pressure (DPP), the prediction of liquid viscosity associates with an error. With the development of machine learning (ML) approaches, studies on fluid properties like other sciences have entered a new phase. In this study, extreme learning machine (ELM) and adaptive neuro-fuzzy inference system with particle swarm optimization (ANFIS-PSO) methods applied to this end. Therefore, a large data bank of reservoir and fluid properties including reservoir temperature and pressure, specific gravity (SG) of gas, API gravity, and gas to oil ratio (Rs) were used. The results showed that R-squared and RMSE for ANFIS-PSO are 0.762 and 0.15, respectively, while these values are 0.941 and 0.06 for ELM which shows that the last model has a better performance in estimating output values. Also, the range of reliable data is determined, and further, a sensitivity analysis was done, which showed that the greatest impact on the viscosity was from SG, and API gravity has the least effect on it. This model can be used as a reference for calculating condensate viscosity and also by expanding the range of datasets, it can be applied in the commercial software.",6,6,0
Machine Learning,Error,"Luo, Xiaodong; Lorentzen, Rolf J.; Bhakta, Tuhin",Accounting for model errors of rock physics models in 4D seismic history matching problems: A perspective of machine learning,Seismic history matching; Iterative ensemble smoother; Model errors; Residual model; Machine learning,ADAPTIVE LOCALIZATION; ENSEMBLE SMOOTHER; FIELD MODEL; PARAMETERS; SCALE; FLUID,"Model errors are ubiquitous in practical history matching problems. A common approach in the literature to accounting for model errors is to treat them as random variables following certain presumed distributions. While such a treatment renders algorithmic convenience, its underpinning assumptions are often invalid. In this work, we adopt an alternative approach, and treat model-error characterization as a functional approximation problem, which can be solved using a generic machine learning method. We then integrate the proposed model-error characterization approach into an ensemble-based history matching framework, and show that, with very minor modifications, existing ensemble-based history matching algorithms can be readily deployed to solve the history matching problem in the presence of model errors. To demonstrate the efficacy of the integrated history matching framework, we apply it to account for potential model errors of a rock physics model in 4D seismic history matching applied to the full Norne benchmark case. The numerical results indicate that the proposed model-error characterization approach helps improve the qualities of estimated reservoir models, and leads to more accurate forecasts of production data. This suggests that accounting for model errors from a perspective of machine learning serves as a viable way to deal with model imperfection in practical history matching problems.",5,5,0
Machine Learning,Error,"Blanes de Oliveira, Lucas Abreu; Carneiro, Cleyton de Carvalho",Synthetic geochemical well logs generation using ensemble machine learning techniques for the Brazilian pre-salt reservoirs,Neutron-induced spectroscopy; Gamma ray spectroscopy; Formation evaluation; Artificial intelligence,GAMMA-RAY SPECTROSCOPY; MINERALOGY,"Geochemical logs are an essential tool for hydrocarbon reservoir characterization. The rock composition given by these logs is useful for porosity calculation, stratigraphic modeling, diagenesis estimation, and well acidification. In reduced logging operations performed in carbonate reservoirs of the Brazilian pre-salt, the geochemical tool is no longer acquired, aiming at optimization and cost reduction. This research aims the development of synthetic geochemical logs using machine learning algorithms. The database includes 22 wells with complete logging acquisition, and the input logs are natural gamma-ray, gamma-ray spectroscopy, density, photoelectric factor, neutron porosity, nuclear magnetic resonance, and sonic. The chemical elements chosen as output are Al, Ca, Fe, Mg, Na, Si, S, and Ti. Five models based on machine learning are trained using 19 wells: Support-vector machine, Multilayer perceptron, Random Forest, AdaBoost, and XGBoost. AdaBoost represents the best algorithm because, in addition to showing the best results, it allowed for a more simplified preprocessing and hyperparameter tuning. The evaluation of the models applies R-2 and root mean squared error (RMSE) in validation data and cross-validation. Robust models are acquired for Al, Ca, Fe, Mg, Si, S, and Ti, with R-2 above 0.80. Na shows R-2 slightly above 0.70. All the models have RMSE between 10(-2) to 10(-4). The most important logs during training are density, photoelectric factor, K, Th, U, and neutron porosity. Synthetic geochemical logs created for three test wells show a good agreement with acquired logs, being able to reproduce general trends of the pre-salt formations. The machine learning model is capable of substituting the acquisition of geochemical logs with high confidence, representing cost reduction, and supplying engineers and geoscientists with quality data to be used in formation evaluation.",4,4,3
Machine Learning,Error,"Yin, Qishuai; Yang, Jin; Tyagi, Mayank; Zhou, Xu; Wang, Ning; Tong, Gang; Xie, Renjun; Liu, Hexing; Cao, Bohan",Downhole quantitative evaluation of gas kick during deepwater drilling with deep learning using pilot-scale rig data,Gas kick; Downhole quantitative evaluation; Pilot-scale test well experiment; Compressed air injection; Deep-water drilling,,"Gas kick occurs frequently during deep-water drilling operations caused by the lack of safe margin between pore pressure and leakage pressure. The existing research is limited to gas kick classification and cannot quantitatively evaluate the gas kick risk in the downhole very well. Thus, the objective of this work is to systematically use Long Short-Term Memory (LSTM) Recurrent Neural Network (RNN) models based on pilot-scale rig data for quantitative evaluation of gas kick risk. Furthermore, the quantitative evaluation is not surface but downhole. First, the gas kick simulation experiment is accomplished in the pilot-scale test well and produces the gas kick dataset, which is based on the multi-source data fusion through the surface monitoring technologies, riser monitoring technologies and downhole monitoring technologies. Second, the training features are selected and grouped as Sets1-5 to study the features' sensitivity. Third, the raw data is processed and prepared for the following machine learning framework. Fourth, there are five (5) LSTM models trained on Sets1-5. The results indicate that the models' Loss decrease with the increase of feature number, which has fully demonstrated the effectiveness of PWD, EKD, and Doppler parameters. Finally, there are four representative case studies (artificial gas kick) that are used to test the above five models. The compressed air injected rate (AR) prediction error and detection time-delay decrease with the increase of feature number. The LSTM model trained with the combination of surfaceriser-downhole comprehensive detection technologies performs the best in reducing both the prediction error and detection time delay, which could be used to quantitatively evaluate the downhole gas kick risk in the more accurate, faster, more stable, more reliable, and cost-effective manner, and it is effective and worthy of promotion.",3,3,4
Machine Learning,Error,"Maldonado-Cruz, Eduardo; Pyrcz, Michael J.",Tuning machine learning dropout for subsurface uncertainty model accuracy,Numerical simulation; Machine learning; Surrogate modeling; Uncertainty estimation; Hyperparameter optimization; Model goodness,NEURAL-NETWORKS; DEEP,"Machine learning hyperparameter tuning generally relies on minimizing the prediction error and maximizing the accuracy at withheld testing data locations. However, for many subsurface applications, prediction accuracy is not sufficient, and we must consider the goodness, accuracy, and precision, of the entire uncertainty model. Bayesian deep neural networks provide a robust framework to model uncertainty. But at a high computational cost and difficulty to scale in high-dimensional parameter spaces. Dropout offers a potential alternative for calculating prediction model realizations to represent the uncertainty model. We propose a method to compare the entire uncertainty model based on the prediction realizations and the addition of a single objective function, known as uncertainty model goodness, to the loss function to integrate model uncertainty for improved tuning of the dropout frequency in deep learning models. We test our method with a subsurface flow surrogate model based on an image-to-image regression problem. Implementing the proposed method with the uncertainty model goodness results in accurate and precise uncertainty models using the tuned dropout hyperparameter. We test the robustness and generalization of the proposed method with out-of-distribution testing data.",3,3,4
Machine Learning,Error,"Chaikine, Ilia A.; Gates, Ian D.",A machine learning model for predicting multi-stage horizontal well production,Horizontal multistage fracture; Machine learning; Production; Unconventional reservoirs; Hydraulic fracturing; Predictive models,,"In this study, a hybrid convolutional-recurrent neural network (c-RNN) is evaluated for making predictions of the five-year cumulative production profiles in multistage hydraulically fractured wells. The model was trained by using a combinations of completion parameters, rock mechanical properties, and well spacing and completion order for each stage of 74 wells in the Montney Formation in Alberta. The prediction accuracy of the various combinations was measured by using the mean average percent error and mean absolute error generated through the leave-one-out method. The best combination of inputs was found to be the rock mechanical properties surrounding each perforation cluster, the proppant amount used for every stage, and the spacing and completion order of neighboring wells. The novelty of this study is that the input variables used are at the stage level rather than the average of the entire well. The accuracy of the model was found to increase exponentially as the production of multiple wells was aggregated. The approach yields insights for planning new well drills in fields with existing development since it provides the ability to run multiple field development scenarios without having to spend capital.",3,3,3
Machine Learning,Well Logs,"Ali, Muhammad; Jiang, Ren; Ma, Huolin; Pan, Heping; Abbas, Khizar; Ashraf, Umar; Ullah, Jar",Machine learning-A novel approach of well logs similarity based on synchronization measures to predict shear sonic logs,Machine learning; Geophysical similarity analysis; Multidimensional scaling; Jaccard and Overlap similarities; Well logs,,"This study proposes a novel approach to predict missing shear sonic log responses more precisely and accurately using similarity patterns of various wells with similar geophysical properties, which is important in decision making and planning of hydrocarbon exploration. Deep Neural Network (DNN) along with the similarity metrics such as Jaccard and Overlap similarities are employed to examine the relationship between the wells. Further, dimensionality reduction techniques including Multi-Dimensional Scaling (MDS) and well-ranking process are applied to extract common geophysical responses of the wells. A higher response indicates the existence of a strong similarity. This can also be verified by the superimposed of well log data. The potential benefits of our novel method are following; (a) it does not follow the zone-by-zone prediction of the missing logs such as rock physics methods, (b) it outputs the uncertainties facilitated that is by the least-squares method. Having the potential of demonstrating shear sonic log prediction in hydrocarbon-bearing zones, which cannot be precisely predicted by the Greenberg-Castagna method that only works in brine-saturated rocks, this approach will provide improved accuracy, where shear sonic logs are missing and need to be predicted for geomechanics, rock physics, and other applications.",10,10,5
Machine Learning,Well Logs,"Alzubaidi, Fatimah; Mostaghimi, Peyman; Swietojanski, Pawel; Clark, Stuart R.; Armstrong, Ryan T.",Automated lithology classification from drill core images using convolutional neural networks,Convolutional neural networks; Deep learning; Lithology logs; Core analysis,FACIES ANALYSIS; WELL LOGS; PREDICTION; LITHOFACIES,"In hydrocarbon reservoir evaluation, lithology is a key characteristic for determination of storage capacity and rock properties. Lithology is usually predicted from well log data or directly identified through manual inspection by geologists during core logging. Automatic prediction of lithology has been a focus of many studies inspired by rapid developments in machine learning. Studies mostly focus on predicting lithofacies from well logs using neural networks, and more recently from borehole image logs using convolutional neural network (CNN). Although core is more representative of reservoir lithology than well log data, employing machine learning for automatic lithology identification from core is limited. A CNN-based approach is developed to classify core images into three lithologies: sandstone, limestone, and shale. The model is based on ResNeXt-50 architecture, which had better performance in lithology prediction than ResNet-18 and Inception-v3 architectures. Our method processes core tray images and outputs lithology logs in a fully automated procedure and predicts the lithologies of new (unseen) core with an accuracy of 93.12%.",9,11,13
Machine Learning,Well Logs,"Mahmoud, Ahmed Abdulhamid; Elkatatny, Salaheldin; Al-AbdulJabbar, Ahmad",Application of machine learning models for real-time prediction of the formation lithology and tops from the drilling parameters,Formation lithology; Formation tops; Machine learning; Real-time; Drilling parameters,NEURAL-NETWORKS; LOG DATA; PENETRATION; RESERVOIRS,"Lithology changes significantly affect the drilling program and the total cost of drilling an oil well, therefore, it is very important to detect the lithology variation and formation tops while drilling. Nowadays, the lithology changes are estimated from the geological data, which increases the uncertainty, especially during the exploration phase because of the data limitation. This study investigates the ability to use three machine learning models, namely, the artificial neural networks (ANN), adaptive neuro-fuzzy inference system (ANFIS), and functional neural networks (FNN) to predict the lithology changes and the formation tops in real-time while drilling. These models were trained on 3162 datasets of six inputs (drilling parameters) to enable real-time prediction of the lithology changes and formation tops through four different formations of sandstone at top, followed by anhydrite, then carbonate with shale streaks, and finally carbonate formation. The optimized models were then tested on 1356 datasets gathered from a well other than the training well. The results of this study confirmed the high accuracy of the optimized ANN model which outperformed both ANFIS and FNN models in predicting the actual lithology distribution and formation tops through both training and testing wells. The ANN model predicted the different four formations considered in this study with an accuracy of more than 98.1% for training and testing data. Although the ANFIS and FNN models predicted the carbonate/shale formation top accurately for the training data, they were not able to predict the top of all formations accurately for the testing data.",7,7,3
Machine Learning,Well Logs,"Yasin, Qamar; Sohail, Ghulam Mohyuddin; Khalid, Perveiz; Baklouti, Syrine; Du, Qizhen","Application of machine learning tool to predict the porosity of clastic depositional system, Indus Basin, Pakistan",Seismic inversion; Support vector machine; Rock physics; Porosity; Particle swarm optimization; Sawan gas field,SAWAN GAS-FIELD; KRISHNA-GODAVARI BASIN; SEISMIC ATTRIBUTES; MULTIATTRIBUTE TRANSFORMS; ROCK PHYSICS; WELL LOGS; RESERVOIR; SHALE; INVERSION; MODEL,"Porosity is one of the key factors of a reservoir system that is typically distributed in a spatially non-uniform and non-linear manner. Nevertheless, spatial distribution of porosity in stratigraphic traps (channel sand bodies) is challenging due to the variations in depositional environments, shale intercalation, and repetition of textural changes in the pore sizes. This paper presents a strategy of joint inversion that combines support vector machine (SVM) and particle swarm optimization (PSO) algorithms to predict the spatial distribution of porosity using well logs and seismic data. In addition, Gaussian simulation algorithms (sequential Gaussian and Gaussian indicator simulations) were used to predict lithology and porosity distribution using wireline logs and core data. Rock physics modeling was performed to bridge the gap between the elastic and petrophysical properties for seismic-inversion based reservoir characterization. The results show that the joint inversion strategy leads to the most stable prediction of AI and porosity distribution in the lower Goru heterogeneous reservoir of Sawan Gas Field, Pakistan. The calibration of the individual spatial distribution of lithology and porosity from wireline logs data using Gaussian simulation algorithms and post-stack seismic inversion using SVM and PSO; revealed favorable matching. In fact, the spatial pattern of low AI corresponds with the high porosity and sandstone lithofacies. The study results provide valuable insights for identifying the sweet spots in the heterogeneous lower Goru clastic packages of Sawan Gas Field through quantitative analysis of rock physics, petrophysics, seismic inversion, and fuzzy optimization. The proposed joint inversion strategy may be considered useful for the prediction of porosity in similar context of extremely heterogeneous stratigraphic traps in other basins of the world.",6,6,8
Machine Learning,Well Logs,"Feng, Runhai",Improving uncertainty analysis in well log classification by machine learning with a scaling algorithm,Machine learning; Uncertainty analysis; Platt scaling; Reliability diagram,RESERVOIR; LITHOFACIES; IDENTIFICATION,"Uncertainty is an important indicator that can provide the confidence in the predictions. However, most machine learning methods in classification problems are incapable of predicting an accurate probability that matches the observed distribution of each class. To overcome this problem and improve the uncertainty analysis in lithofacies classification, a novel calibration process is performed on the validation subset using scaling algorithms. The validation subset should be separated from the training data in order to reduce overfitting and avoid unwanted biases. Random forest is selected as the machine learning classifier owing to its relative ease of use, and can handle high-dimensional input features quite well. The proposed approach is applied to two real datasets to demonstrate the improvement in the uncertainty quantification. Reliability diagram shows that the calibrated probability is closer to the diagonal truth, compared with the uncalibrated one. In addition to the visual check, a multiclass Brier score of calibrated model is lower than that by uncalibrated system, which can be referred to as a loss function. For the classification results by calibrated and uncalibrated classifiers on the testing subset, an increase of the Matthews correlation coefficient also means that the calibrated model has a better performance.",6,6,0
Machine Learning,Well Logs,"Sun, Jian; Chen, Mingqiang; Li, Qi; Ren, Long; Dou, Mengyuan; Zhang, Jixuan",A new method for predicting formation lithology while drilling at horizontal well bit,Logging while drilling; Machine learning; Real-time interpretation; Lithology prediction,IDENTIFICATION; CLASSIFICATION; ALGORITHMS,"The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of ""zero length"" (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the ""zero length"" on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.",4,5,3
Machine Learning,Well Logs,"Blanes de Oliveira, Lucas Abreu; Carneiro, Cleyton de Carvalho",Synthetic geochemical well logs generation using ensemble machine learning techniques for the Brazilian pre-salt reservoirs,Neutron-induced spectroscopy; Gamma ray spectroscopy; Formation evaluation; Artificial intelligence,GAMMA-RAY SPECTROSCOPY; MINERALOGY,"Geochemical logs are an essential tool for hydrocarbon reservoir characterization. The rock composition given by these logs is useful for porosity calculation, stratigraphic modeling, diagenesis estimation, and well acidification. In reduced logging operations performed in carbonate reservoirs of the Brazilian pre-salt, the geochemical tool is no longer acquired, aiming at optimization and cost reduction. This research aims the development of synthetic geochemical logs using machine learning algorithms. The database includes 22 wells with complete logging acquisition, and the input logs are natural gamma-ray, gamma-ray spectroscopy, density, photoelectric factor, neutron porosity, nuclear magnetic resonance, and sonic. The chemical elements chosen as output are Al, Ca, Fe, Mg, Na, Si, S, and Ti. Five models based on machine learning are trained using 19 wells: Support-vector machine, Multilayer perceptron, Random Forest, AdaBoost, and XGBoost. AdaBoost represents the best algorithm because, in addition to showing the best results, it allowed for a more simplified preprocessing and hyperparameter tuning. The evaluation of the models applies R-2 and root mean squared error (RMSE) in validation data and cross-validation. Robust models are acquired for Al, Ca, Fe, Mg, Si, S, and Ti, with R-2 above 0.80. Na shows R-2 slightly above 0.70. All the models have RMSE between 10(-2) to 10(-4). The most important logs during training are density, photoelectric factor, K, Th, U, and neutron porosity. Synthetic geochemical logs created for three test wells show a good agreement with acquired logs, being able to reproduce general trends of the pre-salt formations. The machine learning model is capable of substituting the acquisition of geochemical logs with high confidence, representing cost reduction, and supplying engineers and geoscientists with quality data to be used in formation evaluation.",4,4,3
Machine Learning,Well Logs,"Zahmatkesh, Iman; Kadkhodaie, Ali; Soleimani, Bahman; Azarpour, Moslem","Integration of well log-derived facies and 3D seismic attributes for seismic facies mapping: A case study from mansuri oil field, SW Iran",Seismic facies analysis; Seismic attributes; Well log facies; Reservoir quality; Asmari reservoir; Supervised neural network,MULTIATTRIBUTE TRANSFORMS; GAS-FIELD; CLASSIFICATION; RESERVOIR; CARBONATE; MACHINE; IDENTIFICATION; PARAMETERS; EXAMPLE; PART,"The recognition and mapping of rock facies is a pivotal step in reliable reservoir characterization and planning development operations. The present study aimed to present a practical workflow by integrating threedimensional (3D) seismic attributes and well-log facies analysis to determine the spatial distribution of electrofacies rock types of the Oligo-Miocene Asmari reservoir in Mansuri oilfield located in the southwestern part of Iran. The workflow begins with integrating well logs, core data, and geological information from the selected ?key wells? to build an electrofacies model, which could help reservoir facies to be classified and estimated in the cored and uncored wells, respectively. In addition, a group of 3D seismic attribute volumes derived from amplitude, frequency, and time characteristics of the post-stacked 3D seismic data were identified to specify the heterogeneity of the vertical and lateral rock facies within the reservoir. Additionally, the seismic attributes were analyzed using unsupervised and supervised learning techniques to identify seismic facies. The extraction of the seismic facies at multiple-well locations within the 3D classified volumes demonstrated that the supervised neural network learning method, as compared to the unsupervised approach, could more accurately estimate the desired seismic facies. The results of the ultimate rock facies maps of different vertical slices in the Asmari reservoir indicated that electrofacies with good reservoir quality were best developed on the top of the reservoir, mostly with NW-SE elongation at the crest line of the structure. The applied workflow allowed the localities of the buried sand channels to be identified and mapped. Accordingly, seismic facies mapping shed light on the spatial heterogeneity and quality of the reservoir, which could be used to guide the development drilling for optimal recovering of the unswept hydrocarbons.",4,4,3
Machine Learning,Support Vector Machine,"Otchere, Daniel Asante; Ganat, Tarek Omar Arbi; Gholami, Raoof; Ridha, Syahrir",Application of supervised machine learning paradigms in the prediction of petroleum reservoir properties: Comparative analysis of ANN and SVM models,Artificial intelligence (AI); Supervised machine learning; Artificial neural network (ANN); Support vector machine (SVM); Relevance vector machine (RVM); Hybrid intelligent system,,"The advent of Artificial Intelligence (AI) in the petroleum industry has seen an increase in its use in exploration, development, production, reservoir engineering and management planning to accelerate decision making, reduce cost and time. Supervised machine learning has gained much popularity in establishing a relationship between complex non-linear datasets. This type of machine learning algorithm has showcased its superiority over petroleum engineering regression techniques in terms of prediction errors for high dimensional data, computational power and memory. This review focuses on the most widely used machine learning algorithm employed in the petroleum industry, the Artificial Neural Network (ANN) with different shallow models used in reservoir characterisation. The Support Vector Machine (SVM) and Relevant Vector Machine (RVM) has over the years emerged as competitive algorithms where in most cases based on this review it outperformed the ANN. This makes it preferable than the ANN when there are limited data sets. Finally, hybridisation of multiple algorithms methodologies also showed improved performance over singularly applied algorithms offering a pathway in improving reservoir characterisation based on supervised machine learning as future scope of work.",20,20,14
Machine Learning,Support Vector Machine,"Sabah, Mohammad; Mehrad, Mohammad; Ashrafi, Seyed Babak; Wood, David A.; Fathi, Shadi",Hybrid machine learning algorithms to enhance lost-circulation prediction and management in the Marun oil field,Lost circulation while drilling; Multilayer perception; Least square support vector machine; Evolutionary algorithms; Marun oil field,ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINE; MULTILAYER PERCEPTRON; OPTIMIZATION; MODELS; RESERVOIR; ASMARI,"Drilling fluid loss of circulation is a challenging issue to resolve for many oil and gas wells as drilling progresses. It imposes enormous expenses on drilling industry. One of the common practices to solve this problem or make it less severe is introducing various loss circulation materials (LCM) into the circulating drilling fluid. The ability to predict the amount of mud loss before drilling a particular formation would provide engineers with invaluable information to assist them in selecting appropriate LCM properties such as particle size distribution. In this study, a number of heuristic search algorithms including genetic algorithm (GA), particle swarm size (PSO), and cuckoo search algorithm (COA) are combined with two machine-learning techniques namely multilayer perception (MLP) neural network and least square support vector machine (LSSVM) to present different hybrid algorithms in prediction of lost circulation. The established database consists of 2820 cases (datasets) extracted from available drilling reports of 305 drilled wells in the Marun oil field. These datasets are associated with drilling operation variables, formation specifications, and drilling mud characteristics which totally include 18 input variables and 1 output. Pre-processing of data involves filtering with Savitzky-Golay (SG) filter and ranking features using wrapper method. Results show that hybrid intelligent models are highly capable of predicting lost circulation before drilling a certain formation. Furthermore, LSSVM-COA and LSSVM-PSO achieve coefficients of determination of 0.9424 and 0.9391, respectively, making them the two most accurate models. GA cannot match the prediction performance of the other two algorithms in enhancing machine-learning techniques for this purpose. MLP-GA with a coefficient of determination (R-2) and RMSE of 0.9304 and 25.26 (bbl/hr), respectively, yields the weakest prediction performance. Hybrid intelligent models, coupling optimizers and machine learning algorithms show themselves to be superior to applying standalone machine-learning methodologies for predicting loss of circulation.",13,13,6
Machine Learning,Support Vector Machine,"Rashidi, Sina; Mehrad, Mohammad; Ghorbani, Hamzeh; Wood, David A.; Mohamadian, Nima; Moghadasi, Jamshid; Davoodi, Shadfar",Determination of bubble point pressure & oil formation volume factor of crude oils applying multiple hidden layers extreme learning machine algorithms,Oil formation volume factor; Bubble point pressure; Multi-layer extreme learning machine; Hybrid machine learning algorithms; Least squares support vector machine,SUPPORT VECTOR MACHINE; SHEAR-WAVE VELOCITY; PVT PROPERTIES; CORRELATION-COEFFICIENTS; RELATIVE PERMEABILITY; RESERVOIR; PREDICTION; MODEL; SYSTEMS; PERFORMANCE,"An important requirement of reservoir management is to understand the properties of reservoir fluids and dependent phase behaviors. This makes it possible to determine the properties of reservoir fluids in laboratory pressure-volume-temperature (PVT) tests. Such laboratory tests are costly and time consuming, and reservoir data are sometimes not available. When estimating the in-place fluid volumes and/or designing enhanced recovery processes information on bubble point pressure (BPP) and oil formation volume factor (OFVF) is required. Predicting these two parameters is therefore one of the priorities of reservoir engineers. It is becoming increasingly beneficial to be able to predict BPP and OFVF with efficient machine-learning algorithms based on underlying variables that are more easily measured directly in the field. In this study, a dataset of 638 data records of published crude oil fluid samples from around the world is evaluated. After filtering the dataset for outliers, 591 data records for BPP and 599 datasets for OFVF are evaluated with efficient hybrid machinelearning algorithms (multi-layer extreme learning machine ?MELM? and least squares support vector machine ? LSSVM) optimized using a genetic algorithm ?GA? and a particle swarm optimizer ?PSO? to improve their prediction performance. Four underlying variables are considered for each data record: temperature (T), solution gas oil ratio (Rs), gas specific gravity (?g) and oil gravity (API). The PSO- MELM-PSO hybrid algorithm achieved the highest prediction accuracy measured in terms of root mean square errors (RMSE) of 33.5 psi for BPP and 0.0199 for OFVF. The four-hybrid machine-learning-optimization algorithms evaluated all outperform the empirical relationships used for many decades in the oil industry to predict BPP and OFVF.",11,11,1
Machine Learning,Support Vector Machine,"Yasin, Qamar; Sohail, Ghulam Mohyuddin; Khalid, Perveiz; Baklouti, Syrine; Du, Qizhen","Application of machine learning tool to predict the porosity of clastic depositional system, Indus Basin, Pakistan",Seismic inversion; Support vector machine; Rock physics; Porosity; Particle swarm optimization; Sawan gas field,SAWAN GAS-FIELD; KRISHNA-GODAVARI BASIN; SEISMIC ATTRIBUTES; MULTIATTRIBUTE TRANSFORMS; ROCK PHYSICS; WELL LOGS; RESERVOIR; SHALE; INVERSION; MODEL,"Porosity is one of the key factors of a reservoir system that is typically distributed in a spatially non-uniform and non-linear manner. Nevertheless, spatial distribution of porosity in stratigraphic traps (channel sand bodies) is challenging due to the variations in depositional environments, shale intercalation, and repetition of textural changes in the pore sizes. This paper presents a strategy of joint inversion that combines support vector machine (SVM) and particle swarm optimization (PSO) algorithms to predict the spatial distribution of porosity using well logs and seismic data. In addition, Gaussian simulation algorithms (sequential Gaussian and Gaussian indicator simulations) were used to predict lithology and porosity distribution using wireline logs and core data. Rock physics modeling was performed to bridge the gap between the elastic and petrophysical properties for seismic-inversion based reservoir characterization. The results show that the joint inversion strategy leads to the most stable prediction of AI and porosity distribution in the lower Goru heterogeneous reservoir of Sawan Gas Field, Pakistan. The calibration of the individual spatial distribution of lithology and porosity from wireline logs data using Gaussian simulation algorithms and post-stack seismic inversion using SVM and PSO; revealed favorable matching. In fact, the spatial pattern of low AI corresponds with the high porosity and sandstone lithofacies. The study results provide valuable insights for identifying the sweet spots in the heterogeneous lower Goru clastic packages of Sawan Gas Field through quantitative analysis of rock physics, petrophysics, seismic inversion, and fuzzy optimization. The proposed joint inversion strategy may be considered useful for the prediction of porosity in similar context of extremely heterogeneous stratigraphic traps in other basins of the world.",6,6,8
Machine Learning,Support Vector Machine,"Li, Chunxiao; Wang, Dongmei; Kong, Lingyun",Application of Machine Learning Techniques in Mineral Classification for Scanning Electron Microscopy - Energy Dispersive X-Ray Spectroscopy (SEM-EDS) Images,Mineral segmentation; Machine learning; SEM-EDS; U-net; The Bakken Formation,,"Mineral classification and segmentation is time-consuming in geological image processing. The development of machine learning methods shows promise as a technique in replacing manual classification. In this study, performances of five shallow machine classification algorithms and a deep learning algorithm were compared for the goal of pixel-level mineral classification of Scanning Electron Microscopy - Energy Dispersive X-Ray Spectroscopy (SEM-EDS) images. Five machine learning models, including Logistic Regression (LR), Linear Support Vector Machine (SVM), k-Nearest Neighbor (k-NN), Random Forest (RF), and Artificial Neuron Networks (ANN), and a deep learning CNN U-Net model were used in this study. Thirteen mineral phases were classified on SEMEDS images of a shale sample taken from the Bakken Formation. Hyperparameters of models were tuned using a grid-search method. Randomly selected balanced dataset was used for the shallow models, while the original cropped images were used for the U-Net. The experimental results showed that all classification algorithms resulted in high F1 scores ranging from 0.86 to 0.92. The RF demonstrated the best performance among the five machine learning models, with an F1 score of 0.92. Additionally, sensitivity analysis on the size of dataset demonstrated that the LR algorithm and the SVM were less sensitive to the dataset reduction, while the models of k-NN, RF, and ANN were more influenced. Sensitivity analysis of noise suggested that noises added on the element of Silicon, Aluminum, Magnesium, Calcium, Potassium, and Iron would decrease the performance of the RF. Furthermore, the noise in Silicon had the greatest effect on the prediction result compared to the other minerals. In addition, those non-linear classifiers showed a larger performance score drop when the noise was simultaneously included into all the elements density. Though U-Net shows poor performance on the segmentation of minority classes due to the negative effect of imbalanced dataset the U-Net model still outperformed the RF model when it comes to unseen shale samples.",6,6,5
Machine Learning,Support Vector Machine,"Sun, Jian; Chen, Mingqiang; Li, Qi; Ren, Long; Dou, Mengyuan; Zhang, Jixuan",A new method for predicting formation lithology while drilling at horizontal well bit,Logging while drilling; Machine learning; Real-time interpretation; Lithology prediction,IDENTIFICATION; CLASSIFICATION; ALGORITHMS,"The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of ""zero length"" (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the ""zero length"" on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.",4,5,3
Machine Learning,Support Vector Machine,"Zhang, Guoyin; Wang, Zhizhang; Mohaghegh, Shahab; Lin, Chengyan; Sun, Yanan; Pei, Shengjie",Pattern visualization and understanding of machine learning models for permeability prediction in tight sandstone reservoirs,Permeability; Machine learning; Residual neural networks; Predictive pattern; Sensitivity analysis; Wireline logs,ARCHITECTURE; DEPRESSION; NETWORK; DESIGN; LOG,"Permeability prediction is a key and difficult task in hydrocarbon reservoir characterization. Machine learning has long been studied for permeability prediction using porosity and wireline logs but has not been widely accepted and applied in real cases because it is always treated as a Black Box and hard to interpret. In this paper, we propose novel approaches called univariate predictive pattern (UPP) and bivariate predictive pattern (BPP) to visualize predictive patterns learned by machine learning models. Machine learning models for permeability prediction are built in advance, including support vector regression (SVR), random forest (RF), and deep residual neural network (ResNet). The visualized predictive patterns show that ResNet learns the best-fitted nonlinear porosity-permeability relationships from the training dataset, which explains why ResNet achieves the best performance in permeability prediction in the scenario with porosity and wireline logs as input features. Wireline logs provide information about pore structure and contribute differently in machine learning models according to the visualized predictive patterns and quantitative sensitivity analysis. The proposed approach provides us a way to get a glimpse of the Black Box of machine learning models, and is also helpful in sensitivity analysis, feature selection, and model optimization for permeability prediction.",3,3,8
Machine Learning,Data-driven Model,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Machine Learning,Data-driven Model,"Lu, Hongfang; Iseley, Tom; Matthews, John; Liao, Wei; Azimi, Mohammadamin",An ensemble model based on relevance vector machine and multi-objective salp swarm algorithm for predicting burst pressure of corroded pipelines,Corroded pipeline; Burst pressure; Prediction; Relevance vector machine; Multi-objective salp swarm algorithm; Machine learning,API X70 PIPE; FAILURE PRESSURE; PROBABILISTIC ANALYSIS; INTEGRITY ASSESSMENT; CORROSION DEFECTS; STRENGTH; STEEL; DEPTH; LOAD,"Burst pressure is the key to the design of pressure pipelines, and its accurate prediction is of considerable significance to pipeline safety and integrity management. Due to the different corrosion forms of different pipelines, the traditional empirical formula is difficult to predict the burst pressure with high accuracy. This paper proposes an ensemble data-driven model that can train the model based on existing pipeline parameters, corrosion characteristics, and burst pressure data. The trained model can be used to predict the burst pressure of pipelines with other pipeline parameters and corrosion characteristics. In the ensemble model design, a more advanced machine learning model, relevance vector machine, is used as the basic predictor. Multi-objective salp swarm algorithm is utilized to optimize the relevance vector machine, to improve the prediction accuracy and stability. The proposed model is applied to three datasets with different features and inputs. The results reveal that the average absolute percent errors of the proposed model in the three datasets are 3.724%, 1.788%, and 4.133%, respectively, and the standard deviations of the percentage errors are 9.07%, 2.36%, and 5.42%, respectively, which are all in a low level. The results indicate that the proposed model has high prediction accuracy and stability in different datasets, even when the data amount is small. Moreover, the Diebold-Mariano test implies that the proposed model's prediction performance is better than benchmark models, and much better than the model without the optimizer or with the single-objective optimizer.",9,9,5
Machine Learning,Data-driven Model,"Ali, Naseem; Viggiano, Bianca; Tutkun, Murat; Cal, Raul Bayoan",Data-driven machine learning for accurate prediction and statistical quantification of two phase flow regimes,Reduced model; System identification; BI-LSTM; Transfer function,FEEDBACK-CONTROL; IDENTIFICATION,Two different two-phase flow regimes including slug and dispersed flows are examined through the implementation of system identification methods to attain reduced-order models. The obtained models accurately capture the flow dynamics of the studied regimes. The models also provide state-space frequency by defining the transfer functions. The system identification results are compared with those of the bidirectional neural network to predict the phase fraction of the considered two-phase flows. The result of long short-term memory shows correlations of 91% between the real and predicted phase fractions.,5,5,6
Machine Learning,Data-driven Model,"Deng, Lichi; Pan, Yuewei",Data-driven proxy model for waterflood performance prediction and optimization using Echo State Network with Teacher Forcing in mature fields,Data-driven proxy model; Echo state network; Teacher forcing; Machine learning; Waterflood; Optimization,,"Waterflood has been widely applied across the world as the most important secondary recovery process to improve reservoir performance. The schemes applied to waterflood projects involve key decision-making which aims to maximize the net present value (NPV) for a given period, improve recovery and sweep efficiency, maintain reservoir pressure, reduce water production, and avoid water recycling. Traditionally, the preferred approach to estimate the future performance of any given waterflood project is through the numerical reservoir simulation. However, despite the great power and intuition associated with the simulation models, sometimes this potential is unachievable due to massive computational requirements. Also, in some other cases, there may exist no simulation model to begin with. To tackle these problems, data-driven proxy models are proposed. In this research, we propose a novel machine-learning-based proxy model for waterflood performance prediction and further apply it for production optimization purpose to obtain the optimal future well control. The data-driven model is realized using the Echo State Network (ESN) under the paradigm of ""Reservoir Computing"" (RC). Compared with traditional ESNs, this specific methodology includes a feedback loop from the output into the high dimensional ""reservoir"" to achieve improved prediction results for separated phase production rates. Teacher Forcing (TF) technique is used for easier incorporation of the feedback information without introducing additional recurrent loops during the training process. Furthermore, training ESN proxy models utilizes Ridge Regression, thus all calculations within have analytical solutions that guarantee much improved speed when evaluating forward model-runs, which further lowers the computational demand during the optimization process. The proposed workflow is typically more suitable for mature fields since reliable production data after breakthrough from each producer could greatly improve the training process, and it can be used under the circumstance where no reservoir model has been established. In this research, we present two test examples where we apply ESN to learn the reservoir simulation results of waterflood and further perform open-loop optimization on each of them.",5,5,2
Machine Learning,Data-driven Model,"Alali, Ammar M.; Abughaban, Mahmoud F.; Aman, Beshir M.; Ravela, Sai",Hybrid data driven drilling and rate of penetration optimization,ROP; Optimization; Data-driven; Machine learning; Drilling mechanics; Real time adjustments,PREDICTION; INVERSION; ROP,"Optimizing the drilling process for cost and efficiency requires faster drilling with a higher rate of penetration (ROP). A high ROP usually indicates fast and cost-efficient drilling operations; however, high ROPs may induce unintended events, which may lead to nonproductive time (NPT). In this paper, the proposed hybrid, data-driven optimization system aims to improve the drilling process, maximize the ROP, and minimize NPT. This two-phase system leverages existing drilling data (Phase One) and real-time adjustments (Phase Two) to optimize drilling efficiency through the adjustment of controllable dynamic drilling parameters; weight on bit (WOB), pump flow rate (GPM), and rotary speed (RPM). In the first phase, geological data is queried to generate a model of drilling best practices in a certain field with attention to ROP and NPT. After the top-rated wells are identified, the model recommends adjustments to the controllable dynamic drilling parameters (WOB, GPM, RPM) and produces a cross-plot for each ROP. The optimum ROP parameter for each well is subsequently calculated as a conditioned mean based on proximity to the well as an Inverse Distance Weighting (IDW) interpolation. This phase is completed prior to any drilling activity. The second phase considers the model produced in phase one to run an automated drill-off test. The model directs the driller to deviate for controllable parameters WOB and RPM by a small percentage (0-5%), in a Constrained Random Search (CRS) way. These deviations allow the driller to explore new drilling conditions in small increments; the data is then compiled into a heat-map function of ROP and the model is updated to reflect optimum drilling parameters. The adjustments resulted in faster, safer ROP with a potential 22%+ improvement in efficiency and 15-20% cost-reduction. Lastly, to characterize the relationship between the controllable dynamic parameters (WOB, RPM, GPM) to the ROP, an ANN based empirical relationship was derived.",3,3,8
Machine Learning,Data-driven Model,"Tunkiel, Andrzej T.; Sui, Dan; Wiktorski, Tomasz",Training-while-drilling approach to inclination prediction in directional drilling utilizing recurrent neural networks,Directional drilling; Machine learning; Continuous learning; Inclination prediction,MACHINE; ENSEMBLE; MODELS,"Machine Learning adoption within drilling is often impaired by the necessity to train the model on data collected from wells analogous in lithology and equipment used to the well where the model is meant to be deployed. Lithology information is not always well documented and fast-paced development of drilling equipment complicates the challenge even further, as a model would likely become obsolete and inaccurate when new technologies are deployed. To bypass this problem a training-while-drilling method utilizing neural networks that are capable of modelling dynamic behaviour is proposed. It is a continuous learning approach where a data-driven model is developed while the well is being drilled, on data that is received as a continuous stream of information coming from various sensors. The novelty in presented approach is the use of Recurrent Neural Network elements to capture the dynamic behaviour present in data. Such model takes into account not only values of the adjacent data, but also patterns existing in the data series. Moreover, results are presented with a focus on the continuous learning aspect of the method, which was sparsely researched to date. A case study is presented where inclination data is predicted ahead of the inclination sensor in a directional drilling scenario. Our model architecture starts to provide accurate results after only 180 m of training data. Method, architecture, results, and benchmarking against classical approach are discussed; full dataset with complete source code is shared on GitHub.",3,3,3
Machine Learning,Loss,"Sabah, Mohammad; Mehrad, Mohammad; Ashrafi, Seyed Babak; Wood, David A.; Fathi, Shadi",Hybrid machine learning algorithms to enhance lost-circulation prediction and management in the Marun oil field,Lost circulation while drilling; Multilayer perception; Least square support vector machine; Evolutionary algorithms; Marun oil field,ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINE; MULTILAYER PERCEPTRON; OPTIMIZATION; MODELS; RESERVOIR; ASMARI,"Drilling fluid loss of circulation is a challenging issue to resolve for many oil and gas wells as drilling progresses. It imposes enormous expenses on drilling industry. One of the common practices to solve this problem or make it less severe is introducing various loss circulation materials (LCM) into the circulating drilling fluid. The ability to predict the amount of mud loss before drilling a particular formation would provide engineers with invaluable information to assist them in selecting appropriate LCM properties such as particle size distribution. In this study, a number of heuristic search algorithms including genetic algorithm (GA), particle swarm size (PSO), and cuckoo search algorithm (COA) are combined with two machine-learning techniques namely multilayer perception (MLP) neural network and least square support vector machine (LSSVM) to present different hybrid algorithms in prediction of lost circulation. The established database consists of 2820 cases (datasets) extracted from available drilling reports of 305 drilled wells in the Marun oil field. These datasets are associated with drilling operation variables, formation specifications, and drilling mud characteristics which totally include 18 input variables and 1 output. Pre-processing of data involves filtering with Savitzky-Golay (SG) filter and ranking features using wrapper method. Results show that hybrid intelligent models are highly capable of predicting lost circulation before drilling a certain formation. Furthermore, LSSVM-COA and LSSVM-PSO achieve coefficients of determination of 0.9424 and 0.9391, respectively, making them the two most accurate models. GA cannot match the prediction performance of the other two algorithms in enhancing machine-learning techniques for this purpose. MLP-GA with a coefficient of determination (R-2) and RMSE of 0.9304 and 25.26 (bbl/hr), respectively, yields the weakest prediction performance. Hybrid intelligent models, coupling optimizers and machine learning algorithms show themselves to be superior to applying standalone machine-learning methodologies for predicting loss of circulation.",13,13,6
Machine Learning,Loss,"Feng, Runhai",Improving uncertainty analysis in well log classification by machine learning with a scaling algorithm,Machine learning; Uncertainty analysis; Platt scaling; Reliability diagram,RESERVOIR; LITHOFACIES; IDENTIFICATION,"Uncertainty is an important indicator that can provide the confidence in the predictions. However, most machine learning methods in classification problems are incapable of predicting an accurate probability that matches the observed distribution of each class. To overcome this problem and improve the uncertainty analysis in lithofacies classification, a novel calibration process is performed on the validation subset using scaling algorithms. The validation subset should be separated from the training data in order to reduce overfitting and avoid unwanted biases. Random forest is selected as the machine learning classifier owing to its relative ease of use, and can handle high-dimensional input features quite well. The proposed approach is applied to two real datasets to demonstrate the improvement in the uncertainty quantification. Reliability diagram shows that the calibrated probability is closer to the diagonal truth, compared with the uncalibrated one. In addition to the visual check, a multiclass Brier score of calibrated model is lower than that by uncalibrated system, which can be referred to as a loss function. For the classification results by calibrated and uncalibrated classifiers on the testing subset, an increase of the Matthews correlation coefficient also means that the calibrated model has a better performance.",6,6,0
Machine Learning,Loss,"Murtaza, Mobeen; Tariq, Zeeshan; Zhou, Xianmin; Al-Shehri, Dhafer; Mahmoud, Mohamed; Kamal, Muhammad Shahzad",Okra as an environment-friendly fluid loss control additive for drilling fluids: Experimental & modeling studies,Drilling fluids; Viscosifier; Fluid loss controller; ANN; Okra,BENTONITE DISPERSIONS; SILICA,"Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. It is also environment friendly and available in abundance, especially in tropical and subtropical regions. To the best of our knowledge, this is the first report on the application of the okra solution as a fluid loss control additive in drilling fluids. The okra powder was characterized by X-ray fluorescence, Fourier-transform infrared spectroscopy, and scanning electron microscopy. The thermal stability of okra was tested using thermal gravimetric analysis. The microstructure stability of the okra-based solution was analyzed using shear and loss modulus. The okra powder was used in different concentrations (0.25, 0.5, & 1) wt% in a clay free water-based drilling fluid formulation. The experimental study revealed that the addition of 1 wt% okra solution could reduce 20% fluid loss. The okra showed comparable performance compared to the conventional fluid loss control additive, starch. The main advantage was that okra has less impact on rheological properties compared to starch. TGA analysis of okra powder showed that it has strong thermal stability. The pH test showed that okra powder could not affect the pH of the solution. The shear and loss modulus tests revealed that the water-based drilling fluid samples with higher okra powder concentrations could develop a more stable microstructure. Overall, the experimental results suggest that okra containing drilling fluids can be used as an alternate solution to starch in drilling fluids without compromising other drilling fluids' properties. A Machine Learning (ML)-based rheological model was also developed to predict the rheological properties of okra-based drilling fluid formulations. The proposed ML model can predict the rheological properties of Okra-based drilling fluids with high accuracy.",4,4,5
Machine Learning,Loss,"Yin, Qishuai; Yang, Jin; Tyagi, Mayank; Zhou, Xu; Wang, Ning; Tong, Gang; Xie, Renjun; Liu, Hexing; Cao, Bohan",Downhole quantitative evaluation of gas kick during deepwater drilling with deep learning using pilot-scale rig data,Gas kick; Downhole quantitative evaluation; Pilot-scale test well experiment; Compressed air injection; Deep-water drilling,,"Gas kick occurs frequently during deep-water drilling operations caused by the lack of safe margin between pore pressure and leakage pressure. The existing research is limited to gas kick classification and cannot quantitatively evaluate the gas kick risk in the downhole very well. Thus, the objective of this work is to systematically use Long Short-Term Memory (LSTM) Recurrent Neural Network (RNN) models based on pilot-scale rig data for quantitative evaluation of gas kick risk. Furthermore, the quantitative evaluation is not surface but downhole. First, the gas kick simulation experiment is accomplished in the pilot-scale test well and produces the gas kick dataset, which is based on the multi-source data fusion through the surface monitoring technologies, riser monitoring technologies and downhole monitoring technologies. Second, the training features are selected and grouped as Sets1-5 to study the features' sensitivity. Third, the raw data is processed and prepared for the following machine learning framework. Fourth, there are five (5) LSTM models trained on Sets1-5. The results indicate that the models' Loss decrease with the increase of feature number, which has fully demonstrated the effectiveness of PWD, EKD, and Doppler parameters. Finally, there are four representative case studies (artificial gas kick) that are used to test the above five models. The compressed air injected rate (AR) prediction error and detection time-delay decrease with the increase of feature number. The LSTM model trained with the combination of surfaceriser-downhole comprehensive detection technologies performs the best in reducing both the prediction error and detection time delay, which could be used to quantitatively evaluate the downhole gas kick risk in the more accurate, faster, more stable, more reliable, and cost-effective manner, and it is effective and worthy of promotion.",3,3,4
Machine Learning,Loss,"Maldonado-Cruz, Eduardo; Pyrcz, Michael J.",Tuning machine learning dropout for subsurface uncertainty model accuracy,Numerical simulation; Machine learning; Surrogate modeling; Uncertainty estimation; Hyperparameter optimization; Model goodness,NEURAL-NETWORKS; DEEP,"Machine learning hyperparameter tuning generally relies on minimizing the prediction error and maximizing the accuracy at withheld testing data locations. However, for many subsurface applications, prediction accuracy is not sufficient, and we must consider the goodness, accuracy, and precision, of the entire uncertainty model. Bayesian deep neural networks provide a robust framework to model uncertainty. But at a high computational cost and difficulty to scale in high-dimensional parameter spaces. Dropout offers a potential alternative for calculating prediction model realizations to represent the uncertainty model. We propose a method to compare the entire uncertainty model based on the prediction realizations and the addition of a single objective function, known as uncertainty model goodness, to the loss function to integrate model uncertainty for improved tuning of the dropout frequency in deep learning models. We test our method with a subsurface flow surrogate model based on an image-to-image regression problem. Implementing the proposed method with the uncertainty model goodness results in accurate and precise uncertainty models using the tuned dropout hyperparameter. We test the robustness and generalization of the proposed method with out-of-distribution testing data.",3,3,4
Machine Learning,Horizontal Wells,"Mohamadian, Nima; Ghorbani, Hamzeh; Wood, David A.; Mehrad, Mohammad; Davoodi, Shadfar; Rashidi, Sina; Soleimanian, Alireza; Shahvand, Amirafzal Kiani",A geomechanical approach to casing collapse prediction in oil and gas wells aided by machine learning,Hybrid multi-layer perceptron's; Wellbore casing collapse; Maximum horizontal stress; Poisson's ratio; Gachsaran formation; Geomechanical sub-surface model,EMPIRICAL RELATIONS; CREEP-BEHAVIOR; FLOW RATES; RESERVOIRS; MECHANISM; NETWORKS; STRENGTH; FAILURE; ROCK,"The casing-collapse hazard is one that drilling engineers seek to mitigate with careful well design and operating procedures. However, certain rock formations and their fluid pressure and stress conditions are more prone to casing-collapse risks than others. The Gachsaran Formation in south west Iran, is one such formation, central to oil and gas resource exploration and development in the Zagros region and consisting of complex alternations of anhydrite, marl and salt. The casing-collapse incidents in this formation have resulted over decades in substantial lost production and remedial costs to mitigate the issues surrounding wells with failed casing string. High and vertically-varying horizontal stresses across the Gachsaran formation are the challenge to predict and overcome. This study investigates casing collapse in wellbores from an established petroleum geomechanics perspective to develop and compare two hybrid neural-network models, multilayer perceptron's tuned, respectively, with a genetic algorithm (MLP-GA) and a particle swarm algorithm (MLP-PSO). These machine-learning algorithms are configured to predict Poisson's ratio (theta) and maximum horizontal stress (sigma(H)) from available well-log input data. A large dataset from three wellbores drilled though the Gachsaran Formation in the Marun oil field, the second largest in Iran, is used to construct and validate the hybrid MLP models. In the first step, 22323 data records from a collapsed wellbore are divided into training (15626 records; 70%) and independent testing subsets (6697 records; 30%). In the next step, in order to test whether the suggested algorithms could be generalized, the data sets of the other two wells in the field were tested. Those tests confirmed that the algorithms achieved high prediction accuracy for Poisson's ratio and maximum horizontal stress in other wellbores.",14,14,10
Machine Learning,Horizontal Wells,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Machine Learning,Horizontal Wells,"Sun, Jian; Chen, Mingqiang; Li, Qi; Ren, Long; Dou, Mengyuan; Zhang, Jixuan",A new method for predicting formation lithology while drilling at horizontal well bit,Logging while drilling; Machine learning; Real-time interpretation; Lithology prediction,IDENTIFICATION; CLASSIFICATION; ALGORITHMS,"The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of ""zero length"" (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the ""zero length"" on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.",4,5,3
Machine Learning,Horizontal Wells,"Chaikine, Ilia A.; Gates, Ian D.",A machine learning model for predicting multi-stage horizontal well production,Horizontal multistage fracture; Machine learning; Production; Unconventional reservoirs; Hydraulic fracturing; Predictive models,,"In this study, a hybrid convolutional-recurrent neural network (c-RNN) is evaluated for making predictions of the five-year cumulative production profiles in multistage hydraulically fractured wells. The model was trained by using a combinations of completion parameters, rock mechanical properties, and well spacing and completion order for each stage of 74 wells in the Montney Formation in Alberta. The prediction accuracy of the various combinations was measured by using the mean average percent error and mean absolute error generated through the leave-one-out method. The best combination of inputs was found to be the rock mechanical properties surrounding each perforation cluster, the proppant amount used for every stage, and the spacing and completion order of neighboring wells. The novelty of this study is that the input variables used are at the stage level rather than the average of the entire well. The accuracy of the model was found to increase exponentially as the production of multiple wells was aggregated. The approach yields insights for planning new well drills in fields with existing development since it provides the ability to run multiple field development scenarios without having to spend capital.",3,3,3
Machine Learning,Sensitivity Analysis,"Mahdaviara, Mehdi; Rostami, Alireza; Keivanimehr, Farhad; Shahbazi, Khalil",Accurate determination of permeability in carbonate reservoirs using Gaussian Process Regression,Permeability determination; Carbonate reservoir; Pore specific surface area; Gaussian process regression; Sensitivity analysis; Outliers detection,ABSOLUTE PERMEABILITY; BAYESIAN NETWORKS; PREDICTION; MODELS; ALGORITHM; OIL,"The knowledge of reservoir permeability determination is increasingly important in petroleum engineering. Understanding the alteration of the abovementioned parameter as a dynamic characteristic of formations helps the characterization of reservoir rock. The existing models available for permeability determination are mainly developed for sandstone reservoir; therefore, a great challenge is in the prediction of permeability in carbonate heterogeneous rock. The current study addresses the application of Gaussian Process Regression (GPR), a state-of-the-art machine learning algorithm, in estimating permeability of carbonate reservoirs. This Bayesian network offers various benefits including non-linearity and multi-dimensionality. A widespread source of data pertinent to four deposits of Vuktyl' skiy, central Asia, Kuybyhev, and Orenburg was adopted from literature. The data set includes water saturation, effective porosity, and pore specific surface area parameters in association with absolute rock permeability as the target. Four different Kernels of Matern, rational quadratic, exponential, and squared exponential are utilized as the covariance functions of the GPR network. A wide variety of the visualizations and statistical parameters are prepared to assess the potential of the established models in permeability estimation. Finally, it is demonstrated that the GPR (Matern) gives the highest precision with Mean Magnitude Relative Error (MMRE) and Adjusted R-squared equal to 38% and 0.98, respectively. Besides, the applied sensitivity analysis reveals that porosity and irreducible water saturation have the lowest and the highest absolute impact values on permeability estimation. The applicability and validity of the developed models are also demonstrated by means of the so-called Williams' method for outliers detection. At last, it is worthwhile mentioning that the created new methods in this study can be good nominees for permeability determination in characterizing the heterogeneous carbonate reservoirs.",14,14,10
Machine Learning,Sensitivity Analysis,"Li, Chunxiao; Wang, Dongmei; Kong, Lingyun",Application of Machine Learning Techniques in Mineral Classification for Scanning Electron Microscopy - Energy Dispersive X-Ray Spectroscopy (SEM-EDS) Images,Mineral segmentation; Machine learning; SEM-EDS; U-net; The Bakken Formation,,"Mineral classification and segmentation is time-consuming in geological image processing. The development of machine learning methods shows promise as a technique in replacing manual classification. In this study, performances of five shallow machine classification algorithms and a deep learning algorithm were compared for the goal of pixel-level mineral classification of Scanning Electron Microscopy - Energy Dispersive X-Ray Spectroscopy (SEM-EDS) images. Five machine learning models, including Logistic Regression (LR), Linear Support Vector Machine (SVM), k-Nearest Neighbor (k-NN), Random Forest (RF), and Artificial Neuron Networks (ANN), and a deep learning CNN U-Net model were used in this study. Thirteen mineral phases were classified on SEMEDS images of a shale sample taken from the Bakken Formation. Hyperparameters of models were tuned using a grid-search method. Randomly selected balanced dataset was used for the shallow models, while the original cropped images were used for the U-Net. The experimental results showed that all classification algorithms resulted in high F1 scores ranging from 0.86 to 0.92. The RF demonstrated the best performance among the five machine learning models, with an F1 score of 0.92. Additionally, sensitivity analysis on the size of dataset demonstrated that the LR algorithm and the SVM were less sensitive to the dataset reduction, while the models of k-NN, RF, and ANN were more influenced. Sensitivity analysis of noise suggested that noises added on the element of Silicon, Aluminum, Magnesium, Calcium, Potassium, and Iron would decrease the performance of the RF. Furthermore, the noise in Silicon had the greatest effect on the prediction result compared to the other minerals. In addition, those non-linear classifiers showed a larger performance score drop when the noise was simultaneously included into all the elements density. Though U-Net shows poor performance on the segmentation of minority classes due to the negative effect of imbalanced dataset the U-Net model still outperformed the RF model when it comes to unseen shale samples.",6,6,5
Machine Learning,Sensitivity Analysis,"Mousazadeh, Fatemeh; Naeem, Mohammad Hossein Towfighi; Daneshfar, Reza; Soulgani, Bahram Soltani; Naseri, Maryam",Predicting the condensate viscosity near the wellbore by ELM and ANFIS-PSO strategies,Viscosity; Gas condensate; Extreme learning machine; Machine learning; Particle swarm optimization,EXTREME LEARNING-MACHINE; DEW-POINT PRESSURE; GAS; DENSITY; SYSTEMS; MIXTURES; METHANE; MODELS; DECANE; STATE,"By lowering the pressure beneath the dew point as the result of production in gas condensate (GC) reservoirs, liquid droplets are formed in the borehole zone. Accurate calculation of pressure decline and optimization operations in these reservoirs need to know and predict the specific properties such as liquid viscosity. Empirical models have already been developed to predict this parameter. Due to the peculiar behavior of fluids beneath the dew point pressure (DPP), the prediction of liquid viscosity associates with an error. With the development of machine learning (ML) approaches, studies on fluid properties like other sciences have entered a new phase. In this study, extreme learning machine (ELM) and adaptive neuro-fuzzy inference system with particle swarm optimization (ANFIS-PSO) methods applied to this end. Therefore, a large data bank of reservoir and fluid properties including reservoir temperature and pressure, specific gravity (SG) of gas, API gravity, and gas to oil ratio (Rs) were used. The results showed that R-squared and RMSE for ANFIS-PSO are 0.762 and 0.15, respectively, while these values are 0.941 and 0.06 for ELM which shows that the last model has a better performance in estimating output values. Also, the range of reliable data is determined, and further, a sensitivity analysis was done, which showed that the greatest impact on the viscosity was from SG, and API gravity has the least effect on it. This model can be used as a reference for calculating condensate viscosity and also by expanding the range of datasets, it can be applied in the commercial software.",6,6,0
Machine Learning,Sensitivity Analysis,"Zhang, Guoyin; Wang, Zhizhang; Mohaghegh, Shahab; Lin, Chengyan; Sun, Yanan; Pei, Shengjie",Pattern visualization and understanding of machine learning models for permeability prediction in tight sandstone reservoirs,Permeability; Machine learning; Residual neural networks; Predictive pattern; Sensitivity analysis; Wireline logs,ARCHITECTURE; DEPRESSION; NETWORK; DESIGN; LOG,"Permeability prediction is a key and difficult task in hydrocarbon reservoir characterization. Machine learning has long been studied for permeability prediction using porosity and wireline logs but has not been widely accepted and applied in real cases because it is always treated as a Black Box and hard to interpret. In this paper, we propose novel approaches called univariate predictive pattern (UPP) and bivariate predictive pattern (BPP) to visualize predictive patterns learned by machine learning models. Machine learning models for permeability prediction are built in advance, including support vector regression (SVR), random forest (RF), and deep residual neural network (ResNet). The visualized predictive patterns show that ResNet learns the best-fitted nonlinear porosity-permeability relationships from the training dataset, which explains why ResNet achieves the best performance in permeability prediction in the scenario with porosity and wireline logs as input features. Wireline logs provide information about pore structure and contribute differently in machine learning models according to the visualized predictive patterns and quantitative sensitivity analysis. The proposed approach provides us a way to get a glimpse of the Black Box of machine learning models, and is also helpful in sensitivity analysis, feature selection, and model optimization for permeability prediction.",3,3,8
Machine Learning,Gas Production,"Mohamadian, Nima; Ghorbani, Hamzeh; Wood, David A.; Mehrad, Mohammad; Davoodi, Shadfar; Rashidi, Sina; Soleimanian, Alireza; Shahvand, Amirafzal Kiani",A geomechanical approach to casing collapse prediction in oil and gas wells aided by machine learning,Hybrid multi-layer perceptron's; Wellbore casing collapse; Maximum horizontal stress; Poisson's ratio; Gachsaran formation; Geomechanical sub-surface model,EMPIRICAL RELATIONS; CREEP-BEHAVIOR; FLOW RATES; RESERVOIRS; MECHANISM; NETWORKS; STRENGTH; FAILURE; ROCK,"The casing-collapse hazard is one that drilling engineers seek to mitigate with careful well design and operating procedures. However, certain rock formations and their fluid pressure and stress conditions are more prone to casing-collapse risks than others. The Gachsaran Formation in south west Iran, is one such formation, central to oil and gas resource exploration and development in the Zagros region and consisting of complex alternations of anhydrite, marl and salt. The casing-collapse incidents in this formation have resulted over decades in substantial lost production and remedial costs to mitigate the issues surrounding wells with failed casing string. High and vertically-varying horizontal stresses across the Gachsaran formation are the challenge to predict and overcome. This study investigates casing collapse in wellbores from an established petroleum geomechanics perspective to develop and compare two hybrid neural-network models, multilayer perceptron's tuned, respectively, with a genetic algorithm (MLP-GA) and a particle swarm algorithm (MLP-PSO). These machine-learning algorithms are configured to predict Poisson's ratio (theta) and maximum horizontal stress (sigma(H)) from available well-log input data. A large dataset from three wellbores drilled though the Gachsaran Formation in the Marun oil field, the second largest in Iran, is used to construct and validate the hybrid MLP models. In the first step, 22323 data records from a collapsed wellbore are divided into training (15626 records; 70%) and independent testing subsets (6697 records; 30%). In the next step, in order to test whether the suggested algorithms could be generalized, the data sets of the other two wells in the field were tested. Those tests confirmed that the algorithms achieved high prediction accuracy for Poisson's ratio and maximum horizontal stress in other wellbores.",14,14,10
Machine Learning,Gas Production,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Machine Learning,Gas Production,"Mousazadeh, Fatemeh; Naeem, Mohammad Hossein Towfighi; Daneshfar, Reza; Soulgani, Bahram Soltani; Naseri, Maryam",Predicting the condensate viscosity near the wellbore by ELM and ANFIS-PSO strategies,Viscosity; Gas condensate; Extreme learning machine; Machine learning; Particle swarm optimization,EXTREME LEARNING-MACHINE; DEW-POINT PRESSURE; GAS; DENSITY; SYSTEMS; MIXTURES; METHANE; MODELS; DECANE; STATE,"By lowering the pressure beneath the dew point as the result of production in gas condensate (GC) reservoirs, liquid droplets are formed in the borehole zone. Accurate calculation of pressure decline and optimization operations in these reservoirs need to know and predict the specific properties such as liquid viscosity. Empirical models have already been developed to predict this parameter. Due to the peculiar behavior of fluids beneath the dew point pressure (DPP), the prediction of liquid viscosity associates with an error. With the development of machine learning (ML) approaches, studies on fluid properties like other sciences have entered a new phase. In this study, extreme learning machine (ELM) and adaptive neuro-fuzzy inference system with particle swarm optimization (ANFIS-PSO) methods applied to this end. Therefore, a large data bank of reservoir and fluid properties including reservoir temperature and pressure, specific gravity (SG) of gas, API gravity, and gas to oil ratio (Rs) were used. The results showed that R-squared and RMSE for ANFIS-PSO are 0.762 and 0.15, respectively, while these values are 0.941 and 0.06 for ELM which shows that the last model has a better performance in estimating output values. Also, the range of reliable data is determined, and further, a sensitivity analysis was done, which showed that the greatest impact on the viscosity was from SG, and API gravity has the least effect on it. This model can be used as a reference for calculating condensate viscosity and also by expanding the range of datasets, it can be applied in the commercial software.",6,6,0
Machine Learning,Gas Production,"Wei, Wei; Rezazadeh, Alan; Wang, Jingyi; Gates, Ian D.",An analysis of toe-to-heel air injection for heavy oil production using machine learning,Heavy oil; In situ combustion; Toe-to-heel air injection; Machine learning; Data analytics; Clustering analysis,IN-SITU COMBUSTION; GRAVITY DRAINAGE; REACTION MODEL; RECOVERY; SIMULATION; SANDS,"With strong potential for improving productivity, economics, and efficiencies, data analytics and machine learning are rapidly emerging in the oil and gas industry. However, their application in heavy oil production is scarce. In this study, we use clustering methods to analyze the Kerrobert Toe-to-Heel Air Injection (THAI) project to understand the inter-relationships of production variables and seek for optimal operating strategy to maximize production rate. More specifically, we use the K-means, normal mixtures and hierarchical clustering methods to determine how operating parameters contribute to oil production. The results reveal that, at current operation mode, air injection rate is constrained for production maximization due to the balance between heat generation and cooling of combustion system by excess air supply. The results also provide insight for improved productivity from THAI suggesting that cyclic injection may improve process performance. The new insights demonstrate that data analytics can provide new understanding of recovery processes as well as potential process improvement.",6,6,0
Machine Learning,Real Time,"Sun, Jian; Chen, Mingqiang; Li, Qi; Ren, Long; Dou, Mengyuan; Zhang, Jixuan",A new method for predicting formation lithology while drilling at horizontal well bit,Logging while drilling; Machine learning; Real-time interpretation; Lithology prediction,IDENTIFICATION; CLASSIFICATION; ALGORITHMS,"The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of ""zero length"" (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the ""zero length"" on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.",4,5,3
Machine Learning,Real Time,"Alali, Ammar M.; Abughaban, Mahmoud F.; Aman, Beshir M.; Ravela, Sai",Hybrid data driven drilling and rate of penetration optimization,ROP; Optimization; Data-driven; Machine learning; Drilling mechanics; Real time adjustments,PREDICTION; INVERSION; ROP,"Optimizing the drilling process for cost and efficiency requires faster drilling with a higher rate of penetration (ROP). A high ROP usually indicates fast and cost-efficient drilling operations; however, high ROPs may induce unintended events, which may lead to nonproductive time (NPT). In this paper, the proposed hybrid, data-driven optimization system aims to improve the drilling process, maximize the ROP, and minimize NPT. This two-phase system leverages existing drilling data (Phase One) and real-time adjustments (Phase Two) to optimize drilling efficiency through the adjustment of controllable dynamic drilling parameters; weight on bit (WOB), pump flow rate (GPM), and rotary speed (RPM). In the first phase, geological data is queried to generate a model of drilling best practices in a certain field with attention to ROP and NPT. After the top-rated wells are identified, the model recommends adjustments to the controllable dynamic drilling parameters (WOB, GPM, RPM) and produces a cross-plot for each ROP. The optimum ROP parameter for each well is subsequently calculated as a conditioned mean based on proximity to the well as an Inverse Distance Weighting (IDW) interpolation. This phase is completed prior to any drilling activity. The second phase considers the model produced in phase one to run an automated drill-off test. The model directs the driller to deviate for controllable parameters WOB and RPM by a small percentage (0-5%), in a Constrained Random Search (CRS) way. These deviations allow the driller to explore new drilling conditions in small increments; the data is then compiled into a heat-map function of ROP and the model is updated to reflect optimum drilling parameters. The adjustments resulted in faster, safer ROP with a potential 22%+ improvement in efficiency and 15-20% cost-reduction. Lastly, to characterize the relationship between the controllable dynamic parameters (WOB, RPM, GPM) to the ROP, an ANN based empirical relationship was derived.",3,3,8
Machine Learning,Real Time,"Marins, Matheus A.; Barros, Bettina D.; Santos, Ismael H.; Barrionuevo, Daniel C.; Vargas, Ricardo E. V.; Prego, Thiago de M.; de Lima, Amaro A.; de Campos, Marcello L. R.; da Silva, Eduardo A. B.; Netto, Sergio L.",Fault detection and classification in oil wells and production/service lines using random forest,Fault detection and classification; Oil well monitoring; Abnormal event management; Random forest classifier; Machine learning,MACHINE,"This papers deals with the automatic detection and classification of faulty events during the practical operation of oil and gas wells and lines. The events considered here are part of the publicly available 3W database developed by Petrobras, the Brazilian oil holding. Seven fault classes are considered, with distinct dynamics and patterns, as well as several instances of normal operation. A random forest classifier is employed with different statistical measures to identify each fault type. Three experiments are devised in order to evaluate the system performance in distinct classification scenarios. An accuracy rate of 94% indicates a successful performance for the proposed system in detecting real events. Also, the system's time of detection was on average 12% of the transient period that precedes the fault steady-state.",3,3,3
Machine Learning,EOR Methods,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Machine Learning,EOR Methods,"Pirizadeh, Mohsen; Alemohammad, Nafiseh; Manthouri, Mohammad; Pirizadeh, Meysam",A new machine learning ensemble model for class imbalance problem of screening enhanced oil recovery methods,Classification; Ensemble learning; EOR screening; Class imbalance problem; Mutual information; Hyper-parameter tuning,NEAREST-NEIGHBOR; CLASSIFICATION,"Enhanced Oil Recovery (EOR) methods have received a lot of attention today due to the increase in global oil demand and the reduction of oil production capacity from natural extraction methods. EOR methods are the solution for extracting oil from heavy and extra-heavy reservoirs, but the problem for reservoir engineers is choosing the right EOR method for an oilfield. In fact, the number of EOR methods and the features associated with them are very high, so the financial risk of implementing the wrong EOR method leads to feeling the need for an expert screening tool. Until now, various individual classifiers have been used for this purpose, but due to the class imbalance problem of the EOR dataset, most of them do not have good results, therefore, to increase the accuracy of the model, EOR methods with low records in the dataset are ignored, while industry needs all EOR methods. In this study, an ensemble learning-based approach is used to overcome the problem of class imbalance at the algorithmic level instead of the data level. For this purpose, an effective model called B2S is proposed by gathering the advantages of each of the ensemble-based methods, including Bagging, Boosting, and Stacking. As a result, B2S by creating a balance between variance and bias achieved an average test accuracy of 96.94% on the dataset including 426 samples from 10 different EOR methods that had a highly skewed distribution. The average accuracy also increases to 98.12% with a standard deviation of 1.63%, after grouping some relatively similar EOR methods, which indicates the stability of the proposed method. The study also demonstrates direct relation between model performance and the impact of precise pre-processing, nonlinear feature selection using Mutual Information rather than conventional linear methods, and hyper-parameters tuning with newer methods such as Random Search.",7,7,2
Machine Learning,EOR Methods,"Cheraghi, Yasaman; Kord, Shahin; Mashayekhizadeh, Vahid",Application of machine learning techniques for selecting the most suitable enhanced oil recovery method; challenges and opportunities,Enhanced oil recovery; Reservoir engineering; EOR Screening; Advanced EOR Screening; Machine learning,,"A reliable method for selecting the most suitable Enhanced Oil Recovery (EOR) method is of a high necessity in reservoir engineering. Machine Learning (ML) techniques have been widely adopted as an effective and fast approach in primary stage of EOR screening. This paper presents a step-by-step procedure of applying ML in EOR screening with focusing on two main goals. Firstly, the problem of EOR screening is investigated from ML point of view. A large database consisting of more than 1000 experiences of worldwide EOR projects has been gathered from various sources. On the basis of this database, several ML models have been developed for predicting the suitable category of EOR methods for a candidate reservoir. These models include: Shallow and Deep Artificial Neural Networks (ANN), Naive Bayes (NB), Decision Tree (DT), Random Forest (RF) and Dimension Reduction using Principal Component Analysis (PCA). Almost all models performed well in predicting non-observed data with an average accuracy ranging from 80 to 90%. However, RF and the deep ANN models delivered the best performance with an average accuracy of 90%. The results demonstrated that RF model performed much better in comparison with the DT model and improved the classification accuracy from 85 to 91%. In case of ANNs, it was observed that the deeper ANN developed here, improved the classification accuracy from 83 to 90% in comparison with the shallow ANN with one hidden layer. The weakest performance was delivered by NB classifier with an average accuracy of 49%. As the second purpose of this research, reliability of screening results from applying ML techniques is discussed in details. Because, this approach suffers from some serious limitations and challenges, which could unfavorably affect the screening results and never had been considered in previous works. In this work, potential challenges and limitations associated with this well-known approach are introduced from database issues to modeling problems. Accordingly, an important conclusion is that application of ML, although providing a very good insight into primary EOR screening, should not be relied upon as the only method for predictions. It is recommended that the obtained results from this approach should be cross-checked with other EOR screening approaches or with methods based on expert's knowledge.",5,5,3
Machine Learning,Rock Physics,"Ali, Muhammad; Jiang, Ren; Ma, Huolin; Pan, Heping; Abbas, Khizar; Ashraf, Umar; Ullah, Jar",Machine learning-A novel approach of well logs similarity based on synchronization measures to predict shear sonic logs,Machine learning; Geophysical similarity analysis; Multidimensional scaling; Jaccard and Overlap similarities; Well logs,,"This study proposes a novel approach to predict missing shear sonic log responses more precisely and accurately using similarity patterns of various wells with similar geophysical properties, which is important in decision making and planning of hydrocarbon exploration. Deep Neural Network (DNN) along with the similarity metrics such as Jaccard and Overlap similarities are employed to examine the relationship between the wells. Further, dimensionality reduction techniques including Multi-Dimensional Scaling (MDS) and well-ranking process are applied to extract common geophysical responses of the wells. A higher response indicates the existence of a strong similarity. This can also be verified by the superimposed of well log data. The potential benefits of our novel method are following; (a) it does not follow the zone-by-zone prediction of the missing logs such as rock physics methods, (b) it outputs the uncertainties facilitated that is by the least-squares method. Having the potential of demonstrating shear sonic log prediction in hydrocarbon-bearing zones, which cannot be precisely predicted by the Greenberg-Castagna method that only works in brine-saturated rocks, this approach will provide improved accuracy, where shear sonic logs are missing and need to be predicted for geomechanics, rock physics, and other applications.",10,10,5
Machine Learning,Rock Physics,"Yasin, Qamar; Sohail, Ghulam Mohyuddin; Khalid, Perveiz; Baklouti, Syrine; Du, Qizhen","Application of machine learning tool to predict the porosity of clastic depositional system, Indus Basin, Pakistan",Seismic inversion; Support vector machine; Rock physics; Porosity; Particle swarm optimization; Sawan gas field,SAWAN GAS-FIELD; KRISHNA-GODAVARI BASIN; SEISMIC ATTRIBUTES; MULTIATTRIBUTE TRANSFORMS; ROCK PHYSICS; WELL LOGS; RESERVOIR; SHALE; INVERSION; MODEL,"Porosity is one of the key factors of a reservoir system that is typically distributed in a spatially non-uniform and non-linear manner. Nevertheless, spatial distribution of porosity in stratigraphic traps (channel sand bodies) is challenging due to the variations in depositional environments, shale intercalation, and repetition of textural changes in the pore sizes. This paper presents a strategy of joint inversion that combines support vector machine (SVM) and particle swarm optimization (PSO) algorithms to predict the spatial distribution of porosity using well logs and seismic data. In addition, Gaussian simulation algorithms (sequential Gaussian and Gaussian indicator simulations) were used to predict lithology and porosity distribution using wireline logs and core data. Rock physics modeling was performed to bridge the gap between the elastic and petrophysical properties for seismic-inversion based reservoir characterization. The results show that the joint inversion strategy leads to the most stable prediction of AI and porosity distribution in the lower Goru heterogeneous reservoir of Sawan Gas Field, Pakistan. The calibration of the individual spatial distribution of lithology and porosity from wireline logs data using Gaussian simulation algorithms and post-stack seismic inversion using SVM and PSO; revealed favorable matching. In fact, the spatial pattern of low AI corresponds with the high porosity and sandstone lithofacies. The study results provide valuable insights for identifying the sweet spots in the heterogeneous lower Goru clastic packages of Sawan Gas Field through quantitative analysis of rock physics, petrophysics, seismic inversion, and fuzzy optimization. The proposed joint inversion strategy may be considered useful for the prediction of porosity in similar context of extremely heterogeneous stratigraphic traps in other basins of the world.",6,6,8
Machine Learning,Rock Physics,"Luo, Xiaodong; Lorentzen, Rolf J.; Bhakta, Tuhin",Accounting for model errors of rock physics models in 4D seismic history matching problems: A perspective of machine learning,Seismic history matching; Iterative ensemble smoother; Model errors; Residual model; Machine learning,ADAPTIVE LOCALIZATION; ENSEMBLE SMOOTHER; FIELD MODEL; PARAMETERS; SCALE; FLUID,"Model errors are ubiquitous in practical history matching problems. A common approach in the literature to accounting for model errors is to treat them as random variables following certain presumed distributions. While such a treatment renders algorithmic convenience, its underpinning assumptions are often invalid. In this work, we adopt an alternative approach, and treat model-error characterization as a functional approximation problem, which can be solved using a generic machine learning method. We then integrate the proposed model-error characterization approach into an ensemble-based history matching framework, and show that, with very minor modifications, existing ensemble-based history matching algorithms can be readily deployed to solve the history matching problem in the presence of model errors. To demonstrate the efficacy of the integrated history matching framework, we apply it to account for potential model errors of a rock physics model in 4D seismic history matching applied to the full Norne benchmark case. The numerical results indicate that the proposed model-error characterization approach helps improve the qualities of estimated reservoir models, and leads to more accurate forecasts of production data. This suggests that accounting for model errors from a perspective of machine learning serves as a viable way to deal with model imperfection in practical history matching problems.",5,5,0
Machine Learning,Proxy Model,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Machine Learning,Proxy Model,"Deng, Lichi; Pan, Yuewei",Data-driven proxy model for waterflood performance prediction and optimization using Echo State Network with Teacher Forcing in mature fields,Data-driven proxy model; Echo state network; Teacher forcing; Machine learning; Waterflood; Optimization,,"Waterflood has been widely applied across the world as the most important secondary recovery process to improve reservoir performance. The schemes applied to waterflood projects involve key decision-making which aims to maximize the net present value (NPV) for a given period, improve recovery and sweep efficiency, maintain reservoir pressure, reduce water production, and avoid water recycling. Traditionally, the preferred approach to estimate the future performance of any given waterflood project is through the numerical reservoir simulation. However, despite the great power and intuition associated with the simulation models, sometimes this potential is unachievable due to massive computational requirements. Also, in some other cases, there may exist no simulation model to begin with. To tackle these problems, data-driven proxy models are proposed. In this research, we propose a novel machine-learning-based proxy model for waterflood performance prediction and further apply it for production optimization purpose to obtain the optimal future well control. The data-driven model is realized using the Echo State Network (ESN) under the paradigm of ""Reservoir Computing"" (RC). Compared with traditional ESNs, this specific methodology includes a feedback loop from the output into the high dimensional ""reservoir"" to achieve improved prediction results for separated phase production rates. Teacher Forcing (TF) technique is used for easier incorporation of the feedback information without introducing additional recurrent loops during the training process. Furthermore, training ESN proxy models utilizes Ridge Regression, thus all calculations within have analytical solutions that guarantee much improved speed when evaluating forward model-runs, which further lowers the computational demand during the optimization process. The proposed workflow is typically more suitable for mature fields since reliable production data after breakthrough from each producer could greatly improve the training process, and it can be used under the circumstance where no reservoir model has been established. In this research, we present two test examples where we apply ESN to learn the reservoir simulation results of waterflood and further perform open-loop optimization on each of them.",5,5,2
Machine Learning,Rate of Penetration,"Tunkiel, Andrzej T.; Sui, Dan; Wiktorski, Tomasz",Reference dataset for rate of penetration benchmarking,Rate of Penetration; Machine learning; Benchmarking; Volve Dataset,MACHINE; MODELS,"In recent years, there were multiple papers published related to rate of penetration prediction using machine learning vastly outperforming analytical methods. There are models proposed reportedly achieving R2 values as high as 0.996. Unfortunately, it is most often impossible to independently verify these claims as the input data is rarely accessible to others. To solve this problem, this paper presents a database derived from Equinor's public Volve dataset that will serve as a benchmark for rate of penetration prediction methods. By providing a partially processed dataset with unambiguous testing scenarios, scientists can perform machine learning research on a level playing field. This in turn will both discourage publication of methods tested in a substandard manner as well as promote exploration of truly superior solutions. A set of seven wells with nearly 200-000 samples and twelve common attributes is proposed together with reference results from common machine learning algorithms. Data and relevant source code are published on the pages of University of Stavanger and GitHub.",4,4,1
Machine Learning,Rate of Penetration,"Alali, Ammar M.; Abughaban, Mahmoud F.; Aman, Beshir M.; Ravela, Sai",Hybrid data driven drilling and rate of penetration optimization,ROP; Optimization; Data-driven; Machine learning; Drilling mechanics; Real time adjustments,PREDICTION; INVERSION; ROP,"Optimizing the drilling process for cost and efficiency requires faster drilling with a higher rate of penetration (ROP). A high ROP usually indicates fast and cost-efficient drilling operations; however, high ROPs may induce unintended events, which may lead to nonproductive time (NPT). In this paper, the proposed hybrid, data-driven optimization system aims to improve the drilling process, maximize the ROP, and minimize NPT. This two-phase system leverages existing drilling data (Phase One) and real-time adjustments (Phase Two) to optimize drilling efficiency through the adjustment of controllable dynamic drilling parameters; weight on bit (WOB), pump flow rate (GPM), and rotary speed (RPM). In the first phase, geological data is queried to generate a model of drilling best practices in a certain field with attention to ROP and NPT. After the top-rated wells are identified, the model recommends adjustments to the controllable dynamic drilling parameters (WOB, GPM, RPM) and produces a cross-plot for each ROP. The optimum ROP parameter for each well is subsequently calculated as a conditioned mean based on proximity to the well as an Inverse Distance Weighting (IDW) interpolation. This phase is completed prior to any drilling activity. The second phase considers the model produced in phase one to run an automated drill-off test. The model directs the driller to deviate for controllable parameters WOB and RPM by a small percentage (0-5%), in a Constrained Random Search (CRS) way. These deviations allow the driller to explore new drilling conditions in small increments; the data is then compiled into a heat-map function of ROP and the model is updated to reflect optimum drilling parameters. The adjustments resulted in faster, safer ROP with a potential 22%+ improvement in efficiency and 15-20% cost-reduction. Lastly, to characterize the relationship between the controllable dynamic parameters (WOB, RPM, GPM) to the ROP, an ANN based empirical relationship was derived.",3,3,8
Machine Learning,Air Injection,"Wei, Wei; Rezazadeh, Alan; Wang, Jingyi; Gates, Ian D.",An analysis of toe-to-heel air injection for heavy oil production using machine learning,Heavy oil; In situ combustion; Toe-to-heel air injection; Machine learning; Data analytics; Clustering analysis,IN-SITU COMBUSTION; GRAVITY DRAINAGE; REACTION MODEL; RECOVERY; SIMULATION; SANDS,"With strong potential for improving productivity, economics, and efficiencies, data analytics and machine learning are rapidly emerging in the oil and gas industry. However, their application in heavy oil production is scarce. In this study, we use clustering methods to analyze the Kerrobert Toe-to-Heel Air Injection (THAI) project to understand the inter-relationships of production variables and seek for optimal operating strategy to maximize production rate. More specifically, we use the K-means, normal mixtures and hierarchical clustering methods to determine how operating parameters contribute to oil production. The results reveal that, at current operation mode, air injection rate is constrained for production maximization due to the balance between heat generation and cooling of combustion system by excess air supply. The results also provide insight for improved productivity from THAI suggesting that cyclic injection may improve process performance. The new insights demonstrate that data analytics can provide new understanding of recovery processes as well as potential process improvement.",6,6,0
Machine Learning,Air Injection,"Yin, Qishuai; Yang, Jin; Tyagi, Mayank; Zhou, Xu; Wang, Ning; Tong, Gang; Xie, Renjun; Liu, Hexing; Cao, Bohan",Downhole quantitative evaluation of gas kick during deepwater drilling with deep learning using pilot-scale rig data,Gas kick; Downhole quantitative evaluation; Pilot-scale test well experiment; Compressed air injection; Deep-water drilling,,"Gas kick occurs frequently during deep-water drilling operations caused by the lack of safe margin between pore pressure and leakage pressure. The existing research is limited to gas kick classification and cannot quantitatively evaluate the gas kick risk in the downhole very well. Thus, the objective of this work is to systematically use Long Short-Term Memory (LSTM) Recurrent Neural Network (RNN) models based on pilot-scale rig data for quantitative evaluation of gas kick risk. Furthermore, the quantitative evaluation is not surface but downhole. First, the gas kick simulation experiment is accomplished in the pilot-scale test well and produces the gas kick dataset, which is based on the multi-source data fusion through the surface monitoring technologies, riser monitoring technologies and downhole monitoring technologies. Second, the training features are selected and grouped as Sets1-5 to study the features' sensitivity. Third, the raw data is processed and prepared for the following machine learning framework. Fourth, there are five (5) LSTM models trained on Sets1-5. The results indicate that the models' Loss decrease with the increase of feature number, which has fully demonstrated the effectiveness of PWD, EKD, and Doppler parameters. Finally, there are four representative case studies (artificial gas kick) that are used to test the above five models. The compressed air injected rate (AR) prediction error and detection time-delay decrease with the increase of feature number. The LSTM model trained with the combination of surfaceriser-downhole comprehensive detection technologies performs the best in reducing both the prediction error and detection time delay, which could be used to quantitatively evaluate the downhole gas kick risk in the more accurate, faster, more stable, more reliable, and cost-effective manner, and it is effective and worthy of promotion.",3,3,4
Neural Network,Artificial Neural-networks,"Otchere, Daniel Asante; Ganat, Tarek Omar Arbi; Gholami, Raoof; Ridha, Syahrir",Application of supervised machine learning paradigms in the prediction of petroleum reservoir properties: Comparative analysis of ANN and SVM models,Artificial intelligence (AI); Supervised machine learning; Artificial neural network (ANN); Support vector machine (SVM); Relevance vector machine (RVM); Hybrid intelligent system,,"The advent of Artificial Intelligence (AI) in the petroleum industry has seen an increase in its use in exploration, development, production, reservoir engineering and management planning to accelerate decision making, reduce cost and time. Supervised machine learning has gained much popularity in establishing a relationship between complex non-linear datasets. This type of machine learning algorithm has showcased its superiority over petroleum engineering regression techniques in terms of prediction errors for high dimensional data, computational power and memory. This review focuses on the most widely used machine learning algorithm employed in the petroleum industry, the Artificial Neural Network (ANN) with different shallow models used in reservoir characterisation. The Support Vector Machine (SVM) and Relevant Vector Machine (RVM) has over the years emerged as competitive algorithms where in most cases based on this review it outperformed the ANN. This makes it preferable than the ANN when there are limited data sets. Finally, hybridisation of multiple algorithms methodologies also showed improved performance over singularly applied algorithms offering a pathway in improving reservoir characterisation based on supervised machine learning as future scope of work.",20,20,14
Neural Network,Artificial Neural-networks,"Sabah, Mohammad; Mehrad, Mohammad; Ashrafi, Seyed Babak; Wood, David A.; Fathi, Shadi",Hybrid machine learning algorithms to enhance lost-circulation prediction and management in the Marun oil field,Lost circulation while drilling; Multilayer perception; Least square support vector machine; Evolutionary algorithms; Marun oil field,ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINE; MULTILAYER PERCEPTRON; OPTIMIZATION; MODELS; RESERVOIR; ASMARI,"Drilling fluid loss of circulation is a challenging issue to resolve for many oil and gas wells as drilling progresses. It imposes enormous expenses on drilling industry. One of the common practices to solve this problem or make it less severe is introducing various loss circulation materials (LCM) into the circulating drilling fluid. The ability to predict the amount of mud loss before drilling a particular formation would provide engineers with invaluable information to assist them in selecting appropriate LCM properties such as particle size distribution. In this study, a number of heuristic search algorithms including genetic algorithm (GA), particle swarm size (PSO), and cuckoo search algorithm (COA) are combined with two machine-learning techniques namely multilayer perception (MLP) neural network and least square support vector machine (LSSVM) to present different hybrid algorithms in prediction of lost circulation. The established database consists of 2820 cases (datasets) extracted from available drilling reports of 305 drilled wells in the Marun oil field. These datasets are associated with drilling operation variables, formation specifications, and drilling mud characteristics which totally include 18 input variables and 1 output. Pre-processing of data involves filtering with Savitzky-Golay (SG) filter and ranking features using wrapper method. Results show that hybrid intelligent models are highly capable of predicting lost circulation before drilling a certain formation. Furthermore, LSSVM-COA and LSSVM-PSO achieve coefficients of determination of 0.9424 and 0.9391, respectively, making them the two most accurate models. GA cannot match the prediction performance of the other two algorithms in enhancing machine-learning techniques for this purpose. MLP-GA with a coefficient of determination (R-2) and RMSE of 0.9304 and 25.26 (bbl/hr), respectively, yields the weakest prediction performance. Hybrid intelligent models, coupling optimizers and machine learning algorithms show themselves to be superior to applying standalone machine-learning methodologies for predicting loss of circulation.",13,13,6
Neural Network,Artificial Neural-networks,"Mohammadi, Mohammad-Reza; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Husein, Maen M.; Ranjbar, Mohammad",Application of cascade forward neural network and group method of data handling to modeling crude oil pyrolysis during thermal enhanced oil recovery,In-situ combustion; EOR; Pyrolysis; TGA; Artificial neural networks; Group method of data handling,IN-SITU COMBUSTION; MINIMUM MISCIBILITY PRESSURE; GENERALIZED REGRESSION; COMPRESSIBILITY FACTOR; KINETICS; PREDICTION; VISCOSITY; HYBRID; ASPHALTENES; OXIDATION,"Oil recovery during in situ combustion is majorly controlled by hydrocarbon oxidation and pyrolysis reactions, which govern fuel formation and heat evolution. Fuel deposition, in turn, can be accurately predicted in part through crude oil pyrolysis using thermogravimetry analysis (TGA). The theoretical models based on TGA runs, however, may be limited to crude oil samples at hand. In this study, we develop more general models to predict the residual mass during crude oil pyrolysis based on multi-layer perceptron (MLP), cascade forward (CFNN), generalized regression (GRNN), and radial basis function (RBF) neural networks. More than 2000 experimental data spanning wide range of weight percentages of asphaltenes and resins as well as oAPI gravities, heating rates, and temperatures are used. Moreover, six optimization algorithms; including Bayesian regularization (BR), scaled conjugate gradient (SCG), Levenberg-Marquardt (LM), conjugate gradient backpropagation with FletcherReeves updates (CGF), resilient backpropagation (RB), and conjugate gradient backpropagation with PolakRibie ' re updates (CGP) are used to improve the performance and prediction ability of the MLP and CFNN neural networks. The CFNN model optimized with the LM algorithm best fits all the experimental data with a mean absolute percent relative error of 1.04%. Lastly, a mathematical correlation is developed utilizing the group method of data handling (GMDH) to estimate the residual mass of crude oil pyrolysis in TGA. Despite its simplicity, the correlation also provides very good estimates. Sensitivity analysis showed that temperature followed by asphaltenes and resin content showed the highest effect on mass loss during crude oil pyrolysis. Outliers estimation applying the Leverage approach suggested only 1% of the data points could be doubtful.",11,11,1
Neural Network,Artificial Neural-networks,"Mahmoud, Ahmed Abdulhamid; Elkatatny, Salaheldin; Al-AbdulJabbar, Ahmad",Application of machine learning models for real-time prediction of the formation lithology and tops from the drilling parameters,Formation lithology; Formation tops; Machine learning; Real-time; Drilling parameters,NEURAL-NETWORKS; LOG DATA; PENETRATION; RESERVOIRS,"Lithology changes significantly affect the drilling program and the total cost of drilling an oil well, therefore, it is very important to detect the lithology variation and formation tops while drilling. Nowadays, the lithology changes are estimated from the geological data, which increases the uncertainty, especially during the exploration phase because of the data limitation. This study investigates the ability to use three machine learning models, namely, the artificial neural networks (ANN), adaptive neuro-fuzzy inference system (ANFIS), and functional neural networks (FNN) to predict the lithology changes and the formation tops in real-time while drilling. These models were trained on 3162 datasets of six inputs (drilling parameters) to enable real-time prediction of the lithology changes and formation tops through four different formations of sandstone at top, followed by anhydrite, then carbonate with shale streaks, and finally carbonate formation. The optimized models were then tested on 1356 datasets gathered from a well other than the training well. The results of this study confirmed the high accuracy of the optimized ANN model which outperformed both ANFIS and FNN models in predicting the actual lithology distribution and formation tops through both training and testing wells. The ANN model predicted the different four formations considered in this study with an accuracy of more than 98.1% for training and testing data. Although the ANFIS and FNN models predicted the carbonate/shale formation top accurately for the training data, they were not able to predict the top of all formations accurately for the testing data.",7,7,3
Neural Network,Artificial Neural-networks,"Zhu, Zhaopeng; Song, Xianzhi; Li, Gensheng; Xu, Zhengming; Zhu, Shuo; Yao, Xuezhe; Jing, Silin",Prediction of the settling velocity of the rod-shaped proppant in vertical fracture using artificial neural network,Rod-shaped proppant; Settling orientation; Settling velocity; Vertical fracture; Neural network,,"As a new technology proppant, rod-shaped proppant is receiving more and more attention because it can greatly improve the performance of hydraulic fracturing. With special shape, the rod-shaped proppant is subject to greater flow resistance, resulting in complex migration in fractures. Accurate prediction of the settling velocity of rod proppant in fracture is important for predicting the transport distance and bed height of rod proppant in hydraulic fractures to improve the fracture performance. In this study, high-speed photography and transparent parallel plates were used to simulate and record the settling process of proppant in vertical fractures. A total of 588 effective tests were conducted to reveal the influence of proppant shape, fracturing fluid properties, and the wall effect of fracture on the settling characteristics involving the range of proppant aspect ratio and Reynolds number are 1.5-5.0 and 0.001-172.54, respectively. It was found that the rod proppant settled vertically at the low Reynolds number and horizontally at the high Reynolds number. First, an artificial neural network model of settling orientation with the prediction accuracy of 100% is established as the basis for predicting settlement velocity. The topological structure of the neural network is further extended to establish the prediction model of settling velocity with mean relative error of 1.21%. The relative importance of each input factor to the settling velocity was analyzed by the connection weights algorithm, and the weight and bias of the neural network are provided for the application and generalization of the model. Finally, the neural network model is evaluated objectively by comparing with the mathematical model. This study is a successful exploration of artificial intelligence in particle migration and will provide guidance for improving the performance of rod proppant in hydraulic fracturing.",6,6,5
Neural Network,Artificial Neural-networks,"Kwon, Seoyoon; Park, Gayoung; Jang, Youngho; Cho, Jinhyung; Chu, Min-gon; Min, Baehyun",Determination of oil well placement using convolutional neural network coupled with robust optimization under geological uncertainty,Convolutional neural network; Robust optimization; Well placement; Geological uncertainty,INTELLIGENCE APPLICATIONS; MODEL; PREDICTION,"This study integrates a convolutional neural network (CNN) within the framework of robust optimization for determining the placement of an oil production well at a petroleum reservoir under geological uncertainty. The proposed algorithm identifies the well location that maximizes the expectation of cumulative oil production of equiprobable realizations. CNN, which inputs near-wellbore permeability and outputs cumulative oil production at a feasible well location, is trained to correlate between petrophysical spatial data and hydrocarbon productivity with several realizations. The trained CNN estimates the productivity at every feasible well location for all given realizations. The approach is tested with application to a set of realizations describing a channelized oil reservoir with an aquifer. The validity of the approach is evaluated by comparing the similarity between the full-physics reservoir simulation (RS) and CNN results for qualified well locations. The most productive well location based on the simulation results is selected as the optimal well placement. The performance of the CNN is also compared with that of an artificial neural network (ANN) for cases with varied numbers of realizations that provide training data with the neural networks. CNN outperforms ANN because of its feature extraction of multi-dimensional data from convolution. A sensitivity analysis is conducted to analyze the effects of the volume of training data on the predictability of the neural networks with k-fold cross-validation. The findings highlight that the integrated approach can be used as an efficient decision-making tool for solving well placement optimization problems with accuracy at an affordable computational cost.",6,6,3
Neural Network,Artificial Neural-networks,"Cheraghi, Yasaman; Kord, Shahin; Mashayekhizadeh, Vahid",Application of machine learning techniques for selecting the most suitable enhanced oil recovery method; challenges and opportunities,Enhanced oil recovery; Reservoir engineering; EOR Screening; Advanced EOR Screening; Machine learning,,"A reliable method for selecting the most suitable Enhanced Oil Recovery (EOR) method is of a high necessity in reservoir engineering. Machine Learning (ML) techniques have been widely adopted as an effective and fast approach in primary stage of EOR screening. This paper presents a step-by-step procedure of applying ML in EOR screening with focusing on two main goals. Firstly, the problem of EOR screening is investigated from ML point of view. A large database consisting of more than 1000 experiences of worldwide EOR projects has been gathered from various sources. On the basis of this database, several ML models have been developed for predicting the suitable category of EOR methods for a candidate reservoir. These models include: Shallow and Deep Artificial Neural Networks (ANN), Naive Bayes (NB), Decision Tree (DT), Random Forest (RF) and Dimension Reduction using Principal Component Analysis (PCA). Almost all models performed well in predicting non-observed data with an average accuracy ranging from 80 to 90%. However, RF and the deep ANN models delivered the best performance with an average accuracy of 90%. The results demonstrated that RF model performed much better in comparison with the DT model and improved the classification accuracy from 85 to 91%. In case of ANNs, it was observed that the deeper ANN developed here, improved the classification accuracy from 83 to 90% in comparison with the shallow ANN with one hidden layer. The weakest performance was delivered by NB classifier with an average accuracy of 49%. As the second purpose of this research, reliability of screening results from applying ML techniques is discussed in details. Because, this approach suffers from some serious limitations and challenges, which could unfavorably affect the screening results and never had been considered in previous works. In this work, potential challenges and limitations associated with this well-known approach are introduced from database issues to modeling problems. Accordingly, an important conclusion is that application of ML, although providing a very good insight into primary EOR screening, should not be relied upon as the only method for predictions. It is recommended that the obtained results from this approach should be cross-checked with other EOR screening approaches or with methods based on expert's knowledge.",5,5,3
Neural Network,Artificial Neural-networks,"Gouda, Abdelrahman; Gomaa, Sayed; Attia, Attia; Emara, Ramadan; Desouky, S. M.; El-hoshoudy, A. N.",Development of an artificial neural network model for predicting the dew point pressure of retrograde gas condensate,Gas condensate; Dew point pressure; PVT; Artificial neural network model; Empirical correlations; And computer programing,DEWPOINT PRESSURE; RESERVOIRS; REGRESSION; EQUATION; MACHINE,"Optimal management and development plans for gas condensate reservoirs require authentic prediction for the dew point pressure (DPP). Traditionally, DPP is experimentally measured through a constant mass expansion test (CME), however, this test is relatively prohibitive and time-consuming. Equations of state and empirical correlations are employed in determining the (DPP), but due to the lack of generalized and inaccurate predictive paradigms, it is an incentive for researchers to establish new rigorous predictive models with wider applicability ranges and higher accuracy. This study tries to develop a new intelligent predictive model and to build a simple program based on 453 gas condensate samples that cover a wide range of chemical composition, reservoir temperatures, and fluid characteristics. The artificial neural network is conducted as an intelligent tool owing to its high capability and flexibility in defining the data pattern. A detailed comparison between widely used empirical correlations, PR-EOS, SRK- EOS, and the proposed new ANN model is provided in this study. Statistical and graphical analysis depicted the outstanding performance of the new model with R2 = 95.3%, ARE = 0.0069% and AARE = 5.03%.",4,4,2
Neural Network,Artificial Neural-networks,"Mahmoodpour, Soran; Kamari, Ehsan; Esfahani, Mohammad Reza; Mehr, Amir Karimi",Prediction of cementation factor for low-permeability Iranian carbonate reservoirs using particle swarm optimization-artificial neural network model and genetic programming algorithm,The cementation factor of carbonate reservoirs; RCAL data; Hybrid PSO-ANN model; Genetic programming algorithm,,"cementation factor is a crucial parameter that has a significant influence on the estimation of reservoir parameters. Laboratory measurements for cementation factor are available for occasional cases because experimental special core analyses for determination of cementation factor values are expensive and time-consuming. While this factor plays a significant role in determining water saturation, there is no comprehensive and precise relationship for the case of Iranian carbonate reservoirs. In this article, a unique model was used based on a powerful combination of artificial neural network (ANN) and particle swarm optimization (PSO) algorithm to model the cementation factor. In the second phase of simulation, a correlation for the cementation factor was discovered by genetic programming (GP) algorithm. Both the PSO-ANN model and GP algorithm are trained by input variables such as porosity, permeability, and grain density derived from 175 routine core analysis (RCAL) samples of 21 carbonated oil fields. To determine the relative impact of the independent variables on cementation factor the sensitivity analysis was carried out for both models. The comparison between the PSO-ANN model output and the experimental cementation factor data clearly demonstrated that the built model can predict the cementation factor with great precision; the mean square error between the model predictions and the experimental data was less than 0.07. The root mean square error of training and testing data sets for the new developed correlation using GP algorithm were 0.0902 and 0.0727 respectively. Finally, to evaluate the validity and reliability of the developed models, a comparison was implemented between these two models and other empirical models over an external employment data set (21 data point). This comparison revealed that the GP algorithm and PSO-ANN model deliver a higher performance capacity compared to other proposed correlations for predicting cementation exponent.",4,4,0
Neural Network,Artificial Neural-networks,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Neural Network,Artificial Neural-networks,"Yin, Qishuai; Yang, Jin; Tyagi, Mayank; Zhou, Xu; Wang, Ning; Tong, Gang; Xie, Renjun; Liu, Hexing; Cao, Bohan",Downhole quantitative evaluation of gas kick during deepwater drilling with deep learning using pilot-scale rig data,Gas kick; Downhole quantitative evaluation; Pilot-scale test well experiment; Compressed air injection; Deep-water drilling,,"Gas kick occurs frequently during deep-water drilling operations caused by the lack of safe margin between pore pressure and leakage pressure. The existing research is limited to gas kick classification and cannot quantitatively evaluate the gas kick risk in the downhole very well. Thus, the objective of this work is to systematically use Long Short-Term Memory (LSTM) Recurrent Neural Network (RNN) models based on pilot-scale rig data for quantitative evaluation of gas kick risk. Furthermore, the quantitative evaluation is not surface but downhole. First, the gas kick simulation experiment is accomplished in the pilot-scale test well and produces the gas kick dataset, which is based on the multi-source data fusion through the surface monitoring technologies, riser monitoring technologies and downhole monitoring technologies. Second, the training features are selected and grouped as Sets1-5 to study the features' sensitivity. Third, the raw data is processed and prepared for the following machine learning framework. Fourth, there are five (5) LSTM models trained on Sets1-5. The results indicate that the models' Loss decrease with the increase of feature number, which has fully demonstrated the effectiveness of PWD, EKD, and Doppler parameters. Finally, there are four representative case studies (artificial gas kick) that are used to test the above five models. The compressed air injected rate (AR) prediction error and detection time-delay decrease with the increase of feature number. The LSTM model trained with the combination of surfaceriser-downhole comprehensive detection technologies performs the best in reducing both the prediction error and detection time delay, which could be used to quantitatively evaluate the downhole gas kick risk in the more accurate, faster, more stable, more reliable, and cost-effective manner, and it is effective and worthy of promotion.",3,3,4
Neural Network,Well Logs,"Tian, Miao; Omre, Henning; Xu, Huaimin",Inversion of well logs into lithology classes accounting for spatial dependencies by using hidden markov models and recurrent neural networks,Hidden markov model; Recurrent neural network; Lithology classification; Well logs inversion,STATISTICAL-ANALYSIS; FACIES; IDENTIFICATION; CLASSIFICATION; PREDICTION,"Lithology is a crucial factor in reservoir characterization. Due to the limited availability of cores, the classes of the subsurface lithologies in boreholes need to be predicted from indirect measurements like well logs. However, the spatial interdependence between sediments and the spatial coupling between the well logs data pose challenges in this lithology classification. Numerous proposed classifiers are based on spatial element-wise independence and these classifiers usually fail to provide accurate predictions. In this study, we focus on two classification models from the Bayesian and the deep learning framework, which both take spatial context into account. We discuss a kernel-based hidden Markov (HM) model and a kind of recurrent neural network model named gated recurrent unit (GRU). Cross-validation results from these two models of three partially cored real wells are compared to result from a simple non-spatial deep neural network (DNN) model. The cross-validation results indicate that the lithology classifiers from models taking vertical spatial dependency into account are much more reliable in terms of classification accuracy and geological interpretation. The probabilistically defined HM model performs better than the neural network GRU model.",10,10,5
Neural Network,Well Logs,"Ali, Muhammad; Jiang, Ren; Ma, Huolin; Pan, Heping; Abbas, Khizar; Ashraf, Umar; Ullah, Jar",Machine learning-A novel approach of well logs similarity based on synchronization measures to predict shear sonic logs,Machine learning; Geophysical similarity analysis; Multidimensional scaling; Jaccard and Overlap similarities; Well logs,,"This study proposes a novel approach to predict missing shear sonic log responses more precisely and accurately using similarity patterns of various wells with similar geophysical properties, which is important in decision making and planning of hydrocarbon exploration. Deep Neural Network (DNN) along with the similarity metrics such as Jaccard and Overlap similarities are employed to examine the relationship between the wells. Further, dimensionality reduction techniques including Multi-Dimensional Scaling (MDS) and well-ranking process are applied to extract common geophysical responses of the wells. A higher response indicates the existence of a strong similarity. This can also be verified by the superimposed of well log data. The potential benefits of our novel method are following; (a) it does not follow the zone-by-zone prediction of the missing logs such as rock physics methods, (b) it outputs the uncertainties facilitated that is by the least-squares method. Having the potential of demonstrating shear sonic log prediction in hydrocarbon-bearing zones, which cannot be precisely predicted by the Greenberg-Castagna method that only works in brine-saturated rocks, this approach will provide improved accuracy, where shear sonic logs are missing and need to be predicted for geomechanics, rock physics, and other applications.",10,10,5
Neural Network,Well Logs,"Alzubaidi, Fatimah; Mostaghimi, Peyman; Swietojanski, Pawel; Clark, Stuart R.; Armstrong, Ryan T.",Automated lithology classification from drill core images using convolutional neural networks,Convolutional neural networks; Deep learning; Lithology logs; Core analysis,FACIES ANALYSIS; WELL LOGS; PREDICTION; LITHOFACIES,"In hydrocarbon reservoir evaluation, lithology is a key characteristic for determination of storage capacity and rock properties. Lithology is usually predicted from well log data or directly identified through manual inspection by geologists during core logging. Automatic prediction of lithology has been a focus of many studies inspired by rapid developments in machine learning. Studies mostly focus on predicting lithofacies from well logs using neural networks, and more recently from borehole image logs using convolutional neural network (CNN). Although core is more representative of reservoir lithology than well log data, employing machine learning for automatic lithology identification from core is limited. A CNN-based approach is developed to classify core images into three lithologies: sandstone, limestone, and shale. The model is based on ResNeXt-50 architecture, which had better performance in lithology prediction than ResNet-18 and Inception-v3 architectures. Our method processes core tray images and outputs lithology logs in a fully automated procedure and predicts the lithologies of new (unseen) core with an accuracy of 93.12%.",9,11,13
Neural Network,Well Logs,"Mahmoud, Ahmed Abdulhamid; Elkatatny, Salaheldin; Al-AbdulJabbar, Ahmad",Application of machine learning models for real-time prediction of the formation lithology and tops from the drilling parameters,Formation lithology; Formation tops; Machine learning; Real-time; Drilling parameters,NEURAL-NETWORKS; LOG DATA; PENETRATION; RESERVOIRS,"Lithology changes significantly affect the drilling program and the total cost of drilling an oil well, therefore, it is very important to detect the lithology variation and formation tops while drilling. Nowadays, the lithology changes are estimated from the geological data, which increases the uncertainty, especially during the exploration phase because of the data limitation. This study investigates the ability to use three machine learning models, namely, the artificial neural networks (ANN), adaptive neuro-fuzzy inference system (ANFIS), and functional neural networks (FNN) to predict the lithology changes and the formation tops in real-time while drilling. These models were trained on 3162 datasets of six inputs (drilling parameters) to enable real-time prediction of the lithology changes and formation tops through four different formations of sandstone at top, followed by anhydrite, then carbonate with shale streaks, and finally carbonate formation. The optimized models were then tested on 1356 datasets gathered from a well other than the training well. The results of this study confirmed the high accuracy of the optimized ANN model which outperformed both ANFIS and FNN models in predicting the actual lithology distribution and formation tops through both training and testing wells. The ANN model predicted the different four formations considered in this study with an accuracy of more than 98.1% for training and testing data. Although the ANFIS and FNN models predicted the carbonate/shale formation top accurately for the training data, they were not able to predict the top of all formations accurately for the testing data.",7,7,3
Neural Network,Well Logs,"Sun, Jian; Chen, Mingqiang; Li, Qi; Ren, Long; Dou, Mengyuan; Zhang, Jixuan",A new method for predicting formation lithology while drilling at horizontal well bit,Logging while drilling; Machine learning; Real-time interpretation; Lithology prediction,IDENTIFICATION; CLASSIFICATION; ALGORITHMS,"The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of ""zero length"" (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the ""zero length"" on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.",4,5,3
Neural Network,Well Logs,"Zahmatkesh, Iman; Kadkhodaie, Ali; Soleimani, Bahman; Azarpour, Moslem","Integration of well log-derived facies and 3D seismic attributes for seismic facies mapping: A case study from mansuri oil field, SW Iran",Seismic facies analysis; Seismic attributes; Well log facies; Reservoir quality; Asmari reservoir; Supervised neural network,MULTIATTRIBUTE TRANSFORMS; GAS-FIELD; CLASSIFICATION; RESERVOIR; CARBONATE; MACHINE; IDENTIFICATION; PARAMETERS; EXAMPLE; PART,"The recognition and mapping of rock facies is a pivotal step in reliable reservoir characterization and planning development operations. The present study aimed to present a practical workflow by integrating threedimensional (3D) seismic attributes and well-log facies analysis to determine the spatial distribution of electrofacies rock types of the Oligo-Miocene Asmari reservoir in Mansuri oilfield located in the southwestern part of Iran. The workflow begins with integrating well logs, core data, and geological information from the selected ?key wells? to build an electrofacies model, which could help reservoir facies to be classified and estimated in the cored and uncored wells, respectively. In addition, a group of 3D seismic attribute volumes derived from amplitude, frequency, and time characteristics of the post-stacked 3D seismic data were identified to specify the heterogeneity of the vertical and lateral rock facies within the reservoir. Additionally, the seismic attributes were analyzed using unsupervised and supervised learning techniques to identify seismic facies. The extraction of the seismic facies at multiple-well locations within the 3D classified volumes demonstrated that the supervised neural network learning method, as compared to the unsupervised approach, could more accurately estimate the desired seismic facies. The results of the ultimate rock facies maps of different vertical slices in the Asmari reservoir indicated that electrofacies with good reservoir quality were best developed on the top of the reservoir, mostly with NW-SE elongation at the crest line of the structure. The applied workflow allowed the localities of the buried sand channels to be identified and mapped. Accordingly, seismic facies mapping shed light on the spatial heterogeneity and quality of the reservoir, which could be used to guide the development drilling for optimal recovering of the unswept hydrocarbons.",4,4,3
Neural Network,Well Logs,"Yuan, Zhenyu; Huang, Handong; Jiang, Yuxin; Li, Jingjing",Hybrid deep neural networks for reservoir production prediction,Hybrid networks; Deep neural networks; Convolutional neural networks; Multiple sources; Structural measurements; Production prediction,,"For production prediction, existing physics-based methods often depend on some hypotheses and are confined to certain types of reservoirs. Some data-driven methods take single-source or single-type data as inputs and discard the spatial correlation of reservoir formation contained in structural measurements. Taking multi-source, mixed-type measurements into consideration, we developed an architecture of hybrid deep neural networks (HDNNs) for reservoir production prediction. Despite discrete geologic and engineering measurements, some structural data such as logging images and curves, which contains more details with reservoir formations, were taken as inputs. Hybrid architecture is the key to establish complex nonlinear relationship between target production and mixed inputs. Multiple networks were aggregated to cope with different measurements. For instance, convolutional neural networks (CNN) and multilayer perceptron (MLP) network were configured to separately extract features from structural and discrete inputs. Learned features were then concatenated and fed to subsequent networks for target learning. The implementation of the proposed network consists of four steps: data gathering, data preprocessing, model training and target inferencing. For gathered structural, numerical and categorical data, some essential preprocesses like resampling, normalizing and one-code encoding were performed to prepare dataset for model training. Applied to a development oil block and compared with a typical MLP model and CNN model, the proposed HDNN model stands out with high accuracy and good generalization. The HDNN model converges well both on training and validation dataset. The performance on test dataset demonstrates high accuracy with relative mean absolute error as 6.28%. Further application on three test wells achieved acceptable prediction results.",4,4,3
Neural Network,Well Logs,"Arno, Mikkel Leite; Godhavn, John-Morten; Aamo, Ole Morten",At-bit estimation of rock density from real-time drilling data using deep learning with online calibration,At-bit virtual density log; Deep learning; Streaming learning,,"We present a novel streaming learning approach, utilizing a deep neural network (DNN) to learn from data available during operation to estimate at-bit density using drilling parameters. Since every wellbore is different, the relationship between drilling parameters and at-bit density varies. Equipment used, well trajectory, friction and bit wear are examples of conditions that affect this relationship and makes a pre-trained model unable to represent an accurate input/output mapping applicable to all wells. However, using delayed density log measurements, continuously supervising updates to the model is possible during operation. The algorithm has been tested on drilling data from wells on a field operated by Equinor and compared to a standard deep learning approach, where results show that a streaming learning approach outperforms the traditional method. Statistical analyses have been performed to verify the statistical significance and effect size on the data sets. Data visualizations using a t-distributed Stochastic Neighbor Embedding (t-SNE) indicate that the relationship between drilling parameters and density log indeed vary between wellbores, making generalizability an issue for a traditional supervised learning approach to this problem, and motivating a streaming learning approach. Using the proposed method, more accurate at-bit estimates can be made, providing preliminary indications ahead of the tool placed 20-30 m behind the bit, which, dependent on rate of penetration (ROP), will be available 20-120 min later.",4,4,2
Neural Network,Well Logs,"Tatsipie, Nelson R. K.; Sheng, James J.",Generating pseudo well logs for a part of the upper Bakken using recurrent neural networks,Well logs; Recurrent neural networks; Gamma ray,,"To develop a reservoir, we need to understand the distribution of key reservoir properties. Those formation properties are mostly derived from well log data. However, obtaining well log data is so expensive that the data we acquire is never sufficient. Therefore, we need to create pseudo data from real measured data. One approach is to generate synthetic well logs using recurrent neural networks (RNNs). Though relatively nascent, it is proven that RNNs allow for the generation of well logs with reasonable accuracy at a fraction of the price. Currently, gamma ray is the most cultivated well log in the E&P process today (owing to its decisive role during drilling operations and affordable price). All the same, a more extensive log suite is required to comprehend the producibility and frackability of hydrocarbon reservoirs like shale reservoirs. In this study, an upper Bakken database of 97 wells which contain gamma ray, bulk density, photoelectric index, density porosity, neutron porosity, true resistivity, compressional and shear slowness was used to develop deep learning models apt to creating synthetic logs for another set of 40 wells in the upper Bakken. The latter wells only had measured gamma ray. Using petroleum engineering concepts and RNNs, data-driven models capable of generating the remaining logs were created. The data-driven models were validated using wells with logs that have been removed from the database to serve as blind validation wells. The performance of the models (5-10 Mean Average Percentage Error and R-squared of 0.6-0.8) suggests the workflow described in this study is a viable way to maximize the value of a gamma ray log. With the ability to generate logs of similar quality for all wells in a shale asset (starting only with gamma ray), superior reservoir evaluation and thus improved reservoir management can be achieved.",4,4,1
Neural Network,Results Show,"Sabah, Mohammad; Mehrad, Mohammad; Ashrafi, Seyed Babak; Wood, David A.; Fathi, Shadi",Hybrid machine learning algorithms to enhance lost-circulation prediction and management in the Marun oil field,Lost circulation while drilling; Multilayer perception; Least square support vector machine; Evolutionary algorithms; Marun oil field,ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINE; MULTILAYER PERCEPTRON; OPTIMIZATION; MODELS; RESERVOIR; ASMARI,"Drilling fluid loss of circulation is a challenging issue to resolve for many oil and gas wells as drilling progresses. It imposes enormous expenses on drilling industry. One of the common practices to solve this problem or make it less severe is introducing various loss circulation materials (LCM) into the circulating drilling fluid. The ability to predict the amount of mud loss before drilling a particular formation would provide engineers with invaluable information to assist them in selecting appropriate LCM properties such as particle size distribution. In this study, a number of heuristic search algorithms including genetic algorithm (GA), particle swarm size (PSO), and cuckoo search algorithm (COA) are combined with two machine-learning techniques namely multilayer perception (MLP) neural network and least square support vector machine (LSSVM) to present different hybrid algorithms in prediction of lost circulation. The established database consists of 2820 cases (datasets) extracted from available drilling reports of 305 drilled wells in the Marun oil field. These datasets are associated with drilling operation variables, formation specifications, and drilling mud characteristics which totally include 18 input variables and 1 output. Pre-processing of data involves filtering with Savitzky-Golay (SG) filter and ranking features using wrapper method. Results show that hybrid intelligent models are highly capable of predicting lost circulation before drilling a certain formation. Furthermore, LSSVM-COA and LSSVM-PSO achieve coefficients of determination of 0.9424 and 0.9391, respectively, making them the two most accurate models. GA cannot match the prediction performance of the other two algorithms in enhancing machine-learning techniques for this purpose. MLP-GA with a coefficient of determination (R-2) and RMSE of 0.9304 and 25.26 (bbl/hr), respectively, yields the weakest prediction performance. Hybrid intelligent models, coupling optimizers and machine learning algorithms show themselves to be superior to applying standalone machine-learning methodologies for predicting loss of circulation.",13,13,6
Neural Network,Results Show,"Yuyang, Liu; Xinhua, Ma; Xiaowei, Zhang; Wei, Guo; Lixia, Kang; Rongze, Yu; Yuping, Sun",Shale gas well flowback rate prediction for Weiyuan field based on a deep learning algorithm,Shale gas; Deep learning; Flowback characteristic; Flowback rate; Data analysis,SICHUAN BASIN; SIMULATION; MODEL,"The flowback rate of a shale gas well is controlled by many factors, such as geological and engineering factors, which have a certain complexity. For the aforementioned reason, the knowledge-driven method often has difficulty effectively capturing the correlation rules among multiple datasets. As a data-driven algorithm, deep learning has strong advantages in data correlation analysis, nonlinear fitting and other applications. In this paper, an algorithm is set up to forecast the shale gas well flowback rate by using a deep learning algorithm based on the flowback characteristic factors and data from 286 shale gas wells in the Weiyuan field. An algorithm and prediction model of the flowback parameters of the Weiyuan shale gas wells is established to effectively capture their flowback characteristics. First, the general situation of the study area is briefly introduced, and the data used to predict the flowback rate in this area are analyzed. Second, based on the deep learning algorithm, two kinds of deep feedforward neural network structures and a neural network-based prediction method of shale gas well flowback rate are designed. Finally, according to the regional data, the prediction and analysis of the flowback rate of Weiyuan shale gas wells are carried out. The results show that the correlations between 17 factors, such as fracturing section length and shale gas well flowback rate, are not obvious, but that the deep learning method proposed in this paper can effectively and accurately capture the correlations between the data and predict the flowback rate. The results show high accuracy.",7,7,6
Neural Network,Results Show,"Liu, Cancan; Zhan, Qinjian; Yang, Lu; Zheng, Xigui; Li, Peng; Shahani, Niaz Muhammad",Recognition of interface and category of roadway roof strata based on drilling parameters,Measurement while drilling; Drilling parameters; Strata interface; Strata category; Pattern recognition,,"Measurement while drilling is an important part of the intelligent development of coal mines and the development trend of roof formation detection. The main purpose of this paper is to study the best identification method of rock interface and category based on drilling parameters. Firstly, the borehole drilling device was independently developed; Secondly, 4 concrete blocks were poured to simulate the different rock formations; Thirdly, displacement, rotational speed, torque, and sound pressure level data were collected during drilling the concrete blocks, and the original data was processed by the local linear kernel estimation method; Finally, Kmeans clustering and change points detection method, was used to identify the rock formation interface respectively, and BP neural network and support vector machine method was used to identify the rock category respectively. Experimental results show that the local linear kernel estimation method based on exponentially weighted loss function can better reflect the response characteristics of drilling parameters. The change point detection method based on the penetration rate is better for the rock interface prediction (the sum of the two interface errors is 10.25 mm). Besides, with the penetration rate and sound pressure level as input parameters, BP neural network and support vector machine can achieve the operational classification of rock formations. This research is of great significance for understanding the prediction of the interface and category of rock formation in coal mines, which can not only promote safe mining but also reflect efficient coal production.",5,5,13
Neural Network,Results Show,"Ali, Naseem; Viggiano, Bianca; Tutkun, Murat; Cal, Raul Bayoan",Data-driven machine learning for accurate prediction and statistical quantification of two phase flow regimes,Reduced model; System identification; BI-LSTM; Transfer function,FEEDBACK-CONTROL; IDENTIFICATION,Two different two-phase flow regimes including slug and dispersed flows are examined through the implementation of system identification methods to attain reduced-order models. The obtained models accurately capture the flow dynamics of the studied regimes. The models also provide state-space frequency by defining the transfer functions. The system identification results are compared with those of the bidirectional neural network to predict the phase fraction of the considered two-phase flows. The result of long short-term memory shows correlations of 91% between the real and predicted phase fractions.,5,5,6
Neural Network,Results Show,"Lu, Hao; Li, Qing; Yue, Dali; Wu, Shenghe; Fu, Yupu; Tang, Renzhi; Zhang, Zhenyu","Study on optimal selection of porosity logging interpretation methods for Chang 7(3) segment of the Yanchang Formation in the southwestern Ordos Basin, China",Zhangjiatan Shale; Tuff; Multi-component volume model; Back propagation neural network; Logging parameter; Error analysis,SHALE; MODEL,"The physical properties of tight shale reservoirs have always been a hot topic of discussion, and the tuff reservoirs have also attracted more and more attention. Log predicting of the porosity is also important for the exploration and development of tight oil. Tight oil resources have been found in tight shale and tuff reservoirs in the Chang 7 Member of the Upper Triassic Yanchang Formation in the Ordos Basin, China. However, the logging method that effectively predicting porosity of the Chang 7 Member is lacking, and few people have discussed how to optimize the log interpretation methods. In this study, the characteristics of shale and tuff reservoirs were summarized by microscope and scanning electron microscope observation, X-ray diffraction, pore and permeability experiment, and the logging data. In order to find the optimal method of porosity prediction, four methods were performed: multiple regression fitting, multi-component volume model, porosity logging formula, and back propagation neural network method. The ""Zhangjiatan Shale"" of the Chang 7 Member is characterized by abundant sandy lamina and tuff lamina, compared with the tuff reservoir, the enrichment of pyrite (average 22.7 wt%) and total organic matter (>6%) increase the content of intercrystalline pores and organic matter related pores, the logging response is characterized by high natural gamma ray, low spontaneous potential and high acoustic. The tuff reservoir is mainly composed of vitric tuff and crystal-vitric tuff, hence, the rich in intergranular pore and micro-fracture can be explained by the dissolution and devitrification of vitric and crystal fragments, and the logging characteristic is opposite to that of the ""Zhangjiatan Shale"". Four methods for predicting porosity are established. First, appropriate logging parameters are selected for regression fitting in the ""Zhangjiatan Shale"" (e.g., gamma ray, deep lateral logging resistivity, density and spontaneous potential) and tuff reservoir (e.g., acoustic, density, compensated neutron logging). Then, the rock multi-component volume model was established as rock skeleton, clay or tuff matter, organic matter, and pores. The logging parameters of the skeleton, clay and organic matter were obtained by intersection graphs, which were applied in the improved porosity logging formulas. The effect of organic matter on logging was considered into the traditional porosity prediction formula, a third prediction method was established. Finally, the BP method was introduced into the porosity prediction work, and the neural network parameters were adjusted according to the log and porosity data. The learning rate and the learning accuracy were set as 0.1 and 10(-6) in the study area. The error analysis between the result predicted and measured shows that the multi-component volume model is suitable for the ""Zhangjiatan Shale"" (the correlative coefficient R>80%), while the back propagation neural network is the best method for the tuff reservoir (the correlative coefficient R>90%).",4,4,8
Neural Network,Results Show,"Arno, Mikkel Leite; Godhavn, John-Morten; Aamo, Ole Morten",At-bit estimation of rock density from real-time drilling data using deep learning with online calibration,At-bit virtual density log; Deep learning; Streaming learning,,"We present a novel streaming learning approach, utilizing a deep neural network (DNN) to learn from data available during operation to estimate at-bit density using drilling parameters. Since every wellbore is different, the relationship between drilling parameters and at-bit density varies. Equipment used, well trajectory, friction and bit wear are examples of conditions that affect this relationship and makes a pre-trained model unable to represent an accurate input/output mapping applicable to all wells. However, using delayed density log measurements, continuously supervising updates to the model is possible during operation. The algorithm has been tested on drilling data from wells on a field operated by Equinor and compared to a standard deep learning approach, where results show that a streaming learning approach outperforms the traditional method. Statistical analyses have been performed to verify the statistical significance and effect size on the data sets. Data visualizations using a t-distributed Stochastic Neighbor Embedding (t-SNE) indicate that the relationship between drilling parameters and density log indeed vary between wellbores, making generalizability an issue for a traditional supervised learning approach to this problem, and motivating a streaming learning approach. Using the proposed method, more accurate at-bit estimates can be made, providing preliminary indications ahead of the tool placed 20-30 m behind the bit, which, dependent on rate of penetration (ROP), will be available 20-120 min later.",4,4,2
Neural Network,Results Show,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Neural Network,Gas,"Sabah, Mohammad; Mehrad, Mohammad; Ashrafi, Seyed Babak; Wood, David A.; Fathi, Shadi",Hybrid machine learning algorithms to enhance lost-circulation prediction and management in the Marun oil field,Lost circulation while drilling; Multilayer perception; Least square support vector machine; Evolutionary algorithms; Marun oil field,ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINE; MULTILAYER PERCEPTRON; OPTIMIZATION; MODELS; RESERVOIR; ASMARI,"Drilling fluid loss of circulation is a challenging issue to resolve for many oil and gas wells as drilling progresses. It imposes enormous expenses on drilling industry. One of the common practices to solve this problem or make it less severe is introducing various loss circulation materials (LCM) into the circulating drilling fluid. The ability to predict the amount of mud loss before drilling a particular formation would provide engineers with invaluable information to assist them in selecting appropriate LCM properties such as particle size distribution. In this study, a number of heuristic search algorithms including genetic algorithm (GA), particle swarm size (PSO), and cuckoo search algorithm (COA) are combined with two machine-learning techniques namely multilayer perception (MLP) neural network and least square support vector machine (LSSVM) to present different hybrid algorithms in prediction of lost circulation. The established database consists of 2820 cases (datasets) extracted from available drilling reports of 305 drilled wells in the Marun oil field. These datasets are associated with drilling operation variables, formation specifications, and drilling mud characteristics which totally include 18 input variables and 1 output. Pre-processing of data involves filtering with Savitzky-Golay (SG) filter and ranking features using wrapper method. Results show that hybrid intelligent models are highly capable of predicting lost circulation before drilling a certain formation. Furthermore, LSSVM-COA and LSSVM-PSO achieve coefficients of determination of 0.9424 and 0.9391, respectively, making them the two most accurate models. GA cannot match the prediction performance of the other two algorithms in enhancing machine-learning techniques for this purpose. MLP-GA with a coefficient of determination (R-2) and RMSE of 0.9304 and 25.26 (bbl/hr), respectively, yields the weakest prediction performance. Hybrid intelligent models, coupling optimizers and machine learning algorithms show themselves to be superior to applying standalone machine-learning methodologies for predicting loss of circulation.",13,13,6
Neural Network,Gas,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Neural Network,Gas,"Yuyang, Liu; Xinhua, Ma; Xiaowei, Zhang; Wei, Guo; Lixia, Kang; Rongze, Yu; Yuping, Sun",Shale gas well flowback rate prediction for Weiyuan field based on a deep learning algorithm,Shale gas; Deep learning; Flowback characteristic; Flowback rate; Data analysis,SICHUAN BASIN; SIMULATION; MODEL,"The flowback rate of a shale gas well is controlled by many factors, such as geological and engineering factors, which have a certain complexity. For the aforementioned reason, the knowledge-driven method often has difficulty effectively capturing the correlation rules among multiple datasets. As a data-driven algorithm, deep learning has strong advantages in data correlation analysis, nonlinear fitting and other applications. In this paper, an algorithm is set up to forecast the shale gas well flowback rate by using a deep learning algorithm based on the flowback characteristic factors and data from 286 shale gas wells in the Weiyuan field. An algorithm and prediction model of the flowback parameters of the Weiyuan shale gas wells is established to effectively capture their flowback characteristics. First, the general situation of the study area is briefly introduced, and the data used to predict the flowback rate in this area are analyzed. Second, based on the deep learning algorithm, two kinds of deep feedforward neural network structures and a neural network-based prediction method of shale gas well flowback rate are designed. Finally, according to the regional data, the prediction and analysis of the flowback rate of Weiyuan shale gas wells are carried out. The results show that the correlations between 17 factors, such as fracturing section length and shale gas well flowback rate, are not obvious, but that the deep learning method proposed in this paper can effectively and accurately capture the correlations between the data and predict the flowback rate. The results show high accuracy.",7,7,6
Neural Network,Gas,"Gouda, Abdelrahman; Gomaa, Sayed; Attia, Attia; Emara, Ramadan; Desouky, S. M.; El-hoshoudy, A. N.",Development of an artificial neural network model for predicting the dew point pressure of retrograde gas condensate,Gas condensate; Dew point pressure; PVT; Artificial neural network model; Empirical correlations; And computer programing,DEWPOINT PRESSURE; RESERVOIRS; REGRESSION; EQUATION; MACHINE,"Optimal management and development plans for gas condensate reservoirs require authentic prediction for the dew point pressure (DPP). Traditionally, DPP is experimentally measured through a constant mass expansion test (CME), however, this test is relatively prohibitive and time-consuming. Equations of state and empirical correlations are employed in determining the (DPP), but due to the lack of generalized and inaccurate predictive paradigms, it is an incentive for researchers to establish new rigorous predictive models with wider applicability ranges and higher accuracy. This study tries to develop a new intelligent predictive model and to build a simple program based on 453 gas condensate samples that cover a wide range of chemical composition, reservoir temperatures, and fluid characteristics. The artificial neural network is conducted as an intelligent tool owing to its high capability and flexibility in defining the data pattern. A detailed comparison between widely used empirical correlations, PR-EOS, SRK- EOS, and the proposed new ANN model is provided in this study. Statistical and graphical analysis depicted the outstanding performance of the new model with R2 = 95.3%, ARE = 0.0069% and AARE = 5.03%.",4,4,2
Neural Network,Gas,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Neural Network,Gas,"Yin, Qishuai; Yang, Jin; Tyagi, Mayank; Zhou, Xu; Wang, Ning; Tong, Gang; Xie, Renjun; Liu, Hexing; Cao, Bohan",Downhole quantitative evaluation of gas kick during deepwater drilling with deep learning using pilot-scale rig data,Gas kick; Downhole quantitative evaluation; Pilot-scale test well experiment; Compressed air injection; Deep-water drilling,,"Gas kick occurs frequently during deep-water drilling operations caused by the lack of safe margin between pore pressure and leakage pressure. The existing research is limited to gas kick classification and cannot quantitatively evaluate the gas kick risk in the downhole very well. Thus, the objective of this work is to systematically use Long Short-Term Memory (LSTM) Recurrent Neural Network (RNN) models based on pilot-scale rig data for quantitative evaluation of gas kick risk. Furthermore, the quantitative evaluation is not surface but downhole. First, the gas kick simulation experiment is accomplished in the pilot-scale test well and produces the gas kick dataset, which is based on the multi-source data fusion through the surface monitoring technologies, riser monitoring technologies and downhole monitoring technologies. Second, the training features are selected and grouped as Sets1-5 to study the features' sensitivity. Third, the raw data is processed and prepared for the following machine learning framework. Fourth, there are five (5) LSTM models trained on Sets1-5. The results indicate that the models' Loss decrease with the increase of feature number, which has fully demonstrated the effectiveness of PWD, EKD, and Doppler parameters. Finally, there are four representative case studies (artificial gas kick) that are used to test the above five models. The compressed air injected rate (AR) prediction error and detection time-delay decrease with the increase of feature number. The LSTM model trained with the combination of surfaceriser-downhole comprehensive detection technologies performs the best in reducing both the prediction error and detection time delay, which could be used to quantitatively evaluate the downhole gas kick risk in the more accurate, faster, more stable, more reliable, and cost-effective manner, and it is effective and worthy of promotion.",3,3,4
Neural Network,Pattern,"Ali, Muhammad; Jiang, Ren; Ma, Huolin; Pan, Heping; Abbas, Khizar; Ashraf, Umar; Ullah, Jar",Machine learning-A novel approach of well logs similarity based on synchronization measures to predict shear sonic logs,Machine learning; Geophysical similarity analysis; Multidimensional scaling; Jaccard and Overlap similarities; Well logs,,"This study proposes a novel approach to predict missing shear sonic log responses more precisely and accurately using similarity patterns of various wells with similar geophysical properties, which is important in decision making and planning of hydrocarbon exploration. Deep Neural Network (DNN) along with the similarity metrics such as Jaccard and Overlap similarities are employed to examine the relationship between the wells. Further, dimensionality reduction techniques including Multi-Dimensional Scaling (MDS) and well-ranking process are applied to extract common geophysical responses of the wells. A higher response indicates the existence of a strong similarity. This can also be verified by the superimposed of well log data. The potential benefits of our novel method are following; (a) it does not follow the zone-by-zone prediction of the missing logs such as rock physics methods, (b) it outputs the uncertainties facilitated that is by the least-squares method. Having the potential of demonstrating shear sonic log prediction in hydrocarbon-bearing zones, which cannot be precisely predicted by the Greenberg-Castagna method that only works in brine-saturated rocks, this approach will provide improved accuracy, where shear sonic logs are missing and need to be predicted for geomechanics, rock physics, and other applications.",10,10,5
Neural Network,Pattern,"Liu, Cancan; Zhan, Qinjian; Yang, Lu; Zheng, Xigui; Li, Peng; Shahani, Niaz Muhammad",Recognition of interface and category of roadway roof strata based on drilling parameters,Measurement while drilling; Drilling parameters; Strata interface; Strata category; Pattern recognition,,"Measurement while drilling is an important part of the intelligent development of coal mines and the development trend of roof formation detection. The main purpose of this paper is to study the best identification method of rock interface and category based on drilling parameters. Firstly, the borehole drilling device was independently developed; Secondly, 4 concrete blocks were poured to simulate the different rock formations; Thirdly, displacement, rotational speed, torque, and sound pressure level data were collected during drilling the concrete blocks, and the original data was processed by the local linear kernel estimation method; Finally, Kmeans clustering and change points detection method, was used to identify the rock formation interface respectively, and BP neural network and support vector machine method was used to identify the rock category respectively. Experimental results show that the local linear kernel estimation method based on exponentially weighted loss function can better reflect the response characteristics of drilling parameters. The change point detection method based on the penetration rate is better for the rock interface prediction (the sum of the two interface errors is 10.25 mm). Besides, with the penetration rate and sound pressure level as input parameters, BP neural network and support vector machine can achieve the operational classification of rock formations. This research is of great significance for understanding the prediction of the interface and category of rock formation in coal mines, which can not only promote safe mining but also reflect efficient coal production.",5,5,13
Neural Network,Pattern,"Kim, Joonyi; Lee, Kyungbook; Choe, Jonggeun",Efficient and robust optimization for well patterns using a PSO algorithm with a CNN-based proxy model,Proxy model; Convolutional&nbsp; neural&nbsp; network (CNN); Time of flight (TOF); Field development&nbsp; plan (FDP); Particle swarm optimization (PSO); Optimization constraints,JOINT OPTIMIZATION; PARTICLE SWARM; PLACEMENT,"One objective of the field development plan (FDP) is to optimize well patterns, that is, the number and type of well (producers or injectors) and their locations, in order to maximize net present value (NPV). Optimization cost, including reservoir simulation, is strongly needed in terms of a global solution because of countless FDP scenarios, especially robust optimization for considering geological uncertainty. To solve this problem efficiently and reliably, this study introduces a convolutional neural network (CNN)-based proxy model into particle swarm optimization (PSO). For the proxy model, three map types having the same dimension as the reservoir model were fed into the input layer, giving an NPV for a given well-pattern scenario. The first map was a well configuration map, which consists of 1, -1, and 0 for producer, injector, and no well, respectively. The second and third maps were time-of-flight (TOF) maps from producers and injectors, respectively. Because the type of input data is an image, the CNN could extract features from 3500 scenarios while training the proxy model. When the predicted NPVs from the trained CNN-based proxy model were verified for 750 test data, the coefficients of determination for the true NPVs from reservoir simulation were higher than 0.94. In addition, the proxy model was flexibly applied to various well patterns, even for different numbers of wells because it utilizes TOF maps as input data. Three points are handled in PSO-Proxy to achieve a realistic well pattern: optimization of the number of wells, well spacing constraint, and operational condition for injection wells. The optimized well pattern maximizes NPV with the optimal number of producers and injectors under the predefined maximum number of wells. In the case of well spacing, two distances, that is, the distance between the wells and the distance between a production well and reservoir boundary, are used as criteria for the solution in terms of the filter method before evaluating the NPV. For injectors, water injection is controlled by bottomhole pressure instead of a constant injection rate, which gives meaningless injection wells placed at the edge of the reservoir. When the proposed method was tested using a 2-dimensional (D) synthetic field and 3-D Egg model, its well patterns showed approximately 1.2% lower NPV than the solution from a conventional method, PSO-ECL. This was relatively small when considering that there was approximately 7.8% NPV changes in each optimization run of the PSOECL. In addition, PSO-Proxy required only 21% and 8.6% of the optimization cost of the PSO-ECL for the 2-D and 3-D cases, respectively. Therefore, the proposed method was found to enable reliable and efficient decisionmaking for FDP; further, as the reservoir complexity increases, the CNN-based proxy model should be able to reduce the optimization time dramatically.",5,5,2
Neural Network,Pattern,"Gouda, Abdelrahman; Gomaa, Sayed; Attia, Attia; Emara, Ramadan; Desouky, S. M.; El-hoshoudy, A. N.",Development of an artificial neural network model for predicting the dew point pressure of retrograde gas condensate,Gas condensate; Dew point pressure; PVT; Artificial neural network model; Empirical correlations; And computer programing,DEWPOINT PRESSURE; RESERVOIRS; REGRESSION; EQUATION; MACHINE,"Optimal management and development plans for gas condensate reservoirs require authentic prediction for the dew point pressure (DPP). Traditionally, DPP is experimentally measured through a constant mass expansion test (CME), however, this test is relatively prohibitive and time-consuming. Equations of state and empirical correlations are employed in determining the (DPP), but due to the lack of generalized and inaccurate predictive paradigms, it is an incentive for researchers to establish new rigorous predictive models with wider applicability ranges and higher accuracy. This study tries to develop a new intelligent predictive model and to build a simple program based on 453 gas condensate samples that cover a wide range of chemical composition, reservoir temperatures, and fluid characteristics. The artificial neural network is conducted as an intelligent tool owing to its high capability and flexibility in defining the data pattern. A detailed comparison between widely used empirical correlations, PR-EOS, SRK- EOS, and the proposed new ANN model is provided in this study. Statistical and graphical analysis depicted the outstanding performance of the new model with R2 = 95.3%, ARE = 0.0069% and AARE = 5.03%.",4,4,2
Neural Network,Pattern,"Zhang, Guoyin; Wang, Zhizhang; Mohaghegh, Shahab; Lin, Chengyan; Sun, Yanan; Pei, Shengjie",Pattern visualization and understanding of machine learning models for permeability prediction in tight sandstone reservoirs,Permeability; Machine learning; Residual neural networks; Predictive pattern; Sensitivity analysis; Wireline logs,ARCHITECTURE; DEPRESSION; NETWORK; DESIGN; LOG,"Permeability prediction is a key and difficult task in hydrocarbon reservoir characterization. Machine learning has long been studied for permeability prediction using porosity and wireline logs but has not been widely accepted and applied in real cases because it is always treated as a Black Box and hard to interpret. In this paper, we propose novel approaches called univariate predictive pattern (UPP) and bivariate predictive pattern (BPP) to visualize predictive patterns learned by machine learning models. Machine learning models for permeability prediction are built in advance, including support vector regression (SVR), random forest (RF), and deep residual neural network (ResNet). The visualized predictive patterns show that ResNet learns the best-fitted nonlinear porosity-permeability relationships from the training dataset, which explains why ResNet achieves the best performance in permeability prediction in the scenario with porosity and wireline logs as input features. Wireline logs provide information about pore structure and contribute differently in machine learning models according to the visualized predictive patterns and quantitative sensitivity analysis. The proposed approach provides us a way to get a glimpse of the Black Box of machine learning models, and is also helpful in sensitivity analysis, feature selection, and model optimization for permeability prediction.",3,3,8
Neural Network,Pattern,"Tunkiel, Andrzej T.; Sui, Dan; Wiktorski, Tomasz",Training-while-drilling approach to inclination prediction in directional drilling utilizing recurrent neural networks,Directional drilling; Machine learning; Continuous learning; Inclination prediction,MACHINE; ENSEMBLE; MODELS,"Machine Learning adoption within drilling is often impaired by the necessity to train the model on data collected from wells analogous in lithology and equipment used to the well where the model is meant to be deployed. Lithology information is not always well documented and fast-paced development of drilling equipment complicates the challenge even further, as a model would likely become obsolete and inaccurate when new technologies are deployed. To bypass this problem a training-while-drilling method utilizing neural networks that are capable of modelling dynamic behaviour is proposed. It is a continuous learning approach where a data-driven model is developed while the well is being drilled, on data that is received as a continuous stream of information coming from various sensors. The novelty in presented approach is the use of Recurrent Neural Network elements to capture the dynamic behaviour present in data. Such model takes into account not only values of the adjacent data, but also patterns existing in the data series. Moreover, results are presented with a focus on the continuous learning aspect of the method, which was sparsely researched to date. A case study is presented where inclination data is predicted ahead of the inclination sensor in a directional drilling scenario. Our model architecture starts to provide accurate results after only 180 m of training data. Method, architecture, results, and benchmarking against classical approach are discussed; full dataset with complete source code is shared on GitHub.",3,3,3
Neural Network,Convolutional Neural Network,"Alzubaidi, Fatimah; Mostaghimi, Peyman; Swietojanski, Pawel; Clark, Stuart R.; Armstrong, Ryan T.",Automated lithology classification from drill core images using convolutional neural networks,Convolutional neural networks; Deep learning; Lithology logs; Core analysis,FACIES ANALYSIS; WELL LOGS; PREDICTION; LITHOFACIES,"In hydrocarbon reservoir evaluation, lithology is a key characteristic for determination of storage capacity and rock properties. Lithology is usually predicted from well log data or directly identified through manual inspection by geologists during core logging. Automatic prediction of lithology has been a focus of many studies inspired by rapid developments in machine learning. Studies mostly focus on predicting lithofacies from well logs using neural networks, and more recently from borehole image logs using convolutional neural network (CNN). Although core is more representative of reservoir lithology than well log data, employing machine learning for automatic lithology identification from core is limited. A CNN-based approach is developed to classify core images into three lithologies: sandstone, limestone, and shale. The model is based on ResNeXt-50 architecture, which had better performance in lithology prediction than ResNet-18 and Inception-v3 architectures. Our method processes core tray images and outputs lithology logs in a fully automated procedure and predicts the lithologies of new (unseen) core with an accuracy of 93.12%.",9,11,13
Neural Network,Convolutional Neural Network,"Kwon, Seoyoon; Park, Gayoung; Jang, Youngho; Cho, Jinhyung; Chu, Min-gon; Min, Baehyun",Determination of oil well placement using convolutional neural network coupled with robust optimization under geological uncertainty,Convolutional neural network; Robust optimization; Well placement; Geological uncertainty,INTELLIGENCE APPLICATIONS; MODEL; PREDICTION,"This study integrates a convolutional neural network (CNN) within the framework of robust optimization for determining the placement of an oil production well at a petroleum reservoir under geological uncertainty. The proposed algorithm identifies the well location that maximizes the expectation of cumulative oil production of equiprobable realizations. CNN, which inputs near-wellbore permeability and outputs cumulative oil production at a feasible well location, is trained to correlate between petrophysical spatial data and hydrocarbon productivity with several realizations. The trained CNN estimates the productivity at every feasible well location for all given realizations. The approach is tested with application to a set of realizations describing a channelized oil reservoir with an aquifer. The validity of the approach is evaluated by comparing the similarity between the full-physics reservoir simulation (RS) and CNN results for qualified well locations. The most productive well location based on the simulation results is selected as the optimal well placement. The performance of the CNN is also compared with that of an artificial neural network (ANN) for cases with varied numbers of realizations that provide training data with the neural networks. CNN outperforms ANN because of its feature extraction of multi-dimensional data from convolution. A sensitivity analysis is conducted to analyze the effects of the volume of training data on the predictability of the neural networks with k-fold cross-validation. The findings highlight that the integrated approach can be used as an efficient decision-making tool for solving well placement optimization problems with accuracy at an affordable computational cost.",6,6,3
Neural Network,Convolutional Neural Network,"Kim, Joonyi; Lee, Kyungbook; Choe, Jonggeun",Efficient and robust optimization for well patterns using a PSO algorithm with a CNN-based proxy model,Proxy model; Convolutional&nbsp; neural&nbsp; network (CNN); Time of flight (TOF); Field development&nbsp; plan (FDP); Particle swarm optimization (PSO); Optimization constraints,JOINT OPTIMIZATION; PARTICLE SWARM; PLACEMENT,"One objective of the field development plan (FDP) is to optimize well patterns, that is, the number and type of well (producers or injectors) and their locations, in order to maximize net present value (NPV). Optimization cost, including reservoir simulation, is strongly needed in terms of a global solution because of countless FDP scenarios, especially robust optimization for considering geological uncertainty. To solve this problem efficiently and reliably, this study introduces a convolutional neural network (CNN)-based proxy model into particle swarm optimization (PSO). For the proxy model, three map types having the same dimension as the reservoir model were fed into the input layer, giving an NPV for a given well-pattern scenario. The first map was a well configuration map, which consists of 1, -1, and 0 for producer, injector, and no well, respectively. The second and third maps were time-of-flight (TOF) maps from producers and injectors, respectively. Because the type of input data is an image, the CNN could extract features from 3500 scenarios while training the proxy model. When the predicted NPVs from the trained CNN-based proxy model were verified for 750 test data, the coefficients of determination for the true NPVs from reservoir simulation were higher than 0.94. In addition, the proxy model was flexibly applied to various well patterns, even for different numbers of wells because it utilizes TOF maps as input data. Three points are handled in PSO-Proxy to achieve a realistic well pattern: optimization of the number of wells, well spacing constraint, and operational condition for injection wells. The optimized well pattern maximizes NPV with the optimal number of producers and injectors under the predefined maximum number of wells. In the case of well spacing, two distances, that is, the distance between the wells and the distance between a production well and reservoir boundary, are used as criteria for the solution in terms of the filter method before evaluating the NPV. For injectors, water injection is controlled by bottomhole pressure instead of a constant injection rate, which gives meaningless injection wells placed at the edge of the reservoir. When the proposed method was tested using a 2-dimensional (D) synthetic field and 3-D Egg model, its well patterns showed approximately 1.2% lower NPV than the solution from a conventional method, PSO-ECL. This was relatively small when considering that there was approximately 7.8% NPV changes in each optimization run of the PSOECL. In addition, PSO-Proxy required only 21% and 8.6% of the optimization cost of the PSO-ECL for the 2-D and 3-D cases, respectively. Therefore, the proposed method was found to enable reliable and efficient decisionmaking for FDP; further, as the reservoir complexity increases, the CNN-based proxy model should be able to reduce the optimization time dramatically.",5,5,2
Neural Network,Convolutional Neural Network,"Yuan, Zhenyu; Huang, Handong; Jiang, Yuxin; Li, Jingjing",Hybrid deep neural networks for reservoir production prediction,Hybrid networks; Deep neural networks; Convolutional neural networks; Multiple sources; Structural measurements; Production prediction,,"For production prediction, existing physics-based methods often depend on some hypotheses and are confined to certain types of reservoirs. Some data-driven methods take single-source or single-type data as inputs and discard the spatial correlation of reservoir formation contained in structural measurements. Taking multi-source, mixed-type measurements into consideration, we developed an architecture of hybrid deep neural networks (HDNNs) for reservoir production prediction. Despite discrete geologic and engineering measurements, some structural data such as logging images and curves, which contains more details with reservoir formations, were taken as inputs. Hybrid architecture is the key to establish complex nonlinear relationship between target production and mixed inputs. Multiple networks were aggregated to cope with different measurements. For instance, convolutional neural networks (CNN) and multilayer perceptron (MLP) network were configured to separately extract features from structural and discrete inputs. Learned features were then concatenated and fed to subsequent networks for target learning. The implementation of the proposed network consists of four steps: data gathering, data preprocessing, model training and target inferencing. For gathered structural, numerical and categorical data, some essential preprocesses like resampling, normalizing and one-code encoding were performed to prepare dataset for model training. Applied to a development oil block and compared with a typical MLP model and CNN model, the proposed HDNN model stands out with high accuracy and good generalization. The HDNN model converges well both on training and validation dataset. The performance on test dataset demonstrates high accuracy with relative mean absolute error as 6.28%. Further application on three test wells achieved acceptable prediction results.",4,4,3
Neural Network,Convolutional Neural Network,"Lu, Chunhua; Jiang, Hanqiao; You, Chengcheng; Wang, Yong; Ma, Kang; Li, Junjian",A novel method to determine the thief zones in heavy oil reservoirs based on convolutional neural network,Convolutional neural network; Orthogonal design; Thief zone; Heavy oil; Automatic classification,,"The tracer breakthrough curve tends to be unimodal in heavy oil reservoir due to high oil-water viscosity ratio, which makes it difficult to classify thief zone (TZ) in these reservoirs using tracer breakthrough curve. To solve the problem, the paper applies the convolutional neural network (CNN) to achieve fast and accurate classification of TZ in heavy oil reservoir. The tracer flow analytical model is established by equating TZ with the flow tubes that satisfy the Hagen-Poiseuille equation. Then, 3000 tracer breakthrough curves are generated by the model as sample. Additionally, one-hot encoding method is applied to deal with these sample curves. Through the orthogonal design, the optimal combination of hyperparameters are determined to establish an OD-CNN model. According to the results, the number of convolutional layers is the most significant influencing factor in the accuracy of OD-CNN. Besides, the optimal hyperparameter combination for OD-CNN is detailed as follows. The number of convolutional layers is 4, the dropout rate is 0.6, the initialization method is Xavier normal, the optimizer is Adam, and the activation function is ReLU. Compared with random forest (RF) and K-means, the accuracy of OD-CNN on the training set is 94.67%, which is higher than 82.30% of RF and 75.63% of k-means. Moreover, OD-CNN can correctly classify 89 of the 100 curves from the oilfield indicating the reliability of OD-CNN. Thus, applying orthogonal design to OD-CNN can avoid the blindness of hyperparameter combination optimization and significantly reduce computing time.",3,3,2
Neural Network,Support Vector Machine,"Otchere, Daniel Asante; Ganat, Tarek Omar Arbi; Gholami, Raoof; Ridha, Syahrir",Application of supervised machine learning paradigms in the prediction of petroleum reservoir properties: Comparative analysis of ANN and SVM models,Artificial intelligence (AI); Supervised machine learning; Artificial neural network (ANN); Support vector machine (SVM); Relevance vector machine (RVM); Hybrid intelligent system,,"The advent of Artificial Intelligence (AI) in the petroleum industry has seen an increase in its use in exploration, development, production, reservoir engineering and management planning to accelerate decision making, reduce cost and time. Supervised machine learning has gained much popularity in establishing a relationship between complex non-linear datasets. This type of machine learning algorithm has showcased its superiority over petroleum engineering regression techniques in terms of prediction errors for high dimensional data, computational power and memory. This review focuses on the most widely used machine learning algorithm employed in the petroleum industry, the Artificial Neural Network (ANN) with different shallow models used in reservoir characterisation. The Support Vector Machine (SVM) and Relevant Vector Machine (RVM) has over the years emerged as competitive algorithms where in most cases based on this review it outperformed the ANN. This makes it preferable than the ANN when there are limited data sets. Finally, hybridisation of multiple algorithms methodologies also showed improved performance over singularly applied algorithms offering a pathway in improving reservoir characterisation based on supervised machine learning as future scope of work.",20,20,14
Neural Network,Support Vector Machine,"Sabah, Mohammad; Mehrad, Mohammad; Ashrafi, Seyed Babak; Wood, David A.; Fathi, Shadi",Hybrid machine learning algorithms to enhance lost-circulation prediction and management in the Marun oil field,Lost circulation while drilling; Multilayer perception; Least square support vector machine; Evolutionary algorithms; Marun oil field,ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINE; MULTILAYER PERCEPTRON; OPTIMIZATION; MODELS; RESERVOIR; ASMARI,"Drilling fluid loss of circulation is a challenging issue to resolve for many oil and gas wells as drilling progresses. It imposes enormous expenses on drilling industry. One of the common practices to solve this problem or make it less severe is introducing various loss circulation materials (LCM) into the circulating drilling fluid. The ability to predict the amount of mud loss before drilling a particular formation would provide engineers with invaluable information to assist them in selecting appropriate LCM properties such as particle size distribution. In this study, a number of heuristic search algorithms including genetic algorithm (GA), particle swarm size (PSO), and cuckoo search algorithm (COA) are combined with two machine-learning techniques namely multilayer perception (MLP) neural network and least square support vector machine (LSSVM) to present different hybrid algorithms in prediction of lost circulation. The established database consists of 2820 cases (datasets) extracted from available drilling reports of 305 drilled wells in the Marun oil field. These datasets are associated with drilling operation variables, formation specifications, and drilling mud characteristics which totally include 18 input variables and 1 output. Pre-processing of data involves filtering with Savitzky-Golay (SG) filter and ranking features using wrapper method. Results show that hybrid intelligent models are highly capable of predicting lost circulation before drilling a certain formation. Furthermore, LSSVM-COA and LSSVM-PSO achieve coefficients of determination of 0.9424 and 0.9391, respectively, making them the two most accurate models. GA cannot match the prediction performance of the other two algorithms in enhancing machine-learning techniques for this purpose. MLP-GA with a coefficient of determination (R-2) and RMSE of 0.9304 and 25.26 (bbl/hr), respectively, yields the weakest prediction performance. Hybrid intelligent models, coupling optimizers and machine learning algorithms show themselves to be superior to applying standalone machine-learning methodologies for predicting loss of circulation.",13,13,6
Neural Network,Support Vector Machine,"Liu, Cancan; Zhan, Qinjian; Yang, Lu; Zheng, Xigui; Li, Peng; Shahani, Niaz Muhammad",Recognition of interface and category of roadway roof strata based on drilling parameters,Measurement while drilling; Drilling parameters; Strata interface; Strata category; Pattern recognition,,"Measurement while drilling is an important part of the intelligent development of coal mines and the development trend of roof formation detection. The main purpose of this paper is to study the best identification method of rock interface and category based on drilling parameters. Firstly, the borehole drilling device was independently developed; Secondly, 4 concrete blocks were poured to simulate the different rock formations; Thirdly, displacement, rotational speed, torque, and sound pressure level data were collected during drilling the concrete blocks, and the original data was processed by the local linear kernel estimation method; Finally, Kmeans clustering and change points detection method, was used to identify the rock formation interface respectively, and BP neural network and support vector machine method was used to identify the rock category respectively. Experimental results show that the local linear kernel estimation method based on exponentially weighted loss function can better reflect the response characteristics of drilling parameters. The change point detection method based on the penetration rate is better for the rock interface prediction (the sum of the two interface errors is 10.25 mm). Besides, with the penetration rate and sound pressure level as input parameters, BP neural network and support vector machine can achieve the operational classification of rock formations. This research is of great significance for understanding the prediction of the interface and category of rock formation in coal mines, which can not only promote safe mining but also reflect efficient coal production.",5,5,13
Neural Network,Support Vector Machine,"Sun, Jian; Chen, Mingqiang; Li, Qi; Ren, Long; Dou, Mengyuan; Zhang, Jixuan",A new method for predicting formation lithology while drilling at horizontal well bit,Logging while drilling; Machine learning; Real-time interpretation; Lithology prediction,IDENTIFICATION; CLASSIFICATION; ALGORITHMS,"The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of ""zero length"" (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the ""zero length"" on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.",4,5,3
Neural Network,Support Vector Machine,"Zhang, Guoyin; Wang, Zhizhang; Mohaghegh, Shahab; Lin, Chengyan; Sun, Yanan; Pei, Shengjie",Pattern visualization and understanding of machine learning models for permeability prediction in tight sandstone reservoirs,Permeability; Machine learning; Residual neural networks; Predictive pattern; Sensitivity analysis; Wireline logs,ARCHITECTURE; DEPRESSION; NETWORK; DESIGN; LOG,"Permeability prediction is a key and difficult task in hydrocarbon reservoir characterization. Machine learning has long been studied for permeability prediction using porosity and wireline logs but has not been widely accepted and applied in real cases because it is always treated as a Black Box and hard to interpret. In this paper, we propose novel approaches called univariate predictive pattern (UPP) and bivariate predictive pattern (BPP) to visualize predictive patterns learned by machine learning models. Machine learning models for permeability prediction are built in advance, including support vector regression (SVR), random forest (RF), and deep residual neural network (ResNet). The visualized predictive patterns show that ResNet learns the best-fitted nonlinear porosity-permeability relationships from the training dataset, which explains why ResNet achieves the best performance in permeability prediction in the scenario with porosity and wireline logs as input features. Wireline logs provide information about pore structure and contribute differently in machine learning models according to the visualized predictive patterns and quantitative sensitivity analysis. The proposed approach provides us a way to get a glimpse of the Black Box of machine learning models, and is also helpful in sensitivity analysis, feature selection, and model optimization for permeability prediction.",3,3,8
Neural Network,Recurrent Neural Networks,"Tian, Miao; Omre, Henning; Xu, Huaimin",Inversion of well logs into lithology classes accounting for spatial dependencies by using hidden markov models and recurrent neural networks,Hidden markov model; Recurrent neural network; Lithology classification; Well logs inversion,STATISTICAL-ANALYSIS; FACIES; IDENTIFICATION; CLASSIFICATION; PREDICTION,"Lithology is a crucial factor in reservoir characterization. Due to the limited availability of cores, the classes of the subsurface lithologies in boreholes need to be predicted from indirect measurements like well logs. However, the spatial interdependence between sediments and the spatial coupling between the well logs data pose challenges in this lithology classification. Numerous proposed classifiers are based on spatial element-wise independence and these classifiers usually fail to provide accurate predictions. In this study, we focus on two classification models from the Bayesian and the deep learning framework, which both take spatial context into account. We discuss a kernel-based hidden Markov (HM) model and a kind of recurrent neural network model named gated recurrent unit (GRU). Cross-validation results from these two models of three partially cored real wells are compared to result from a simple non-spatial deep neural network (DNN) model. The cross-validation results indicate that the lithology classifiers from models taking vertical spatial dependency into account are much more reliable in terms of classification accuracy and geological interpretation. The probabilistically defined HM model performs better than the neural network GRU model.",10,10,5
Neural Network,Recurrent Neural Networks,"Tatsipie, Nelson R. K.; Sheng, James J.",Generating pseudo well logs for a part of the upper Bakken using recurrent neural networks,Well logs; Recurrent neural networks; Gamma ray,,"To develop a reservoir, we need to understand the distribution of key reservoir properties. Those formation properties are mostly derived from well log data. However, obtaining well log data is so expensive that the data we acquire is never sufficient. Therefore, we need to create pseudo data from real measured data. One approach is to generate synthetic well logs using recurrent neural networks (RNNs). Though relatively nascent, it is proven that RNNs allow for the generation of well logs with reasonable accuracy at a fraction of the price. Currently, gamma ray is the most cultivated well log in the E&P process today (owing to its decisive role during drilling operations and affordable price). All the same, a more extensive log suite is required to comprehend the producibility and frackability of hydrocarbon reservoirs like shale reservoirs. In this study, an upper Bakken database of 97 wells which contain gamma ray, bulk density, photoelectric index, density porosity, neutron porosity, true resistivity, compressional and shear slowness was used to develop deep learning models apt to creating synthetic logs for another set of 40 wells in the upper Bakken. The latter wells only had measured gamma ray. Using petroleum engineering concepts and RNNs, data-driven models capable of generating the remaining logs were created. The data-driven models were validated using wells with logs that have been removed from the database to serve as blind validation wells. The performance of the models (5-10 Mean Average Percentage Error and R-squared of 0.6-0.8) suggests the workflow described in this study is a viable way to maximize the value of a gamma ray log. With the ability to generate logs of similar quality for all wells in a shale asset (starting only with gamma ray), superior reservoir evaluation and thus improved reservoir management can be achieved.",4,4,1
Neural Network,Recurrent Neural Networks,"Yin, Qishuai; Yang, Jin; Tyagi, Mayank; Zhou, Xu; Wang, Ning; Tong, Gang; Xie, Renjun; Liu, Hexing; Cao, Bohan",Downhole quantitative evaluation of gas kick during deepwater drilling with deep learning using pilot-scale rig data,Gas kick; Downhole quantitative evaluation; Pilot-scale test well experiment; Compressed air injection; Deep-water drilling,,"Gas kick occurs frequently during deep-water drilling operations caused by the lack of safe margin between pore pressure and leakage pressure. The existing research is limited to gas kick classification and cannot quantitatively evaluate the gas kick risk in the downhole very well. Thus, the objective of this work is to systematically use Long Short-Term Memory (LSTM) Recurrent Neural Network (RNN) models based on pilot-scale rig data for quantitative evaluation of gas kick risk. Furthermore, the quantitative evaluation is not surface but downhole. First, the gas kick simulation experiment is accomplished in the pilot-scale test well and produces the gas kick dataset, which is based on the multi-source data fusion through the surface monitoring technologies, riser monitoring technologies and downhole monitoring technologies. Second, the training features are selected and grouped as Sets1-5 to study the features' sensitivity. Third, the raw data is processed and prepared for the following machine learning framework. Fourth, there are five (5) LSTM models trained on Sets1-5. The results indicate that the models' Loss decrease with the increase of feature number, which has fully demonstrated the effectiveness of PWD, EKD, and Doppler parameters. Finally, there are four representative case studies (artificial gas kick) that are used to test the above five models. The compressed air injected rate (AR) prediction error and detection time-delay decrease with the increase of feature number. The LSTM model trained with the combination of surfaceriser-downhole comprehensive detection technologies performs the best in reducing both the prediction error and detection time delay, which could be used to quantitatively evaluate the downhole gas kick risk in the more accurate, faster, more stable, more reliable, and cost-effective manner, and it is effective and worthy of promotion.",3,3,4
Neural Network,Recurrent Neural Networks,"Tunkiel, Andrzej T.; Sui, Dan; Wiktorski, Tomasz",Training-while-drilling approach to inclination prediction in directional drilling utilizing recurrent neural networks,Directional drilling; Machine learning; Continuous learning; Inclination prediction,MACHINE; ENSEMBLE; MODELS,"Machine Learning adoption within drilling is often impaired by the necessity to train the model on data collected from wells analogous in lithology and equipment used to the well where the model is meant to be deployed. Lithology information is not always well documented and fast-paced development of drilling equipment complicates the challenge even further, as a model would likely become obsolete and inaccurate when new technologies are deployed. To bypass this problem a training-while-drilling method utilizing neural networks that are capable of modelling dynamic behaviour is proposed. It is a continuous learning approach where a data-driven model is developed while the well is being drilled, on data that is received as a continuous stream of information coming from various sensors. The novelty in presented approach is the use of Recurrent Neural Network elements to capture the dynamic behaviour present in data. Such model takes into account not only values of the adjacent data, but also patterns existing in the data series. Moreover, results are presented with a focus on the continuous learning aspect of the method, which was sparsely researched to date. A case study is presented where inclination data is predicted ahead of the inclination sensor in a directional drilling scenario. Our model architecture starts to provide accurate results after only 180 m of training data. Method, architecture, results, and benchmarking against classical approach are discussed; full dataset with complete source code is shared on GitHub.",3,3,3
Neural Network,Fracture,"Yuyang, Liu; Xinhua, Ma; Xiaowei, Zhang; Wei, Guo; Lixia, Kang; Rongze, Yu; Yuping, Sun",Shale gas well flowback rate prediction for Weiyuan field based on a deep learning algorithm,Shale gas; Deep learning; Flowback characteristic; Flowback rate; Data analysis,SICHUAN BASIN; SIMULATION; MODEL,"The flowback rate of a shale gas well is controlled by many factors, such as geological and engineering factors, which have a certain complexity. For the aforementioned reason, the knowledge-driven method often has difficulty effectively capturing the correlation rules among multiple datasets. As a data-driven algorithm, deep learning has strong advantages in data correlation analysis, nonlinear fitting and other applications. In this paper, an algorithm is set up to forecast the shale gas well flowback rate by using a deep learning algorithm based on the flowback characteristic factors and data from 286 shale gas wells in the Weiyuan field. An algorithm and prediction model of the flowback parameters of the Weiyuan shale gas wells is established to effectively capture their flowback characteristics. First, the general situation of the study area is briefly introduced, and the data used to predict the flowback rate in this area are analyzed. Second, based on the deep learning algorithm, two kinds of deep feedforward neural network structures and a neural network-based prediction method of shale gas well flowback rate are designed. Finally, according to the regional data, the prediction and analysis of the flowback rate of Weiyuan shale gas wells are carried out. The results show that the correlations between 17 factors, such as fracturing section length and shale gas well flowback rate, are not obvious, but that the deep learning method proposed in this paper can effectively and accurately capture the correlations between the data and predict the flowback rate. The results show high accuracy.",7,7,6
Neural Network,Fracture,"Zhu, Zhaopeng; Song, Xianzhi; Li, Gensheng; Xu, Zhengming; Zhu, Shuo; Yao, Xuezhe; Jing, Silin",Prediction of the settling velocity of the rod-shaped proppant in vertical fracture using artificial neural network,Rod-shaped proppant; Settling orientation; Settling velocity; Vertical fracture; Neural network,,"As a new technology proppant, rod-shaped proppant is receiving more and more attention because it can greatly improve the performance of hydraulic fracturing. With special shape, the rod-shaped proppant is subject to greater flow resistance, resulting in complex migration in fractures. Accurate prediction of the settling velocity of rod proppant in fracture is important for predicting the transport distance and bed height of rod proppant in hydraulic fractures to improve the fracture performance. In this study, high-speed photography and transparent parallel plates were used to simulate and record the settling process of proppant in vertical fractures. A total of 588 effective tests were conducted to reveal the influence of proppant shape, fracturing fluid properties, and the wall effect of fracture on the settling characteristics involving the range of proppant aspect ratio and Reynolds number are 1.5-5.0 and 0.001-172.54, respectively. It was found that the rod proppant settled vertically at the low Reynolds number and horizontally at the high Reynolds number. First, an artificial neural network model of settling orientation with the prediction accuracy of 100% is established as the basis for predicting settlement velocity. The topological structure of the neural network is further extended to establish the prediction model of settling velocity with mean relative error of 1.21%. The relative importance of each input factor to the settling velocity was analyzed by the connection weights algorithm, and the weight and bias of the neural network are provided for the application and generalization of the model. Finally, the neural network model is evaluated objectively by comparing with the mathematical model. This study is a successful exploration of artificial intelligence in particle migration and will provide guidance for improving the performance of rod proppant in hydraulic fracturing.",6,6,5
Neural Network,Fracture,"Ahmed, S.; Alameri, W.; Ahmed, W. W.; Khan, S. A.",Rheological behavior of scCO(2)-Foam for improved hydrocarbon recovery: Experimental and deep learning approach,,REAL-TIME PREDICTION; FRACTURING FLUID; SHALE-GAS; DRILLING-FLUIDS; FOAM STABILITY; OIL; PERFORMANCE; VISCOSITY; TEMPERATURE; PRESSURE,"CO2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO2 foam is a key factor to control the efficiency of fracturing process that is strongly influenced by different process parameters such as foam quality, temperature, pressure, and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO2 foams by varying different process variables. CO2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (<1.8%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO2 foam projects for fracturing unconventional reservoirs.",3,3,5
Neural Network,Fracture,"Chaikine, Ilia A.; Gates, Ian D.",A machine learning model for predicting multi-stage horizontal well production,Horizontal multistage fracture; Machine learning; Production; Unconventional reservoirs; Hydraulic fracturing; Predictive models,,"In this study, a hybrid convolutional-recurrent neural network (c-RNN) is evaluated for making predictions of the five-year cumulative production profiles in multistage hydraulically fractured wells. The model was trained by using a combinations of completion parameters, rock mechanical properties, and well spacing and completion order for each stage of 74 wells in the Montney Formation in Alberta. The prediction accuracy of the various combinations was measured by using the mean average percent error and mean absolute error generated through the leave-one-out method. The best combination of inputs was found to be the rock mechanical properties surrounding each perforation cluster, the proppant amount used for every stage, and the spacing and completion order of neighboring wells. The novelty of this study is that the input variables used are at the stage level rather than the average of the entire well. The accuracy of the model was found to increase exponentially as the production of multiple wells was aggregated. The approach yields insights for planning new well drills in fields with existing development since it provides the ability to run multiple field development scenarios without having to spend capital.",3,3,3
Neural Network,Sensitivity Analysis,"Mohammadi, Mohammad-Reza; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin; Husein, Maen M.; Ranjbar, Mohammad",Application of cascade forward neural network and group method of data handling to modeling crude oil pyrolysis during thermal enhanced oil recovery,In-situ combustion; EOR; Pyrolysis; TGA; Artificial neural networks; Group method of data handling,IN-SITU COMBUSTION; MINIMUM MISCIBILITY PRESSURE; GENERALIZED REGRESSION; COMPRESSIBILITY FACTOR; KINETICS; PREDICTION; VISCOSITY; HYBRID; ASPHALTENES; OXIDATION,"Oil recovery during in situ combustion is majorly controlled by hydrocarbon oxidation and pyrolysis reactions, which govern fuel formation and heat evolution. Fuel deposition, in turn, can be accurately predicted in part through crude oil pyrolysis using thermogravimetry analysis (TGA). The theoretical models based on TGA runs, however, may be limited to crude oil samples at hand. In this study, we develop more general models to predict the residual mass during crude oil pyrolysis based on multi-layer perceptron (MLP), cascade forward (CFNN), generalized regression (GRNN), and radial basis function (RBF) neural networks. More than 2000 experimental data spanning wide range of weight percentages of asphaltenes and resins as well as oAPI gravities, heating rates, and temperatures are used. Moreover, six optimization algorithms; including Bayesian regularization (BR), scaled conjugate gradient (SCG), Levenberg-Marquardt (LM), conjugate gradient backpropagation with FletcherReeves updates (CGF), resilient backpropagation (RB), and conjugate gradient backpropagation with PolakRibie ' re updates (CGP) are used to improve the performance and prediction ability of the MLP and CFNN neural networks. The CFNN model optimized with the LM algorithm best fits all the experimental data with a mean absolute percent relative error of 1.04%. Lastly, a mathematical correlation is developed utilizing the group method of data handling (GMDH) to estimate the residual mass of crude oil pyrolysis in TGA. Despite its simplicity, the correlation also provides very good estimates. Sensitivity analysis showed that temperature followed by asphaltenes and resin content showed the highest effect on mass loss during crude oil pyrolysis. Outliers estimation applying the Leverage approach suggested only 1% of the data points could be doubtful.",11,11,1
Neural Network,Sensitivity Analysis,"Kwon, Seoyoon; Park, Gayoung; Jang, Youngho; Cho, Jinhyung; Chu, Min-gon; Min, Baehyun",Determination of oil well placement using convolutional neural network coupled with robust optimization under geological uncertainty,Convolutional neural network; Robust optimization; Well placement; Geological uncertainty,INTELLIGENCE APPLICATIONS; MODEL; PREDICTION,"This study integrates a convolutional neural network (CNN) within the framework of robust optimization for determining the placement of an oil production well at a petroleum reservoir under geological uncertainty. The proposed algorithm identifies the well location that maximizes the expectation of cumulative oil production of equiprobable realizations. CNN, which inputs near-wellbore permeability and outputs cumulative oil production at a feasible well location, is trained to correlate between petrophysical spatial data and hydrocarbon productivity with several realizations. The trained CNN estimates the productivity at every feasible well location for all given realizations. The approach is tested with application to a set of realizations describing a channelized oil reservoir with an aquifer. The validity of the approach is evaluated by comparing the similarity between the full-physics reservoir simulation (RS) and CNN results for qualified well locations. The most productive well location based on the simulation results is selected as the optimal well placement. The performance of the CNN is also compared with that of an artificial neural network (ANN) for cases with varied numbers of realizations that provide training data with the neural networks. CNN outperforms ANN because of its feature extraction of multi-dimensional data from convolution. A sensitivity analysis is conducted to analyze the effects of the volume of training data on the predictability of the neural networks with k-fold cross-validation. The findings highlight that the integrated approach can be used as an efficient decision-making tool for solving well placement optimization problems with accuracy at an affordable computational cost.",6,6,3
Neural Network,Sensitivity Analysis,"Mahmoodpour, Soran; Kamari, Ehsan; Esfahani, Mohammad Reza; Mehr, Amir Karimi",Prediction of cementation factor for low-permeability Iranian carbonate reservoirs using particle swarm optimization-artificial neural network model and genetic programming algorithm,The cementation factor of carbonate reservoirs; RCAL data; Hybrid PSO-ANN model; Genetic programming algorithm,,"cementation factor is a crucial parameter that has a significant influence on the estimation of reservoir parameters. Laboratory measurements for cementation factor are available for occasional cases because experimental special core analyses for determination of cementation factor values are expensive and time-consuming. While this factor plays a significant role in determining water saturation, there is no comprehensive and precise relationship for the case of Iranian carbonate reservoirs. In this article, a unique model was used based on a powerful combination of artificial neural network (ANN) and particle swarm optimization (PSO) algorithm to model the cementation factor. In the second phase of simulation, a correlation for the cementation factor was discovered by genetic programming (GP) algorithm. Both the PSO-ANN model and GP algorithm are trained by input variables such as porosity, permeability, and grain density derived from 175 routine core analysis (RCAL) samples of 21 carbonated oil fields. To determine the relative impact of the independent variables on cementation factor the sensitivity analysis was carried out for both models. The comparison between the PSO-ANN model output and the experimental cementation factor data clearly demonstrated that the built model can predict the cementation factor with great precision; the mean square error between the model predictions and the experimental data was less than 0.07. The root mean square error of training and testing data sets for the new developed correlation using GP algorithm were 0.0902 and 0.0727 respectively. Finally, to evaluate the validity and reliability of the developed models, a comparison was implemented between these two models and other empirical models over an external employment data set (21 data point). This comparison revealed that the GP algorithm and PSO-ANN model deliver a higher performance capacity compared to other proposed correlations for predicting cementation exponent.",4,4,0
Neural Network,Sensitivity Analysis,"Zhang, Guoyin; Wang, Zhizhang; Mohaghegh, Shahab; Lin, Chengyan; Sun, Yanan; Pei, Shengjie",Pattern visualization and understanding of machine learning models for permeability prediction in tight sandstone reservoirs,Permeability; Machine learning; Residual neural networks; Predictive pattern; Sensitivity analysis; Wireline logs,ARCHITECTURE; DEPRESSION; NETWORK; DESIGN; LOG,"Permeability prediction is a key and difficult task in hydrocarbon reservoir characterization. Machine learning has long been studied for permeability prediction using porosity and wireline logs but has not been widely accepted and applied in real cases because it is always treated as a Black Box and hard to interpret. In this paper, we propose novel approaches called univariate predictive pattern (UPP) and bivariate predictive pattern (BPP) to visualize predictive patterns learned by machine learning models. Machine learning models for permeability prediction are built in advance, including support vector regression (SVR), random forest (RF), and deep residual neural network (ResNet). The visualized predictive patterns show that ResNet learns the best-fitted nonlinear porosity-permeability relationships from the training dataset, which explains why ResNet achieves the best performance in permeability prediction in the scenario with porosity and wireline logs as input features. Wireline logs provide information about pore structure and contribute differently in machine learning models according to the visualized predictive patterns and quantitative sensitivity analysis. The proposed approach provides us a way to get a glimpse of the Black Box of machine learning models, and is also helpful in sensitivity analysis, feature selection, and model optimization for permeability prediction.",3,3,8
Neural Network,Low Permeability,"Lu, Hao; Li, Qing; Yue, Dali; Wu, Shenghe; Fu, Yupu; Tang, Renzhi; Zhang, Zhenyu","Study on optimal selection of porosity logging interpretation methods for Chang 7(3) segment of the Yanchang Formation in the southwestern Ordos Basin, China",Zhangjiatan Shale; Tuff; Multi-component volume model; Back propagation neural network; Logging parameter; Error analysis,SHALE; MODEL,"The physical properties of tight shale reservoirs have always been a hot topic of discussion, and the tuff reservoirs have also attracted more and more attention. Log predicting of the porosity is also important for the exploration and development of tight oil. Tight oil resources have been found in tight shale and tuff reservoirs in the Chang 7 Member of the Upper Triassic Yanchang Formation in the Ordos Basin, China. However, the logging method that effectively predicting porosity of the Chang 7 Member is lacking, and few people have discussed how to optimize the log interpretation methods. In this study, the characteristics of shale and tuff reservoirs were summarized by microscope and scanning electron microscope observation, X-ray diffraction, pore and permeability experiment, and the logging data. In order to find the optimal method of porosity prediction, four methods were performed: multiple regression fitting, multi-component volume model, porosity logging formula, and back propagation neural network method. The ""Zhangjiatan Shale"" of the Chang 7 Member is characterized by abundant sandy lamina and tuff lamina, compared with the tuff reservoir, the enrichment of pyrite (average 22.7 wt%) and total organic matter (>6%) increase the content of intercrystalline pores and organic matter related pores, the logging response is characterized by high natural gamma ray, low spontaneous potential and high acoustic. The tuff reservoir is mainly composed of vitric tuff and crystal-vitric tuff, hence, the rich in intergranular pore and micro-fracture can be explained by the dissolution and devitrification of vitric and crystal fragments, and the logging characteristic is opposite to that of the ""Zhangjiatan Shale"". Four methods for predicting porosity are established. First, appropriate logging parameters are selected for regression fitting in the ""Zhangjiatan Shale"" (e.g., gamma ray, deep lateral logging resistivity, density and spontaneous potential) and tuff reservoir (e.g., acoustic, density, compensated neutron logging). Then, the rock multi-component volume model was established as rock skeleton, clay or tuff matter, organic matter, and pores. The logging parameters of the skeleton, clay and organic matter were obtained by intersection graphs, which were applied in the improved porosity logging formulas. The effect of organic matter on logging was considered into the traditional porosity prediction formula, a third prediction method was established. Finally, the BP method was introduced into the porosity prediction work, and the neural network parameters were adjusted according to the log and porosity data. The learning rate and the learning accuracy were set as 0.1 and 10(-6) in the study area. The error analysis between the result predicted and measured shows that the multi-component volume model is suitable for the ""Zhangjiatan Shale"" (the correlative coefficient R>80%), while the back propagation neural network is the best method for the tuff reservoir (the correlative coefficient R>90%).",4,4,8
Neural Network,Low Permeability,"Mahmoodpour, Soran; Kamari, Ehsan; Esfahani, Mohammad Reza; Mehr, Amir Karimi",Prediction of cementation factor for low-permeability Iranian carbonate reservoirs using particle swarm optimization-artificial neural network model and genetic programming algorithm,The cementation factor of carbonate reservoirs; RCAL data; Hybrid PSO-ANN model; Genetic programming algorithm,,"cementation factor is a crucial parameter that has a significant influence on the estimation of reservoir parameters. Laboratory measurements for cementation factor are available for occasional cases because experimental special core analyses for determination of cementation factor values are expensive and time-consuming. While this factor plays a significant role in determining water saturation, there is no comprehensive and precise relationship for the case of Iranian carbonate reservoirs. In this article, a unique model was used based on a powerful combination of artificial neural network (ANN) and particle swarm optimization (PSO) algorithm to model the cementation factor. In the second phase of simulation, a correlation for the cementation factor was discovered by genetic programming (GP) algorithm. Both the PSO-ANN model and GP algorithm are trained by input variables such as porosity, permeability, and grain density derived from 175 routine core analysis (RCAL) samples of 21 carbonated oil fields. To determine the relative impact of the independent variables on cementation factor the sensitivity analysis was carried out for both models. The comparison between the PSO-ANN model output and the experimental cementation factor data clearly demonstrated that the built model can predict the cementation factor with great precision; the mean square error between the model predictions and the experimental data was less than 0.07. The root mean square error of training and testing data sets for the new developed correlation using GP algorithm were 0.0902 and 0.0727 respectively. Finally, to evaluate the validity and reliability of the developed models, a comparison was implemented between these two models and other empirical models over an external employment data set (21 data point). This comparison revealed that the GP algorithm and PSO-ANN model deliver a higher performance capacity compared to other proposed correlations for predicting cementation exponent.",4,4,0
Neural Network,Low Permeability,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
Neural Network,Proxy Model,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani; Ng, Cuthbert Shang Wui; Zeraibi, Noureddine",Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms,Water alternating gas (WAG); Enhanced oil recovery (EOR); Machine learning; Nature-inspired algorithms; Constraints handling,WATER-ALTERNATING-GAS; MINIMUM MISCIBILITY PRESSURE; ENHANCED OIL-RECOVERY; BOX-BEHNKEN DESIGN; ASPHALTENE PRECIPITATION; COLONY OPTIMIZATION; GENERALIZED MODELS; HYDROGEN-SULFIDE; NEURAL-NETWORK; PROXY MODEL,"To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from ""Gullfaks"" in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg-Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.",8,8,2
Neural Network,Proxy Model,"Kim, Joonyi; Lee, Kyungbook; Choe, Jonggeun",Efficient and robust optimization for well patterns using a PSO algorithm with a CNN-based proxy model,Proxy model; Convolutional&nbsp; neural&nbsp; network (CNN); Time of flight (TOF); Field development&nbsp; plan (FDP); Particle swarm optimization (PSO); Optimization constraints,JOINT OPTIMIZATION; PARTICLE SWARM; PLACEMENT,"One objective of the field development plan (FDP) is to optimize well patterns, that is, the number and type of well (producers or injectors) and their locations, in order to maximize net present value (NPV). Optimization cost, including reservoir simulation, is strongly needed in terms of a global solution because of countless FDP scenarios, especially robust optimization for considering geological uncertainty. To solve this problem efficiently and reliably, this study introduces a convolutional neural network (CNN)-based proxy model into particle swarm optimization (PSO). For the proxy model, three map types having the same dimension as the reservoir model were fed into the input layer, giving an NPV for a given well-pattern scenario. The first map was a well configuration map, which consists of 1, -1, and 0 for producer, injector, and no well, respectively. The second and third maps were time-of-flight (TOF) maps from producers and injectors, respectively. Because the type of input data is an image, the CNN could extract features from 3500 scenarios while training the proxy model. When the predicted NPVs from the trained CNN-based proxy model were verified for 750 test data, the coefficients of determination for the true NPVs from reservoir simulation were higher than 0.94. In addition, the proxy model was flexibly applied to various well patterns, even for different numbers of wells because it utilizes TOF maps as input data. Three points are handled in PSO-Proxy to achieve a realistic well pattern: optimization of the number of wells, well spacing constraint, and operational condition for injection wells. The optimized well pattern maximizes NPV with the optimal number of producers and injectors under the predefined maximum number of wells. In the case of well spacing, two distances, that is, the distance between the wells and the distance between a production well and reservoir boundary, are used as criteria for the solution in terms of the filter method before evaluating the NPV. For injectors, water injection is controlled by bottomhole pressure instead of a constant injection rate, which gives meaningless injection wells placed at the edge of the reservoir. When the proposed method was tested using a 2-dimensional (D) synthetic field and 3-D Egg model, its well patterns showed approximately 1.2% lower NPV than the solution from a conventional method, PSO-ECL. This was relatively small when considering that there was approximately 7.8% NPV changes in each optimization run of the PSOECL. In addition, PSO-Proxy required only 21% and 8.6% of the optimization cost of the PSO-ECL for the 2-D and 3-D cases, respectively. Therefore, the proposed method was found to enable reliable and efficient decisionmaking for FDP; further, as the reservoir complexity increases, the CNN-based proxy model should be able to reduce the optimization time dramatically.",5,5,2
Neural Network,Horizontal Wells,"Sun, Jian; Chen, Mingqiang; Li, Qi; Ren, Long; Dou, Mengyuan; Zhang, Jixuan",A new method for predicting formation lithology while drilling at horizontal well bit,Logging while drilling; Machine learning; Real-time interpretation; Lithology prediction,IDENTIFICATION; CLASSIFICATION; ALGORITHMS,"The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of ""zero length"" (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the ""zero length"" on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.",4,5,3
Neural Network,Horizontal Wells,"Chaikine, Ilia A.; Gates, Ian D.",A machine learning model for predicting multi-stage horizontal well production,Horizontal multistage fracture; Machine learning; Production; Unconventional reservoirs; Hydraulic fracturing; Predictive models,,"In this study, a hybrid convolutional-recurrent neural network (c-RNN) is evaluated for making predictions of the five-year cumulative production profiles in multistage hydraulically fractured wells. The model was trained by using a combinations of completion parameters, rock mechanical properties, and well spacing and completion order for each stage of 74 wells in the Montney Formation in Alberta. The prediction accuracy of the various combinations was measured by using the mean average percent error and mean absolute error generated through the leave-one-out method. The best combination of inputs was found to be the rock mechanical properties surrounding each perforation cluster, the proppant amount used for every stage, and the spacing and completion order of neighboring wells. The novelty of this study is that the input variables used are at the stage level rather than the average of the entire well. The accuracy of the model was found to increase exponentially as the production of multiple wells was aggregated. The approach yields insights for planning new well drills in fields with existing development since it provides the ability to run multiple field development scenarios without having to spend capital.",3,3,3
Neural Network,EOR Screening,"Cheraghi, Yasaman; Kord, Shahin; Mashayekhizadeh, Vahid",Application of machine learning techniques for selecting the most suitable enhanced oil recovery method; challenges and opportunities,Enhanced oil recovery; Reservoir engineering; EOR Screening; Advanced EOR Screening; Machine learning,,"A reliable method for selecting the most suitable Enhanced Oil Recovery (EOR) method is of a high necessity in reservoir engineering. Machine Learning (ML) techniques have been widely adopted as an effective and fast approach in primary stage of EOR screening. This paper presents a step-by-step procedure of applying ML in EOR screening with focusing on two main goals. Firstly, the problem of EOR screening is investigated from ML point of view. A large database consisting of more than 1000 experiences of worldwide EOR projects has been gathered from various sources. On the basis of this database, several ML models have been developed for predicting the suitable category of EOR methods for a candidate reservoir. These models include: Shallow and Deep Artificial Neural Networks (ANN), Naive Bayes (NB), Decision Tree (DT), Random Forest (RF) and Dimension Reduction using Principal Component Analysis (PCA). Almost all models performed well in predicting non-observed data with an average accuracy ranging from 80 to 90%. However, RF and the deep ANN models delivered the best performance with an average accuracy of 90%. The results demonstrated that RF model performed much better in comparison with the DT model and improved the classification accuracy from 85 to 91%. In case of ANNs, it was observed that the deeper ANN developed here, improved the classification accuracy from 83 to 90% in comparison with the shallow ANN with one hidden layer. The weakest performance was delivered by NB classifier with an average accuracy of 49%. As the second purpose of this research, reliability of screening results from applying ML techniques is discussed in details. Because, this approach suffers from some serious limitations and challenges, which could unfavorably affect the screening results and never had been considered in previous works. In this work, potential challenges and limitations associated with this well-known approach are introduced from database issues to modeling problems. Accordingly, an important conclusion is that application of ML, although providing a very good insight into primary EOR screening, should not be relied upon as the only method for predictions. It is recommended that the obtained results from this approach should be cross-checked with other EOR screening approaches or with methods based on expert's knowledge.",5,5,3
Neural Network,EOR Screening,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
CO2,CO2 Storage,"Abdulelah, Hesham; Al-Yaseri, Ahmed; Ali, Muhammad; Giwelli, Ausama; Negash, Berihun Mamo; Sarmadivaleh, Mohammad",CO2/Basalt's interfacial tension and wettability directly from gas density: Implications for Carbon Geo-sequestration,Carbon geo-sequestration; Basalt rocks; Interfacial tension; Carbon dioxide; Capillary trapping,MOLECULAR-DYNAMICS SIMULATION; CONTACT-ANGLE; CO2 STORAGE; TEMPERATURE; PRESSURE; ENERGY; SURFACTANT; SANDSTONE; IMPACT; QUARTZ,"There is an urgent need to store millions of tons of CO2 in deep underground formations to reduce anthropogenic emissions in the atmosphere. Basaltic rocks are recently depicted as feasible and safe candidates for storing CO2 in mineralized form. The leakage of stored CO2 in basaltic rocks could be minimized due to the mineralization process reported to occur in timescales magnitude shorter than those predicted for sandstone reservoirs. Rock/CO2 interfacial tension and wettability are essential factors to understand the interaction between CO2 and basalt rocks. Low values of rock/CO2 interfacial tension suggest stronger CO2-rock interaction, thus lower CO2 capacity is inferred, and vice versa. In other words, low values of rock/CO2 interfacial tension indicate stronger adhesion of CO2 molecules onto the rock surface. In this study, we have experimentally investigated basalt/CO2 interfacial tension under various pressures ranged from 4 MPa to 20 MPa and at temperatures of 308 degrees K and 333 degrees K. Our findings suggest that, as expected, Basalt/CO2 interfacial tension decreases as the pressure increases and increases as the temperature increases; solid/water interfacial energy decreases with increasing the temperature. The results also revealed that Basalt's CO2 sealing capacity is reduced as the contact angle (pressure) and temperature increases. The CO2 sealing capacity was reduced by up to 50% as the contact angle became similar to 80 degrees or when the pressure reached 17 MPa. We also found that there is a remarkable relationship between Basalt/CO2 IFT and CO2 density (rho) at 308 K and 333 K. The introduced relationship could serve as a handy tool to give a quick prediction of IFT CO2/basalt in basaltic formation or other CO2/solid systems. Determining solid/gas surface energy helps explain why minerals/rocks offer different wettability at certain pressure and temperature, leading to a better understanding of geological CO2-storage processes.",10,10,11
CO2,CO2 Storage,"Cui, Guodong; Yang, Lihong; Fang, Jichao; Qiu, Zhichao; Wang, Yuting; Ren, Shaoran",Geochemical reactions and their influence on petrophysical properties of ultra-low permeability oil reservoirs during water and CO2 flooding,Geochemical reactions; Water compatibility; Reactive flow simulation; Petrophysical properties,SANDSTONE; INJECTION; STORAGE; SEQUESTRATION; TEMPERATURES,"Complex geochemical reactions can occur during the water and CO2 flooding for improved oil recovery, influencing the reservoir porosity and permeability, especially for low-permeability reservoirs. Core flooding experiments can be adopted to assess this effect, but it usually takes months or even years to accomplish. In this study, scaling and geochemical reaction experiments were firstly conducted to investigate the precipitation and dissolution of the main minerals induced by water and CO2 injection, based on a typical low-permeability oil reservoir in Xinjiang Oilfield China. Secondly, reactive flow simulation models were then established, based on the experimental data, to evaluate the influence of the geochemical reactions on the porosity and permeability in the reservoir. The experimental results show that the injection water can result in severe mineral precipitation after it mixes with the original formation water, while the injected CO2 can acidize the formation water and result in the dissolution of some minerals (e.g. calcite and silicate) and precipitation of dolomite, which can change the composition of the formation water. The simulation results show that severe carbonate precipitation can occur near the injection well, resulting in a decrease in porosity and permeability after 10 years of water injection. However, the change of rock minerals induced by CO2 injection can cause a slight increase in porosity and permeability near the injector, which benefits the injection of ultra-low permeability reservoirs. Therefore, CO2 flooding is recommended for improved oil recovery.",10,10,4
CO2,CO2 Storage,"Al-Yaseri, Ahmed; Jha, Nilesh Kumar",On hydrogen wettability of basaltic rock,Hydrogen geo-storage; Hydrogen wettability; Deep saline aquifer; Basalt formation,SALINITY SURFACTANT NANOFLUIDS; CARBON DIOXIDE/BRINE; HIGH-TEMPERATURE; HIGH-PRESSURE; STORAGE; WATER; CO2; SOLUBILITY; OIL; CHEMISTRY,"One of the major challenges pertaining to a full hydrogen economy is hydrogen storage in the Earth's subsurface formations, such as deep saline aquifers and depleted oil and gas reservoirs. Generally, sedimentary basins are considered for this purpose due to their potential for large-scale storage. However, basaltic formations are also in comparable proportions having voluminous volcanic rocks, vast expansions, and high thickness. We, thus, in this work, evaluate brine/hydrogen/rock wettability of the real Basalt rock samples from CarbFix site in Iceland. Wettability is one of the significant parameters that highly influences the spreading and migration of the gas (as seen for CO2 capillary trapping investigations), interfacial area, mass transfer, and mineralization. We carried out brine/gas/Basalt three-phase contact angle measurements for some gases (CO2, N-2, and He) under storage conditions of high temperature (323 K) and pressures (5, 10, 15, and 20 MPa). The analogy drawn from developed correlation for H-2 from the contact angle trend of He (density close to H-2 density) and empirical correlations reveals that a strong water-wetting state of Basalt can be expected for H-2. The high water-wetting state of Basalt in the presence of H-2 at storage conditions may be suitable for capillary trapping of H-2 for long term storage in Basaltic formation.",9,9,6
CO2,CO2 Storage,"Wang, Yang; Cheng, Hongfei; Hu, Qinhong; Liu, Luofu; Jia, Langbo; Gao, Shasha; Wang, Ye","Pore structure heterogeneity of Wufeng-Longmaxi shale, Sichuan Basin, China: Evidence from gas physisorption and multifractal geometries",Multifractal; Heterogeneity; Connectivity; Gas adsorption; Pore structure; Isolated organic matter,METHANE ADSORPTION; ORDOS BASIN; ORGANIC-MATTER; N-2 ADSORPTION; FE-SEM; POROSITY; INSIGHTS; MARINE; AREA; MATURATION,"Understanding the heterogeneity of the nanoscale pore structure is critical for assessment of hydrocarbon flow and storage in porous reservoirs. Multifractal theory is a powerful method to acquire the detailed heterogeneity information of the multiple pore system. The generalized dimension spectrum and singularity spectrum are two forms to depict the multifractal feature. Hurst exponent (H) and the width of singularity spectrum (Delta alpha) are two parameters to effectively assess the pore connectivity and heterogeneity, respectively. In this study, multifractal analysis was performed on over-mature Wufeng-Longmaxi shales and their corresponding isolated organic matter (OM) via gas physisorption (CO2 and N-2) test to ascertain the pore heterogeneity and its governing factors. Micropore (diameter<2 nm) structure in bulk shale contains stronger pore heterogeneity but weaker connectivity than meso-macropore (diameter = 2-100 nm) structure. The comparison of heterogeneity features of shale versus its isolated OM reveals that micropore associated with minerals could enhance the micropore heterogeneity in bulk shale, while meso-macmpore existing in minerals could reduce the meso-macmpore heterogeneity in bulk shale. Besides, the total organic carbon content has a positive effect on the micropore heterogeneity. The micropore and meso-macmpore volume have a certain impact on the pore heterogeneity in the corresponding pore size ranges. Compared with the low-mature Bakken shale, the over-mature Wufeng-Longmaxi shale contains the stronger micropore heterogeneity but weaker meso-macmpore heterogeneity, where less difference between the micropore and meso-macropore heterogeneities was also observed. We deduced that the whole shale pore spectrum likely tends to be homogeneous along with the OM thermal maturation.",7,7,26
CO2,CO2 Storage,"Gambelli, Alberto Maria; Filipponi, Mirko; Rossi, Federico",How methane release may affect carbon dioxide storage during replacement processes in natural gas hydrate reservoirs,Natural gas hydrate; Carbon dioxide storage; CO2/CH4 replacement; CO2 capture; Gaseous phase composition,THERMAL-STIMULATION; PHASE-EQUILIBRIUM; CO2 STORAGE; RECOVERY; DISSOCIATION; DEPRESSURIZATION; VERIFICATION; EXCHANGE; ENERGY,"Methane replacement with carbon dioxide molecules in natural gas hydrate reservoirs mainly occurs in two different methods. The first is based on initial CH4 hydrate dissociation and a following CO2 hydrate formation, with all related problems for sediment deformation and so on. With the second method, the direct CO2/CH4 exchange occurs in already present cages, thus avoiding environmental problems and ensuring an exchange ratio close to 1. Because of practical difficulties in perfectly applying the second method, the initial methane release may produce a binary gaseous phase over the hydrate sediment, whose concentration may affect hydrate formation, till favouring CH4 hydrate re-formation rather than CO2 hydrate formation. The present experimental work analysed such aspect, by showing how that concentration may modify the formation trend, mainly in terms of carbon dioxide storage, and also proving the importance of thermodynamic conditions in this sense.",7,7,9
CO2,CO2 Storage,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
CO2,CO2 Storage,"Jia, Bao; Chen, Zeliang; Xian, Chenggang",Investigations of CO2 storage capacity and flow behavior in shale formation,Shale; CO2; Adsorption; Molecular diffusion,ENHANCED OIL-RECOVERY; CARBON-DIOXIDE; ADSORPTION; PRESSURE; RESERVOIRS; METHANE; INJECTION; NETWORKS; SORPTION; EOR,"CO2 storage, CO2 stimulation, CO2-enhanced oil recovery (EOR), and CO2-enhanced gas recovery (EGR) in shale reservoirs have recently attracted attention. Thorough investigations mimicking high pressure and high-temperature subsurface conditions are necessary to understand the interaction between CO2 and organic-rich shales, advance the fundamental understating of flow mechanisms in unconventional reservoirs, and successfully implement a field project. Most of the previous work focused on one aspect of adsorption, flow behavior, and reservoir numerical simulation. We suggest that a single approach investigation may lead to incomplete conclusions of CO2 injection in shales. This work comprehensively evaluates CO2 storage potential and injectivity in the Bakken Formation through various approaches. Samples are tested from the Lower Bakken Shale (LBS), the Middle Bakken (MB), and the Upper Bakken Shale (UBS). In terms of absolute and Gibbs/excess, adsorption isotherms of these two types are both measured, and the adsorbate density is estimated. We differentiate two adsorption isotherms and emphasize the correct use of the isotherm in the current commercial reservoir simulator, which is relatively obscure in the existing literature body. Nuclear magnetic resonance (NMR) confirms a portion of bitumen/absorption mobilization because of CO2 exposure. In the compositional simulations of CO2 injection in shales, several novel conclusions are obtained regarding analyzing main control factors; the most important one is that adsorption outweighs molecular diffusion in determining CO2 injection rate.",4,4,19
CO2,CO2 Storage,"Ali, Muhammad; Jha, Nilesh Kumar; Al-Yaseri, Ahmed; Zhang, Yihuai; Iglauer, Stefan; Sarmadivaleh, Mohammad",Hydrogen wettability of quartz substrates exposed to organic acids; Implications for hydrogen geo-storage in sandstone reservoirs,Hydrogen geo-storage; Hydrogen storage capacity; Hydrogen wettability; Sandstone aquifer,SUPERCRITICAL CO2; CARBON-DIOXIDE; WET CARBONATE; HIGH-PRESSURE; CRUDE-OIL; TEMPERATURE; CO2-WETTABILITY; SURFACES; ADSORPTION; NANOFLUID,"Hydrogen is presently evaluated as a clean fuel to mitigate anthropogenic CO2 emissions and reduce the greenhouse gas effect. However, one of the major challenges for implementing a full hydrogen economy is hydrogen storage (as hydrogen is highly volatile and compressible). The solution to this problem is storing hydrogen into geological formations (as they are abundant and have large storing quantities). One of the key factors in this process is the wettability of the formation, which determines fluid dynamics, containment security, withdrawal rates, and storage capacities. To do this, we have determined the wettability of sandstone rock representative substrate through an extensive set of experiments in the presence of hydrogen. Whereas, almost all of these formations contains organic acids (hexanoic C6, lauric C12, and lignoceric C24 acids, respectively), even in minute concentrations, ranging from C4 to C26. Therefore, to fully comprehend the H2 wettability in a realistic scenario, we have aged quartz substrates in organic acids and conducted contact angle measurements under assorted storage conditions (temperature of 323 K, pressure of 0.1, 15, and 25 MPa). Our results show that pure quartz was inherently strongly water-wet (where 0a is 40.8 degrees and 0r is 35.1 degrees) and turned to intermediate water-wet (0a is 91.3 degrees and 0r is 82.7 degrees) in presence of H2 (at 323 K and 25 MPa) when the rock substrate was aged with organic acids having longer alkyl chain (10-2 Molarity (M) of lignoceric acid). This study, thus, provides crucial information for the implementation of the future hydrogen economy.",3,3,12
CO2,CO2 Storage,"Jani, Priyesh; Imqam, Abdulmohsin",Class C fly ash-based alkali activated cement as a potential alternative cement for CO2 storage applications,Fly ash geopolymer cement; CO2; Portland cement,,"Long-term storage of carbon dioxide (CO2) inside depleted reservoirs can help reduce the impact of greenhouse gas emissions. Portland cement has been shown to degrade significantly during long-term contact with CO2. This research aims to provide a new environmentally friendly, Class C fly ash-based cement as a potential alternative to Portland cement for CO2 storage wells. This was achieved by comparing the mechanical degradation of Portland cement and Class C fly ash-based alkali-activated cement in a CO2 environment. A specially designed setup was constructed to create an in situ high pressure and high-temperature CO2 environment. Seventy-two cores of Portland cement and Class C fly ash-based cement were prepared for this study. The results show that CO2 reacted with the water in the vessel and formed carbonic acid, which reduced the water pH to 6.8. Millimeter-sized crystals of calcium carbonate (CaCO3) were observed on the surface of the Portland cement cores after the CO2 exposure. The surface of the fly ash-based alkali-activated cement cores was not substantively changed after the exposure. No significant change in density was observed for both types of cement during the 14 days of CO2 exposure. Portland cement showed a significant reduction in compressive strength, and this reduction developed as the exposure time increased. Interestingly, Class C fly ash-based cement showed no reduction in compressive strength, and only a small amount of reduction was observed after 14 days of exposure. This research compared the mechanical degradation of Portland cement and Class C fly ash-based alkali-activated cement in a high-pressure and high-temperature CO2 environment.",3,3,9
CO2,CO2 Storage,"Cho, Yongchae; Jun, Hyunggu",Estimation and uncertainty analysis of the CO2 storage volume in the sleipner field via 4D reversible-jump markov-chain Monte Carlo,Carbon capture and sequestration; Time-lapse monitoring; Markov-chain Monte Carlo; Uncertainty analysis; Volume estimation,,"Many scientists have developed technology to store CO2 in the subsurface and to monitor the storage conditions to comply with the requirements for zero detectable leakage and greenhouse gas control. The goal of this research is to propose a novel workflow to estimate the stored CO2 volume and to quantify the uncertainty of the injected volume. We implemented geophysical stochastic inversion using the time-lapse 3D seismic volumes as inputs, which provides an indirect estimation of the velocity changes and the migration path of the injected gas content. When performing the inversion, we employed the reversible-jump approach and used the Sleipner time-lapse 3D seismic volumes to demonstrate the proposed workflow. The inversion result was validated via forward modeling and pseudo well log interpretation. We then built a structural geology model and populated porosity logs by performing 500 realizations for volumetric analysis. In a comparison of the measured volume of the injected gas via volumetric analysis results, the predicted subsurface CO2 volume linearly increases in the same phase with the injection rate, and the volume estimation error is less than 17%.",3,3,2
CO2,Supercritical CO2,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
CO2,Supercritical CO2,"Yang, Bing; Wang, Haizhu; Wang, Bin; Shen, Zhonghou; Zheng, Yong; Jia, Zhaoyang; Yan, Wanjuan",Digital quantification of fracture in full-scale rock using micro-CT images: A fracturing experiment with N-2 and CO2,Supercritical CO2; Fracturing laboratory experiment; CT scanning; Fracture reconstruction; Quantitative fracture analysis,SUPERCRITICAL CARBON-DIOXIDE; INITIATION PRESSURE; SHALE GAS; WATER; FLUIDS; PROPAGATION; OIL; SKELETONIZATION; PERMEABILITY; EXTENSION,"How to effectively and cleanly exploit unconventional resources is currently being widely concerned. Due to the unavoidable limitations of water-based fracturing, CO2 and N-2 etc., are regarded as alternative fluids for some specific reservoirs such as the arid area or high clay swelling formation. To investigate the characteristics of fracture induced by nonaqueous fluid in unconventional fight formation, fracturing experiments on fight sandstone using different fluid of water, N-2, liquid CO2 (L-CO2) and supercritical CO2 (SC-CO2) were conducted. A novel fracture analysis approach based on CT scanning is also proposed to quantitatively analyze the micromorphology of fractures including fracture network pattern, fractal dimension (FD), aperture, area ratio (AR) and fracture volume etc. Results show that water and N-2 can only induce a relatively simple fracture pattern. Whereas, fractures induced by CO2-based fluid have more complex fracture geometry with many fracture branches and various propagation orientations. Quantitative analysis based on image processing and fracture reconstruction algorithm indicates that the CO2-based fluid has up to 4.4 times larger fracture-induced capacity and can create fracture with up to 2.6 times higher complexity and 23.4% higher roughness than that generated by water-based fracturing. Comparing to SC-CO2, L-CO2 and water, N-2 has the least fracture-induced capacity (83% of water) and produces more smooth and uniform fractures. On the other hand, the distributions of deviation angle suggest that fracture propagation is not only influenced by stress state, but also significantly affected by the original bedding plane. This experimental study proposes a precise and effective approach for fracture characteristic quantification, which can be further implemented into fracture simulation model. It also provides theoretical reference and guidance for field operation of waterless fracturing in development of unconventional oil and gas.",6,6,12
CO2,Supercritical CO2,"Zhou, Junping; Yang, Kang; Zhou, Lei; Jiang, Yongdong; Xian, Xuefu; Zhang, Chengpeng; Tian, Shifeng; Fan, Maolin; Lu, Zhaohui",Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure,Shale reservoir; Supercritical carbon dioxide fracturing; Carbon dioxide sequestration; Mechanical alteration; Carbon dioxide-water-shale interaction,SUPERCRITICAL CO2 TREATMENT; PORE STRUCTURE; CARBON-DIOXIDE; FRACTAL ANALYSIS; MULTIFRACTAL CHARACTERISTICS; ADSORPTION BEHAVIORS; FAILURE MECHANISMS; GAS; NMR; WATER,"CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D-1 and pore volume fractal dimensions D-2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO(2), and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D-1 and D-2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.",5,6,24
CO2,Supercritical CO2,"Zhao, Mingwei; Li, Yang; Gao, Mingwei; Wang, Tao; Dai, Caili; Wang, Xin; Guan, Baoshan; Liu, Ping",Formulation and performance evaluation of polymer-thickened supercritical CO2 fracturing fluid,Supercritical CO2; Fracturing fluid; System formulation; Performance evaluation; Wetting reversal,,"Compared with conventional water-based fracturing fluid, supercritical CO2 fracturing fluid has the characteristics of inhibiting water sensitive damage and improving flowback efficiency. In view of the problems of low viscosity, poor sand-carrying performance and large filtration loss capacity of pure supercritical CO2, a supercritical CO2 fracturing fluid system had been prepared: 5% polydimethylsiloxane +5% kerosene +90% supercritical CO2. The rheological property, sand-carrying property, filtration loss property, core damage property and wetting inversion property of the system were systematically studied through performance evaluation experiments. At 325 K, the viscosity of the system can reach 4.67 mPa s, which was 54.26 times higher than that of pure supercritical CO2. The performance evaluation showed that the system had a good rheological property. The sand-carrying capacity was improved by 38.17%, and the filtration loss coefficient was decreased by 71.71% at most. The interaction results between CO2 and reservoir showed that the system could effectively increase the porosity and permeability of the core. For ultra-low permeability sandstone core, the porosity was increased by 7.71%, the permeability was increased by 115.20%. While for shale core, the porosity was increased by 6.99%, permeability was increased by 102.44%. At the same time, the system can change the core wetted by water phase into a neutral wetted one which was favorable for oil and gas flow. This system is expected to be further studied in oilfield applications.",5,5,11
CO2,Supercritical CO2,"Zhou, Bobo; Kang, Wanli; Yang, Hongbin; Zhu, Tongyu; Zhang, Hongwen; Li, Xinxin; Sarsenbekuly, Bauyrzhan; Sarsenbek, Turtabayev",Preparation and properties of an acid-resistant preformed particle gel for conformance control,Preformed particle gel; Acid-resistant; CO2 flooding reservoir; Conformance control,ENHANCED OIL-RECOVERY; POLYACRYLAMIDE; MICROSPHERES; PERFORMANCE; RESERVOIRS; MECHANISM; SYSTEMS; SIZE,"In order to solve the problem of poor acid-resistant of preformed particle gel (PPG) as conformance control material in reservoirs with supercritical CO2 flooding, acrylamide (AM), N,N'-methylene bisacrylamide (MBA) and dimethyldiallylammonium chloride (DMDAAC) were used to prepare an acid-resistant preformed particle gel (AR-PPG) by radical polymerization method. Fourier transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM) were used to analyze the structural property of AR-PPG. The swelling capability, viscoelasticity and shear resistance of AR-PPG in acid environment have been studied. The conformance control system with good dispersion stability was selected and its plugging behavior was studied. The results showed that the swelling ratio of AR-PPG in acid environment was 1.41. Compared with conventional PPG, AR-PPG displayed better swelling capability, shearing resistance and viscoelastic properties in acidic environment. In addition, the conformance control system with good dispersion was 1000 mg/L AR-PPG dispersed in 1000 mg/L cationic polyacrylamide (CPAM) solution. The plugging rate of this conformance control system could be 70.8% in the low permeability micro-fracture core after supercritical CO2 flooding. This work can provide an alternative material for plugging and conformance control in oilfields of supercritical CO2 flooding.",5,5,9
CO2,Supercritical CO2,"Ali, Muhammad; Jha, Nilesh Kumar; Al-Yaseri, Ahmed; Zhang, Yihuai; Iglauer, Stefan; Sarmadivaleh, Mohammad",Hydrogen wettability of quartz substrates exposed to organic acids; Implications for hydrogen geo-storage in sandstone reservoirs,Hydrogen geo-storage; Hydrogen storage capacity; Hydrogen wettability; Sandstone aquifer,SUPERCRITICAL CO2; CARBON-DIOXIDE; WET CARBONATE; HIGH-PRESSURE; CRUDE-OIL; TEMPERATURE; CO2-WETTABILITY; SURFACES; ADSORPTION; NANOFLUID,"Hydrogen is presently evaluated as a clean fuel to mitigate anthropogenic CO2 emissions and reduce the greenhouse gas effect. However, one of the major challenges for implementing a full hydrogen economy is hydrogen storage (as hydrogen is highly volatile and compressible). The solution to this problem is storing hydrogen into geological formations (as they are abundant and have large storing quantities). One of the key factors in this process is the wettability of the formation, which determines fluid dynamics, containment security, withdrawal rates, and storage capacities. To do this, we have determined the wettability of sandstone rock representative substrate through an extensive set of experiments in the presence of hydrogen. Whereas, almost all of these formations contains organic acids (hexanoic C6, lauric C12, and lignoceric C24 acids, respectively), even in minute concentrations, ranging from C4 to C26. Therefore, to fully comprehend the H2 wettability in a realistic scenario, we have aged quartz substrates in organic acids and conducted contact angle measurements under assorted storage conditions (temperature of 323 K, pressure of 0.1, 15, and 25 MPa). Our results show that pure quartz was inherently strongly water-wet (where 0a is 40.8 degrees and 0r is 35.1 degrees) and turned to intermediate water-wet (0a is 91.3 degrees and 0r is 82.7 degrees) in presence of H2 (at 323 K and 25 MPa) when the rock substrate was aged with organic acids having longer alkyl chain (10-2 Molarity (M) of lignoceric acid). This study, thus, provides crucial information for the implementation of the future hydrogen economy.",3,3,12
CO2,Supercritical CO2,"Zhang, Mengda; Li, Deng; Kang, Yong; Huang, Man; Yuan, Miao",Experimental study on the rock erosion performance of a pulsed abrasive supercritical CO2 jet,Supercritical CO2; Abrasive jet; Unconventional energy resources; Rock erosion; Helmholtz nozzle,,"An experimental study on the erosion behaviors of pulsed abrasive supercritical CO2 jets (PASJ) was performed using sandstone as the target specimen. The erosion depth, erosion area, and mass loss of the crater caused by PASJ were discussed in detail. The optimal configuration of the Helmholtz nozzle was first determined, and then influences of erosion-related working parameters including the jet pressure, abrasive particle size, ambient fluid and jet impingement angle on the rock erosion performance were analyzed with this nozzle. The results indicate that increasing jet pressure helps improve the erosion depth and area, which is mainly the result of increased jet kinetic energy. The erosion capability of PASJ is highly dependent on the size of abrasive particles. Coarser particles shows greater effectiveness in producing deeper erosion craters and the jets are more likely to retain rock-erosion ability as the standoff distance increases. At a given standoff distance, the crater eroded in air is deeper than those eroded in gaseous CO2 and in supercritical CO2, because the particles are slowed much more slowly in air under decreased drag. Moreover, the area of the crater eroded by PASJ in air is also largest due to the highest radial spreading rate. Finally, it was found that mass loss and erosion depth first increase and then decrease with the increase of jet impingement angle (theta) and the maximum values are reached at theta = 70 degrees, whilst the erosion area increases monotonically with decreasing jet impingement angle.",3,3,8
CO2,CO2 Flooding,"Cui, Guodong; Yang, Lihong; Fang, Jichao; Qiu, Zhichao; Wang, Yuting; Ren, Shaoran",Geochemical reactions and their influence on petrophysical properties of ultra-low permeability oil reservoirs during water and CO2 flooding,Geochemical reactions; Water compatibility; Reactive flow simulation; Petrophysical properties,SANDSTONE; INJECTION; STORAGE; SEQUESTRATION; TEMPERATURES,"Complex geochemical reactions can occur during the water and CO2 flooding for improved oil recovery, influencing the reservoir porosity and permeability, especially for low-permeability reservoirs. Core flooding experiments can be adopted to assess this effect, but it usually takes months or even years to accomplish. In this study, scaling and geochemical reaction experiments were firstly conducted to investigate the precipitation and dissolution of the main minerals induced by water and CO2 injection, based on a typical low-permeability oil reservoir in Xinjiang Oilfield China. Secondly, reactive flow simulation models were then established, based on the experimental data, to evaluate the influence of the geochemical reactions on the porosity and permeability in the reservoir. The experimental results show that the injection water can result in severe mineral precipitation after it mixes with the original formation water, while the injected CO2 can acidize the formation water and result in the dissolution of some minerals (e.g. calcite and silicate) and precipitation of dolomite, which can change the composition of the formation water. The simulation results show that severe carbonate precipitation can occur near the injection well, resulting in a decrease in porosity and permeability after 10 years of water injection. However, the change of rock minerals induced by CO2 injection can cause a slight increase in porosity and permeability near the injector, which benefits the injection of ultra-low permeability reservoirs. Therefore, CO2 flooding is recommended for improved oil recovery.",10,10,4
CO2,CO2 Flooding,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
CO2,CO2 Flooding,"Zhou, Bobo; Kang, Wanli; Yang, Hongbin; Zhu, Tongyu; Zhang, Hongwen; Li, Xinxin; Sarsenbekuly, Bauyrzhan; Sarsenbek, Turtabayev",Preparation and properties of an acid-resistant preformed particle gel for conformance control,Preformed particle gel; Acid-resistant; CO2 flooding reservoir; Conformance control,ENHANCED OIL-RECOVERY; POLYACRYLAMIDE; MICROSPHERES; PERFORMANCE; RESERVOIRS; MECHANISM; SYSTEMS; SIZE,"In order to solve the problem of poor acid-resistant of preformed particle gel (PPG) as conformance control material in reservoirs with supercritical CO2 flooding, acrylamide (AM), N,N'-methylene bisacrylamide (MBA) and dimethyldiallylammonium chloride (DMDAAC) were used to prepare an acid-resistant preformed particle gel (AR-PPG) by radical polymerization method. Fourier transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM) were used to analyze the structural property of AR-PPG. The swelling capability, viscoelasticity and shear resistance of AR-PPG in acid environment have been studied. The conformance control system with good dispersion stability was selected and its plugging behavior was studied. The results showed that the swelling ratio of AR-PPG in acid environment was 1.41. Compared with conventional PPG, AR-PPG displayed better swelling capability, shearing resistance and viscoelastic properties in acidic environment. In addition, the conformance control system with good dispersion was 1000 mg/L AR-PPG dispersed in 1000 mg/L cationic polyacrylamide (CPAM) solution. The plugging rate of this conformance control system could be 70.8% in the low permeability micro-fracture core after supercritical CO2 flooding. This work can provide an alternative material for plugging and conformance control in oilfields of supercritical CO2 flooding.",5,5,9
CO2,CO2 Flooding,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
CO2,CO2 Flooding,"Dong, Baojun; Zeng, Dezhi; Yu, Zhiming; Cai, LeLe; Yu, Huiyong; Shi, ShanZhi; Tian, Gang; Yi, Yonggang",Major corrosion influence factors analysis in the production well of CO2 flooding and the optimization of relative anti-corrosion measures,CO2 corrosion; Corrosion influence factors; Anti-Corrosion measures; Corrosion inhibitor; Corrosion-resistant alloys; CO2 flooding,,"Major corrosion influence factors in the production well of CO2 flooding in Xinjiang oilfield were investigated, and corresponding anticorrosion measures (relating to corrosion inhibitors and corrosion-resistant alloys) had been contrasted in order to select a most suitable scheme to solve the tubing corrosion issue. The results showed that the corrosion of N80 steel in liquid phase was mainly affected by temperature, while in gas phase by temperature and CO2 partial pressure. As to the corrosion of 3Cr steel, in liquid phase, the influencing factors were temperature and chloride concentration, and in gas phase, it was mainly affected by temperature. The safe service life of N80 and P110 steel in liquid phase were less than 8 years, whereas that of 9Cr and 13Cr steel both exceeded 30 years. In gas phase, the safe service life of N80 and P110 steel were 11.65 years and 16.55 years respectively, while that of 3Cr, 9Cr and 13Cr steel were more than 30 years. Suitable for production well in CO2 flooding, No.6 corrosion inhibitor was selected. The corrosion rate of tubing could be controlled within 0.076 mm/y by adding 1000 ppm corrosion inhibitor. 9Cr steel was recommended to be used as the tubing of new production wells for CO2 flooding, and, for old wells, the method of continuous filling corrosion inhibitor was recommended to resist corrosion.",3,4,9
CO2,CO2 Flooding,"Wang, Yuxia; Shang, Qinghua; Zhou, Lifa; Jiao, Zunsheng",Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin,Permeability heterogeneity; CO2 flooding; EOR; Tight sandstone reservoir; Ordos Basin,OIL-RECOVERY; CARBON-DIOXIDE; INJECTION,"Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200-1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with elastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO 2 -EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high-low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high-low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.",3,3,6
CO2,Low Permeability,"Cui, Guodong; Yang, Lihong; Fang, Jichao; Qiu, Zhichao; Wang, Yuting; Ren, Shaoran",Geochemical reactions and their influence on petrophysical properties of ultra-low permeability oil reservoirs during water and CO2 flooding,Geochemical reactions; Water compatibility; Reactive flow simulation; Petrophysical properties,SANDSTONE; INJECTION; STORAGE; SEQUESTRATION; TEMPERATURES,"Complex geochemical reactions can occur during the water and CO2 flooding for improved oil recovery, influencing the reservoir porosity and permeability, especially for low-permeability reservoirs. Core flooding experiments can be adopted to assess this effect, but it usually takes months or even years to accomplish. In this study, scaling and geochemical reaction experiments were firstly conducted to investigate the precipitation and dissolution of the main minerals induced by water and CO2 injection, based on a typical low-permeability oil reservoir in Xinjiang Oilfield China. Secondly, reactive flow simulation models were then established, based on the experimental data, to evaluate the influence of the geochemical reactions on the porosity and permeability in the reservoir. The experimental results show that the injection water can result in severe mineral precipitation after it mixes with the original formation water, while the injected CO2 can acidize the formation water and result in the dissolution of some minerals (e.g. calcite and silicate) and precipitation of dolomite, which can change the composition of the formation water. The simulation results show that severe carbonate precipitation can occur near the injection well, resulting in a decrease in porosity and permeability after 10 years of water injection. However, the change of rock minerals induced by CO2 injection can cause a slight increase in porosity and permeability near the injector, which benefits the injection of ultra-low permeability reservoirs. Therefore, CO2 flooding is recommended for improved oil recovery.",10,10,4
CO2,Low Permeability,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
CO2,Low Permeability,"Zhao, Mingwei; Li, Yang; Gao, Mingwei; Wang, Tao; Dai, Caili; Wang, Xin; Guan, Baoshan; Liu, Ping",Formulation and performance evaluation of polymer-thickened supercritical CO2 fracturing fluid,Supercritical CO2; Fracturing fluid; System formulation; Performance evaluation; Wetting reversal,,"Compared with conventional water-based fracturing fluid, supercritical CO2 fracturing fluid has the characteristics of inhibiting water sensitive damage and improving flowback efficiency. In view of the problems of low viscosity, poor sand-carrying performance and large filtration loss capacity of pure supercritical CO2, a supercritical CO2 fracturing fluid system had been prepared: 5% polydimethylsiloxane +5% kerosene +90% supercritical CO2. The rheological property, sand-carrying property, filtration loss property, core damage property and wetting inversion property of the system were systematically studied through performance evaluation experiments. At 325 K, the viscosity of the system can reach 4.67 mPa s, which was 54.26 times higher than that of pure supercritical CO2. The performance evaluation showed that the system had a good rheological property. The sand-carrying capacity was improved by 38.17%, and the filtration loss coefficient was decreased by 71.71% at most. The interaction results between CO2 and reservoir showed that the system could effectively increase the porosity and permeability of the core. For ultra-low permeability sandstone core, the porosity was increased by 7.71%, the permeability was increased by 115.20%. While for shale core, the porosity was increased by 6.99%, permeability was increased by 102.44%. At the same time, the system can change the core wetted by water phase into a neutral wetted one which was favorable for oil and gas flow. This system is expected to be further studied in oilfield applications.",5,5,11
CO2,Low Permeability,"Zhou, Bobo; Kang, Wanli; Yang, Hongbin; Zhu, Tongyu; Zhang, Hongwen; Li, Xinxin; Sarsenbekuly, Bauyrzhan; Sarsenbek, Turtabayev",Preparation and properties of an acid-resistant preformed particle gel for conformance control,Preformed particle gel; Acid-resistant; CO2 flooding reservoir; Conformance control,ENHANCED OIL-RECOVERY; POLYACRYLAMIDE; MICROSPHERES; PERFORMANCE; RESERVOIRS; MECHANISM; SYSTEMS; SIZE,"In order to solve the problem of poor acid-resistant of preformed particle gel (PPG) as conformance control material in reservoirs with supercritical CO2 flooding, acrylamide (AM), N,N'-methylene bisacrylamide (MBA) and dimethyldiallylammonium chloride (DMDAAC) were used to prepare an acid-resistant preformed particle gel (AR-PPG) by radical polymerization method. Fourier transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM) were used to analyze the structural property of AR-PPG. The swelling capability, viscoelasticity and shear resistance of AR-PPG in acid environment have been studied. The conformance control system with good dispersion stability was selected and its plugging behavior was studied. The results showed that the swelling ratio of AR-PPG in acid environment was 1.41. Compared with conventional PPG, AR-PPG displayed better swelling capability, shearing resistance and viscoelastic properties in acidic environment. In addition, the conformance control system with good dispersion was 1000 mg/L AR-PPG dispersed in 1000 mg/L cationic polyacrylamide (CPAM) solution. The plugging rate of this conformance control system could be 70.8% in the low permeability micro-fracture core after supercritical CO2 flooding. This work can provide an alternative material for plugging and conformance control in oilfields of supercritical CO2 flooding.",5,5,9
CO2,Low Permeability,"Wang, Yuxia; Shang, Qinghua; Zhou, Lifa; Jiao, Zunsheng",Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin,Permeability heterogeneity; CO2 flooding; EOR; Tight sandstone reservoir; Ordos Basin,OIL-RECOVERY; CARBON-DIOXIDE; INJECTION,"Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200-1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with elastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO 2 -EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high-low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high-low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.",3,3,6
CO2,Low Permeability,"Enab, Khaled; Ertekin, Turgay",Screening and optimization of CO2-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network,Low permeability reservoirs; Artificial neural network; Water alternating gas injection; Carbon dioxide injection; EOR CO2-WAG; Fish-bone well,,"Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power. In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes. The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.",3,3,5
CO2,Foam,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
CO2,Foam,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
CO2,Foam,"Fu, Chunkai; Liu, Ning",Rheology and stability of nanoparticle-stabilized CO2 foam under reservoir conditions,Nanoparticle; Apparent viscosity; Foam stability; CO2 foam,ENHANCED OIL-RECOVERY; POLYMER; SURFACTANTS; BEHAVIOR; FLUIDS,"This study investigates the rheology and stability of nanoparticle-stabilized CO2 foams under reservoir conditions (high temperature and high pressure) for fracturing applications. The effects of different parameters on foam apparent viscosity and foam stability were experimentally investigated including the effects of nanoparticle concentration, salinity, foam quality (Gamma), shear rate and temperature. The power law model was applied to calculate foam apparent viscosity owing to its pseudo-plastic behavior, and the changes of foam heights over time were used to evaluate foam stability. Results showed that the CO2 foam apparent viscosity featured a mountain-shaped curve versus F, with the peak apparent viscosity obtained at 70% foam quality. The increase of salinity (up to 11%) in the continuous phase improved both foam stability and rheology. Higher nanoparticle concentration could contribute to better foam stability, but there was a threshold concentration, above which the foam apparent viscosity remained stabilized. The CO2 foam stabilized by nanoparticles displayed a shear-thickening behavior as the experiment flow rate increased from 6 mL/min to 18 mL/min. Further studies showed that as the total flow rate increased, the CO2 foam became finer-textured with better stability. Elevated temperatures could undermine foam apparent viscosity and long-term stability. The results of this study could provide guidelines as to the design of foam fracturing systems for field applications.",4,4,4
CO2,Foam,"Lopes, Leandro F.; Facanha, Juliana M. F.; Maqueira, Luis; Ribeiro, Felipe R. T.; Perez-Gramatges, Aurora",Coarsening reduction strategies to stabilize CO2-foam formed with a zwitterionic surfactant in porous media,CO2 mobility control; Foam stability; Micromodel; Gas mixture; Nanoparticles,ENHANCED OIL-RECOVERY; IMPROVED CO2 UTILIZATION; INTERFACIAL-TENSION; FOAM GENERATION; NANOPARTICLES; WATER; ADSORPTION; LIMESTONE; PRESSURE; VISUALIZATION,"Micromodel experiments at high-pressure high-temperature conditions were performed to evaluate the impact of different coarsening reduction strategies on CO2-foams stabilized with a zwitterionic surfactant, using silica nanoparticles in small concentration and mixing CO2 with a less water-soluble gas (nitrogen). The CO2-foam stabilized only by the surfactant showed poor behavior in the porous media, while an improvement in both foam texture (bubble density at the inlet of the micromodel) and gas trapping was qualitatively seen in the experiments using a nanofluid containing silica nanoparticles. The strong adsorption of the nanoparticles at the gas-water interface allowed to reduce the coarsening mechanism, reaching a minimum pressure gradient for strong foam generation throughout the micromodel chip. The use of a small concentration of nanoparticles in combination with the zwitterionic surfactant proved to be effective in reducing gas mobility without significant increase in pressure drop, which could be used as a strategy to control the mobility of injected CO2 in high permeability porous media, with reduced loss of injectivity. Coarsening was also reduced by using a mixture of CO2 and N2 as foaming gas, with an even greater gas mobility reduction, achieving a pressure drop 7.6 times higher compared to the CO2-foam stabilized only by surfactant. Furthermore, larger areas with trapped gas were visualized along the micromodel when co-injecting the mixture of gases and the zwitterionic surfactant solution. The large decrease in gas mobility seen for this strategy suggests that using a gas mixture would be suitable to control gas mobility in high-permeability channels and to block thief zones. The combination of using a gas mixture and a nanofluid to decrease CO2-foam destruction in porous media yielded a slight reduction in gas mobility, similar to that obtained with CO2-foam in the presence of nanoparticles, for they had similar pressuredrop values at same injection flow rate. The results obtained in this work demonstrated the importance of interfacial phenomena for tuning of coarsening and coalescence mechanisms associated with CO2-foam stability to the desired pore-scale application.",3,3,7
CO2,Foam,"Ahmed, S.; Alameri, W.; Ahmed, W. W.; Khan, S. A.",Rheological behavior of scCO(2)-Foam for improved hydrocarbon recovery: Experimental and deep learning approach,,REAL-TIME PREDICTION; FRACTURING FLUID; SHALE-GAS; DRILLING-FLUIDS; FOAM STABILITY; OIL; PERFORMANCE; VISCOSITY; TEMPERATURE; PRESSURE,"CO2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO2 foam is a key factor to control the efficiency of fracturing process that is strongly influenced by different process parameters such as foam quality, temperature, pressure, and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO2 foams by varying different process variables. CO2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (<1.8%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO2 foam projects for fracturing unconventional reservoirs.",3,3,5
CO2,Coal,"Xue, Yi; Liu, Jia; Ranjith, P. G.; Liang, Xin; Wang, Songhe",Investigation of the influence of gas fracturing on fracturing characteristics of coal mass and gas extraction efficiency based on a multi-physical field model,Gas fracturing; Hydro-mechanical coupling; Gas extraction efficiency; Fracture criterion; Non-uniform stress,OIL-RECOVERY; SHALE; PRESSURE; FLOW; CO2; RESERVOIRS; DIFFUSION; METHANE; PERMEABILITY; PRECIPITATION,"Coal seam gas recovery is a critical way to achieve clean energy development and reduce greenhouse gas emissions. Gas fracturing, as a necessary and advantageous stimulation measure, can effectively achieve gas extraction from deep coal seams and ensure safe production in deep coal mines. In this study, a hydro-mechanical coupling model is established to analyze the damage characteristics of coal seams during gas fracturing. The model focuses on three aspects: (a). the fracture criterion of type-I fracture under the action of multiple stress states in the fracturing process; (b). the characteristics of post-peak strain softening of coal and its influence on coal permeability; (c). the influence of non-uniform stress state on directional compression deformation and directional permeability of coal. The difference between gas fracturing (nitrogen, CO2) and hydraulic fracturing is studied based on this coupling model. The development of fractures in coal seam gas reservoirs after gas fracturing is investigated, and the influences of the coal parameters of the gas extraction process after fracturing are determined. Results show that because of the different compression coefficients, viscosities of water and gas and the slippage effect, there are obvious differences in the fracturing pressure of gas and water. Under the same parameters, the hydraulic fracturing method needs larger fracture initiation pressure than the gas fracturing method (nitrogen, CO2). For two kinds of media (nitrogen, CO2) in gas fracturing, in addition to the parameter difference of gas itself, the adsorption of CO2 is also the main factor affecting the fracturing pressure. The increase of coal permeability and Biot's coefficient will reduce the fracture initiation pressure, and the increase of confining pressure will increase the fracture initiation pressure.",39,39,25
CO2,Coal,"Huang, Qiming; Wu, Bing; Liu, Yu; Guo, Zhiguo; Wang, Gang; Sun, Lulu",Experimental and simulation investigations of the impact of polyacrylamide on CBM ad-/desorption,Slickwater; Coalbed methane; Polyacrylamide; Adsorption; Desorption,PORE STRUCTURE; FRACTURING FLUID; CO2 SORPTION; COAL; ADSORPTION; METHANE; CARBON; DIFFUSION; PRESSURE; NITROGEN,"Slickwater is commonly used during hydraulic fracturing in coalbed gas well, which is often prepared with polyacrylamide as the friction reducer. To investigate the impact of polyacrylamide on CBM ad-/desorption after a fracturing operation, slickwater with different concentrations of polyacrylamide were prepared and used to treat Illinois coal samples. Both isothermal ad-/desorption experiments and molecular simulations were conducted to investigate the impact of slickwater. Nuclear magnetic resonance measurements were performed to analyse the evolution of surface functional groups of coal during slickwater treatment. The results show that there is no significant chemical reaction between the coal component and polyacrylamide. Because of the porosity of the polyacrylamide coating adhered onto the surface of the pore, polyacrylamide has a significant sorption capacity of methane. The methane sorption amount of the 'coal-slickwater' system is higher than that of raw coal. However, with the increase of the amount of residue entering the pores, the porous structure of the polyacrylamide coating becomes denser, blocking some pores and the pore surface area is reduced; thus, the overall sorption capacity of the 'coal-polyacrylamide' system decreases.",16,16,17
CO2,Coal,"Wang, Haiyan; Yang, Xin; Du, Feng; Wang, Gongda; Wang, Yuanyuan; Zhao, Wei; Wang, Heng",Calculation of the diffusion coefficient of gas diffusion in coal: The comparison of numerical model and traditional analytical model,Coal gas; Diffusion coefficient; Numerical model; Analytical model,CARBON-DIOXIDE; DISPERSIVE DIFFUSION; PORE STRUCTURE; CO2 DIFFUSION; METHANE; ADSORPTION; PRESSURE; SORPTION; ANTHRACITE; MECHANISMS,"The prediction and calculation of the gas diffusion coefficient in a coal matrix is a key scientific issue in the study of gas diffusion behavior in coal. Due to its inherent shortcomings, the diffusion coefficient obtained from analytical models and widely used in academia does not fully reflect the gas diffusion law in actual coal seams. Therefore, numerical models have received increasing attention because they consider the actual conditions of gas diffusion in coal. In this work, four coal types were selected for adsorption/desorption kinetics experiments. The diffusion coefficients calculated by the analytical model and numerical model were compared. The results indicate that the diffusion coefficient obtained from the numerical model is much larger than that from the analytical model. The bidisperse numerical model is more accurate than the bidisperse analytical model. The evolution of the diffusion coefficient with the gas pressure differs for the adsorption and desorption stage.",7,7,19
CO2,Coal,"Liu, Peng; Liu, Ang; Zhong, Fangxiang; Jiang, Yongdong; Li, Jiajun",Pore/fracture structure and gas permeability alterations induced by ultrasound treatment in coal and its application to enhanced coalbed methane recovery,Ultrasound treatment; Coal structure; Gas permeability; CBM recovery,ADSORPTION CAPACITY; MOISTURE-CONTENT; BITUMINOUS COAL; CO2 INJECTION; TEMPERATURE; STRESS; IMPACT; PORES; TRANSDUCERS; MODEL,"Ultrasonic treatment is a highly potential method for reservoir permeability modification in enhanced coalbed methane recovery. Quantitative evaluations of ultrasonic induced changes in structure and permeability in coal are of great interest for potential field applications of ultrasound technology. In this study the scanning electron microscope (SEM) and low-temperature liquid nitrogen (LTLN) were used to examine the ultrasound induced alterations in coal pore/fracture, and further measured gas permeability in coal by coupling the ultrasound field and external stress. The SEM images show that ultrasound treatment can extend the original pore/fracture, increase the connectivity and remove barriers in gas seepage channel in coal. The LTLN data reveals that with the ultrasonic treatment (25 kHz, 18 kW, 2 h), the maximum N2adsorption quantity of the tested samples increased by 106.5%-258.4%, and the average pore diameter increased by 37.06%-81.40%; the specific surface area increased by 94.80%-118.15%, and the total pore volume increased by 87.12%-252.55%. It implies that coal pores in size ranging from 1 nm to 100 nm can be remarkably improved by ultrasonic treatment, which is significant beneficial to promote gas desorption/diffusion within coal matrix. Permeability tests demonstrate that gas permeability in stressed coal increased by 29.3%-57.1% with the implement of ultrasound field (25 kHz, 18 kW, 30 min). Ultrasonic performance on permeability improvement is proportional to the treatment time, but the function of ultrasonic fracturing has time threshold effect, and after a certain period of treatment, the ultrasonic fracturing performance becomes very limited in stressed coal.",6,6,16
CO2,Coal,"Gao, Zheng; Li, Bobo; Li, Jianhua; Wang, Bin; Ren, Chonghong; Xu, Jiang; Chen, Shuai",Coal permeability related to matrix-fracture interaction at different temperatures and stresses,Coal permeability; Temperature; Stress; Boundary conditions; Matrix; Fracture interaction,MODEL DEVELOPMENT; GAS INTERACTIONS; PORE PRESSURE; THERMAL-STIMULATION; METHANE ADSORPTION; CO2 PERMEABILITY; ANTHRACITE COAL; INDUCED STRAIN; SICHUAN BASIN; EVOLUTION,"Heat injection is considered to be an effective technique to increase Coalbed methane (CBM) production, which indicates the important role of temperature in gas flow. In this paper, two different experimental schemes have been designed, and the seepage tests concerning variable effective stress and variable pore pressure have been carried out respectively under different temperature conditions. A permeability model that considered the combined effect of temperature and stress was developed, and further extended so that it could be applied under other boundary conditions. An effective deformation factor f(m) was introduced to characterize the contribution of the change of coal matrix width to the change of fracture width, and the relationship between f(m) and temperature, under three boundary conditions, was quantitatively analyzed. Under constant pore pressure, the increase of effective stress will reduce the permeability. Under constant effective stress, an increase of pore pressure will lead to the decrease in permeability. Temperature would affect the permeability characteristics of coal from physical and chemical aspects, which were mainly manifested as inhibition, and this effect significantly weakened during the high stress stage. In terms of model matching, the permeability model results from each boundary condition were in good agreement with the measured results. In addition, the effective deformation factor f(m) increased exponentially over temperature under different boundary conditions. It is thought that these findings would provide a theoretical basis for the further study of coal matrix-fracture interaction, and CBM exploitation.",3,3,12
CO2,Porous Media,"Foyen, T.; Alcorn, Z. P.; Ferno, M. A.; Barrabino, A.; Holt, T.",CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants,CO2 foam; CO2 EOR; CO2 storage; CCUS; Surfactants; Mobility control,PERMEABILITY; STORAGE; FLOW; DESIGN; FIELD,"Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (S-w*). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.",4,4,55
CO2,Porous Media,"Jiang, M.; Xu, Z. G.; Zhou, Z. P.",Pore-scale investigation on reactive flow in porous media considering dissolution and precipitation by LBM,Dissolution and precipitation; Porous media; Lattice Boltzmann method; Volume of pixel; Multicomponent,LATTICE-BOLTZMANN; BOUNDARY-CONDITIONS; NATURAL-CONVECTION; 2-PHASE FLOW; SHALE; PERMEABILITY; SIMULATION; CO2; PARTICLES; EVOLUTION,"The reactive transport process in oil gas reservoirs is complicated due to the coupling between dissolution and precipitation. In the present study, based on lattice Boltzmann method, the coupled dissolution and precipitation process in randomly generated porous media by quartet structure generation is investigated at the scale of geological pores. The fluid velocity, temperature and concentration in porous media are solved by multicomponent flow lattice Boltzmann model, multicomponent thermal lattice Boltzmann model and mass transport lattice Boltzmann model, respectively. The solid phase is updated by volume of pixel method. The results show that the dissolution reaction rate has a positive impact on the consumption of reactants. For different precipitation reaction rates, there exists an optimal value resulting in abundant precipitate and sparse solid distribution. Reaction equilibrium constant affects reaction rates slightly but influence the solid morphology heavily. The coupled dissolution and precipitation process accelerates with the increase of Peclet number, but the precipitate produced increases with the decrease of Peclet number.",4,4,13
CO2,Porous Media,"Lopes, Leandro F.; Facanha, Juliana M. F.; Maqueira, Luis; Ribeiro, Felipe R. T.; Perez-Gramatges, Aurora",Coarsening reduction strategies to stabilize CO2-foam formed with a zwitterionic surfactant in porous media,CO2 mobility control; Foam stability; Micromodel; Gas mixture; Nanoparticles,ENHANCED OIL-RECOVERY; IMPROVED CO2 UTILIZATION; INTERFACIAL-TENSION; FOAM GENERATION; NANOPARTICLES; WATER; ADSORPTION; LIMESTONE; PRESSURE; VISUALIZATION,"Micromodel experiments at high-pressure high-temperature conditions were performed to evaluate the impact of different coarsening reduction strategies on CO2-foams stabilized with a zwitterionic surfactant, using silica nanoparticles in small concentration and mixing CO2 with a less water-soluble gas (nitrogen). The CO2-foam stabilized only by the surfactant showed poor behavior in the porous media, while an improvement in both foam texture (bubble density at the inlet of the micromodel) and gas trapping was qualitatively seen in the experiments using a nanofluid containing silica nanoparticles. The strong adsorption of the nanoparticles at the gas-water interface allowed to reduce the coarsening mechanism, reaching a minimum pressure gradient for strong foam generation throughout the micromodel chip. The use of a small concentration of nanoparticles in combination with the zwitterionic surfactant proved to be effective in reducing gas mobility without significant increase in pressure drop, which could be used as a strategy to control the mobility of injected CO2 in high permeability porous media, with reduced loss of injectivity. Coarsening was also reduced by using a mixture of CO2 and N2 as foaming gas, with an even greater gas mobility reduction, achieving a pressure drop 7.6 times higher compared to the CO2-foam stabilized only by surfactant. Furthermore, larger areas with trapped gas were visualized along the micromodel when co-injecting the mixture of gases and the zwitterionic surfactant solution. The large decrease in gas mobility seen for this strategy suggests that using a gas mixture would be suitable to control gas mobility in high-permeability channels and to block thief zones. The combination of using a gas mixture and a nanofluid to decrease CO2-foam destruction in porous media yielded a slight reduction in gas mobility, similar to that obtained with CO2-foam in the presence of nanoparticles, for they had similar pressuredrop values at same injection flow rate. The results obtained in this work demonstrated the importance of interfacial phenomena for tuning of coarsening and coalescence mechanisms associated with CO2-foam stability to the desired pore-scale application.",3,3,7
CO2,Porous Media,"Pinilla, Andres; Asuaje, Miguel; Hurtado, Camila; Hoyos, Angela; Ramirez, Luis; Padron, Aaron; Ratkovich, Nicolas",3D CFD simulation of a horizontal well at pore scale for heavy oil fields,Viscous fingering; Pore-scale; Horizontal well; CFD; Heavy oil; Recovery factor,POROUS-MEDIA; CO2 DISPLACEMENT; FLOW; CAPILLARY; PRESSURE; WATER; FRACTURE; DRAINAGE,"Water production in the oil industry has become so common that colloquial expressions such as ""oil companies no longer produce oil, but water"" have been unconsciously accepted in this industry. Nevertheless, water production is a serious issue in heavy oil fields with strong aquifers or fields under waterflooding for two reasons: It increases the costs affecting the economic viability of a project, and it has a serious environmental impact due to increasing energy consumption and CO2 emissions. The root cause behind this problem is a phenomenon called Viscous Fingering, which appears mainly by the viscosity ratio between the phases. This study aims to understand better the Viscous Fingering phenomenon associated with a horizontal well in 3D. For the first time, a scaled horizontal well in a numerical constructed porous media was studied using a full 3D Computational Fluid Dynamics (CFD) model. The horizontal well was scaled using the Reynolds law of similarity from a real section of a horizontal well. While the porous media was made with the DEM physical model using spherical 7mmparticles, which allows reproducing rock properties such as permeability and porosity. This phenomenon was studied at three different scaled production rates, 1000, 1500, and 2000 bbl/d. Finally, three different oils were considered to study the influence of the viscosity ratio in the CFD modeling of the fingering. It was determined that CM was capable of simulating Viscous Fingering for horizontal wells at the pore scale. Also, it could give information such as production and water cut-profiles, location and time of breakthrough, and specific locations of unrecoverable oil along the reservoir. The information given by the CFD approach could be useful for the development and improvement of completion and enhanced recovery techniques.",3,3,4
CO2,Interfacial Tension,"Abdulelah, Hesham; Al-Yaseri, Ahmed; Ali, Muhammad; Giwelli, Ausama; Negash, Berihun Mamo; Sarmadivaleh, Mohammad",CO2/Basalt's interfacial tension and wettability directly from gas density: Implications for Carbon Geo-sequestration,Carbon geo-sequestration; Basalt rocks; Interfacial tension; Carbon dioxide; Capillary trapping,MOLECULAR-DYNAMICS SIMULATION; CONTACT-ANGLE; CO2 STORAGE; TEMPERATURE; PRESSURE; ENERGY; SURFACTANT; SANDSTONE; IMPACT; QUARTZ,"There is an urgent need to store millions of tons of CO2 in deep underground formations to reduce anthropogenic emissions in the atmosphere. Basaltic rocks are recently depicted as feasible and safe candidates for storing CO2 in mineralized form. The leakage of stored CO2 in basaltic rocks could be minimized due to the mineralization process reported to occur in timescales magnitude shorter than those predicted for sandstone reservoirs. Rock/CO2 interfacial tension and wettability are essential factors to understand the interaction between CO2 and basalt rocks. Low values of rock/CO2 interfacial tension suggest stronger CO2-rock interaction, thus lower CO2 capacity is inferred, and vice versa. In other words, low values of rock/CO2 interfacial tension indicate stronger adhesion of CO2 molecules onto the rock surface. In this study, we have experimentally investigated basalt/CO2 interfacial tension under various pressures ranged from 4 MPa to 20 MPa and at temperatures of 308 degrees K and 333 degrees K. Our findings suggest that, as expected, Basalt/CO2 interfacial tension decreases as the pressure increases and increases as the temperature increases; solid/water interfacial energy decreases with increasing the temperature. The results also revealed that Basalt's CO2 sealing capacity is reduced as the contact angle (pressure) and temperature increases. The CO2 sealing capacity was reduced by up to 50% as the contact angle became similar to 80 degrees or when the pressure reached 17 MPa. We also found that there is a remarkable relationship between Basalt/CO2 IFT and CO2 density (rho) at 308 K and 333 K. The introduced relationship could serve as a handy tool to give a quick prediction of IFT CO2/basalt in basaltic formation or other CO2/solid systems. Determining solid/gas surface energy helps explain why minerals/rocks offer different wettability at certain pressure and temperature, leading to a better understanding of geological CO2-storage processes.",10,10,11
CO2,Interfacial Tension,"Zhang, Yusong; Liu, Qi; Ye, Hang; Yang, LeiLei; Luo, Dan; Peng, Bo","Nanoparticles as foam stabilizer: Mechanism, control parameters and application in foam flooding for enhanced oil recovery",Nanoparticles; Enhanced oil recovery; Wettability; Stabilizing foam; Influence factors; Stability measurement,IN-WATER FOAMS; CARBON DIOXIDE EMULSIONS; CO2 FOAM; SURFACTANT ADSORPTION; NONIONIC SURFACTANT; SILICA NANOPARTICLES; INTERFACIAL-TENSION; SUPERCRITICAL CO2; AQUEOUS FOAMS; NANO-SILICA,"Recently, numbers of studies have been conducted by using nanoparticles as novel foam stabilizer to enhance oil recovery (EOR). However, previous studies have not classified the nanoparticles into hydrophilic and hydrophobic/modified to explain the influence factors and mechanisms of different wettability nanoparticles stabilizing foam. Moreover, the mechanisms of nanoparticles stabilizing foam for EOR and the nanoparticles modification mechanism have not been discussed amply. In this review, the control parameters and the mechanisms of hydrophilic and hydrophobic nanoparticles on foam stability were discussed, and methods to evaluate foam stability were summarized. Meanwhile, the mechanisms of nanoparticles modification were introduced. Finally, the direction of the future studies and their application limitations were also pointed out. The main factors affected the application of nanoparticles stabilized foam included the types of nanoparticles, the modifiers for nanoparticles, the salinity, temperature and the concentration ratio between nanoparticles and surfactant. Both hydrophilic and hydrophobic nanoparticles could enhance the detachment energy, form network structure to stabilize foam. The synergistic effects between nanoparticles and surfactant and the existence state of nanoparticles on lamellae were different between hydrophilic and hydrophobic nanoparticles. NPs-foam could improve sweep efficiency in reservoir, emulsify the crude oil and flow into low permeability pores by fluid diversion. The foam stability measurement methods included viscosity measurement, core flooding experiment, foam thickness and size measurement, drop pressure measurement in dynamic state, and half-life time of foam in static state. It can be concluded that the synergistic effects influenced the hydrophobicity of nanoparticles, the moderate hydrophobic (contact angle similar to 90 degrees) nanoparticles were the optimum for stabilizing foam. For modified nanoparticles, the modified routes should be refined to identify the optimal modifier and synthesis route. The control parameters of nanoparticles stabilized foam should be studied further, and the low-cost and environmentalfriendly nanoparticles could be the potential foam stabilizer.",8,9,17
CO2,Interfacial Tension,"Lopes, Leandro F.; Facanha, Juliana M. F.; Maqueira, Luis; Ribeiro, Felipe R. T.; Perez-Gramatges, Aurora",Coarsening reduction strategies to stabilize CO2-foam formed with a zwitterionic surfactant in porous media,CO2 mobility control; Foam stability; Micromodel; Gas mixture; Nanoparticles,ENHANCED OIL-RECOVERY; IMPROVED CO2 UTILIZATION; INTERFACIAL-TENSION; FOAM GENERATION; NANOPARTICLES; WATER; ADSORPTION; LIMESTONE; PRESSURE; VISUALIZATION,"Micromodel experiments at high-pressure high-temperature conditions were performed to evaluate the impact of different coarsening reduction strategies on CO2-foams stabilized with a zwitterionic surfactant, using silica nanoparticles in small concentration and mixing CO2 with a less water-soluble gas (nitrogen). The CO2-foam stabilized only by the surfactant showed poor behavior in the porous media, while an improvement in both foam texture (bubble density at the inlet of the micromodel) and gas trapping was qualitatively seen in the experiments using a nanofluid containing silica nanoparticles. The strong adsorption of the nanoparticles at the gas-water interface allowed to reduce the coarsening mechanism, reaching a minimum pressure gradient for strong foam generation throughout the micromodel chip. The use of a small concentration of nanoparticles in combination with the zwitterionic surfactant proved to be effective in reducing gas mobility without significant increase in pressure drop, which could be used as a strategy to control the mobility of injected CO2 in high permeability porous media, with reduced loss of injectivity. Coarsening was also reduced by using a mixture of CO2 and N2 as foaming gas, with an even greater gas mobility reduction, achieving a pressure drop 7.6 times higher compared to the CO2-foam stabilized only by surfactant. Furthermore, larger areas with trapped gas were visualized along the micromodel when co-injecting the mixture of gases and the zwitterionic surfactant solution. The large decrease in gas mobility seen for this strategy suggests that using a gas mixture would be suitable to control gas mobility in high-permeability channels and to block thief zones. The combination of using a gas mixture and a nanofluid to decrease CO2-foam destruction in porous media yielded a slight reduction in gas mobility, similar to that obtained with CO2-foam in the presence of nanoparticles, for they had similar pressuredrop values at same injection flow rate. The results obtained in this work demonstrated the importance of interfacial phenomena for tuning of coarsening and coalescence mechanisms associated with CO2-foam stability to the desired pore-scale application.",3,3,7
CO2,Carbon Steel,"Elgaddafi, Rida; Ahmed, Ramadan; Shah, Subhash",Corrosion of carbon steel in CO2 saturated brine at elevated temperatures,Corrosion; Carbon dioxide; Brine; Temperature; Salt concentration; Carbon steel,HIGH-PRESSURE; MILD-STEEL; DIOXIDE CORROSION; MECHANISTIC MODEL; SODIUM-CHLORIDE; THERMODYNAMIC PROPERTIES; CR STEELS; PART 1; IRON; BEHAVIOR,"One of the main challenges in oil and gas wells is ensuring wellbore and casing integrity in a CO2 saturated brine environment. The integrity of a well casing relies on its mechanical properties and corrosion resistance to harsh downhole conditions. This paper discloses the results of a mathematical modeling study and experimental investigation conducted to understand the corrosion behavior of carbon steel (AISI 1045 Medium Carbon steel) in CO2 saturated brine. Corrosion experiments were carried out at 0.83 MPa varying temperature and CO2 partial pressure (CPP). To prepare test fluid, 1 wt % NaCl was added to deionized water and thoroughly mixed. The Weight loss (WL) and Linear polarization resistance (LPR) techniques were employed for investigating corrosion. A comprehensive corrosion model is formulated to predict corrosion in a CO2 environment containing high-salt concentration. Results indicate a strong impact of temperature on CO2 corrosion in brine environment. At low CPPs (P-CO2 <= 0.41 MPa), the pick corrosion rate was noted at 43 degrees C. Furthermore, the influence of NaCl content on corrosion was strongly affected by CO2 concentration. The model is predominantly in agreement with existing corrosion measurements and it predicts the inhibiting effect of salt in CO2 corrosion.",7,7,5
CO2,Carbon Steel,"Santos, B. A. F.; Serenario, M. E. D.; Souza, R. C.; Oliveira, J. R.; Vaz, G. L.; Gomes, J. A. C. P.; Bueno, A. H. S.",The electrolyte renewal effect on the corrosion mechanisms of API X65 carbon steel under sweet and sour environments,Carbon steel; CO2; EIS; SEM; XRD; high temperature corrosion,,"Sweet and sour services are the most common media found inside the pipelines of petroleum industry. They are one of the main causes of degradation by corrosion that lead to several financial and environmental losses worldwide. They also are responsible for the formation of corrosion products that might play a protective feature on the metal surface diminishing the corrosive processes. However, conditions in the field are not necessarily favourable for the precipitation of protective structures given the physicochemical dynamism inside the pipes. Then, the need to address this issue that occurs inside the tubes becomes crucial for the correct assessment of the development of protective corrosion products hence to give a more realistic approach to the lab conditions. Therefore, this paper presents a methodology to investigate the electrolyte renewal effects on API X65 carbon steel corrosion under CO2 and H2S (thiosulfate) environments at 4,5 bar of pressure, temperatures of 90 degrees C and 120 degrees C over 150 h. Electrochemical techniques (LPR and EIS), weight loss and characterizations were conducted in two different average pH, 3,3 and 4,5. The proposed methodology was capable to delay the development of protective scales in renewed media. The corrosion rates were higher for conditions with electrolyte renewal and higher temperature. FeCO3 formation was favoured at high pH and 120 degrees C whilst FeS structures were dominant at 90 degrees C. Sulphides were more cracked and uneven in renewed media whereas carbonate crystals presented higher anchorage to the substrate and were able to develop in sizeable diameters. Unrenewed media presented the best electrochemical responses.",5,5,1
CO2,Cement,"Lin, Miruo; Xi, Kelai; Cao, Yingchang; Liu, Quyang; Zhang, Zehan; Li, Ke","Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin",Shale oil reservoir; Petrographic features; Diagenetic alteration; Heterogeneity of reservoirs in shale strata,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; BOHAI BAY BASIN; RESERVOIR QUALITY; SANDSTONE RESERVOIRS; JIYANG DEPRESSION; SEDIMENTARY-ROCKS; JIMSAR SAG; LITHOFACIES CLASSIFICATION; ORGANIC GEOCHEMISTRY,"Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation.",5,5,10
CO2,Cement,"Jani, Priyesh; Imqam, Abdulmohsin",Class C fly ash-based alkali activated cement as a potential alternative cement for CO2 storage applications,Fly ash geopolymer cement; CO2; Portland cement,,"Long-term storage of carbon dioxide (CO2) inside depleted reservoirs can help reduce the impact of greenhouse gas emissions. Portland cement has been shown to degrade significantly during long-term contact with CO2. This research aims to provide a new environmentally friendly, Class C fly ash-based cement as a potential alternative to Portland cement for CO2 storage wells. This was achieved by comparing the mechanical degradation of Portland cement and Class C fly ash-based alkali-activated cement in a CO2 environment. A specially designed setup was constructed to create an in situ high pressure and high-temperature CO2 environment. Seventy-two cores of Portland cement and Class C fly ash-based cement were prepared for this study. The results show that CO2 reacted with the water in the vessel and formed carbonic acid, which reduced the water pH to 6.8. Millimeter-sized crystals of calcium carbonate (CaCO3) were observed on the surface of the Portland cement cores after the CO2 exposure. The surface of the fly ash-based alkali-activated cement cores was not substantively changed after the exposure. No significant change in density was observed for both types of cement during the 14 days of CO2 exposure. Portland cement showed a significant reduction in compressive strength, and this reduction developed as the exposure time increased. Interestingly, Class C fly ash-based cement showed no reduction in compressive strength, and only a small amount of reduction was observed after 14 days of exposure. This research compared the mechanical degradation of Portland cement and Class C fly ash-based alkali-activated cement in a high-pressure and high-temperature CO2 environment.",3,3,9
CO2,Tight Sandstone,"Wang, Yuxia; Shang, Qinghua; Zhou, Lifa; Jiao, Zunsheng",Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin,Permeability heterogeneity; CO2 flooding; EOR; Tight sandstone reservoir; Ordos Basin,OIL-RECOVERY; CARBON-DIOXIDE; INJECTION,"Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200-1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with elastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO 2 -EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high-low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high-low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.",3,3,6
CO2,Tight Sandstone,"Zhang, C. P.; Cheng, P.; Ma, Z. Y.; Ranjith, P. G.; Zhou, J. P.",Comparison of fracturing unconventional gas reservoirs using CO2 and water: An experimental study,CO2-based fracturing; Hydraulic fracturing; Breakdown pressure; Fracture aperture; Fracture morphology,CARBON-DIOXIDE; HYDRAULIC CONDUCTIVITY; TIGHT SANDSTONE; FLOW BEHAVIOR; SHALE GAS; PROPAGATION; INITIATION; PERMEABILITY; WELLBORE,"CO2-based fracturing (CBF) has been regarded as the most promising alternative to water-based fracturing (WBF) in water-sensitive unconventional gas reservoirs, and the fracture initiation and propagation at different in-site stresses created by CBF is crucial to the flow conductivity of fracture network. The main aim of this study is to compare the fracturing efficiency of WBF and CBF by conducting a series of fracturing tests on siltstone samples. According to the experimental results, the breakdown pressure linearly increases with the confining pressure, and the slope is 1.3928 and 1.6422 for CBF and WBF, respectively, and the much lower breakdown pressure for CBF is because of the fast penetration of CO2 through the rock matrix, which significantly reduces the effective stress around the borehole. Importantly, the observed fracture aperture for CBF is much greater than that for WBF, the maximum fracture aperture for CBF is around 2 to 5 times greater than that for WBF under the same test conditions. The difference in fracture aperture depends on the presence of discrete blocks and particles, and CBF can create greater and more loose particles in both mechanically-created method and hydraulically-created method to keep the created fractures open after the release of the injection pressure. The greater fracture aperture of CBF is favourable for the flow capacity of the fractures and therefore reservoir productivity, which is verified by the permeability tests with 190.43 times of permeability than that of WBF. Interestingly, the greater fracture width expansion for CBF perpendicular to the major principal pressure promotes the generation of horizontal fractures, even when the injection pressure is smaller than the major principal pressure, and the probability of horizontal fracture for CBF is 4-5 times of that for WBF, which reflect its great potential to create complex fracture network in unconventional gas reservoirs. The test results reveal that CBF is superior to the WBF since it is capable to create much more complex and efficient fracture networks. The findings are beneficial to understand the difference of fracturing behaviours at different in-site stresses between WBF and CBF, and provide experimental guidance for the exploitation of water-sensitive unconventional gas reservoirs by CBF.",3,3,4
Organic Matter,Pores,"Wang, Yang; Cheng, Hongfei; Hu, Qinhong; Liu, Luofu; Jia, Langbo; Gao, Shasha; Wang, Ye","Pore structure heterogeneity of Wufeng-Longmaxi shale, Sichuan Basin, China: Evidence from gas physisorption and multifractal geometries",Multifractal; Heterogeneity; Connectivity; Gas adsorption; Pore structure; Isolated organic matter,METHANE ADSORPTION; ORDOS BASIN; ORGANIC-MATTER; N-2 ADSORPTION; FE-SEM; POROSITY; INSIGHTS; MARINE; AREA; MATURATION,"Understanding the heterogeneity of the nanoscale pore structure is critical for assessment of hydrocarbon flow and storage in porous reservoirs. Multifractal theory is a powerful method to acquire the detailed heterogeneity information of the multiple pore system. The generalized dimension spectrum and singularity spectrum are two forms to depict the multifractal feature. Hurst exponent (H) and the width of singularity spectrum (Delta alpha) are two parameters to effectively assess the pore connectivity and heterogeneity, respectively. In this study, multifractal analysis was performed on over-mature Wufeng-Longmaxi shales and their corresponding isolated organic matter (OM) via gas physisorption (CO2 and N-2) test to ascertain the pore heterogeneity and its governing factors. Micropore (diameter<2 nm) structure in bulk shale contains stronger pore heterogeneity but weaker connectivity than meso-macropore (diameter = 2-100 nm) structure. The comparison of heterogeneity features of shale versus its isolated OM reveals that micropore associated with minerals could enhance the micropore heterogeneity in bulk shale, while meso-macmpore existing in minerals could reduce the meso-macmpore heterogeneity in bulk shale. Besides, the total organic carbon content has a positive effect on the micropore heterogeneity. The micropore and meso-macmpore volume have a certain impact on the pore heterogeneity in the corresponding pore size ranges. Compared with the low-mature Bakken shale, the over-mature Wufeng-Longmaxi shale contains the stronger micropore heterogeneity but weaker meso-macmpore heterogeneity, where less difference between the micropore and meso-macropore heterogeneities was also observed. We deduced that the whole shale pore spectrum likely tends to be homogeneous along with the OM thermal maturation.",7,7,26
Organic Matter,Pores,"Teng, Juan; Deng, Hucheng; Liu, Bei; Chen, Wenling; Fu, Meiyan; Xia, Yu; Yu, Hanze","Insights of the pore system of lacustrine shales from immature to late mature with the aid of petrology, mineralogy and porosimetry: A case study of the Triassic Yanchang Formation of the Ordos Basin, North China",pore evolution; pore size distribution; organic-matter pores; thermal maturation; lacustrine shale; Ordos Basin,CHANG 7 MEMBER; NORTHEASTERN BRITISH-COLUMBIA; MATURATION GRADIENT INSIGHTS; NANOMETER-SCALE PORES; ORGANIC-MATTER; ROCK PROPERTIES; GAS-ADSORPTION; BARNETT SHALE; ALBANY SHALE; MECHANICAL COMPACTION,"The study of pore network evolution is an important aspect of tight shale reservoir characterization. Pore spaces in shales consist of three major types: interparticle pores and intraparticle pores associated with mineral matrix and organic-matter pores. In this study, the evolution of pore networks for each pore type in lacustrine shales during thermal maturation was studied based on a suite of 19 Triassic Yanchang Formation shale samples from the Ordos Basin across a maturation gradient from immature to late mature (vitrinite reflectance (R-o) from 0.36 to 1.30%). The results show that different pore types follow systematic evolutions during thermal maturation and that the evolution of pore type and pore size is critically controlled by multiple diagenetic processes such as mechanical compaction, cementation, mineral dissolution, clay mineral transformation, and organic matter thermal maturation. Specifically, at immature and early mature stages (R-o < 0.55%), pores associated with mineral matrix are abundant and have moderate pore sizes. Interparticle pores exhibit preferential orientation along clay platelets. At the mature stage (0.55% < R-o < 1.15%), pores associated with mineral matrix have the smallest size, and interparticle pores become less common and show reduced preferential orientation because of mechanical compaction and cementation. Organic-matter pores start to develop at a maturity level of R-o 0.77% and higher. The total porosity and BET specific surface area show minimum values at R-o 1.12%, mainly because pre-existing matrix-related pores are destroyed by mechanical compaction and filled by migrated bitumen and liquid hydrocarbons, and then they increase when R-o exceeds 1.12%, which likely results from the development of secondary organic-matter nanopores due to the generation and expulsion of gaseous hydrocarbons. An increase in pore size of matrix-related pores at the late mature stage (1.15% < R-o < 1.30%) could be a result of dissolution by organic acid generated during organic matter thermal maturation.",7,9,5
Organic Matter,Pores,"Lu, Hao; Li, Qing; Yue, Dali; Wu, Shenghe; Fu, Yupu; Tang, Renzhi; Zhang, Zhenyu","Study on optimal selection of porosity logging interpretation methods for Chang 7(3) segment of the Yanchang Formation in the southwestern Ordos Basin, China",Zhangjiatan Shale; Tuff; Multi-component volume model; Back propagation neural network; Logging parameter; Error analysis,SHALE; MODEL,"The physical properties of tight shale reservoirs have always been a hot topic of discussion, and the tuff reservoirs have also attracted more and more attention. Log predicting of the porosity is also important for the exploration and development of tight oil. Tight oil resources have been found in tight shale and tuff reservoirs in the Chang 7 Member of the Upper Triassic Yanchang Formation in the Ordos Basin, China. However, the logging method that effectively predicting porosity of the Chang 7 Member is lacking, and few people have discussed how to optimize the log interpretation methods. In this study, the characteristics of shale and tuff reservoirs were summarized by microscope and scanning electron microscope observation, X-ray diffraction, pore and permeability experiment, and the logging data. In order to find the optimal method of porosity prediction, four methods were performed: multiple regression fitting, multi-component volume model, porosity logging formula, and back propagation neural network method. The ""Zhangjiatan Shale"" of the Chang 7 Member is characterized by abundant sandy lamina and tuff lamina, compared with the tuff reservoir, the enrichment of pyrite (average 22.7 wt%) and total organic matter (>6%) increase the content of intercrystalline pores and organic matter related pores, the logging response is characterized by high natural gamma ray, low spontaneous potential and high acoustic. The tuff reservoir is mainly composed of vitric tuff and crystal-vitric tuff, hence, the rich in intergranular pore and micro-fracture can be explained by the dissolution and devitrification of vitric and crystal fragments, and the logging characteristic is opposite to that of the ""Zhangjiatan Shale"". Four methods for predicting porosity are established. First, appropriate logging parameters are selected for regression fitting in the ""Zhangjiatan Shale"" (e.g., gamma ray, deep lateral logging resistivity, density and spontaneous potential) and tuff reservoir (e.g., acoustic, density, compensated neutron logging). Then, the rock multi-component volume model was established as rock skeleton, clay or tuff matter, organic matter, and pores. The logging parameters of the skeleton, clay and organic matter were obtained by intersection graphs, which were applied in the improved porosity logging formulas. The effect of organic matter on logging was considered into the traditional porosity prediction formula, a third prediction method was established. Finally, the BP method was introduced into the porosity prediction work, and the neural network parameters were adjusted according to the log and porosity data. The learning rate and the learning accuracy were set as 0.1 and 10(-6) in the study area. The error analysis between the result predicted and measured shows that the multi-component volume model is suitable for the ""Zhangjiatan Shale"" (the correlative coefficient R>80%), while the back propagation neural network is the best method for the tuff reservoir (the correlative coefficient R>90%).",4,4,8
Organic Matter,Pores,"An, Cheng; Killough, John; Xia, Xiaoyang",Investigating the effects of stress creep and effective stress coefficient on stress-dependent permeability measurements of shale rock,Permeability measurement; Stress creep; Effective stress coefficient; Clay and organic matter,LAW,"Rock permeability is an essential factor for production prediction and economic evaluation, which is often measured based on core samples in laboratory. However, several phenomena such as stress creep and path-dependent stress still present difficulties in correctly measuring and interpreting permeability under varying compaction stresses for core measurements. In this study, an improved stress-dependent permeability model is proposed to consider the effect of time-dependent compaction behavior on permeability measurements by incorporating the stress creep mechanism. Besides, how to correctly interpret stress-dependent permeability results with effective stress coefficient is introduced in detail. A coupled flow-geomechanics model is also developed to investigate the impact of effective stress coefficient on permeability change and cumulative production. Due to the stress creep phenomenon, rock permeability could be significantly overestimated if not enough measurement time is provided. The creep strain is highly related to the content of clay and kerogen. This is because the increasing creep strain over time is mainly from the closure of pre-existed micro-fractures and the compression of Nano-pores inside the soft materials, such as clay and kerogen. The creep strain model and improved stress-dependent permeability model were validated by comparing with multiple experimental data. Effective stress coefficient cannot be simply assumed one for organic-rich or clay-rich shale reservoirs, especially when pore pressure is changed to alter net effective stress in permeability measurements. A large effective stress coefficient amplifies the sensitivity of pore pressure change on the variation of both effective stress and permeability. The simulation results show a larger effective stress coefficient could provide higher cumulative production because of stronger compression from effective stress. The improved knowledge of stress creep and effective stress coefficient enables the development of best practices for permeability measurement of tight rock and provides more accurate permeability results for reservoir management and field development.",4,4,8
Organic Matter,Pores,"Xie, Xinhui; Deng, Hucheng; Fu, Meiyan; Hu, Lanxiao; He, Jianhua","Evaluation of pore structure characteristics of four types of continental shales with the aid of low-pressure nitrogen adsorption and an improved FE-SEM technique in Ordos Basin, China",Pore structure; Compositional classification; Yan-Chang #7 formation; Pore-size distribution,MISSISSIPPIAN BARNETT SHALE; TRIASSIC YANCHANG FORMATION; NORTH-CENTRAL TEXAS; FORT-WORTH BASIN; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; TRANSITIONAL SHALE; MICRO-FRACTURES; LONGMAXI SHALES; SICHUAN BASIN,"The upper Triassic continental shale of Yan-Chang #7 Formation, in Ordos Basin, China, exhibits complex geological conditions that lead to a complicated pore structure of the targeted formation. To reveal the pore structure and understand its influential factors, we first classify the shale samples into four categories according to the organic and clay contents (type #1: clay content (A) over cap > (A) over cap 52.0% and TOC (A) over cap >(A) over cap 3.0%, type #2: clay content >52% and TOC (A) over cap <<(A)over cap> 3.0%, type #3: clay content (A) over cap <<(A)over cap> 52.0% and TOC (A) over cap >(A) over cap 3.0%, type #4: clay content (A) over cap (A) over cap 52.0% and TOC (A) over cap >(A) over cap 3.0%). Then, the pore structure, total pore volume, and specific surface area are investigated by the low-pressure nitrogen adsorption analysis for each category. Next, the field-emission scanning electron microscopy analysis combined with the image processing is used to quantify the surface porosities of different types of pores and pore-size distributions of the samples. Results demonstrate that total pore volume and specific surface area are positively correlated with TOC and clay minerals (i.e., illite) but negatively correlated with brittle minerals (i.e., quartz and feldspar). Clay mineral is a major contributor to interparticle pores and micro-fractures. Higher TOC, illite, and chlorite contents lead to more pores/fractures in organic matter, while higher quartz content results in more intraparticle pores. The obtained results help to characterize the pore structure of Yan-Chang #7 Formation accurately as well as explore and exploit shale resources in this area.",4,4,2
Organic Matter,Pores,"Qing, Fan; Yan, Jianping; Wang, Jun; Hu, Qinhong; Wang, Min; Geng, Bin; Chao, Jing","Pore structure and fluid saturation of near-oil source low-permeability turbidite sandstone of the Dongying Sag in the Bohai Bay Basin, east China",Dongying sag; Low-permeability turbidite sandstone; Pore structure; Oil saturation; Mercury intrusion porosimetry; Pore-throat radius,MAGNETIC-RESONANCE NMR; SHAHEJIE FORMATION; ORDOS BASIN; WATER SATURATION; GRAIN-SIZE; POROSITY; RESERVOIR; DEPRESSION; AREA; DIAGENESIS,"Pore structure and oil saturation are important parameters in petroleum exploration and development, and the relationship between them is closer in near-oil source reservoirs (with a short-distance migration of oil and gas) than in other reservoirs. Using epoxy-impregnated thin sections, scanning electron microscopy (SEM), conventional core analyses of porosity and permeability, mercury intrusion porosimetry, and well logging, the characteristics of the petrology, physical properties, and pore structure we studied, as well as the relationship between pore structure and fluid saturation (maximum mercury intrusion saturation S-max and oil saturation S-o) of the near-oil source low-permeability turbidite sandstone reservoirs in the Es-3 member of the Dongying Sag, Bohai Bay Basin, eastern China. The results indicate that the turbidite sandstone reservoirs are mainly composed of fine sandstone and siltstone, with porosities and permeabilities ranging from 5 to 25% and 0.1 to 40 mD, respectively, and can be classified as medium to low porosity and extra-low to ultra-low permeability reservoirs. The pore types of high-quality reservoirs are mainly dominated by intergranular pores, both primary and dissolved, probably due to the influence of the acidic fluids generated from the cracking of organic matter. The pore structure is complex with respect to the pore-throat size distribution, and the overall pore-throat radius is small. Several pore structure parameters together affect the fluid saturation distribution, among which the medium pore-throat radius (R-50) and medium saturation pressure (P-50) are especially correlated with oil saturation. Different pore structure types have different characteristics of fluid saturation distribution, and the oil-bearing grade and oil saturation of the reservoirs above the oil-water contact are typically positively correlated with pore structure. This study will help to classify the pore structure in the wellbore profile and improve the accuracy of the oil saturation calculation by well logging.",4,4,1
Organic Matter,Pores,"Hou, Haihai; Shao, Longyi; Li, Yonghong; Liu, Lei; Liang, Guodong; Zhang, Wenlong; Wang, Xuetian; Wang, Weichao","Effect of paleoclimate and paleoenvironment on organic matter accumulation in lacustrine shale: Constraints from lithofacies and element geochemistry in the northern Qaidam Basin, NW China",Shale gas; Low thermal maturity; Lacustrine shale; Lacustrine basin evolution; Shimengou Formation; Middle Jurassic,CHANG 7 MEMBER; DEPOSITIONAL ENVIRONMENT; ANOXIC ENVIRONMENTS; PORE STRUCTURE; WESTERN HUBEI; ORDOS BASIN; BLACK SHALE; EOCENE; RIVER; SEDIMENTOLOGY,"Organic matter enrichment in lacustrine shale is significantly influenced by paleoclimate and paleoenvironment. In this study, a total of 24 shale samples were vertically collected from the YQ-1 drilling well in the northern Qaidam Basin, north-western China. The high-resolution geochemistry analyses were performed to provide a detailed geological description of these samples through lithofacies interpretation, total organic carbon (TOC) content testing, element geochemistry analysis, and mineralogical composition characterization. The results show that four lithofacies types can be identified in the Middle Jurassic Shimengou Formation, which consist of the brown oil shale with horizontal bedding, the black shale with well-developed lamination, the grey-black mudstone with horizontal and wavy bedding, and the carbonaceous mudstone with plant debris. The former two types were preserved in the Upper Member and were mainly deposited in a deep and semi-deep lake environment, whereas the latter two types were preserved in the Lower Member and were deposited in a littoralshallow lake. The TOC content, paleo-salinity, redox action, and paleo-productivity of the shales in the Upper Member are higher than those in the Lower Member, and other parameters, such as the chemical weathering degree and terrestrial clastic input, are higher in the shales of the Lower Member. Based on lithofacies and geochemical data, the shales in the Lower Member were deposited in a small, shallow freshwater lake within an oxygen-rich and relatively wet and hot paleoclimate, whereas the shales in the Upper Member were deposited in a large, deep, and saline water lake with dysoxic-anoxic conditions and a relatively arid and cold paleoclimate. The organic matter content in the Lower Member was primarily determined by the amount of detritus input with a low paleo-productivity owing to a strong weathering, whereas that in the Upper Member was dominated by anoxic processes under a good preservation and a low deposition rate. The model reflecting the relationship between accommodation and sediment-fill is employed to analyse the mechanism of organic matter accumulation. Three depositional stages are distinguished within the Shimengou Formation corresponding to overfilled, underfilled, and balanced-filled sediments with average TOC contents of 0.84 %, 4.95 %, and 6.09 %, respectively. This study reveals the dominated factors controlling organic matter enrichment in a continental basin and proposes a TOC distribution mechanism, which could provide a guide for the shale gas and shale oil exploration.",3,3,27
Organic Matter,Pores,"Jiu, Bo; Huang, Wenhui; Mu, Nana; Li, Yuan","Types and controlling factors of ordovician paleokarst carbonate reservoirs in the southeastern Ordos Basin, China",Karstification; Carbonate rock; Reservoir; Dissolution; Diagenesis,THERMOCHEMICAL SULFATE REDUCTION; SICHUAN BASIN; MAJIAGOU FORMATION; DIAGENETIC ALTERATION; NATURAL-GAS; TARIM BASIN; OIL-FIELD; ORIGIN; KARST; QUALITY,"With continuous improvements in oil and gas exploration technology and the increasing demand for oil and gas resources, the focus of oil and gas exploration has shifted from deep to ultradeep reservoirs. This study targeted the carbonate karst reservoirs of the Ordovician Ma5 Member in the southeastern Ordos Basin. Based on the analysis of cores, thin sections, cathodoluminescence, scanning electron microscopy (SEM), carbon and oxygen isotopes and trace elements, we discuss the development characteristics, types and influencing factors of paleokarst reservoirs. Petrology and geochemistry show three kinds of karstification in the study area: quasicontemporaneous karst, epigenetic karst and deep burial karst. The quasi-contemporaneous and epigenetic paleokarsts were mainly controlled by freshwater, where the soluble components of the strata were preferentially dissolved. The deep burial karstification was dominated by the reaction product H2S from thermochemical sulfate reduction (TSR) between sulfate minerals and organic matter, during which hydrothermal fluid provided the required activation energy for the reaction. The observations of cores and thin sections show that the paleokarst reservoirs are composed of different kinds of dissolution pores and fractures and cemented by multistage calcite and siliceous cements. Influenced by freshwater leaching and hydrothermal fluid, the three paleokarst processes led to negative anomalies in delta O-18 and delta C-13, while the low delta Ce, low delta Eu and rare earth element (REE) partition modes confirm that the intensity of freshwater leaching was stronger than that of hydrothermal fluid. The controlling factors of the paleokarst reservoirs included acidic fluids, paleogeomorphology and paleostructure in each diagenetic stage. According to the structural background and core characteristics, we establish a development model and spatial evolution model of the paleokarst reservoirs in the southeastern Ordos Basin.",3,3,11
Organic Matter,Pores,"Gao, Qi; Cheng, Yuanfang; Han, Songcai; Yan, Chuanliang; Li, Yang; Han, Zhongying",Effect of shale matrix heterogeneity on gas transport during production: A microscopic investigation,Shale gas; Matrix heterogeneity; Organic matter; Inorganic matter; Apparent permeability,,"Shale gas is playing increasingly important roles in transforming the global energy markets due to the huge demand for cleaner energy in the future. To extract shale gas at the commercial rate, formations must be hydraulically fractured to provide more contact area between the wellbores and reservoirs. Although the properties of hydraulic fractures are the key to gas production in the early stage, it is the matrix properties that determine the long-term production performance of the wells. However, understanding the gas transport behaviours in shale matrix is still a challenge at present. In this paper, to analyze shale gas flow at the microscale, an improved numerical model is developed, which is able to simultaneously capture the mechanical deformation of organic matter (OM) and inorganic matter (iOM), gas flow in OM and iOM, and fluid and solid interaction between the OM and iOM. The modelling results show that due to the coexistence of OM and iOM, the gas transport and shale matrix deformation behaviours exhibit regional differences. Specifically, during the gas production process, pore pressure in OM declines slower, gas density and Knudsen number in OM own larger values, and the apparent permeability and volumetric strain of OM are smaller. Therefore, taking matrix heterogeneity into consideration is necessary for accurately describing shale gas flow. In addition, numerical simulations are carried out to investigate the effect of a multitude of parameters on the modelling results. These parameters include nanopore compressibility, nanopore radius, matrix porosity, Langmuir volume and Langmuir pressure, and total organic carbon (TOC). The sensitivity of apparent permeability evolution in OM and iOM on each parameter is reported and discussed. The obtained results provide new insights for understanding gas transport in shale reservoirs from a microscopic perspective.",3,3,2
Organic Matter,Depositional Environment,"Zhang, Kun; Liu, Rong; Liu, Zhaojun","Sedimentary sequence evolution and organic matter accumulation characteristics of the Chang 8-Chang 7 members in the Upper Triassic Yanchang Formation, southwest Ordos Basin, central China",Sedimentary environment; Paleoclimate; Organic matter accumulation; Yanchang formation; Ordos basin,SILURIAN LONGMAXI FORMATION; DEVONIAN DUVERNAY FORMATION; TIGHT SANDSTONE RESERVOIRS; GEOCHEMICAL CHARACTERISTICS; DEPOSITIONAL ENVIRONMENT; BLACK SHALES; OIL-SHALE; STRATIGRAPHIC ANALYSIS; ELEMENT GEOCHEMISTRY; MARCELLUS FORMATION,"Lacustrine organic-rich shales are widely developed in the Chang 7 member of the Yanchang Formation in the Ordos Basin. These shales have been proven to be the source rocks for crude oil and shale oil. The study of sedimentary evolution and the characteristics of organic matter (OM) accumulation is an important factor for the exploration and development of oil and gas resources. Based on the lithological assemblages, lithofacies, mineral contents, log curves and geochemical data, the sequence stratigraphic framework of the Chang 8-Chang 7 members of the Yanchang Formation in the southern margin of the Ordos Basin were established. A complete third-order sequence was identified, and it included four systems tracts: a lowstand systems tract (LST), a transgressive systems tract (TST), a highstand systems tract (HST) and a regressive systems tract (RST). By using organic petrology, organic geochemistry and elemental geochemistry, the abundance and source of OM, paleoclimate, paleowater conditions, paleoproductivity, and deposition rates of the different systems tracts of the Chang 8-Chang 7 are studied in detail. Various factors controlled the accumulation of OM in the different systems tracts. The abundance of OM in the LST is low, the kerogen type is mainly type III (including vitrinite); the abundance of OM increased gradually in the TST, the kerogen types are III and II2 (including vitrinite and sporophyte); the OM is mainly concentrated in the HST, and the kerogen type is mainly type ID (including alginite), biomarker compounds show that OM has a mixed source of land plant and planktonic material; the abundance of OM in the RST is relatively high, the kerogen type is mainly type II2 and III (including vitrinite and alginite). The main controlling factor for OM accumulation was paleoclimate, which affected the primary productivity of lake and the chemical properties of the water column (redox and paleosalinity), leading to differences in OM accumulation under different climatic conditions. Hydrothermal activities contributed to anoxia and a salinity increase in lake bottom waters, with volcanic ash providing large amounts of essential nutrients for algal blooms. Based on the V/Cr, Sr/Ba, P/Ti and (La/Yb)(N) ratios with TOC values, the abundance of OM is positively correlated with paleoproductivity and water column reducibility, and negatively correlated with paleosalinity. The abundance of OM first increases and then decreases with increasing sedimentation rate. In general, the accumulation of OM was promoted under warm and humid climates, anoxic fresh to brackish water and adequate paleoproductivity.",8,8,9
Organic Matter,Depositional Environment,"You, Jiyuan; Liu, Yiqun; Song, Shanshan; Zhou, Dingwu; Yang, Yiyao",Characteristics and controlling factors of LORS from the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin,LORS; Redox conditions; Paleoproductivity; Volcanic and hydrothermal activities; Yanchang formation; Ordos basin,GEOCHEMICAL CHARACTERISTICS; SEQUENCE STRATIGRAPHY; CHINA IMPLICATIONS; BARNETT SHALE; TRACE-METALS; DEEP-SEA; EVOLUTION; ACCUMULATION; PRODUCTIVITY; MORPHOLOGY,"Lacustrine organic-rich shale (LORS) developed in the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin. LORS has been proven to be a source of crude oil and tight oil, as well as a source and reservoir for shale oil in the basin. A total of 35 LORS samples were collected from Well Z233 and analysed by mineralogy and element geochemistry to reveal the characteristics and controlling factors of LORS. The following results were obtained: In the oil shale, the organic matter is composed of type I and type II kerogen, with a pre- dominance of type II. The organic matter is mature and reaches high levels of abundance. (2)Through further analysis. The values of w(U)/w(Th), w(V)/w(Cr), w(Ni)/w(Co), the size and morphology of pyrite, indicates that the lake water of the LORS deposition period in the study area is anoxic or suboxic state. the TOC of the samples was found to have significant positive correlations with the w(Mo) and w(Ba-bio) contents. Paleoproductivity can be inferred to be the key factor controlling organic matter enrichment in the LORS. (3)Volcanic and hydrothermal activities promote the development of LORS, provide nutrients needed by organisms, promote the growth of organisms, and improve paleoproductivity. Hydrothermal activity leads to the formation of an anoxic environment at the bottom of the lake, and tuff will cover the sediments, which promotes LORS preservation. This study reveals in detail paleoproductivity is the main factor in the formation of LORS during the evolution of the basin. Volcanic and hydrothermal activities promoted the increase of paleoproductivity, and finally the oil shale layers with the richest organic matter have been formed. And thereby deepens our theoretical understanding of organic matter enrichment.",5,5,4
Organic Matter,Depositional Environment,"Liu, Zixuan; Yan, Detian; Du, Xuebin; Li, Shuangjian","Organic matter accumulation of the early Cambrian black shales on the flank of Micangshan-Hannan Uplift, northern upper Yangtze Block, South China",Black shales; Redox environment; Primary productivity; Chemical index of alteration (CIA),MARINE REDOX STRATIFICATION; NIUTITANG SHALE; DEPOSITIONAL ENVIRONMENT; RICH SHALES; FRACTAL CHARACTERISTICS; GEOCHEMICAL EVIDENCE; SEDIMENTATION-RATE; OCEAN OXYGENATION; GUIZHOU PROVINCE; LONGMAXI SHALES,"The Micangshan-Hannan Uplift area is proved a new shale gas exploration area with massive potential of Niutitang Formation in the past three years. Nevertheless, the organic matter enrichment mechanisms of this set of organic-rich shales lack discussion. Here, eighty-two samples of a drilling well from the Micangshan-Hannan Uplift, Upper Yangtze Block, South China were investigated for the organic matter (OM) accumulation mechanisms by geochemical analysis. Specifically, paleoredox conditions are classified by V/Sc, U/Th, and U-au; primary productivity is evaluated by TOC, Cu/Al, Ni/Al and, P/Al; sediment flux is indicated by Ti/Al; and paleoclimate is inferred by CIA and Ga/Rb ratios. Vertically, the Kuanchuanpu dolomite, underlying the Niutitang black shales, with TOC contents from 0.34% to 1.18% (avg. 0.71%), was deposited in oxic and low productivity conditions under lower sea level and more humid climate. Upwards, the silica-dominated and clay-rich siliceous mudstone (Assemblage 1) of Niutitang Formation, characterized by high TOC contents from 1.31% to 4.66% (avg. 2.78%) was classified into three units. The OM enrichment of Unit 1 was controlled by both anoxic condition and high primary productivity resulting from rapid sea level rise and increasing aeolian flux under cold and arid climate. The OM enrichment of Unit 2 was manipulated by the dysoxic bottom water condition, although the primary productivity remained relatively high. Then, the OM enrichment of Unit 3 was dominated by increasing primary productivity of surface water due to higher aeolian input and the dysoxic with intermittent anoxic condition advantageous for OM preservation. At last, the mixed siliceous mudstone (Assemblage 2) of Niutitang Formation displayed much lower TOC contents (avg. 1.34%). Both of oxic condition as well as lower primary productivity due to the declining aeolian flux led to the less efficient OM accumulation. In sum, the favorable organic matter accumulation in Niutitang Formation was controlled by anoxic bottom water condition and high primary productivity, which was related to the Early Cambrian global transgression and increasing aeolian flux under cold and arid climate.",4,4,12
Organic Matter,Depositional Environment,"Mussa, Agostinho; Kalkreuth, Wolfgang; Pimentel Mizusaki, Ana Maria; Bicca, Marcos Muller; Bojesen-Koefoed, Jorgen A.","Geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation",Parnaiba basin; Pimenteiras formation; Hydrocarbon generation; Geochemistry; Petrology; Palynofacies,,"The Paleozoic-Mesozoic Parnaiba Basin is an intraplate volcano-sedimentary basin from which the Pimenteiras Formation (Devonian) has potential for hydrocarbon generation, mainly natural gas. The thermal influence of igneous intrusions contributes to hydrocarbon generation in the basin. This present paper provides a geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation using geochemical and petrographic parameters. A total of 60 shale samples of the Pimenteiras Formation from three wells underwent analysis for TOC content, Rock-Eval pyrolysis, x-ray diffraction, organic petrology and palynofacies. The TOC content varies from 1.54 to 16.60 wt%, with the variations being related to different conditions of accumulation and preservation of the organic matter. The S-1 values range between 4.20 and 51.43 mg HC/g rock, with an average of 14.9 mg HC/g rock, and S-2 varies between 3.41 and 16.28 mg HC/g rock, with an average of 7.3 mg HC/g rock, showing very good to excellent source rock potential. The low Tmax values with an average of 430 degrees C indicate immaturity despite the high S-1 and S-2 values. The high S-1 values can be related to natural impregnation or contamination by drilling fluids. The HI vs Tmax plot showing the presence of kerogen type II and III, with potential for oil and gas generation. The mineral assemblage is associated with diagenetic or thermal processes (illite) and oxidation conditions (hematite and pyrite). The talc and chlorite can be related to metamorphism and provenance, while the calcite and gypsum indicate evaporitic conditions. The vitrinite reflectance varies between 0.31 and 0.67% Rrandom (average of 0.55% Rrandom). Thus, the samples can be classified as immature and mature and are consistent with Tmax values. The palynological records show a significant presence of phytoclasts and variations of palynomorphs along with the sequences from top to bottom, suggesting a transitional depositional environment (marine and continental) associated with the Devonian transgressive-regressive cycles. The data reinforce that the Pimenteiras Formation has the potential for hydrocarbon generation, mainly gas.",4,4,2
Organic Matter,Depositional Environment,"Alkhafaji, Mohamed W.","Biomarker assessment of oil biodegradation, water washing, and source rock characteristics of oil seeps from the Foothill Zone along the Tigris River, Northern Iraq",Source rock depositional environment; Biomarkers; Oil seeps; Biodegradation; Water washing; Hammam Al-Alil; Qaiyarah; Fat'ha; Northern Iraq,TRIASSIC SHUBLIK FORMATION; LOWER FARS FORMATION; IN-SOURCE ROCKS; CRUDE OILS; DEPOSITIONAL ENVIRONMENT; PETROLEUM GENERATION; THERMAL MATURITY; FOLD BELT; IDENTIFICATION; MARKERS,"Oil seep samples from the Foothill Zone of northern Iraq were geochemically characterized to determine the level of biodegradation and water washing of the seeps and to determine the depositional environment (including sedimentary facies, oxicity, and organic matter type) of correlative source rocks. Eight samples from three seeps sites (Hammam Al-Alil, Qaiyarah, and Fat'ha) were investigated. Detailed saturated and aromatic biomarkers were analyzed using GC-FID and GC-MS, in addition to measurement of carbon isotopes and the sulphur content. Qaiyarah samples range from non-biodegraded to moderately biodegraded; whereas Hammam Al-Alil and Fat'ha samples are moderately biodegraded. The Hammam Al-Alil and Fat'ha samples are also affected by water washing. Biomarker, carbon isotope, and sulphur data suggest that these oil seeps contain oil expelled during the early oil window from carbonate source rocks of Jurassic age. Correlative source rocks were deposited in an anoxic marine environment. The most likely source rock candidates include the Sargelu, Naoklekan, and Chia Gara formations.",4,4,1
Organic Matter,Depositional Environment,"Hou, Haihai; Shao, Longyi; Li, Yonghong; Liu, Lei; Liang, Guodong; Zhang, Wenlong; Wang, Xuetian; Wang, Weichao","Effect of paleoclimate and paleoenvironment on organic matter accumulation in lacustrine shale: Constraints from lithofacies and element geochemistry in the northern Qaidam Basin, NW China",Shale gas; Low thermal maturity; Lacustrine shale; Lacustrine basin evolution; Shimengou Formation; Middle Jurassic,CHANG 7 MEMBER; DEPOSITIONAL ENVIRONMENT; ANOXIC ENVIRONMENTS; PORE STRUCTURE; WESTERN HUBEI; ORDOS BASIN; BLACK SHALE; EOCENE; RIVER; SEDIMENTOLOGY,"Organic matter enrichment in lacustrine shale is significantly influenced by paleoclimate and paleoenvironment. In this study, a total of 24 shale samples were vertically collected from the YQ-1 drilling well in the northern Qaidam Basin, north-western China. The high-resolution geochemistry analyses were performed to provide a detailed geological description of these samples through lithofacies interpretation, total organic carbon (TOC) content testing, element geochemistry analysis, and mineralogical composition characterization. The results show that four lithofacies types can be identified in the Middle Jurassic Shimengou Formation, which consist of the brown oil shale with horizontal bedding, the black shale with well-developed lamination, the grey-black mudstone with horizontal and wavy bedding, and the carbonaceous mudstone with plant debris. The former two types were preserved in the Upper Member and were mainly deposited in a deep and semi-deep lake environment, whereas the latter two types were preserved in the Lower Member and were deposited in a littoralshallow lake. The TOC content, paleo-salinity, redox action, and paleo-productivity of the shales in the Upper Member are higher than those in the Lower Member, and other parameters, such as the chemical weathering degree and terrestrial clastic input, are higher in the shales of the Lower Member. Based on lithofacies and geochemical data, the shales in the Lower Member were deposited in a small, shallow freshwater lake within an oxygen-rich and relatively wet and hot paleoclimate, whereas the shales in the Upper Member were deposited in a large, deep, and saline water lake with dysoxic-anoxic conditions and a relatively arid and cold paleoclimate. The organic matter content in the Lower Member was primarily determined by the amount of detritus input with a low paleo-productivity owing to a strong weathering, whereas that in the Upper Member was dominated by anoxic processes under a good preservation and a low deposition rate. The model reflecting the relationship between accommodation and sediment-fill is employed to analyse the mechanism of organic matter accumulation. Three depositional stages are distinguished within the Shimengou Formation corresponding to overfilled, underfilled, and balanced-filled sediments with average TOC contents of 0.84 %, 4.95 %, and 6.09 %, respectively. This study reveals the dominated factors controlling organic matter enrichment in a continental basin and proposes a TOC distribution mechanism, which could provide a guide for the shale gas and shale oil exploration.",3,3,27
Organic Matter,Pyrolysis,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Organic Matter,Pyrolysis,"Yasin, Qamar; Baklouti, Syrine; Khalid, Perveiz; Ali, Syed Haroon; Boateng, Cyril D.; Du, Qizhen","Evaluation of shale gas reservoirs in complex structural enclosures: A case study from Patala Formation in the Kohat-Potwar Plateau, Pakistan",Kohat-potwar plateau; Patala formation; Shale gas; Rock-eval pyrolysis; Petrophysics,SILURIAN LONGMAXI FORMATION; SOUTHERN SICHUAN BASIN; GEOLOGICAL FACTORS; THERMAL MATURITY; ORGANIC-CARBON; MARINE SHALE; SALT RANGE; ROCK; BRITTLENESS; EOCENE,"Breakthroughs in shale gas exploration and production technology in China point to a possible solution to Pakistan's current energy crises. In this study, we evaluate the shale gas prospects in the Kohat-Potwar Plateau of Pakistan by establishing an integrated approach involving the analysis of fundamental elastic and petrophysical properties, Rock-Eval pyrolysis, and the sealing mechanism of shale. Detailed geochemical and petrophysical evaluation of the Patala Formation in the Kohat-Potwar Plateau indicates the good potential for shale gas with the following characteristics similar to the Longmaxi shale of Sichuan Basin China, i.e., (i) complex structural types sandwiched by tight limestone strata with low porosity (less than 3%), ultra-low permeability, high density, and large thickness which provides strong sealing capacity for gas preservation and enrichment; (ii) multiphase tectonic evolution of Patala Formation allowed various slippage processes to develop fractures and enhance the porosity and permeability; (iii) high organic matter content and thermal maturation stage (TOC > 2%, 416-445 SC); (iv) high brittle minerals content (e.g., calcite and dolomite > 40%); and (v) large formation thickness (>30 m) at shallow burial depth < 2500 m. This study emphasizes the critical role of the sealing mechanism in shale gas reservoirs. Furthermore, the results suggest that the evaluation and development of shale gas potential using petrophysical and geochemical analysis may be inadequate. Further scrutiny of the roof and floor of reservoirs' efficient sealing capacities is essential to understand the extent of shale gas preservation and enrichment. The study results provide valuable insights for identifying the sweet spots and preservation condition of shale gas in the Kohat-Potwar Plateau of Pakistan.",6,6,4
Organic Matter,Pyrolysis,"Lin, Miruo; Xi, Kelai; Cao, Yingchang; Liu, Quyang; Zhang, Zehan; Li, Ke","Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin",Shale oil reservoir; Petrographic features; Diagenetic alteration; Heterogeneity of reservoirs in shale strata,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; BOHAI BAY BASIN; RESERVOIR QUALITY; SANDSTONE RESERVOIRS; JIYANG DEPRESSION; SEDIMENTARY-ROCKS; JIMSAR SAG; LITHOFACIES CLASSIFICATION; ORGANIC GEOCHEMISTRY,"Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation.",5,5,10
Organic Matter,Pyrolysis,"Mussa, Agostinho; Kalkreuth, Wolfgang; Pimentel Mizusaki, Ana Maria; Bicca, Marcos Muller; Bojesen-Koefoed, Jorgen A.","Geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation",Parnaiba basin; Pimenteiras formation; Hydrocarbon generation; Geochemistry; Petrology; Palynofacies,,"The Paleozoic-Mesozoic Parnaiba Basin is an intraplate volcano-sedimentary basin from which the Pimenteiras Formation (Devonian) has potential for hydrocarbon generation, mainly natural gas. The thermal influence of igneous intrusions contributes to hydrocarbon generation in the basin. This present paper provides a geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation using geochemical and petrographic parameters. A total of 60 shale samples of the Pimenteiras Formation from three wells underwent analysis for TOC content, Rock-Eval pyrolysis, x-ray diffraction, organic petrology and palynofacies. The TOC content varies from 1.54 to 16.60 wt%, with the variations being related to different conditions of accumulation and preservation of the organic matter. The S-1 values range between 4.20 and 51.43 mg HC/g rock, with an average of 14.9 mg HC/g rock, and S-2 varies between 3.41 and 16.28 mg HC/g rock, with an average of 7.3 mg HC/g rock, showing very good to excellent source rock potential. The low Tmax values with an average of 430 degrees C indicate immaturity despite the high S-1 and S-2 values. The high S-1 values can be related to natural impregnation or contamination by drilling fluids. The HI vs Tmax plot showing the presence of kerogen type II and III, with potential for oil and gas generation. The mineral assemblage is associated with diagenetic or thermal processes (illite) and oxidation conditions (hematite and pyrite). The talc and chlorite can be related to metamorphism and provenance, while the calcite and gypsum indicate evaporitic conditions. The vitrinite reflectance varies between 0.31 and 0.67% Rrandom (average of 0.55% Rrandom). Thus, the samples can be classified as immature and mature and are consistent with Tmax values. The palynological records show a significant presence of phytoclasts and variations of palynomorphs along with the sequences from top to bottom, suggesting a transitional depositional environment (marine and continental) associated with the Devonian transgressive-regressive cycles. The data reinforce that the Pimenteiras Formation has the potential for hydrocarbon generation, mainly gas.",4,4,2
Organic Matter,Pyrolysis,"Yang, Dong; Wang, Lei; Zhao, Yangsheng; Kang, Zhiqin",Investigating pilot test of oil shale pyrolysis and oil and gas upgrading by water vapor injection,Oil shale; Water vapor; Hydrogen-rich; Shale oil; Light components; Heteroatomic compounds,EXTRACTION; CHINA; BED,"The technology of oil shale pyrolysis by water vapor injection uses high-temperature steam as a heat carrier to heat oil shale. Water vapor not only plays the role of transferring and exchanging heat, but it also chemically reacts with organic matter and some oil and gas products, altering the generation characteristics of oil and gas products. In this paper, we developed a long reaction distance test system for oil shale pyrolysis by water vapor injection and obtained the effects of heat injection temperature and time on the quality of oil and gas products. First, the results showed that with increasing pyrolysis temperature, the hydrogen content in the gas components gradually increased and then tended to be stable. In the process of heat injection temperature, increasing from 330 degrees C to 475 degrees C, the hydrogen content increased from 1.05% to 66.64%. High hydrogen concentration was mainly due to the reaction of water vapor with carbon residues, water vapor conversion reactions, and steam gasification reactions of hydrocarbon gases. Then, for shale oil, when the injection temperature was higher than 500 degrees C, the content of light components in shale oil remained at high levels, but the content of heteroatomic compounds was very little and the quality of shale oil was good. Next, when the injection temperature was controlled to 555 degrees C and the pyrolysis time was increased from 0 h to 4 h, the hydrogen content in the gas products increased first and then decreased, but the heteroatomic contents in the shale oil products increased first and then decreased. When the pyrolysis time was 2.5 h, the hydrogen content peaked, reaching 87.6%. When the pyrolysis time was 2 h, the content of heteroatoms peaked and reached 8.22%. Overall, when the injection temperature was 555 degrees C and the injection time reached 3 h, the shale oil formed through oil shale cracking presented higher quality.",3,3,5
Organic Matter,Pyrolysis,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Organic Matter,Chang 7 Oil,"Zhang, Kun; Liu, Rong; Liu, Zhaojun","Sedimentary sequence evolution and organic matter accumulation characteristics of the Chang 8-Chang 7 members in the Upper Triassic Yanchang Formation, southwest Ordos Basin, central China",Sedimentary environment; Paleoclimate; Organic matter accumulation; Yanchang formation; Ordos basin,SILURIAN LONGMAXI FORMATION; DEVONIAN DUVERNAY FORMATION; TIGHT SANDSTONE RESERVOIRS; GEOCHEMICAL CHARACTERISTICS; DEPOSITIONAL ENVIRONMENT; BLACK SHALES; OIL-SHALE; STRATIGRAPHIC ANALYSIS; ELEMENT GEOCHEMISTRY; MARCELLUS FORMATION,"Lacustrine organic-rich shales are widely developed in the Chang 7 member of the Yanchang Formation in the Ordos Basin. These shales have been proven to be the source rocks for crude oil and shale oil. The study of sedimentary evolution and the characteristics of organic matter (OM) accumulation is an important factor for the exploration and development of oil and gas resources. Based on the lithological assemblages, lithofacies, mineral contents, log curves and geochemical data, the sequence stratigraphic framework of the Chang 8-Chang 7 members of the Yanchang Formation in the southern margin of the Ordos Basin were established. A complete third-order sequence was identified, and it included four systems tracts: a lowstand systems tract (LST), a transgressive systems tract (TST), a highstand systems tract (HST) and a regressive systems tract (RST). By using organic petrology, organic geochemistry and elemental geochemistry, the abundance and source of OM, paleoclimate, paleowater conditions, paleoproductivity, and deposition rates of the different systems tracts of the Chang 8-Chang 7 are studied in detail. Various factors controlled the accumulation of OM in the different systems tracts. The abundance of OM in the LST is low, the kerogen type is mainly type III (including vitrinite); the abundance of OM increased gradually in the TST, the kerogen types are III and II2 (including vitrinite and sporophyte); the OM is mainly concentrated in the HST, and the kerogen type is mainly type ID (including alginite), biomarker compounds show that OM has a mixed source of land plant and planktonic material; the abundance of OM in the RST is relatively high, the kerogen type is mainly type II2 and III (including vitrinite and alginite). The main controlling factor for OM accumulation was paleoclimate, which affected the primary productivity of lake and the chemical properties of the water column (redox and paleosalinity), leading to differences in OM accumulation under different climatic conditions. Hydrothermal activities contributed to anoxia and a salinity increase in lake bottom waters, with volcanic ash providing large amounts of essential nutrients for algal blooms. Based on the V/Cr, Sr/Ba, P/Ti and (La/Yb)(N) ratios with TOC values, the abundance of OM is positively correlated with paleoproductivity and water column reducibility, and negatively correlated with paleosalinity. The abundance of OM first increases and then decreases with increasing sedimentation rate. In general, the accumulation of OM was promoted under warm and humid climates, anoxic fresh to brackish water and adequate paleoproductivity.",8,8,9
Organic Matter,Chang 7 Oil,"You, Jiyuan; Liu, Yiqun; Li, Yijun; Zhou, Dingwu; Zheng, Qinghua; Yang, Yiyao; Shi, Jian; Gao, Haofeng",Influencing factor of Chang 7 oil shale of Triassic Yanchang Formation in Ordos Basin: Constraint from hydrothermal fluid,Elemental geochemistry; Hydrothermal sediment; Oil shale; Yanchang formation; Ordos basin,EAST PACIFIC RISE; ORGANIC-MATTER; RIDGE; FRANCISCAN; CHERTS; ROCKS; CREST,"The Chang 7 oil shales of the Triassic Yanchang Formation in the southern margin of the Ordos Basin has been a concern of researchers because of the extensive development of lacustrine hydrothermal sedimentary rocks in it. Here, we studied the petrological and mineralogical characteristics of hydrothermal sedimentary rocks through ordinary thin sections, scanning electron microscope and electron probe observations, and evidences about hydrothermal activity were identified from the oil shales. On this basis, we further complete their geochemical analysis. The results show that the Cs, U, Th, Pb, and Mn of the Chang 7 oil shale have significant positive anomalies and that the Eu and Ta elements have negative anomalies. The TOC value of Chang 7 oil shale ranges from 0.18 wt% to 18.15 wt%, with an average value of 3.85 wt%. The average value of the Chang7-3 section is 5.33 wt%, the average value of the Chang7-2 section is 2.15 wt%, and the average value of the Chang7-1 is 3.05 wt%. In addition, the hydrothermal index of Chang 7 source rock shows: The correlation coefficient between the hydrothermal index and the TOC content is as high as 0.86 and 0.85. There is the most hydrothermal input in Chang7-3 deposition period, it was somewhat weakened in the Chang 7-2 deposition period, and it was enhanced in the Chang 7-1 deposition period. Hydrothermal deposition is involved in the hydrocarbon generation of oil shales. The greater the hydrothermal input intensity is, the greater the TOC content of the oil shale is.",7,7,3
Organic Matter,Chang 7 Oil,"Su, Kaiming; Chen, Shijia; Hou, Yuting; Zhang, Haifeng; Zhang, Xiaolei; Zhang, Wenxuan; Liu, Guanglin; Hu, Cong; Han, Meimei","Geochemical characteristics, origin of the Chang 8 oil and natural gas in the southwestern Ordos Basin, China",Petroleum geochemistry; Organic maturity; Oil and gas genesis; Biodegradation; Yanchang formation; Southwestern ordos basin,,"Petroleum exploration in the Ordos Basin gradually expanded to the edge of the basin, but encountered difficulties on the southwestern edge. Compared with mature exploration areas inside the basin, the nature of reservoir fluids in the southwestern area is more complex. In order to better understand the oil/gas system in this area, this study conducted a detailed research on the geochemical characteristics of potential source rocks and reservoir fluids in this area. The results show that although the Chang 7 oil group in the study area developed thicker mudstone and has a high abundance of organic matter, the low degree of thermal evolution limits its hydrocarbon production. The Chang 8 oil in the study area is the result of lateral migration of products from mature source rocks inside the basin, which can be explained by the similar biomarker characteristics and gradually changing nitrogen compounds between them. Anaerobic biodegradation is an important factor that complicates the fluid properties in the study area. It not only thickens part of the oil, but also produces secondary biogenic natural gas, mainly methane.",5,5,10
Organic Matter,Chang 7 Oil,"Lu, Hao; Li, Qing; Yue, Dali; Wu, Shenghe; Fu, Yupu; Tang, Renzhi; Zhang, Zhenyu","Study on optimal selection of porosity logging interpretation methods for Chang 7(3) segment of the Yanchang Formation in the southwestern Ordos Basin, China",Zhangjiatan Shale; Tuff; Multi-component volume model; Back propagation neural network; Logging parameter; Error analysis,SHALE; MODEL,"The physical properties of tight shale reservoirs have always been a hot topic of discussion, and the tuff reservoirs have also attracted more and more attention. Log predicting of the porosity is also important for the exploration and development of tight oil. Tight oil resources have been found in tight shale and tuff reservoirs in the Chang 7 Member of the Upper Triassic Yanchang Formation in the Ordos Basin, China. However, the logging method that effectively predicting porosity of the Chang 7 Member is lacking, and few people have discussed how to optimize the log interpretation methods. In this study, the characteristics of shale and tuff reservoirs were summarized by microscope and scanning electron microscope observation, X-ray diffraction, pore and permeability experiment, and the logging data. In order to find the optimal method of porosity prediction, four methods were performed: multiple regression fitting, multi-component volume model, porosity logging formula, and back propagation neural network method. The ""Zhangjiatan Shale"" of the Chang 7 Member is characterized by abundant sandy lamina and tuff lamina, compared with the tuff reservoir, the enrichment of pyrite (average 22.7 wt%) and total organic matter (>6%) increase the content of intercrystalline pores and organic matter related pores, the logging response is characterized by high natural gamma ray, low spontaneous potential and high acoustic. The tuff reservoir is mainly composed of vitric tuff and crystal-vitric tuff, hence, the rich in intergranular pore and micro-fracture can be explained by the dissolution and devitrification of vitric and crystal fragments, and the logging characteristic is opposite to that of the ""Zhangjiatan Shale"". Four methods for predicting porosity are established. First, appropriate logging parameters are selected for regression fitting in the ""Zhangjiatan Shale"" (e.g., gamma ray, deep lateral logging resistivity, density and spontaneous potential) and tuff reservoir (e.g., acoustic, density, compensated neutron logging). Then, the rock multi-component volume model was established as rock skeleton, clay or tuff matter, organic matter, and pores. The logging parameters of the skeleton, clay and organic matter were obtained by intersection graphs, which were applied in the improved porosity logging formulas. The effect of organic matter on logging was considered into the traditional porosity prediction formula, a third prediction method was established. Finally, the BP method was introduced into the porosity prediction work, and the neural network parameters were adjusted according to the log and porosity data. The learning rate and the learning accuracy were set as 0.1 and 10(-6) in the study area. The error analysis between the result predicted and measured shows that the multi-component volume model is suitable for the ""Zhangjiatan Shale"" (the correlative coefficient R>80%), while the back propagation neural network is the best method for the tuff reservoir (the correlative coefficient R>90%).",4,4,8
Organic Matter,Chang 7 Oil,"Hou, Haihai; Shao, Longyi; Li, Yonghong; Liu, Lei; Liang, Guodong; Zhang, Wenlong; Wang, Xuetian; Wang, Weichao","Effect of paleoclimate and paleoenvironment on organic matter accumulation in lacustrine shale: Constraints from lithofacies and element geochemistry in the northern Qaidam Basin, NW China",Shale gas; Low thermal maturity; Lacustrine shale; Lacustrine basin evolution; Shimengou Formation; Middle Jurassic,CHANG 7 MEMBER; DEPOSITIONAL ENVIRONMENT; ANOXIC ENVIRONMENTS; PORE STRUCTURE; WESTERN HUBEI; ORDOS BASIN; BLACK SHALE; EOCENE; RIVER; SEDIMENTOLOGY,"Organic matter enrichment in lacustrine shale is significantly influenced by paleoclimate and paleoenvironment. In this study, a total of 24 shale samples were vertically collected from the YQ-1 drilling well in the northern Qaidam Basin, north-western China. The high-resolution geochemistry analyses were performed to provide a detailed geological description of these samples through lithofacies interpretation, total organic carbon (TOC) content testing, element geochemistry analysis, and mineralogical composition characterization. The results show that four lithofacies types can be identified in the Middle Jurassic Shimengou Formation, which consist of the brown oil shale with horizontal bedding, the black shale with well-developed lamination, the grey-black mudstone with horizontal and wavy bedding, and the carbonaceous mudstone with plant debris. The former two types were preserved in the Upper Member and were mainly deposited in a deep and semi-deep lake environment, whereas the latter two types were preserved in the Lower Member and were deposited in a littoralshallow lake. The TOC content, paleo-salinity, redox action, and paleo-productivity of the shales in the Upper Member are higher than those in the Lower Member, and other parameters, such as the chemical weathering degree and terrestrial clastic input, are higher in the shales of the Lower Member. Based on lithofacies and geochemical data, the shales in the Lower Member were deposited in a small, shallow freshwater lake within an oxygen-rich and relatively wet and hot paleoclimate, whereas the shales in the Upper Member were deposited in a large, deep, and saline water lake with dysoxic-anoxic conditions and a relatively arid and cold paleoclimate. The organic matter content in the Lower Member was primarily determined by the amount of detritus input with a low paleo-productivity owing to a strong weathering, whereas that in the Upper Member was dominated by anoxic processes under a good preservation and a low deposition rate. The model reflecting the relationship between accommodation and sediment-fill is employed to analyse the mechanism of organic matter accumulation. Three depositional stages are distinguished within the Shimengou Formation corresponding to overfilled, underfilled, and balanced-filled sediments with average TOC contents of 0.84 %, 4.95 %, and 6.09 %, respectively. This study reveals the dominated factors controlling organic matter enrichment in a continental basin and proposes a TOC distribution mechanism, which could provide a guide for the shale gas and shale oil exploration.",3,3,27
Organic Matter,Natural Gas,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Organic Matter,Natural Gas,"Su, Kaiming; Chen, Shijia; Hou, Yuting; Zhang, Haifeng; Zhang, Xiaolei; Zhang, Wenxuan; Liu, Guanglin; Hu, Cong; Han, Meimei","Geochemical characteristics, origin of the Chang 8 oil and natural gas in the southwestern Ordos Basin, China",Petroleum geochemistry; Organic maturity; Oil and gas genesis; Biodegradation; Yanchang formation; Southwestern ordos basin,,"Petroleum exploration in the Ordos Basin gradually expanded to the edge of the basin, but encountered difficulties on the southwestern edge. Compared with mature exploration areas inside the basin, the nature of reservoir fluids in the southwestern area is more complex. In order to better understand the oil/gas system in this area, this study conducted a detailed research on the geochemical characteristics of potential source rocks and reservoir fluids in this area. The results show that although the Chang 7 oil group in the study area developed thicker mudstone and has a high abundance of organic matter, the low degree of thermal evolution limits its hydrocarbon production. The Chang 8 oil in the study area is the result of lateral migration of products from mature source rocks inside the basin, which can be explained by the similar biomarker characteristics and gradually changing nitrogen compounds between them. Anaerobic biodegradation is an important factor that complicates the fluid properties in the study area. It not only thickens part of the oil, but also produces secondary biogenic natural gas, mainly methane.",5,5,10
Organic Matter,Natural Gas,"Mussa, Agostinho; Kalkreuth, Wolfgang; Pimentel Mizusaki, Ana Maria; Bicca, Marcos Muller; Bojesen-Koefoed, Jorgen A.","Geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation",Parnaiba basin; Pimenteiras formation; Hydrocarbon generation; Geochemistry; Petrology; Palynofacies,,"The Paleozoic-Mesozoic Parnaiba Basin is an intraplate volcano-sedimentary basin from which the Pimenteiras Formation (Devonian) has potential for hydrocarbon generation, mainly natural gas. The thermal influence of igneous intrusions contributes to hydrocarbon generation in the basin. This present paper provides a geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation using geochemical and petrographic parameters. A total of 60 shale samples of the Pimenteiras Formation from three wells underwent analysis for TOC content, Rock-Eval pyrolysis, x-ray diffraction, organic petrology and palynofacies. The TOC content varies from 1.54 to 16.60 wt%, with the variations being related to different conditions of accumulation and preservation of the organic matter. The S-1 values range between 4.20 and 51.43 mg HC/g rock, with an average of 14.9 mg HC/g rock, and S-2 varies between 3.41 and 16.28 mg HC/g rock, with an average of 7.3 mg HC/g rock, showing very good to excellent source rock potential. The low Tmax values with an average of 430 degrees C indicate immaturity despite the high S-1 and S-2 values. The high S-1 values can be related to natural impregnation or contamination by drilling fluids. The HI vs Tmax plot showing the presence of kerogen type II and III, with potential for oil and gas generation. The mineral assemblage is associated with diagenetic or thermal processes (illite) and oxidation conditions (hematite and pyrite). The talc and chlorite can be related to metamorphism and provenance, while the calcite and gypsum indicate evaporitic conditions. The vitrinite reflectance varies between 0.31 and 0.67% Rrandom (average of 0.55% Rrandom). Thus, the samples can be classified as immature and mature and are consistent with Tmax values. The palynological records show a significant presence of phytoclasts and variations of palynomorphs along with the sequences from top to bottom, suggesting a transitional depositional environment (marine and continental) associated with the Devonian transgressive-regressive cycles. The data reinforce that the Pimenteiras Formation has the potential for hydrocarbon generation, mainly gas.",4,4,2
Organic Matter,Natural Gas,"Lu, Jungang; Luo, Zhaoyang; Zou, Hongliang; Li, Yanping; Hu, ZhengZhou; Zhou, Zengyuan; Zhu, Jiang; Han, Meimei; Zhao, Liping; Lin, Zonghui","Geochemical characteristics, origin, and mechanism of differential accumulation of natural gas in the carboniferous kelameili gas field in Junggar basin, China",Junggar basin; Volcanic gas reservoir; Geochemical characteristics; Carbon isotope; Light hydrocarbon,ORDOS BASIN; STABLE CARBON; LIGHT-HYDROCARBONS; PETROLEUM; EVOLUTION; OIL; RESERVOIRS; ISOTOPES; ROCKS,"Since the discovery of the Kelameili gas field, the exploration of volcanic gas reservoirs in the Junggar Basin has attracted considerable attention. However, owing to the limitations involved in studying the characteristics of the origin and distribution of the volcanic gas reservoirs in this area, the study of gas reservoirs in the South fault terrace area of the Kelameili gas field as a typical peripheral area is greatly restricted, and the exploration process is relatively slow. Therefore, it is necessary to analyse and compare the differences in the geochemical characteristics of the natural gas between the Kelameili gas field and the fault terrace area of the south belt by analysing the natural gas geochemistry, hydrocarbon generation evolution, and structural evolution. In addition, geochemical experiments involving the natural gas components, carbon isotopes, light hydrocarbons, hydrocarbon generation, and evolutionary history of the source rocks and the interpretation of seismic profiles reflecting the structural evolution, help clarifying the genetic type of the volcanic gas reservoirs and the source of the natural gas in this area. The results indicate the following. (1) The natural gas in the study area has undergone thermal genesis and is generated by kerogen cracking. It is a typical humic gas with high maturity. (2) The origin of the natural gas is the Carboniferous source rock in the depression, which is significantly different from the natural gas from the typical Permian and Jurassic. (3) The primary reason for the difference in natural gas accumulation is that the Carboniferous source rock entered the high-maturity stage in the Early Jurassic. The formation time of the trap is earlier than that of the high-maturity stage of the source rock evolution, which can capture multi-stage source rock products. (4) Based on the hydrocarbon source conditions that the hydrocarbon supply horizon of the Kelameili gas field has a high maturity of organic matter, and insufficient hydrocarbon supply, it is considered that traps capturing the multi-stage source rock products represent a larger scale of natural gas accumulation. The results of this study can deepen the understanding of volcanic gas reservoirs in the Junggar Basin and guidethe exploration and development of global volcanic gas reservoirs and the surrounding large-scale gas fields.",3,4,11
Organic Matter,Hydrocarbon Expulsion,"Teng, Juan; Deng, Hucheng; Liu, Bei; Chen, Wenling; Fu, Meiyan; Xia, Yu; Yu, Hanze","Insights of the pore system of lacustrine shales from immature to late mature with the aid of petrology, mineralogy and porosimetry: A case study of the Triassic Yanchang Formation of the Ordos Basin, North China",pore evolution; pore size distribution; organic-matter pores; thermal maturation; lacustrine shale; Ordos Basin,CHANG 7 MEMBER; NORTHEASTERN BRITISH-COLUMBIA; MATURATION GRADIENT INSIGHTS; NANOMETER-SCALE PORES; ORGANIC-MATTER; ROCK PROPERTIES; GAS-ADSORPTION; BARNETT SHALE; ALBANY SHALE; MECHANICAL COMPACTION,"The study of pore network evolution is an important aspect of tight shale reservoir characterization. Pore spaces in shales consist of three major types: interparticle pores and intraparticle pores associated with mineral matrix and organic-matter pores. In this study, the evolution of pore networks for each pore type in lacustrine shales during thermal maturation was studied based on a suite of 19 Triassic Yanchang Formation shale samples from the Ordos Basin across a maturation gradient from immature to late mature (vitrinite reflectance (R-o) from 0.36 to 1.30%). The results show that different pore types follow systematic evolutions during thermal maturation and that the evolution of pore type and pore size is critically controlled by multiple diagenetic processes such as mechanical compaction, cementation, mineral dissolution, clay mineral transformation, and organic matter thermal maturation. Specifically, at immature and early mature stages (R-o < 0.55%), pores associated with mineral matrix are abundant and have moderate pore sizes. Interparticle pores exhibit preferential orientation along clay platelets. At the mature stage (0.55% < R-o < 1.15%), pores associated with mineral matrix have the smallest size, and interparticle pores become less common and show reduced preferential orientation because of mechanical compaction and cementation. Organic-matter pores start to develop at a maturity level of R-o 0.77% and higher. The total porosity and BET specific surface area show minimum values at R-o 1.12%, mainly because pre-existing matrix-related pores are destroyed by mechanical compaction and filled by migrated bitumen and liquid hydrocarbons, and then they increase when R-o exceeds 1.12%, which likely results from the development of secondary organic-matter nanopores due to the generation and expulsion of gaseous hydrocarbons. An increase in pore size of matrix-related pores at the late mature stage (1.15% < R-o < 1.30%) could be a result of dissolution by organic acid generated during organic matter thermal maturation.",7,9,5
Organic Matter,Hydrocarbon Expulsion,"Zhu, Chenxi; Jiang, Fujie; Zhang, Pengyuan; Hu, Tao; Liu, Ying; Xu, Tianwu; Zhang, Yun-xian; Deng, Qian; Zhou, Yongshui; Xiong, Hang; Song, Zezhang","Identification of effective source rocks in different sedimentary environments and evaluation of hydrocarbon resources potential: A case study of paleogene source rocks in the Dongpu Depression, Bohai Bay Basin",Continental basin; Saline lacustrine basin; Effective source rock; Hydrocarbon expulsion threshold; Resource potential; Dongpu depression,,"Source rocks in lacustrine rifting basins have great heterogeneity, which leads to imprecise assessments of hydrocarbon resources. Previous studies evaluated the source rocks of different sedimentary environments in lacustrine basins or depressions using the same lower limit of effective source rocks (i.e., the minimum total organic carbon (TOC) at which the source rocks are capable of expelling hydrocarbons). In this study, the source rock samples were selected from five formations in the Dongpu Depression for organic geochemical experiments and quantitative simulations of hydrocarbon expulsion. According to salinity differences, every formation was divided into a saline area, transition area and freshwater area. The results show that the maximum thickness of source rocks developed in the saline and transition areas is 700 m. Additionally, source rocks with a higher TOC and oil-prone organic matter types (II1 and II2) also develop in the saline and transition areas, and most have entered the mature stage. The TOC values corresponding to the lower limit of effective source rocks in the saline, transition, and freshwater areas are 0.3%, 0.4% and 0.5%, respectively. Furthermore, the hydrocarbon expulsion ratio (amount of hydrocarbon discharged per unit of TOC from the source rocks) for the freshwater area is 253.1 mg/g, while the ratios in the saline and transition areas are relatively higher at 439.4 mg/g and 369.3 mg/g, respectively. The hydrocarbon expulsion rate (change in the expulsion ratio per unit thermal evolution degree) and hydrocarbon expulsion efficiency (ratio of cumulative hydrocarbon expulsion amount to generation amount) in the saline, transition and freshwater areas present maxima when the Ro (vitrinite reflectance) values are 0.95%, 0.85% and 0.82%, respectively. The hydrocarbon expulsion quantities in the saline, transition and freshwater areas account for 24%, 49% and 27% of the total, respectively. Therefore, the main hydrocarbon expulsion area is the transition area of the Dongpu Depression associated with the thickest source rocks. Es-3(M) and Es-3(L) source rocks in the transition area with high organic matter abundant and type II kerogen are more promising than the other formations. This study is the first to report on effective source rocks in different sedimentary environments in lacustrine basins and can provide guidance for future exploration in the Dongpu Depression and a reference for future research on source rocks in other lacustrine basins.",4,4,7
Organic Matter,Hydrocarbon Expulsion,"Hong, Sung Kyung; Lee, Kyungbook; Lee, Hyun Suk; Choi, Jiyoung; Mort, Andy","Assessment of shale gas potential from geochemical data in the Late Devonian shale succession, Liard Basin, Canada",Liard Basin; Late Devonian; Shale gas potential; Retained gas volume; Original TOC,,"The shale gas potential of a Late Devonian shale sequence in the Liard Basin, an important unconventional gas reservoir, was assessed using the retained gas volume based on gas generation potential and hydrocarbon expulsion efficiency. Evaluation of gas generation potential in the Liard Basin depends on understanding the characteristics of the original organic matter. However, due to high thermal maturity, it is difficult to estimate the characteristics of the original organic matter from conventional methods. The type of original organic matter was inferred from inorganic geochemical proxies that reflect productivity (Ex-SiO2), terrestrial sediment input (Al2O3, Zr), and oxygen level in the bottom water (Mo-EF and U-EF). By considering the present day TOC (TOCpd) and the type of original organic matter, the original hydrogen index (HIo) and original total organic carbon (TOCo) values were calculated to range from 200 to 700 mgHC/gTOC and from 0.3 to 29.0 wt%, respectively. The measured TOCpd values were similar to the TOCpd calculated from the 1-D petroleum system model using the original organic matter characteristics inferred in this study, which indicates that the TOCo values are reliable. Based on the evolution of the TOCo during its thermal history, the total gas generation potential in the Late Devonian shale sequence (550 ft) of the Liard Basin is estimated to be 1690 bcf/section. Considering the total gas in place (496 bcf/section), based on the estimated ultimate recovery, approximately 70% of the hydrocarbon might have been expelled. The retained gas volume fluctuates vertically in the Late Devonian shale sequence. The retained gas volume is higher in the 3946-3993 m (136 bcf/section) and 3993-4047 m (281 bcf/ section) intervals than other intervals (less than 60 bcf/section), indicating that these intervals are the most prospective for shale gas exploration and development in the studied well.",3,3,4
Organic Matter,Junggar Basin,"Lin, Miruo; Xi, Kelai; Cao, Yingchang; Liu, Quyang; Zhang, Zehan; Li, Ke","Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin",Shale oil reservoir; Petrographic features; Diagenetic alteration; Heterogeneity of reservoirs in shale strata,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; BOHAI BAY BASIN; RESERVOIR QUALITY; SANDSTONE RESERVOIRS; JIYANG DEPRESSION; SEDIMENTARY-ROCKS; JIMSAR SAG; LITHOFACIES CLASSIFICATION; ORGANIC GEOCHEMISTRY,"Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation.",5,5,10
Organic Matter,Junggar Basin,"Lu, Jungang; Luo, Zhaoyang; Zou, Hongliang; Li, Yanping; Hu, ZhengZhou; Zhou, Zengyuan; Zhu, Jiang; Han, Meimei; Zhao, Liping; Lin, Zonghui","Geochemical characteristics, origin, and mechanism of differential accumulation of natural gas in the carboniferous kelameili gas field in Junggar basin, China",Junggar basin; Volcanic gas reservoir; Geochemical characteristics; Carbon isotope; Light hydrocarbon,ORDOS BASIN; STABLE CARBON; LIGHT-HYDROCARBONS; PETROLEUM; EVOLUTION; OIL; RESERVOIRS; ISOTOPES; ROCKS,"Since the discovery of the Kelameili gas field, the exploration of volcanic gas reservoirs in the Junggar Basin has attracted considerable attention. However, owing to the limitations involved in studying the characteristics of the origin and distribution of the volcanic gas reservoirs in this area, the study of gas reservoirs in the South fault terrace area of the Kelameili gas field as a typical peripheral area is greatly restricted, and the exploration process is relatively slow. Therefore, it is necessary to analyse and compare the differences in the geochemical characteristics of the natural gas between the Kelameili gas field and the fault terrace area of the south belt by analysing the natural gas geochemistry, hydrocarbon generation evolution, and structural evolution. In addition, geochemical experiments involving the natural gas components, carbon isotopes, light hydrocarbons, hydrocarbon generation, and evolutionary history of the source rocks and the interpretation of seismic profiles reflecting the structural evolution, help clarifying the genetic type of the volcanic gas reservoirs and the source of the natural gas in this area. The results indicate the following. (1) The natural gas in the study area has undergone thermal genesis and is generated by kerogen cracking. It is a typical humic gas with high maturity. (2) The origin of the natural gas is the Carboniferous source rock in the depression, which is significantly different from the natural gas from the typical Permian and Jurassic. (3) The primary reason for the difference in natural gas accumulation is that the Carboniferous source rock entered the high-maturity stage in the Early Jurassic. The formation time of the trap is earlier than that of the high-maturity stage of the source rock evolution, which can capture multi-stage source rock products. (4) Based on the hydrocarbon source conditions that the hydrocarbon supply horizon of the Kelameili gas field has a high maturity of organic matter, and insufficient hydrocarbon supply, it is considered that traps capturing the multi-stage source rock products represent a larger scale of natural gas accumulation. The results of this study can deepen the understanding of volcanic gas reservoirs in the Junggar Basin and guidethe exploration and development of global volcanic gas reservoirs and the surrounding large-scale gas fields.",3,4,11
Organic Matter,Junggar Basin,"Xi, Kelai; Cao, Yingchang; Haile, Beyene Girma; Zhu, Ning; Liu, Keyu; Wu, Songtao; Hellevang, Helge","Diagenetic variations with respect to sediment composition and paleo-fluids evolution in conglomerate reservoirs: A case study of the Triassic Baikouquan Formation in Mahu Sag, Junggar Basin, Northwestern China",Diagenetic variations; Sediment composition; Paleo-fluids evolution; Conglomerate reservoir; Mahu sag,TIGHT OIL SANDSTONES; GEOCHEMICAL CONSTRAINTS; JURASSIC SANDSTONES; YANCHANG FORMATION; MASS-TRANSFER; ORDOS BASIN; QUALITY; PREDICTION; POROSITY; SMECTITE,"Understanding reservoir heterogeneity and associated diagenesis, have a paramount importance for efficient petroleum exploration and development strategies. Diagenetic variations and factors that control these processes have, therefore, been investigated in this study using petrographic and geochemical methods, including cath-odoluminescence, scanning electron microscopy, x-ray fluorescence, electron probe microanalyses and stable isotope analysis. Mechanical compaction and chemical diagenesis trends have obviously varied as a function of rock types and geological locations. The conglomerate reservoirs with high content of tuffaceous matrix and characterized by poor sorting showed stronger compaction. The tuffaceous matrix displays a large degree of dissolution during the progressive burial diagenesis due to its thermodynamic instability. The tuffaceous matrix in Na-rich conglomerate reservoir rocks mainly transformed into analcite, while it transformed into illite in K-rich conglomerate reservoir rocks. In most conglomerate reservoirs far away from deep-rooted faults, calcite cements are indicated to have been sourced from the decarboxylation of organic matter in the interbedded mudstones. Carbonate cements in conglomerate reservoirs near the deep-rooted faults possibly formed from hydrothermal fluids or thermochemical oxidation of pre-existing methane accumulations. This study can serve us an excellent example for the control of sediment composition and paleo-fluid evolution on diagenetic variations in fan-delta conglomerate reservoirs.",3,3,4
Organic Matter,Cretaceous,"Al-Khafaji, Amer Jassim; Hakimi, Mohammed Hail; Mohialdeen, Ibrahim M. J.; Idan, Rami M.; Afify, Wafaa E.; Lashin, Aref A.","Geochemical characteristics of crude oils and basin modelling of the probable source rocks in the Southern Mesopotamian Basin, South Iraq",Oil-oil correlation; Cretaceous reservoirs; Carbon isotope; Biomarker ratios; Basin modeling; Mesopotamian basin; South Iraq,PETROLEUM SYSTEM-ANALYSIS; ZAGROS FOLD BELT; DEPOSITIONAL-ENVIRONMENTS; HYDROCARBON GENERATION; SARGELU FORMATION; ORGANIC-MATTER; SHOUSHAN BASIN; WESTERN DESERT; NORTH; MIGRATION,"Bulk property and geochemical analyses were performed on 15 crude oil samples collected from the Early Cretaceous clastic reservoirs in the oilfields of the southern Mesopotamian Basin, South Iraq. Specific gravities ranging between 25.4 and 31.6 API and relatively high sulfur concentrations of up to 1.97 wt % suggest that the samples were generated from kerogen Type IBS at relatively low maturity level. Biomarker ratios and parameters as well as carbon isotope ratios, indicate that the oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions during the Jurassic to Early Cretaceous. Furthermore, biomarker maturity suggests two maturity subgroups for the samples based on their sulfur concentrations and specific gravity values. Sub-group (A) is characterized by oils generated from low-mature source rocks from the Late Jurassic-Early Cretaceous Sulaiy Formation; while the relatively high mature oils of sub-group (B) were generated from organic-rich intervals in the Jurassic Sargelu and Najmah formations. Basin model results revealed that these formations reached a peak oil-generation window at different times, expelling various quantities of oil. The basin model results further suggest that the organic-rich interval in the Sulaiy Formation began to expel little amounts of oil, corresponding to transformation ratio (TR) between 50 and 63% since the Late Miocene to present-day, while the organic-rich intervals in the Sargelu and Najmah formations were the earliest to expel significant amounts of oil, with relatively high TR values of 50-90% during the end of the Late Cretaceous to Early Eocene and continued to the present-day. These generated oils subsequently migrated to the shallow stratigraphic reservoir intervals through the vertical pathway of faults, and are currently extracted for use in the oil industry.",10,10,1
Organic Matter,Cretaceous,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Organic Matter,Hydrogen,"Yang, Dong; Wang, Lei; Zhao, Yangsheng; Kang, Zhiqin",Investigating pilot test of oil shale pyrolysis and oil and gas upgrading by water vapor injection,Oil shale; Water vapor; Hydrogen-rich; Shale oil; Light components; Heteroatomic compounds,EXTRACTION; CHINA; BED,"The technology of oil shale pyrolysis by water vapor injection uses high-temperature steam as a heat carrier to heat oil shale. Water vapor not only plays the role of transferring and exchanging heat, but it also chemically reacts with organic matter and some oil and gas products, altering the generation characteristics of oil and gas products. In this paper, we developed a long reaction distance test system for oil shale pyrolysis by water vapor injection and obtained the effects of heat injection temperature and time on the quality of oil and gas products. First, the results showed that with increasing pyrolysis temperature, the hydrogen content in the gas components gradually increased and then tended to be stable. In the process of heat injection temperature, increasing from 330 degrees C to 475 degrees C, the hydrogen content increased from 1.05% to 66.64%. High hydrogen concentration was mainly due to the reaction of water vapor with carbon residues, water vapor conversion reactions, and steam gasification reactions of hydrocarbon gases. Then, for shale oil, when the injection temperature was higher than 500 degrees C, the content of light components in shale oil remained at high levels, but the content of heteroatomic compounds was very little and the quality of shale oil was good. Next, when the injection temperature was controlled to 555 degrees C and the pyrolysis time was increased from 0 h to 4 h, the hydrogen content in the gas products increased first and then decreased, but the heteroatomic contents in the shale oil products increased first and then decreased. When the pyrolysis time was 2.5 h, the hydrogen content peaked, reaching 87.6%. When the pyrolysis time was 2 h, the content of heteroatoms peaked and reached 8.22%. Overall, when the injection temperature was 555 degrees C and the injection time reached 3 h, the shale oil formed through oil shale cracking presented higher quality.",3,3,5
Organic Matter,Hydrogen,"Hong, Sung Kyung; Lee, Kyungbook; Lee, Hyun Suk; Choi, Jiyoung; Mort, Andy","Assessment of shale gas potential from geochemical data in the Late Devonian shale succession, Liard Basin, Canada",Liard Basin; Late Devonian; Shale gas potential; Retained gas volume; Original TOC,,"The shale gas potential of a Late Devonian shale sequence in the Liard Basin, an important unconventional gas reservoir, was assessed using the retained gas volume based on gas generation potential and hydrocarbon expulsion efficiency. Evaluation of gas generation potential in the Liard Basin depends on understanding the characteristics of the original organic matter. However, due to high thermal maturity, it is difficult to estimate the characteristics of the original organic matter from conventional methods. The type of original organic matter was inferred from inorganic geochemical proxies that reflect productivity (Ex-SiO2), terrestrial sediment input (Al2O3, Zr), and oxygen level in the bottom water (Mo-EF and U-EF). By considering the present day TOC (TOCpd) and the type of original organic matter, the original hydrogen index (HIo) and original total organic carbon (TOCo) values were calculated to range from 200 to 700 mgHC/gTOC and from 0.3 to 29.0 wt%, respectively. The measured TOCpd values were similar to the TOCpd calculated from the 1-D petroleum system model using the original organic matter characteristics inferred in this study, which indicates that the TOCo values are reliable. Based on the evolution of the TOCo during its thermal history, the total gas generation potential in the Late Devonian shale sequence (550 ft) of the Liard Basin is estimated to be 1690 bcf/section. Considering the total gas in place (496 bcf/section), based on the estimated ultimate recovery, approximately 70% of the hydrocarbon might have been expelled. The retained gas volume fluctuates vertically in the Late Devonian shale sequence. The retained gas volume is higher in the 3946-3993 m (136 bcf/section) and 3993-4047 m (281 bcf/ section) intervals than other intervals (less than 60 bcf/section), indicating that these intervals are the most prospective for shale gas exploration and development in the studied well.",3,3,4
Organic Matter,Reaction,"Jiu, Bo; Huang, Wenhui; Mu, Nana; Li, Yuan","Types and controlling factors of ordovician paleokarst carbonate reservoirs in the southeastern Ordos Basin, China",Karstification; Carbonate rock; Reservoir; Dissolution; Diagenesis,THERMOCHEMICAL SULFATE REDUCTION; SICHUAN BASIN; MAJIAGOU FORMATION; DIAGENETIC ALTERATION; NATURAL-GAS; TARIM BASIN; OIL-FIELD; ORIGIN; KARST; QUALITY,"With continuous improvements in oil and gas exploration technology and the increasing demand for oil and gas resources, the focus of oil and gas exploration has shifted from deep to ultradeep reservoirs. This study targeted the carbonate karst reservoirs of the Ordovician Ma5 Member in the southeastern Ordos Basin. Based on the analysis of cores, thin sections, cathodoluminescence, scanning electron microscopy (SEM), carbon and oxygen isotopes and trace elements, we discuss the development characteristics, types and influencing factors of paleokarst reservoirs. Petrology and geochemistry show three kinds of karstification in the study area: quasicontemporaneous karst, epigenetic karst and deep burial karst. The quasi-contemporaneous and epigenetic paleokarsts were mainly controlled by freshwater, where the soluble components of the strata were preferentially dissolved. The deep burial karstification was dominated by the reaction product H2S from thermochemical sulfate reduction (TSR) between sulfate minerals and organic matter, during which hydrothermal fluid provided the required activation energy for the reaction. The observations of cores and thin sections show that the paleokarst reservoirs are composed of different kinds of dissolution pores and fractures and cemented by multistage calcite and siliceous cements. Influenced by freshwater leaching and hydrothermal fluid, the three paleokarst processes led to negative anomalies in delta O-18 and delta C-13, while the low delta Ce, low delta Eu and rare earth element (REE) partition modes confirm that the intensity of freshwater leaching was stronger than that of hydrothermal fluid. The controlling factors of the paleokarst reservoirs included acidic fluids, paleogeomorphology and paleostructure in each diagenetic stage. According to the structural background and core characteristics, we establish a development model and spatial evolution model of the paleokarst reservoirs in the southeastern Ordos Basin.",3,3,11
Organic Matter,Reaction,"Yang, Dong; Wang, Lei; Zhao, Yangsheng; Kang, Zhiqin",Investigating pilot test of oil shale pyrolysis and oil and gas upgrading by water vapor injection,Oil shale; Water vapor; Hydrogen-rich; Shale oil; Light components; Heteroatomic compounds,EXTRACTION; CHINA; BED,"The technology of oil shale pyrolysis by water vapor injection uses high-temperature steam as a heat carrier to heat oil shale. Water vapor not only plays the role of transferring and exchanging heat, but it also chemically reacts with organic matter and some oil and gas products, altering the generation characteristics of oil and gas products. In this paper, we developed a long reaction distance test system for oil shale pyrolysis by water vapor injection and obtained the effects of heat injection temperature and time on the quality of oil and gas products. First, the results showed that with increasing pyrolysis temperature, the hydrogen content in the gas components gradually increased and then tended to be stable. In the process of heat injection temperature, increasing from 330 degrees C to 475 degrees C, the hydrogen content increased from 1.05% to 66.64%. High hydrogen concentration was mainly due to the reaction of water vapor with carbon residues, water vapor conversion reactions, and steam gasification reactions of hydrocarbon gases. Then, for shale oil, when the injection temperature was higher than 500 degrees C, the content of light components in shale oil remained at high levels, but the content of heteroatomic compounds was very little and the quality of shale oil was good. Next, when the injection temperature was controlled to 555 degrees C and the pyrolysis time was increased from 0 h to 4 h, the hydrogen content in the gas products increased first and then decreased, but the heteroatomic contents in the shale oil products increased first and then decreased. When the pyrolysis time was 2.5 h, the hydrogen content peaked, reaching 87.6%. When the pyrolysis time was 2 h, the content of heteroatoms peaked and reached 8.22%. Overall, when the injection temperature was 555 degrees C and the injection time reached 3 h, the shale oil formed through oil shale cracking presented higher quality.",3,3,5
Organic Matter,Spectrum,"Wang, Yang; Cheng, Hongfei; Hu, Qinhong; Liu, Luofu; Jia, Langbo; Gao, Shasha; Wang, Ye","Pore structure heterogeneity of Wufeng-Longmaxi shale, Sichuan Basin, China: Evidence from gas physisorption and multifractal geometries",Multifractal; Heterogeneity; Connectivity; Gas adsorption; Pore structure; Isolated organic matter,METHANE ADSORPTION; ORDOS BASIN; ORGANIC-MATTER; N-2 ADSORPTION; FE-SEM; POROSITY; INSIGHTS; MARINE; AREA; MATURATION,"Understanding the heterogeneity of the nanoscale pore structure is critical for assessment of hydrocarbon flow and storage in porous reservoirs. Multifractal theory is a powerful method to acquire the detailed heterogeneity information of the multiple pore system. The generalized dimension spectrum and singularity spectrum are two forms to depict the multifractal feature. Hurst exponent (H) and the width of singularity spectrum (Delta alpha) are two parameters to effectively assess the pore connectivity and heterogeneity, respectively. In this study, multifractal analysis was performed on over-mature Wufeng-Longmaxi shales and their corresponding isolated organic matter (OM) via gas physisorption (CO2 and N-2) test to ascertain the pore heterogeneity and its governing factors. Micropore (diameter<2 nm) structure in bulk shale contains stronger pore heterogeneity but weaker connectivity than meso-macropore (diameter = 2-100 nm) structure. The comparison of heterogeneity features of shale versus its isolated OM reveals that micropore associated with minerals could enhance the micropore heterogeneity in bulk shale, while meso-macmpore existing in minerals could reduce the meso-macmpore heterogeneity in bulk shale. Besides, the total organic carbon content has a positive effect on the micropore heterogeneity. The micropore and meso-macmpore volume have a certain impact on the pore heterogeneity in the corresponding pore size ranges. Compared with the low-mature Bakken shale, the over-mature Wufeng-Longmaxi shale contains the stronger micropore heterogeneity but weaker meso-macmpore heterogeneity, where less difference between the micropore and meso-macropore heterogeneities was also observed. We deduced that the whole shale pore spectrum likely tends to be homogeneous along with the OM thermal maturation.",7,7,26
Organic Matter,Spectrum,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Organic Matter,Experimental Data,"An, Cheng; Killough, John; Xia, Xiaoyang",Investigating the effects of stress creep and effective stress coefficient on stress-dependent permeability measurements of shale rock,Permeability measurement; Stress creep; Effective stress coefficient; Clay and organic matter,LAW,"Rock permeability is an essential factor for production prediction and economic evaluation, which is often measured based on core samples in laboratory. However, several phenomena such as stress creep and path-dependent stress still present difficulties in correctly measuring and interpreting permeability under varying compaction stresses for core measurements. In this study, an improved stress-dependent permeability model is proposed to consider the effect of time-dependent compaction behavior on permeability measurements by incorporating the stress creep mechanism. Besides, how to correctly interpret stress-dependent permeability results with effective stress coefficient is introduced in detail. A coupled flow-geomechanics model is also developed to investigate the impact of effective stress coefficient on permeability change and cumulative production. Due to the stress creep phenomenon, rock permeability could be significantly overestimated if not enough measurement time is provided. The creep strain is highly related to the content of clay and kerogen. This is because the increasing creep strain over time is mainly from the closure of pre-existed micro-fractures and the compression of Nano-pores inside the soft materials, such as clay and kerogen. The creep strain model and improved stress-dependent permeability model were validated by comparing with multiple experimental data. Effective stress coefficient cannot be simply assumed one for organic-rich or clay-rich shale reservoirs, especially when pore pressure is changed to alter net effective stress in permeability measurements. A large effective stress coefficient amplifies the sensitivity of pore pressure change on the variation of both effective stress and permeability. The simulation results show a larger effective stress coefficient could provide higher cumulative production because of stronger compression from effective stress. The improved knowledge of stress creep and effective stress coefficient enables the development of best practices for permeability measurement of tight rock and provides more accurate permeability results for reservoir management and field development.",4,4,8
Organic Matter,Experimental Data,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Organic Matter,Liquid Hydrocarbons,"Teng, Juan; Deng, Hucheng; Liu, Bei; Chen, Wenling; Fu, Meiyan; Xia, Yu; Yu, Hanze","Insights of the pore system of lacustrine shales from immature to late mature with the aid of petrology, mineralogy and porosimetry: A case study of the Triassic Yanchang Formation of the Ordos Basin, North China",pore evolution; pore size distribution; organic-matter pores; thermal maturation; lacustrine shale; Ordos Basin,CHANG 7 MEMBER; NORTHEASTERN BRITISH-COLUMBIA; MATURATION GRADIENT INSIGHTS; NANOMETER-SCALE PORES; ORGANIC-MATTER; ROCK PROPERTIES; GAS-ADSORPTION; BARNETT SHALE; ALBANY SHALE; MECHANICAL COMPACTION,"The study of pore network evolution is an important aspect of tight shale reservoir characterization. Pore spaces in shales consist of three major types: interparticle pores and intraparticle pores associated with mineral matrix and organic-matter pores. In this study, the evolution of pore networks for each pore type in lacustrine shales during thermal maturation was studied based on a suite of 19 Triassic Yanchang Formation shale samples from the Ordos Basin across a maturation gradient from immature to late mature (vitrinite reflectance (R-o) from 0.36 to 1.30%). The results show that different pore types follow systematic evolutions during thermal maturation and that the evolution of pore type and pore size is critically controlled by multiple diagenetic processes such as mechanical compaction, cementation, mineral dissolution, clay mineral transformation, and organic matter thermal maturation. Specifically, at immature and early mature stages (R-o < 0.55%), pores associated with mineral matrix are abundant and have moderate pore sizes. Interparticle pores exhibit preferential orientation along clay platelets. At the mature stage (0.55% < R-o < 1.15%), pores associated with mineral matrix have the smallest size, and interparticle pores become less common and show reduced preferential orientation because of mechanical compaction and cementation. Organic-matter pores start to develop at a maturity level of R-o 0.77% and higher. The total porosity and BET specific surface area show minimum values at R-o 1.12%, mainly because pre-existing matrix-related pores are destroyed by mechanical compaction and filled by migrated bitumen and liquid hydrocarbons, and then they increase when R-o exceeds 1.12%, which likely results from the development of secondary organic-matter nanopores due to the generation and expulsion of gaseous hydrocarbons. An increase in pore size of matrix-related pores at the late mature stage (1.15% < R-o < 1.30%) could be a result of dissolution by organic acid generated during organic matter thermal maturation.",7,9,5
Organic Matter,Liquid Hydrocarbons,"Leushina, Evgeniya; Mikhaylova, Polina; Kozlova, Elena; Polyakov, Veniamin; Morozov, Nikita; Spasennykh, Mikhail",The effect of organic matter maturity on kinetics and product distribution during kerogen thermal decomposition: the Bazhenov Formation case study,Kinetics; Kerogen; Organic matter maturity; The Bazhenov Formation; Open-system pyrolysis; Oil shale,PETROLEUM SYSTEM; GAS GENERATION; MODELS; OIL; PARAMETERS; SIBERIA; ROCKS,"In this study, we obtained the first data on the compositional kinetics of the Bazhenov kerogen decomposition, which are essential for estimation of the amount and composition of hydrocarbon products in petroleum system modeling and for simulation of organic matter transformation in the processes of thermal enhanced oil recovery. The Bazhenov Formation is one of the priority oil shale formations in the world and is the principal source rock in the West Siberian Petroleum Basin, Russia. The kinetic study was performed on source rock samples with organic matter spanning the range of thermal maturity from immature to early and middle mature. The experiments included (1) the determination of bulk kinetic spectrum from pyrograms obtained using linear heating of rock samples, (2) a series of isothermal pyro-GC-TOFMS/FID experiments carried out at several levels of organic matter conversion, and (3) the calculation of the compositional kinetic spectrum from the experimental data. The kinetic characteristics of the samples were correlated with organic matter maturity. We have demonstrated that with an increase of organic matter maturity, the maximum of activation energy distribution shifts from 51 to 53 kcal/mol (for a fixed frequency factor A = 1.10(14) s(-1)). The kerogen destruction products analyses reveal that for the immature sample the total gas yield is 39%, the percentage of heavy hydrocarbons C16+ is 16%, and the percentage of C-7-C-10 is two times higher than that of C-11-C-15: 30 and 15%, respectively. With the increase of organic matter maturity, the proportion of gas and heavy products decreases. Regardless of organic matter maturity nor conversion degree, the main products of the Bazhenov kerogen transformation are liquid hydrocarbons C-7-C-10, the percentage reaches 54% in the maximum of oil generation.",3,3,3
Organic Matter,Silurian Longmaxi Formation,"Zhang, Kun; Liu, Rong; Liu, Zhaojun","Sedimentary sequence evolution and organic matter accumulation characteristics of the Chang 8-Chang 7 members in the Upper Triassic Yanchang Formation, southwest Ordos Basin, central China",Sedimentary environment; Paleoclimate; Organic matter accumulation; Yanchang formation; Ordos basin,SILURIAN LONGMAXI FORMATION; DEVONIAN DUVERNAY FORMATION; TIGHT SANDSTONE RESERVOIRS; GEOCHEMICAL CHARACTERISTICS; DEPOSITIONAL ENVIRONMENT; BLACK SHALES; OIL-SHALE; STRATIGRAPHIC ANALYSIS; ELEMENT GEOCHEMISTRY; MARCELLUS FORMATION,"Lacustrine organic-rich shales are widely developed in the Chang 7 member of the Yanchang Formation in the Ordos Basin. These shales have been proven to be the source rocks for crude oil and shale oil. The study of sedimentary evolution and the characteristics of organic matter (OM) accumulation is an important factor for the exploration and development of oil and gas resources. Based on the lithological assemblages, lithofacies, mineral contents, log curves and geochemical data, the sequence stratigraphic framework of the Chang 8-Chang 7 members of the Yanchang Formation in the southern margin of the Ordos Basin were established. A complete third-order sequence was identified, and it included four systems tracts: a lowstand systems tract (LST), a transgressive systems tract (TST), a highstand systems tract (HST) and a regressive systems tract (RST). By using organic petrology, organic geochemistry and elemental geochemistry, the abundance and source of OM, paleoclimate, paleowater conditions, paleoproductivity, and deposition rates of the different systems tracts of the Chang 8-Chang 7 are studied in detail. Various factors controlled the accumulation of OM in the different systems tracts. The abundance of OM in the LST is low, the kerogen type is mainly type III (including vitrinite); the abundance of OM increased gradually in the TST, the kerogen types are III and II2 (including vitrinite and sporophyte); the OM is mainly concentrated in the HST, and the kerogen type is mainly type ID (including alginite), biomarker compounds show that OM has a mixed source of land plant and planktonic material; the abundance of OM in the RST is relatively high, the kerogen type is mainly type II2 and III (including vitrinite and alginite). The main controlling factor for OM accumulation was paleoclimate, which affected the primary productivity of lake and the chemical properties of the water column (redox and paleosalinity), leading to differences in OM accumulation under different climatic conditions. Hydrothermal activities contributed to anoxia and a salinity increase in lake bottom waters, with volcanic ash providing large amounts of essential nutrients for algal blooms. Based on the V/Cr, Sr/Ba, P/Ti and (La/Yb)(N) ratios with TOC values, the abundance of OM is positively correlated with paleoproductivity and water column reducibility, and negatively correlated with paleosalinity. The abundance of OM first increases and then decreases with increasing sedimentation rate. In general, the accumulation of OM was promoted under warm and humid climates, anoxic fresh to brackish water and adequate paleoproductivity.",8,8,9
Organic Matter,Silurian Longmaxi Formation,"Yasin, Qamar; Baklouti, Syrine; Khalid, Perveiz; Ali, Syed Haroon; Boateng, Cyril D.; Du, Qizhen","Evaluation of shale gas reservoirs in complex structural enclosures: A case study from Patala Formation in the Kohat-Potwar Plateau, Pakistan",Kohat-potwar plateau; Patala formation; Shale gas; Rock-eval pyrolysis; Petrophysics,SILURIAN LONGMAXI FORMATION; SOUTHERN SICHUAN BASIN; GEOLOGICAL FACTORS; THERMAL MATURITY; ORGANIC-CARBON; MARINE SHALE; SALT RANGE; ROCK; BRITTLENESS; EOCENE,"Breakthroughs in shale gas exploration and production technology in China point to a possible solution to Pakistan's current energy crises. In this study, we evaluate the shale gas prospects in the Kohat-Potwar Plateau of Pakistan by establishing an integrated approach involving the analysis of fundamental elastic and petrophysical properties, Rock-Eval pyrolysis, and the sealing mechanism of shale. Detailed geochemical and petrophysical evaluation of the Patala Formation in the Kohat-Potwar Plateau indicates the good potential for shale gas with the following characteristics similar to the Longmaxi shale of Sichuan Basin China, i.e., (i) complex structural types sandwiched by tight limestone strata with low porosity (less than 3%), ultra-low permeability, high density, and large thickness which provides strong sealing capacity for gas preservation and enrichment; (ii) multiphase tectonic evolution of Patala Formation allowed various slippage processes to develop fractures and enhance the porosity and permeability; (iii) high organic matter content and thermal maturation stage (TOC > 2%, 416-445 SC); (iv) high brittle minerals content (e.g., calcite and dolomite > 40%); and (v) large formation thickness (>30 m) at shallow burial depth < 2500 m. This study emphasizes the critical role of the sealing mechanism in shale gas reservoirs. Furthermore, the results suggest that the evaluation and development of shale gas potential using petrophysical and geochemical analysis may be inadequate. Further scrutiny of the roof and floor of reservoirs' efficient sealing capacities is essential to understand the extent of shale gas preservation and enrichment. The study results provide valuable insights for identifying the sweet spots and preservation condition of shale gas in the Kohat-Potwar Plateau of Pakistan.",6,6,4
Natural Fractures,Well Testing,"Qin, Guowei; Dai, Xu; Sui, Lei; Geng, Meng; Sun, Linghui; Zheng, Yanzhao; Bai, Yanming",Study of massive water huff-n-puff technique in tight oil field and its field application,Massive water huff-n-puff; Tight oil reservoir; Imbibition; Horizontal well,RECOVERY; GAS,"Based on the characteristics of horizontal oil wells in tight reservoirs during their late stage, which are exploited by elastic drive of natural energy and stimulated by large-scale volume fracturing; the massive water huff-n-puff technique is proposed for the use of supplementing the energy of the depleted formations, which can effectively increase the productivity of single horizontal oil well in addition to its financial benefits. In this paper, the massive water huff-n-puff technique is defined and discussed from the following aspects of the mechanism, reservoir engineering, laboratory experiments and so forth. Additionally, comprehensive analyses of the advantages of applying this technique in the development of tight oil reservoirs are provided. By the studies of the pressure composition diagram and the definition of residual injection pressure (RIP) in reservoirs, a massive water huff-n-puff mathematical model was established and the critical parameters for water-flooding were calculated. Laboratory experiments of this technique have shown that it can induce a certain number of micro-fracture networks and its application in actual oilfields also shown positive results. The pilot tests have achieved remarkable increases in productivity and economic benefits. For example, the average daily oil production from a single well is increased by 4.5 t/d (0.8 -> 5.3 t/d), the formation pressure has increased by 9.3 MPa (6.9 -> 16.2 MPa), accumulated oil production has reached 1,987t, and its input-output ratio has shown an enhancement in the range of 1.00:1.74-1.00:4.06. The research results of this technique provide a new way and an important model for efficient development of horizontal wells in tight oil reservoirs.",6,5,3
Natural Fractures,Well Testing,"Wei, Cao; Cheng, Shiqing; Wang, Yang; Shi, Wenyang; Li, Juhua; Zhang, Jia; Yu, Haiyang",Practical pressure-transient analysis solutions for a well intercepted by finite conductivity vertical fracture in naturally fractured reservoirs,Pressure transient analysis; Finite conductivity fracture; Analytical solutions; Naturally fractured reservoir; Triple-porosity reservoir,FLOW,"The semi-analytical or numerical solutions are the most used for pressure-transient analysis (PTA) for finiteconductivity fractured wells in naturally fractured reservoir now. However, the semi-analytical solutions are time-consuming and easily lead to inaccuracy at low fracture conductivity with less discretized segments. The numerical solutions are more time-consuming and usually face convergence and stability problems. These solutions are not convenient for practical well test analysis in Oilfield. Our motivation for this paper is to develop simply, quickly and stably analytical PTA solutions for finite-conductivity fractured wells in naturally fractured reservoir that can serve the well test analysis in Oilfield. We first derive a transformation method which can extend finite-conductivity fracture solutions in homogeneous reservoir to dual-porosity reservoir. Thereafter, analytical solutions for finite-conductivity fractured wells in homogeneous reservoir are presented. Then we provide a series of analytical finite-conductivity fracture solutions in dual-porosity reservoir under different boundary conditions based on the transformation method and homogeneous reservoir solutions. Six solutions given in the published literatures are used to verify the proposed solutions under different dimensionless fracture conductivity (FcD). Results indicate that (a) the proposed solutions are valid for FcD>1 with maximum error (5%) and this error will quickly decreases to around 1%; (b) the proposed solutions are applicable for infinite, closed and constant-pressure boundary conditions; (c) the proposed solutions can be extended to triple-porosity naturally fractured reservoirs after changing the f(s) function; (d) the proposed solutions are accurate and can greatly shorten the time of well test interpretation comparing to conventional solutions. Finally, the pressure-buildup data from Shunbei Oilfield is interpreted using the proposed solutions to verify its feasibility and practicability. The findings of this work can help for better understanding of its potential in quick well test analysis for field cases.",5,5,5
Natural Fractures,Well Testing,"Wang, Lei; Guo, Yintong; Zhou, Jun; Yang, Hanzhi; Yang, Chunhe; Xiao, Jialin","Rock mechanical characteristics of deep marine shale in southern China, a case study in Dingshan block",Deep formation; Shale gas; Mechanical characteristic; Post-peak curve; Failure mode; Fractal dimension,ANISOTROPIC PROPERTIES; BRITTLENESS; STRENGTH; HETEROGENEITY; ENERGY,"The success of commercial exploitation of shale gas has already been achieved in middle-shallow layers of China. But more than 65% of shale gas resources is buried in deep formation (vertical depth >= 3500 m), which has not been effectively developed yet. Deep buried depth is the source of a series of challenges. To clarify the influence of buried depth on mechanical characteristics of shale, tri-axial compression tests considering high confining pressures (80 MPa) are conducted with core samples collected from the gas bearing section of a deep marine shale gas well. The results show that the peak deviatoric stress significantly increases with the growth of confining pressure and exhibits an obvious declining trend from bottom to top in longitudinal profile, whereas Young's modulus and Poisson's ratio were all relatively insensitive to buried depth. Unlike conventional smooth tri-axial test curves, many of the post-peak curves are in ""step-like"" shape, and their corresponding failure patterns are always multi-fractures, all of which are originated from the activation of bedding planes or natural fractures during yielding process and are indications of high brittleness. However, the proportion of specimens with these features decreases from 66.7% to 22.2%, with the confining pressure increased from 30 MPa to 80 MPa. As most of existed indices could not properly describe the brittle characteristic of this type of deep marine shale, a new brittleness index (BI) is proposed by quantifying the complexity of ""step-like"" post-peak curves in fractal dimension. It is demonstrated that BI could effectively capture the influence of confining pressure on brittleness and distinguish those more brittle layers. Owing to the great reduction of brittleness and fracture complexity under high confining pressure, the fracking network in deep formation might be sparser than that in middle-shallow layer at field scale, leading to the poor performance of past fracking deep wells.",5,5,1
Natural Fractures,Well Testing,"Chen, Xiang; Zhao, Liqiang; Liu, Pingli; Du, Juan; Bai, Zongxian; Liu, Jinming; Zhang, Nanlin; Luo, Zhifeng; Xu, Kun; Li, Nianyin",Laboratory study and field verification of a thermo-responsive water shutoff agent,Thermo-responsive water shutoff agent; Working mechanism; Laboratory experiment; Field application verification; Changqing oilfield,,"For the low-pressure and low-permeability oil reservoirs, water injection development and hydraulic fracturing stimulation are essential. The ideal water flooding mode is piston-like displacement. However, due to the heterogeneity of reservoirs, most of the injected water flow to oil wells along the dominant channel (i.e., high permeability area, natural fractures, or artificial fractures), which causes the decrease of oil displacement efficiency, the premature water breakthrough of oil wells, and high water content. Hence, over a span of decades, a compelling body of work has focused on the development of water shutoff agents. According to its working mechanism, water shutoff agents were divided into selective and non-selective water shutoff agents. However, the water shutoff agents mentioned above have been tested in more than 350 wells of Changqing oilfield, and the success rate was unsatisfactory. Therefore, this study aimed to develop a thermo-responsive water shutoff agent (TRWSA) with high plugging strength and compact structure. Through a series of laboratory experiments, the key performances of TRWSA for field application were tested and evaluated. First, the initial viscosity of TRWSA was 34.5 mPa s, which could easily pass through any completion tool (e.g., screen pipe and gravel pack) and enter any size fracture. Second, the TRWSA was non-water soluble and its phase-transition characteristics were not affected by guar gum fracturing fluid. Third, the phase transformation position of TRWSA could be determined by adjusting the SA-DST dosage and the wellbore-reservoir temperature. Fourth, its plugging strength was greater than 19.1 MPa and the volume retention rate was up to 99.13%. In addition, the field application results showed that oil production increased from 0.08 m(3)/d to 5.37 m(3)/d, and water content decreased from 98.6% to 9.8%. The TRWSA was satisfactory and had a great application prospect.",4,4,22
Natural Fractures,Well Testing,"Li, Qingyu; Du, Xin; Tang, Qingjun; Xu, Yandong; Li, Peichao; Lu, Detang",A novel well test model for fractured vuggy carbonate reservoirs with the vertical bead-on-a-string structure,Fractured vuggy carbonate reservoirs; Vertical bead on a string structure; Well test; Type curves; Dimensionless gravity effect coefficient,PRESSURE-TRANSIENT; HORIZONTAL WELL; FLOW BEHAVIOR,"The bead-on-a-string structure has been widely observed in many fractured vuggy carbonate reservoirs, especially in Shunbei oilfield, northwestern China. To date, there are still no appropriate well test methods for analyzing these reservoirs with the vertical bead-on-a-string structure. This paper proposes a new theoretical well test model, which considers the gravity effect and the natural fractures connecting the vuggs, to analyze this kind of reservoirs. First, we establish the mathematical model of fractured vuggy reservoirs with the vertical bead-on-a-string structure. With the different outer boundary conditions, Laplace transform and inversion are employed to solve the well test model. Then, the type curves for the well test model are plotted and discussed. It is found that the gravity effect can be equivalent to a type of constant pressure boundary condition. Take the three-region-two-cave as an example, type curves can be divided into nine distinct flow regimes, including wellbore storage, skin, linear flow I and II, transition flow I and II, vug storage I and II, and boundary flow. The transition flow and vug storage period are named as the vug storage effect. Subsequently, the effects of relevant parameters are studied. It is concluded that the depth of the drop during vug storage effect increases with increasing dimensionless vug storage constant C-vD and dimensionless vug height z(D2)-z(D1); the greater dimensionless gravity effect coefficient G(D) leads to the smaller equivalent boundary distance of the constant pressure boundary condition; the smaller the mobility ratio M-12, the earlier the appearance of the second linear flow regime; the larger the storage ratio omega(12), the more distinct the vug storage effect. Finally, two field case studies are carried out by using the proposed method. The locations and volumes of the caves are estimated, which shows that the proposed theoretical well test model has a great potential of obtaining the formation and cave parameters accurately. However, there is not available data that enable an accurate description of the locations and volumes of the caves by now, the proposed model still needs further field verifications.",4,4,4
Natural Fractures,Well Testing,"Liu, Hui; Liao, Xinwei; Tang, Xuefeng; Chen, Zhiming; Zhao, Xiaoliang; Zou, JianDong",A well test model based on embedded discrete-fracture method for pressure-transient analysis of fractured wells with complex fracture networks,Embedded discrete-fracture method; Pressure transient analysis; Complex fracture network; Mesh-generation algorithm; Flow regime,PRODUCTION SIMULATION; RESERVOIR; BEHAVIOR; OIL,"In this study, a well test model based on the embedded discrete-fracture method (EDFM-WTM) is proposed for the pressure-transient analysis of fractured wells with complex fracture networks (CFNs). The proposed model overcomes the limitations of continuum-fracture models that cannot accurately obtain pressure-transient responses of wells with discretely distributed fractures. The model is verified using the stripe-fracture model in KAPPA software and shows excellent advantages over the stripe-fracture model in both computational performance and simulation workflow simplicity, due to the use of an advanced mesh-generation algorithm and the solution operators. Seven typical flow regimes can be observed on this model's pressure-transient responses. Furthermore, sensitivity analysis is conducted to study the impacts of complex fracture networks. The type curves are developed, and the impacts of fracture properties on pressure-transient responses are also analyzed in detail. The results show that the flow regimes of aAIJdip 1aAI and aAIJdip 2aAI are mainly influenced by the properties of natural fractures, such as their length and number, and that generating a symmetric and orthogonal fracture network around a well can maximize the fluid-supply area.",4,4,1
Natural Fractures,Well Testing,"Xu, Youjie; Li, Xiaoping; Liu, Qiguo; Yang, Sihan; Tan, Xiaohua",A semi-analytical solution of finite-conductivity multi-wing fractured well in naturally fractured reservoirs by boundary element method,Multi-wing fractured well (MWFW); Finite conductivity; Boundary element method (BEM); Pressure transient analysis,PRESSURE TRANSIENT ANALYSIS; SHALE GAS-RESERVOIRS; HORIZONTAL WELLS; VERTICAL WELLS; BEHAVIOR; MODEL,"Large-scale vertical well fracturing leads to formation of multi-wing fractures, which can effectively reduce fluid seepage resistance and increase single well production. As one of the post-fracture evaluation methods, pressure transient analysis is used widely in oil/gas field evaluation by engineers. It is of great significance for petroleum engineers to choose the correct and appropriate well test model for the accurate evaluation of formation parameters. Since oil/gas outer boundary is often rectangle or arbitrarily shape, a semi-analytical model of multiwing fractured well (MWFW) with arbitrarily shaped outer boundary gas reservoirs is presented. The reservoirs and hydraulic fracture mathematical models are established and solved. Coupling reservoirs and hydraulic fracture solution, and then discreting hydraulic fracture and outer boundary. The wellbore pressure solution with arbitrarily shaped outer boundary is obtained by pressure drop superposition, boundary element method (BEM) and Stehfest numerical inversion method. The bi-wing symmetrical hydraulic fracture and MWFW with finite conductivity are verified respectively by using numerical solution and comparison results reaches a good match, which certifies the correctness of the model and solving method. Typical curves of wellbore pressure and rate decline are discussed and influence of conductivity, hydraulic fracture number and hydraulic fracture distribution style et al. on wellbore pressure and rate decline is analyzes by combining with rate distribution of different time and segment. Influence of other parameters (Storativity ratio, interporosity coefficient and boundary shape size) on wellbore pressure and rate decline is also discussed in the end of paper.",3,3,8
Natural Fractures,Well Testing,"Al-Arji, H.; Al-Azman, A.; Le-Hussain, F.; Regenauer-Lieb, K.",Acid stimulation in carbonates: A laboratory test of a wormhole model based on Damohler and Peclet numbers,Carbonate acidizing; Wormhole; Dimensionless numbers; Damkohler; Peclet; Acidic core flooding; HCl injection,DISSOLUTION; ACIDIZATION; TRANSPORT; DOLOMITE; WELLS,"Acid stimulation has been used worldwide as a stimulation technique either by matrix acidizing to remove the near-wellbore permeability impairment which is referred to as formation damage or acid fracturing to enhance the connectivity between wells and reservoirs. Carbonate acid stimulation improves the near-wellbore permeability through the creation of deeply penetrating fluid pathways referred to as wormholes. The stimulation success depends on the length and width of these wormholes. Here, we test the results of a theoretical study which suggests that the effect of acid flow in a reactive porous medium can be fully defined by just two significant dimensionless numbers, the non-dimensional Damkohler and Peclet numbers. The approach was validated in an idealized numerical study and is here tested in a systematically controlled laboratory experiment for real carbonate rocks. In order to obtain statistically meaningful results, we pushed the envelope by testing the prediction of the critical point for the wormholing phenomenon in a difficult domain, where sufficient randomly distributed pathways exist such that the wormholing domain is rarely achieved. The result confirmed that for a randomly-structured highly porous media, the critical point for dissolution pattern formation including the wormholing phenomenon can be fully captured by a domain diagram of inverse Damkohler versus Peclet number as predicted by the theoretical model. The model also holds for moderately tight formations, however, breaks down when the natural permeability drops well below 100 mDarcy. We conclude that the result of this research can be applied to reliably predict the wormholes initiation and various dissolution structures under various injection rate and HCl-concentration.",3,3,4
Natural Fractures,Shale Gas,"Xue, Liang; Liu, Yuetian; Xiong, Yifei; Liu, Yanli; Cui, Xuehui; Lei, Gang",A data-driven shale gas production forecasting method based on the multi-objective random forest regression,Shale gas; Production forecasting; Machine learning; Random forest,DISCRETE-FRACTURE MODEL; PERFORMANCE PREDICTION; RESERVOIR SIMULATION; FLOW; PERMEABILITY; OPTIMIZATION; PRESSURE; WORKFLOW; FACIES; BASIN,"Shale gas is an important unconventional natural gas resource existing in shale reservoir with huge reserves. Due to the ultralow porosity and permeability, it requires the horizontal well drilling and the multi-stage hydraulic fracturing technology to successfully produce the shale gas. The accurate prediction of shale gas production is crucial to the reasonable design of the development plan. However, due to the complex hydraulic fracture network and the gas flow mechanism, the physics-based shale gas production prediction model is still under way. The data-driven model provide an alternative way to deal with the production prediction problem. The multi-objective random forest method is proposed to predict the dynamic production data. The geological and hydraulic fracturing properties are used as input feature. Its prediction performance is evaluated based on the R squared values after determining the appropriate hyper-parameters. The ranking of variable importance can be helpful to improve the interpretability of the data-driven model. The initial peak production rate before declining can be also used as an additional input feature. With the initial peak production rate augmented into the feature set, it can greatly improve the prediction of shale gas production. The variable importance analysis results show that it can be the most influencing factor to prediction accuracy and the ranking of other factors can be altered significantly. The performance of multi-objective random forest (MORF) and multi-output regression chain (MORC) methods are compared, and the comparison result indicates MORC requires a relatively smaller random forest structure, but the prediction performance of MORF is better than MORC. More sample data with less measurement errors can increase the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy of the data-driven shale gas production model but there exists a threshold value to improve the accuracy gain.",13,14,10
Natural Fractures,Shale Gas,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Natural Fractures,Shale Gas,"Wang, Lei; Guo, Yintong; Zhou, Jun; Yang, Hanzhi; Yang, Chunhe; Xiao, Jialin","Rock mechanical characteristics of deep marine shale in southern China, a case study in Dingshan block",Deep formation; Shale gas; Mechanical characteristic; Post-peak curve; Failure mode; Fractal dimension,ANISOTROPIC PROPERTIES; BRITTLENESS; STRENGTH; HETEROGENEITY; ENERGY,"The success of commercial exploitation of shale gas has already been achieved in middle-shallow layers of China. But more than 65% of shale gas resources is buried in deep formation (vertical depth >= 3500 m), which has not been effectively developed yet. Deep buried depth is the source of a series of challenges. To clarify the influence of buried depth on mechanical characteristics of shale, tri-axial compression tests considering high confining pressures (80 MPa) are conducted with core samples collected from the gas bearing section of a deep marine shale gas well. The results show that the peak deviatoric stress significantly increases with the growth of confining pressure and exhibits an obvious declining trend from bottom to top in longitudinal profile, whereas Young's modulus and Poisson's ratio were all relatively insensitive to buried depth. Unlike conventional smooth tri-axial test curves, many of the post-peak curves are in ""step-like"" shape, and their corresponding failure patterns are always multi-fractures, all of which are originated from the activation of bedding planes or natural fractures during yielding process and are indications of high brittleness. However, the proportion of specimens with these features decreases from 66.7% to 22.2%, with the confining pressure increased from 30 MPa to 80 MPa. As most of existed indices could not properly describe the brittle characteristic of this type of deep marine shale, a new brittleness index (BI) is proposed by quantifying the complexity of ""step-like"" post-peak curves in fractal dimension. It is demonstrated that BI could effectively capture the influence of confining pressure on brittleness and distinguish those more brittle layers. Owing to the great reduction of brittleness and fracture complexity under high confining pressure, the fracking network in deep formation might be sparser than that in middle-shallow layer at field scale, leading to the poor performance of past fracking deep wells.",5,5,1
Natural Fractures,Shale Gas,"Lu, Yunhu; Wei, Shiming; Xia, Yang; Jin, Yan",Modeling of geomechanics and fluid flow in fractured shale reservoirs with deformable multi-continuum matrix,Shale gas; Geomechanics; Multi-continuum; Stress alteration,GAS-TRANSPORT; DISCRETE FRACTURE; POROSITY MODEL; POROUS-MEDIA; SIMULATION; REDUCTION; DIFFUSION; IMPACT,"The Efficient development of shale reservoirs becomes increasingly dependent upon infill wells in China to stabilize the gas production. The accurate calculation of dynamic evolution of stress field is important for the design of fracturing and infill wells. The extraction of gas flow results in stress-sensitive and significantly alters the original in-situ stress field, which brings difficulties on geomechanical design for fracturing treatment. Hitherto, the main factors that affect the principal stress alteration is unclear, especially when considering the interference between fractures and wells. Besides, the transport mechanisms of shale gas flow are complex, which bring difficulties in the modeling of deformable multi-continuum. In this paper, an adaptive model that couples multi-continuum matrix and discrete fractures is developed. According to the effective stress coefficients of matrix pores and natural fractures, the total deformation is decomposed into two parts: matrix pore pressure depletion induced deformation and natural fracture pressure depletion induced deformation. The model is then validated to simulate hydromechanical coupling processes in fractured-shale reservoirs during the production period. Sensitivity analysis of stress alteration is also performed to study the alteration angle of the minimum horizontal principal stress during production. The modeling results show that the pressure depletion in natural fractures is the fastest, which dominates the shale deformation. Besides, the gas desorption in organic matters enlarges the alteration angle of the minimum horizontal principal stress during production. Finally, we find the difference between adsorption rate and desorption rate, instead of the total adsorbed gas amount, determines the adsorbed gas production.",5,5,1
Natural Fractures,Shale Gas,"Xu, Youjie; Li, Xiaoping; Liu, Qiguo; Yang, Sihan; Tan, Xiaohua",A semi-analytical solution of finite-conductivity multi-wing fractured well in naturally fractured reservoirs by boundary element method,Multi-wing fractured well (MWFW); Finite conductivity; Boundary element method (BEM); Pressure transient analysis,PRESSURE TRANSIENT ANALYSIS; SHALE GAS-RESERVOIRS; HORIZONTAL WELLS; VERTICAL WELLS; BEHAVIOR; MODEL,"Large-scale vertical well fracturing leads to formation of multi-wing fractures, which can effectively reduce fluid seepage resistance and increase single well production. As one of the post-fracture evaluation methods, pressure transient analysis is used widely in oil/gas field evaluation by engineers. It is of great significance for petroleum engineers to choose the correct and appropriate well test model for the accurate evaluation of formation parameters. Since oil/gas outer boundary is often rectangle or arbitrarily shape, a semi-analytical model of multiwing fractured well (MWFW) with arbitrarily shaped outer boundary gas reservoirs is presented. The reservoirs and hydraulic fracture mathematical models are established and solved. Coupling reservoirs and hydraulic fracture solution, and then discreting hydraulic fracture and outer boundary. The wellbore pressure solution with arbitrarily shaped outer boundary is obtained by pressure drop superposition, boundary element method (BEM) and Stehfest numerical inversion method. The bi-wing symmetrical hydraulic fracture and MWFW with finite conductivity are verified respectively by using numerical solution and comparison results reaches a good match, which certifies the correctness of the model and solving method. Typical curves of wellbore pressure and rate decline are discussed and influence of conductivity, hydraulic fracture number and hydraulic fracture distribution style et al. on wellbore pressure and rate decline is analyzes by combining with rate distribution of different time and segment. Influence of other parameters (Storativity ratio, interporosity coefficient and boundary shape size) on wellbore pressure and rate decline is also discussed in the end of paper.",3,3,8
Natural Fractures,Shale Gas,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Natural Fractures,Shale Gas,"Zhai, Xiaopeng; Chen, Hui; Lou, Yishan; Wu, Huimei",Prediction and control model of shale induced fracture leakage pressure,Shale gas; Leakage rate; Induced fracture; Leakage pressure; Critical value of fracture's width,,"Fractures gradually open under the action of fluid pressure in drilling shale gas reservoirs because of the existence of shale natural fractures, which leads to the leakage of expansible fractures. Induced fracture leakage is difficult to find and control in the early stage of drilling, resulting in great economic losses. The current model of induced fracture leakage pressure model is based on takes rock fracture criterion, which can only be used to judge whether the fracture is fractures created or not but cannot analyze the influence of fracture width change on leakage pressure after natural fracture of shale cracking. In addition, the model cannot control the occurrence of leakage. In this paper, the calculation method of fracture's width change under induced pressure is established. According to the field leakage rate data, a dynamic model of leakage pressure is established based on the parameters of time, leakage rate, fracture's width, fluid viscosity, and wellbore radius. The model is applied to calculate the dynamic change of leakage pressure on the Sichuan Shale Gas Field site and control the induced fracture's change to control leakage. Results show the following observations. (i) The fracture's width and leakage velocity of induced fracture increase with the increase of leakage pressure. Blocking the leakage when any leakage is found on the site is not advisable because it can increase the fracture's width artificially and increase leakage. (ii) The critical value of the fracture's width may cause severe leakage. When the leakage's differential pressure remains unchanged, the relationship between the fracture's width and leakage velocity refers to the power exponent change. The method of controlling the leakage pressure and reducing the fracture's width that is less than the critical leakage fracture degree is adopted for the leakage of the shale gas drilling in the Longmaxi Formation field Jiaoshiba, which effectively reduces the leakage amount. Taking a particular project, for example, controlling leakage pressure of induced fracture is given to verify the feasibility of the method.",3,4,4
Natural Fractures,Carbonate Rock,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Natural Fractures,Carbonate Rock,"Gou, Bo; Zhan, Li; Guo, Jianchun; Zhang, Ran; Zhou, Changlin; Wu, Lin; Ye, Jiexiao; Zeng, Ji",Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan,Fractured carbonate rock; True tri-axial experiment; Reactive fluid; Nonreactive fluid; Fracture propagation; CT scan,LIMESTONE FORMATION; CRITERION; SHALE; ACID,"Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm x 200 mm x 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.",5,5,13
Natural Fractures,Carbonate Rock,"Lai, Jin; Chen, Kangjun; Xin, Yi; Wu, Xingneng; Chen, Xu; Yang, Kefu; Song, Qiuqiang; Wang, Guiwen; Ding, Xiujian","Fracture characterization and detection in the deep Cambrian dolostones in the Tarim Basin, China: Insights from borehole image and sonic logs",Fractures; In-situ stress; Dolostones; Dissolution; Well log expression; Tarim basin,LOWER ORDOVICIAN CARBONATES; TRIASSIC YANCHANG FORMATION; ORDOS BASIN; DOLOMITE RESERVOIRS; NW CHINA; SICHUAN BASIN; HYDROTHERMAL ALTERATION; FORMATION MECHANISM; DENSITY-ESTIMATION; SHALE RESERVOIRS,"Characterization and detection of natural fractures using well logs in ancient deeply buried dolostones with low matrix porosity are very difficult. Core description, thin section analysis, conventional well logs, borehole image and sonic logs are used to document distribution of fractures in deep Cambrian dolostones in the Tarim Basin, China. The SHmax (maximum horizontal stress) direction is determined from drilling induced fractures, borehole breakouts and shear wave birefringence. Natural fractures with various attributes (open to partly open to closed) and orientation (including dip angles) are recognized. Natural fractures are classified into closed fractures, partly closed fractures, vuggy fractures and open fractures, and they can be further classified into high angle fractures, low-medium dip angle fractures, and low angle or horizontal fractures. Natural fractures are mainly associated with the more brittle rocks (dolograinstone, fine-medium-coarse crystalline dolostones), while fractures in dolomicrites and evaporitic gypsums-bearing dolostones are rare. Open to closed fractures are recognized as dark to bright sine waves on image logs, and the presences of open fractures cause minor deviations on the DEN logs, but significant deviations in resistivity values, while AC will be significantly increased in front of fractures. The energy of sonic full-waveforms will be strongly attenuated in front of open fractures. Fractures with strike parallel to the SHmax tend to have large aperture and good connectivity, and are suggested to enhance hydrocarbon productivity. Dolostones adjacent to the deep faults are heavily fractured, and fractures act as the hydrothermal fluid flow pathways, facilitating dissolution process. The abundance of vuggy fractures, and enlargement of the pre-existing microfractures support that fractures had enhanced dissolution. The dissolution along fracture surfaces helps increase fracture porosity. The results of this study about subsurface fracture patterns and their distributions are important for the hydrocarbon exploration and production in the Cambrian dolostones in the Tarim Basin.",4,6,4
Natural Fractures,Carbonate Rock,"Al-Arji, H.; Al-Azman, A.; Le-Hussain, F.; Regenauer-Lieb, K.",Acid stimulation in carbonates: A laboratory test of a wormhole model based on Damohler and Peclet numbers,Carbonate acidizing; Wormhole; Dimensionless numbers; Damkohler; Peclet; Acidic core flooding; HCl injection,DISSOLUTION; ACIDIZATION; TRANSPORT; DOLOMITE; WELLS,"Acid stimulation has been used worldwide as a stimulation technique either by matrix acidizing to remove the near-wellbore permeability impairment which is referred to as formation damage or acid fracturing to enhance the connectivity between wells and reservoirs. Carbonate acid stimulation improves the near-wellbore permeability through the creation of deeply penetrating fluid pathways referred to as wormholes. The stimulation success depends on the length and width of these wormholes. Here, we test the results of a theoretical study which suggests that the effect of acid flow in a reactive porous medium can be fully defined by just two significant dimensionless numbers, the non-dimensional Damkohler and Peclet numbers. The approach was validated in an idealized numerical study and is here tested in a systematically controlled laboratory experiment for real carbonate rocks. In order to obtain statistically meaningful results, we pushed the envelope by testing the prediction of the critical point for the wormholing phenomenon in a difficult domain, where sufficient randomly distributed pathways exist such that the wormholing domain is rarely achieved. The result confirmed that for a randomly-structured highly porous media, the critical point for dissolution pattern formation including the wormholing phenomenon can be fully captured by a domain diagram of inverse Damkohler versus Peclet number as predicted by the theoretical model. The model also holds for moderately tight formations, however, breaks down when the natural permeability drops well below 100 mDarcy. We conclude that the result of this research can be applied to reliably predict the wormholes initiation and various dissolution structures under various injection rate and HCl-concentration.",3,3,4
Natural Fractures,Carbonate Rock,"Mejia, Miguel; Parra, Jose E.; Mejia, Lucas; Pope, Gary A.; Balhoff, Matthew T.",Experiments and numerical simulations of chemical enhanced oil recovery in fractured carbonate rocks,Surfactant FOR; Fractured carbonates; Microemulsion phase behavior; Numerical simulation,SURFACTANT IMBIBITION; PERMEABILITY; SALINITY; DRAINAGE; PHASE; FLOW,"Secondary oil recovery from naturally fractured, oil wet carbonate reservoirs is challenging due to high permeability fractures and unfavorable capillary forces. A series of new tertiary surfactant coreflood experiments in fractured oil wet limestone cores were performed in which surfactants lowered the IFT and formed viscous microemulsions upon mixing with crude oil and brine. The viscous microemulsions cause favorable transverse pressure gradients that result in increased oil recovery. The effects of surfactant slug size, salinity and injection rate were investigated experimentally. In all cases, the injected surfactant solutions recovered significantly more oil than waterflooding. Numerical simulations were used to interpret the experimental results. The experimental oil recovery and pressure drop data were matched by reducing the fluid mobility in the fracture. A new experiment verified that a viscous phase formed in the fracture, which resulted in a significant improvement in oil recovery.",3,3,2
Natural Fractures,Experimental Results,"Wang, Zhiming; Hurter, Suzanne; You, Zhenjiang; Honari, Vahab; Sun, Yuning; Zhang, Shuo",Influences of negative pressure on air-leakage of coalseam gas extraction: Laboratory and CFD-DEM simulations,Coal seam gas; Negative pressure; Air-leakage; Fracture; Blockage; CFD-DEM simulation,FINES MIGRATION; METHANE EXTRACTION; 2-PHASE FLOW; MODEL; PARTICLES; DRAINAGE; RATIO,"Comprehensive understandings of the influences of negative pressure on air-leakage and its driving mechanism are critical for controlling methane concentration during coal seam gas extraction. Laboratory experiments were conducted using an integrated apparatus to study the air-leakage process of coal seam gas extraction under different negative pressures. In addition, a coupled computational fluid dynamics-discrete element approach was used to simulate the process of air flow and particle transport in a natural coal fracture to understand the influential mechanism of negative pressure on air-leakage at the mesoscale. Experimental results show that with an increase in the absolute value of negative pressure, the air-leakage experiences three stages of increase, decrease and increase at Stage I, Stage II and Stage III, respectively. It is reported for the first time and in good agreement with field test data. From experimental and numerical results, at Stage I the air-leakage increases with the absolute value of negative pressure because there is no blockage in fractures around borehole. At Stage II, the further increased absolute value of negative pressure contributes to particles motion in fractures. It gradually leads to the formation of blockage structure composed of aggregated particles in fractures, and the decrease of fracture conductivity and air velocity. With the absolute value of negative pressure rising continuously, the contact forces between the aggregated particles increase. Therefore, the balance of the blockage structure tends to be broken, which helps to understand the air-leakage increase with the absolute value of negative pressure at Stage III. Between Stage II and Stage III, there is a valley point corresponding to the minimum air-leakage, which is important to the improvement of gas extraction performance. The contact forces on the aggregated soft particles are larger than those on the aggregated hard particles under the same negative pressure. Therefore, the blockage structure consisting of soft particles is much easier to be broken than that formed by hard particles. This explains why the absolute value of negative pressure corresponding to the valley point for hard coal model is larger than that for the soft coal model.",5,5,12
Natural Fractures,Experimental Results,"Liu, Huifeng; Bedrikovetsky, Pavel; Yuan, Zebo; Liu, Jv; Liu, Yuxuan",An optimized model of calculating optimal packing ratio for graded proppant placement with consideration of proppant embedment and deformation,Natural fractures; Graded proppant placement; Proppant embedment; Proppant deformation; Fracture conductivity,FRACTURES; SHALE; CONDUCTIVITY; STIMULATION,"The method of micro-sized Graded Proppant Placement (GPP) has been proposed in the industry to increase the size of the stimulated zone in naturally fractured reservoirs. The models of determining the Optimal Proppant Packing Ratio (OPPR) and the optimal injection schedule have also been established. However, all the previous studies neglected the impact of Proppant Embedment into fracture wall and Proppant Deformation (PEPD), and therefore significant discrepancies between modeling results and experimental results have been observed. In this study, models of calculating PEPD are established and incorporated into the GPP model, and the influences of proppant embedment and deformation on OPPR, optimal injection schedule and predicted post-stimulation productivity increase are investigated. Conductivity Correction Factor (CCF) is introduced to find the OPPR and the results are compared with the results obtained from previous models which are based on Permeability Correction Factor (PCF). The results show that smaller proppant Elastic Modulus or smaller rock Elastic Modulus leads to bigger OPPR and lower PCF. The CCF -based OPPR matches better with previous experimental results than the PCF -based value. The study also shows that with consideration of PEPD, OPPR is significantly larger; the optimal proppant concentrations at different stages of graded proppant injection are accordingly larger, and the predicted folds of productivity increase after stimulation is much lower. The results from this study can be used to optimize the planning of GPP. For the stimulations of soft formations like CBM, shale etc. or the stimulations where less-rigid proppants like silica sand or walnut shell are used, the findings of this study are even more important. If the proppants and the formation rock are assumed to be rigid bodies and PEPD are neglected in such situations, 32.5% lower of proppant concentration will be caused, which will consequently lead to under-propping of the fracture and the productivity will not be maximized supposedly. Meanwhile, the predicted folds of productivity increase will be overestimated by 27.5% maximally. The larger the stimulation zone, the stronger the influence of PEPD. PEPD must be considered when planning a large-scale GPP in soft formations. This study is a continuation of the studies conducted by the authors earlier. The major novel elements are that PEPD are considered, the influences of PEPD are investigated, and fracture conductivity is used instead of permeability to find the optimal proppant packing ratio.",5,5,3
Natural Fractures,Experimental Results,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Natural Fractures,Experimental Results,"Mejia, Miguel; Parra, Jose E.; Mejia, Lucas; Pope, Gary A.; Balhoff, Matthew T.",Experiments and numerical simulations of chemical enhanced oil recovery in fractured carbonate rocks,Surfactant FOR; Fractured carbonates; Microemulsion phase behavior; Numerical simulation,SURFACTANT IMBIBITION; PERMEABILITY; SALINITY; DRAINAGE; PHASE; FLOW,"Secondary oil recovery from naturally fractured, oil wet carbonate reservoirs is challenging due to high permeability fractures and unfavorable capillary forces. A series of new tertiary surfactant coreflood experiments in fractured oil wet limestone cores were performed in which surfactants lowered the IFT and formed viscous microemulsions upon mixing with crude oil and brine. The viscous microemulsions cause favorable transverse pressure gradients that result in increased oil recovery. The effects of surfactant slug size, salinity and injection rate were investigated experimentally. In all cases, the injected surfactant solutions recovered significantly more oil than waterflooding. Numerical simulations were used to interpret the experimental results. The experimental oil recovery and pressure drop data were matched by reducing the fluid mobility in the fracture. A new experiment verified that a viscous phase formed in the fracture, which resulted in a significant improvement in oil recovery.",3,3,2
Natural Fractures,Porous Medium,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Natural Fractures,Porous Medium,"Arianfar, Ali; Ramezanzadeh, Ahmad; Khalili, Mohammad",Numerical study of nonlinear fluid flow behavior in natural fractures adjacent to porous medium,Fractured reservoirs; Fracture; Roughness; Porous medium; Permeability; Forchheimer equation,,"It is essential to understand the hydraulic aperture behavior of rock fractures where fluid passes through the rock mass. The geometric parameters of fracture, such as wall roughness and fracture aperture, have a significant effect on its hydro-mechanical behavior. This issue has been addressed in many papers, but the fluid passage through the permeable zone adjacent to the fracture has rarely been studied. Therefore, this paper numerically simulated the fluid behavior in the porous fractured medium. For preparing the model geometry, the 3D scanning of fracture walls was used for the samples taken from one of the oil wells in southern Iran. The geometry of fractures was prepared using ICEM CFD software, and the fluid flow in rock fracture and porous matrix was simulated with Ansys FluentTM software. Given that the two fracture surfaces are connected in reality, the geometry of the model was constructed when the fractures are mated and the connection is established at a certain level (the connection between the two surfaces equal to 15, 30, 45, 60, 75, and 90% of the total area). The results of this simulation showed that the Forchheimer macroscopic relation well describes the nonlinear fluid flow in the rock fracture even considering the permeable matrix. However, the higher the permeability value of the matrix adjacent to the fracture, the higher the fracture permeability value. The results indicated an exponential relationship between the increased permeability and the decreased Forchheimer coefficients, which confirms the easier passage of fluid through the fracture enclosed by a zone of higher permeability. Also, the values of linear and nonlinear coefficients of Forchheimer equation were estimated for each of the geometric models, which showed that the changes in Forchheimer coefficients are exponentially related to the change in the connected surface area.",3,3,9
Natural Fractures,Porous Medium,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Natural Fractures,Porous Medium,"Al-Arji, H.; Al-Azman, A.; Le-Hussain, F.; Regenauer-Lieb, K.",Acid stimulation in carbonates: A laboratory test of a wormhole model based on Damohler and Peclet numbers,Carbonate acidizing; Wormhole; Dimensionless numbers; Damkohler; Peclet; Acidic core flooding; HCl injection,DISSOLUTION; ACIDIZATION; TRANSPORT; DOLOMITE; WELLS,"Acid stimulation has been used worldwide as a stimulation technique either by matrix acidizing to remove the near-wellbore permeability impairment which is referred to as formation damage or acid fracturing to enhance the connectivity between wells and reservoirs. Carbonate acid stimulation improves the near-wellbore permeability through the creation of deeply penetrating fluid pathways referred to as wormholes. The stimulation success depends on the length and width of these wormholes. Here, we test the results of a theoretical study which suggests that the effect of acid flow in a reactive porous medium can be fully defined by just two significant dimensionless numbers, the non-dimensional Damkohler and Peclet numbers. The approach was validated in an idealized numerical study and is here tested in a systematically controlled laboratory experiment for real carbonate rocks. In order to obtain statistically meaningful results, we pushed the envelope by testing the prediction of the critical point for the wormholing phenomenon in a difficult domain, where sufficient randomly distributed pathways exist such that the wormholing domain is rarely achieved. The result confirmed that for a randomly-structured highly porous media, the critical point for dissolution pattern formation including the wormholing phenomenon can be fully captured by a domain diagram of inverse Damkohler versus Peclet number as predicted by the theoretical model. The model also holds for moderately tight formations, however, breaks down when the natural permeability drops well below 100 mDarcy. We conclude that the result of this research can be applied to reliably predict the wormholes initiation and various dissolution structures under various injection rate and HCl-concentration.",3,3,4
Natural Fractures,Fracture Propagation,"Hui, Gang; Chen, Shengnan; Chen, Zhangxing; Gu, Fei",An integrated approach to characterize hydraulic fracturing-induced seismicity in shale reservoirs,Induced seismicity; Hydraulic fracturing; Coupled flow-geomechanics model; Coulomb failure stress; Mitigation strategy,COULOMB STRESS CHANGES; INDUCED EARTHQUAKES; CROOKED LAKE; FOX CREEK; POROELASTICITY; SEQUENCES,"There has been a remarkable increase in induced seismicity in Western Canada and the majority of these events can be related to hydraulic fracturing operations applied to develop unconventional reservoirs. The underlying mechanism of such induced seismicity is still unclear and needs to be investigated to mitigate risks of future events. In this paper, we propose a new integrated approach to characterize hydraulic fracturing-induced seismicity. Inferred faults in the target area were first identified by the ant-tracking approach and hydraulic fractures were characterized by simulating hydraulic fracturing processes. The coupled flow-geomechanics modeling was then performed to compute the Coulomb Failure Stress and determine the reactivation of pre-existing faults. A case study was finally utilized to demonstrate the applicability of the integrated method. Four north-south-oriented faults were interpreted and half-length of hydraulic fractures were calculated from 84 to 127 m. The calculated results of the flow-geomechanics model were in good agreement with the actual induced seismicity spatially and temporally. Three types of triggering mechanisms were accounted for HF-induced seismicity, including hydraulic fractures propagation, the connection between hydraulic fractures and a fault and connections of hydraulic fractures with the natural fractures around the fault. The injection rate could be decreased to mitigate risks of future seismic events.",7,8,2
Natural Fractures,Fracture Propagation,"Gou, Bo; Zhan, Li; Guo, Jianchun; Zhang, Ran; Zhou, Changlin; Wu, Lin; Ye, Jiexiao; Zeng, Ji",Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan,Fractured carbonate rock; True tri-axial experiment; Reactive fluid; Nonreactive fluid; Fracture propagation; CT scan,LIMESTONE FORMATION; CRITERION; SHALE; ACID,"Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm x 200 mm x 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.",5,5,13
Natural Fractures,Fracture Propagation,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Natural Fractures,Acid,"Quainoo, Ato Kwamena; Negash, Berihun Mamo; Bavoh, Cornelius B.; Idris, Alamin",Natural amino acids as potential swelling and dispersion inhibitors for montmorillonite-rich shale formations,Reactive days; Clay swelling and dispersion; Clay stabilizers; Natural amino acids; COSMO-RS Simulation; Activity coefficient and hydrogen bonding,DRILLING-FLUIDS; IONIC LIQUID; COSMO-RS; FILTRATION PROPERTIES; HIGH-PERFORMANCE; WATER; HYDRATE; BENTONITE; BEHAVIOR; METHANE,"In this paper, the destabilization inhibition potentials and mechanisms of Alanine, Arginine, and Proline on montmorillonite clay were investigated. A swelling test was done using an M4600 HPHT Linear swell meter at 1000 psi, 25 degrees C, and 2 wt% inhibitor solutions. Shear rates and temperatures in the range of 0.01 s(-1) to 1000 s(-1) and 25 degrees C - 50 degrees C, respectively, were applied on a high-precision Discovery Hybrid Rheometer to investigate the effect of the amino acids on the suspension's theology. Also, the inhibitors' neutralization and surface modification properties were determined via zeta potential, wettability alteration, and FTIR analyses using the nano zeta sizer, goniometer, and the spectrometer respectively. Furthermore, COSMO-RS was employed to study the hydrogen bonding interactions of amino acids and water. Upon completion, Proline displayed the best inhibition performance reducing the swelling of the montmorillonite by 22.5%, whiles KCl only showed a 17.8% reduction. Also, the rheological tests confirmed that the amino acids positively enhanced the base fluid properties. In addition, Proline, Alanine, and Arginine altered the surface of the clay mineral by 89%, 64%, and 38%, respectively, when compared to the base fluid. This made their clay surfaces less hydrophilic and thus, reduced the attraction between water molecules and the clay mineral. Furthermore, the simulation results showed that amino acids easily form hydrogen bonds with water, thus preventing high amounts of water from saturating the clay mineral, resulting in a significant reduction of swelling in the clay during fracturing. The superior performance of amino acids especially Proline in stabilizing montmorillonite clays, over KCl, makes them suitable candidates to consider in the development of low cost, and eco-friendly clay stabilizers.",6,6,5
Natural Fractures,Acid,"Gou, Bo; Zhan, Li; Guo, Jianchun; Zhang, Ran; Zhou, Changlin; Wu, Lin; Ye, Jiexiao; Zeng, Ji",Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan,Fractured carbonate rock; True tri-axial experiment; Reactive fluid; Nonreactive fluid; Fracture propagation; CT scan,LIMESTONE FORMATION; CRITERION; SHALE; ACID,"Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm x 200 mm x 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.",5,5,13
Natural Fractures,Acid,"Al-Arji, H.; Al-Azman, A.; Le-Hussain, F.; Regenauer-Lieb, K.",Acid stimulation in carbonates: A laboratory test of a wormhole model based on Damohler and Peclet numbers,Carbonate acidizing; Wormhole; Dimensionless numbers; Damkohler; Peclet; Acidic core flooding; HCl injection,DISSOLUTION; ACIDIZATION; TRANSPORT; DOLOMITE; WELLS,"Acid stimulation has been used worldwide as a stimulation technique either by matrix acidizing to remove the near-wellbore permeability impairment which is referred to as formation damage or acid fracturing to enhance the connectivity between wells and reservoirs. Carbonate acid stimulation improves the near-wellbore permeability through the creation of deeply penetrating fluid pathways referred to as wormholes. The stimulation success depends on the length and width of these wormholes. Here, we test the results of a theoretical study which suggests that the effect of acid flow in a reactive porous medium can be fully defined by just two significant dimensionless numbers, the non-dimensional Damkohler and Peclet numbers. The approach was validated in an idealized numerical study and is here tested in a systematically controlled laboratory experiment for real carbonate rocks. In order to obtain statistically meaningful results, we pushed the envelope by testing the prediction of the critical point for the wormholing phenomenon in a difficult domain, where sufficient randomly distributed pathways exist such that the wormholing domain is rarely achieved. The result confirmed that for a randomly-structured highly porous media, the critical point for dissolution pattern formation including the wormholing phenomenon can be fully captured by a domain diagram of inverse Damkohler versus Peclet number as predicted by the theoretical model. The model also holds for moderately tight formations, however, breaks down when the natural permeability drops well below 100 mDarcy. We conclude that the result of this research can be applied to reliably predict the wormholes initiation and various dissolution structures under various injection rate and HCl-concentration.",3,3,4
Natural Fractures,Discrete Fractures,"Rao, Xiang; Xin, Liyuan; He, Yanxiang; Fang, Xiaoyu; Gong, Ruxiang; Wang, Fei; Zhao, Hui; Shi, Junjie; Xu, Yunfeng; Dai, Weixin",Numerical simulation of two-phase heat and mass transfer in fractured reservoirs based on projection-based embedded discrete fracture model (pEDFM),Projection-based embedded discrete fracture model; Heat and mass transfer; Fractured reservoir,SINGLE-PHASE FLOW; TRANSPORT; OIL,"pEDFM is a newly developed numerical simulation framework for mass transfer in fractured reservoirs, and this paper aims to study the application of the pEDFM framework to numerical simulation of two-phase heat and mass transfer in fractured reservoirs. Firstly, the finite volume method is used to discretize the mass and energy conservative equations. Then, all the connections between control volumes including two types of fracture-matrix (f-m), three types of fracture-fracture (f-f) and one type of matrix-matrix (m-m) connections are constructed, and corresponding transmissibility formulas of mass and heat transfer in finite-volume discrete schemes for these connections are given, and Newton iteration method is used to solve the fully implicit coupled discrete equations to obtain cell temperature, pressure and water saturation. Finally, two numerical examples including multiphase flow across high-conductivity fractures and flow barriers are implemented to show that pEDFM can eliminate the errors in EDFM for the calculated temperature profiles. An application case that applies water-flooding to a fractured reservoir model with a fractured horizontal well, four water injection wells, natural fractures and a fault is considered to show that, compared with EDFM, pEDFM can more accurately and effectively handle the numerical simulation of mass and heat transfer in realistic fractured reservoirs with complex geological conditions.",11,11,10
Natural Fractures,Discrete Fractures,"Lu, Yunhu; Wei, Shiming; Xia, Yang; Jin, Yan",Modeling of geomechanics and fluid flow in fractured shale reservoirs with deformable multi-continuum matrix,Shale gas; Geomechanics; Multi-continuum; Stress alteration,GAS-TRANSPORT; DISCRETE FRACTURE; POROSITY MODEL; POROUS-MEDIA; SIMULATION; REDUCTION; DIFFUSION; IMPACT,"The Efficient development of shale reservoirs becomes increasingly dependent upon infill wells in China to stabilize the gas production. The accurate calculation of dynamic evolution of stress field is important for the design of fracturing and infill wells. The extraction of gas flow results in stress-sensitive and significantly alters the original in-situ stress field, which brings difficulties on geomechanical design for fracturing treatment. Hitherto, the main factors that affect the principal stress alteration is unclear, especially when considering the interference between fractures and wells. Besides, the transport mechanisms of shale gas flow are complex, which bring difficulties in the modeling of deformable multi-continuum. In this paper, an adaptive model that couples multi-continuum matrix and discrete fractures is developed. According to the effective stress coefficients of matrix pores and natural fractures, the total deformation is decomposed into two parts: matrix pore pressure depletion induced deformation and natural fracture pressure depletion induced deformation. The model is then validated to simulate hydromechanical coupling processes in fractured-shale reservoirs during the production period. Sensitivity analysis of stress alteration is also performed to study the alteration angle of the minimum horizontal principal stress during production. The modeling results show that the pressure depletion in natural fractures is the fastest, which dominates the shale deformation. Besides, the gas desorption in organic matters enlarges the alteration angle of the minimum horizontal principal stress during production. Finally, we find the difference between adsorption rate and desorption rate, instead of the total adsorbed gas amount, determines the adsorbed gas production.",5,5,1
Natural Fractures,Discrete Fractures,"Li, Longlong; Voskov, Denis",A novel hybrid model for multiphase flow in complex multi-scale fractured systems,Reservoir simulation; Multi-level discrete fracture model; Fractured reservoir; Local-global upscaling,NUMERICAL-SIMULATION; POROUS-MEDIA; RESERVOIR SIMULATION; TRANSPORT; FLUID; PERMEABILITY; RECOVERY; WATER,"We present a multi-level discrete fracture model (MLDFM) to guarantee a robust and efficient solution for naturally fractured reservoir simulation. In MLDFM, we apply a triple continuum model using structured grid for forward simulation where large-scale fractures are represented with numerical embedded discrete fracture model (EDFM) and the secondary fractures are upscaled as third continuum. What makes the triple continuum model different from the previous work is that both the numerical EDFM and the third continuum are treated in a dynamic approach by considering the effect of flow direction on the complex local-scale flow response. For that purpose, we construct a finer unstructured discrete fracture matrix (DFM) grid which represents all fractures explicitly and is conformal to the boundary of coarse structured grid. During a simulation run, we apply a basis function to generate the local boundary conditions at fine scale using the global solution. Benefit from that, we can use a more accurate flow-based approach in the extended local upscaling to re-compute the transmissibility in triple continuum model. Moreover, we apply a local-global upscaling formalism to guarantee dynamically updated local boundary conditions for upscaling. Besides, we present several cases using synthetic and realistic fractured networks to demonstrate the performance of MLDFM. The results prove that the proposed MLDFM approach more accurately captures the flow in complex fractured systems than EDFM solutions by comparing against fine-scale DFM. At the same time, MLDFM is more computationally efficient in comparison with fine scale DFM.",4,4,2
Natural Fractures,Proppant,"Liu, Huifeng; Bedrikovetsky, Pavel; Yuan, Zebo; Liu, Jv; Liu, Yuxuan",An optimized model of calculating optimal packing ratio for graded proppant placement with consideration of proppant embedment and deformation,Natural fractures; Graded proppant placement; Proppant embedment; Proppant deformation; Fracture conductivity,FRACTURES; SHALE; CONDUCTIVITY; STIMULATION,"The method of micro-sized Graded Proppant Placement (GPP) has been proposed in the industry to increase the size of the stimulated zone in naturally fractured reservoirs. The models of determining the Optimal Proppant Packing Ratio (OPPR) and the optimal injection schedule have also been established. However, all the previous studies neglected the impact of Proppant Embedment into fracture wall and Proppant Deformation (PEPD), and therefore significant discrepancies between modeling results and experimental results have been observed. In this study, models of calculating PEPD are established and incorporated into the GPP model, and the influences of proppant embedment and deformation on OPPR, optimal injection schedule and predicted post-stimulation productivity increase are investigated. Conductivity Correction Factor (CCF) is introduced to find the OPPR and the results are compared with the results obtained from previous models which are based on Permeability Correction Factor (PCF). The results show that smaller proppant Elastic Modulus or smaller rock Elastic Modulus leads to bigger OPPR and lower PCF. The CCF -based OPPR matches better with previous experimental results than the PCF -based value. The study also shows that with consideration of PEPD, OPPR is significantly larger; the optimal proppant concentrations at different stages of graded proppant injection are accordingly larger, and the predicted folds of productivity increase after stimulation is much lower. The results from this study can be used to optimize the planning of GPP. For the stimulations of soft formations like CBM, shale etc. or the stimulations where less-rigid proppants like silica sand or walnut shell are used, the findings of this study are even more important. If the proppants and the formation rock are assumed to be rigid bodies and PEPD are neglected in such situations, 32.5% lower of proppant concentration will be caused, which will consequently lead to under-propping of the fracture and the productivity will not be maximized supposedly. Meanwhile, the predicted folds of productivity increase will be overestimated by 27.5% maximally. The larger the stimulation zone, the stronger the influence of PEPD. PEPD must be considered when planning a large-scale GPP in soft formations. This study is a continuation of the studies conducted by the authors earlier. The major novel elements are that PEPD are considered, the influences of PEPD are investigated, and fracture conductivity is used instead of permeability to find the optimal proppant packing ratio.",5,5,3
Natural Fractures,Proppant,"Shi, Fang","XFEM-based numerical modeling of well performance considering proppant transport, embedment, crushing and rock creep in shale gas reservoirs",Hydraulic fracturing; Gas production; Proppant crushing; Shale creep; XFEM,HYDRAULIC-FRACTURE PROPAGATION; FINITE-ELEMENT-METHOD; APPARENT PERMEABILITY; CRACK-GROWTH; CONDUCTIVITY; SIMULATION; FLOW; GEOMECHANICS; CLOSURE; DESORPTION,"Predicting the production rate and estimating the ultimate recovery are of great significance for the optimization of shale gas development. One possible reason for production decline is the width reduction of propped fractures caused by proppant deformation, embedment, crushing, and viscoelasticity of the reservoir. In order to obtain more in-depth knowledge of how these factors influence the gas production, a novel approach is proposed to simulate the processes of both hydraulic fracturing and gas production using the extended finite element method (XFEM). On the one hand, a numerical model which involves the coupled processes of deformation of the porous rock medium, fluid flow and leak-off, crack propagation, and proppant transport is proposed to obtain the proppant distribution for the hydraulic fracturing simulation. On the other hand, a coupled rock deformation and two-phase flow model considering stress-dependent fracture conductivity, crushing of proppant grains, creep of surrounding rock, gas diffusion and desorption, and influence of natural fractures is developed for the flowback and gas production simulation. The fracture closure during the shut-in and flowback process of fracturing fluid is considered. In addition, the size effects of proppant grains are investigated by using Weibull theory. After validation of the proposed model through history-matching, the sensitivity analysis of the proposed model on gas production is conducted. This study reveals that the proppant size has a dominant influence. Although proppant with larger grain sizes leads to a more permeable propped fracture, it is found that only proppant grains of proper size, not too large or too small, has the potential to achieve economic gas production due to the combined effects of size effect of the grains and ""bridging out"" of the proppant. The second influential factor on the gas production is the proppant concentration which is followed by the viscosity of shale formation, the Young's modulus of proppant, and the Young's modulus of shale formation. This study leads to a better understanding of proppant-related mechanisms involved in hydraulic fracturing and gas production and provides an efficient numerical tool for the prediction of well performance in field development planning.",3,3,8
Natural Fractures,Shale Oil,"Gong, Lei; Wang, Jie; Gao, Shuai; Fu, Xiaofei; Liu, Bo; Miao, Fengbin; Zhou, Xinping; Meng, Qingkuan","Characterization, controlling factors and evolution of fracture effectiveness in shale oil reservoirs",Shale oil; Fracture effectiveness; Filling behavior; Fracture aperture; Oiliness; Qingshankou formation,TIGHT-GAS SANDSTONES; EAGLE FORD FORMATION; BOHAI BAY BASIN; NATURAL FRACTURES; MECHANICAL STRATIGRAPHY; CENGONG BLOCK; DEVELOPMENTAL CHARACTERISTICS; QUANTITATIVE PREDICTION; NIUTITANG FORMATION; DOMINANT FACTORS,"Fracture effectiveness is of great significance for seeking shale oil exploration targets. The fracture effectiveness and primary controlling factors in the Cretaceous Qing-1 Member shale oil reservoir in Gulong Sag, China, was evaluated based on precise fracture characterization on core samples and thin sections. The evolution sequence of fracture effectiveness was subsequently discussed. Structural fractures, diagenetic fractures and overpressure fractures are found in the study area, where structural fracture is the most important ones, which is characterized by high density, large aperture and weak filling. Structural fractures were formed in three stages and underwent two filling events, while fractures growing at the third stage with no filling are the most effective ones. Diagenetic fractures can be classified into bedding-parallel fractures and stylolites, where the former is partly filled, and the latter is fully filled by dark minerals. Hence, these fractures can act as seepage barriers. The overpressure fractures have large apertures but short length and are insensitively filled. Fracture effectiveness varies greatly as a function of cementation, fracture growth period, dissolution, tectonic activity at later stage, abnormal high pressure and current tectonic stress field. Fractures developing at earlier stage are commonly filled, which tends to be ineffective. Structural inversion at a later stage, abnormal high pressure and dissolution can reopen fractures and improve their effectiveness. The fractures parallel to the current maximum principal stress with high dip-angle have large apertures and good effectiveness.",23,25,13
Natural Fractures,Shale Oil,"Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, Naseem; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Yang, Shangfeng; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar","Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan",Talhar shale; Total organic richness; Petrography; Vitrinite reflectance; Hydraulic fracking; Mineralogy; Wireline logs; Biomarkers,,"A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70-90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43-10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Delta log R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C-19 tricyclic terpanes, C-30 pentacyclic triterpanes, and C-27 steranes. Maturity parameters (T-max, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C-23 TT, the lower amounts of C-29/C-30 17 alpha(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., T-max, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, beta beta/beta beta+alpha alpha), and the hopane Ts/(Ts + Tm) and C-31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.",7,7,4
Natural Fractures,Mass Transfer,"Zhang, Qi; Yan, Xia; Shao, Jianli",Fluid flow through anisotropic and deformable double porosity media with ultra-low matrix permeability: A continuum framework,Double porosity; Geomechanics; Upscaling; Anisotropy; Non-Darcy parameter; Consolidation,,"Fractured porous media or double porosity media are common in nature. At the same time, accurate modeling remains a significant challenge due to bi-modal pore size distribution, anisotropy, multi-field coupling, and various flow patterns. This study aims to formulate a comprehensive coupled continuum framework that could adequately consider these critical characteristics. In our framework, fluid flow in the micro-fracture network is modeled with the generalized Darcy's law, in which the equivalent fracture permeability is upscaled from the detailed geological characterizations. The liquid in the much less permeable matrix follows a low-velocity non-Darcy flow characterized by threshold values and non-linearity. The fluid mass transfer is assumed to be a function of the shape factor, pressure difference, and (variable) interface permeability. The solid deformation relies on a thermodynamically consistent effective stress derived from the energy balance equation, and it is modeled following anisotropic poroelastic theory. The discussion revolves around generic double porosity media. Model applications reveal the capability of our framework to capture the crucial roles of coupling, poroelastic coefficients, anisotropy, and ultra-low matrix permeability in dictating the pressure and displacement fields.",12,12,8
Natural Fractures,Mass Transfer,"Rao, Xiang; Xin, Liyuan; He, Yanxiang; Fang, Xiaoyu; Gong, Ruxiang; Wang, Fei; Zhao, Hui; Shi, Junjie; Xu, Yunfeng; Dai, Weixin",Numerical simulation of two-phase heat and mass transfer in fractured reservoirs based on projection-based embedded discrete fracture model (pEDFM),Projection-based embedded discrete fracture model; Heat and mass transfer; Fractured reservoir,SINGLE-PHASE FLOW; TRANSPORT; OIL,"pEDFM is a newly developed numerical simulation framework for mass transfer in fractured reservoirs, and this paper aims to study the application of the pEDFM framework to numerical simulation of two-phase heat and mass transfer in fractured reservoirs. Firstly, the finite volume method is used to discretize the mass and energy conservative equations. Then, all the connections between control volumes including two types of fracture-matrix (f-m), three types of fracture-fracture (f-f) and one type of matrix-matrix (m-m) connections are constructed, and corresponding transmissibility formulas of mass and heat transfer in finite-volume discrete schemes for these connections are given, and Newton iteration method is used to solve the fully implicit coupled discrete equations to obtain cell temperature, pressure and water saturation. Finally, two numerical examples including multiphase flow across high-conductivity fractures and flow barriers are implemented to show that pEDFM can eliminate the errors in EDFM for the calculated temperature profiles. An application case that applies water-flooding to a fractured reservoir model with a fractured horizontal well, four water injection wells, natural fractures and a fault is considered to show that, compared with EDFM, pEDFM can more accurately and effectively handle the numerical simulation of mass and heat transfer in realistic fractured reservoirs with complex geological conditions.",11,11,10
Natural Fractures,Gas Extraction,"Wang, Zhiming; Hurter, Suzanne; You, Zhenjiang; Honari, Vahab; Sun, Yuning; Zhang, Shuo",Influences of negative pressure on air-leakage of coalseam gas extraction: Laboratory and CFD-DEM simulations,Coal seam gas; Negative pressure; Air-leakage; Fracture; Blockage; CFD-DEM simulation,FINES MIGRATION; METHANE EXTRACTION; 2-PHASE FLOW; MODEL; PARTICLES; DRAINAGE; RATIO,"Comprehensive understandings of the influences of negative pressure on air-leakage and its driving mechanism are critical for controlling methane concentration during coal seam gas extraction. Laboratory experiments were conducted using an integrated apparatus to study the air-leakage process of coal seam gas extraction under different negative pressures. In addition, a coupled computational fluid dynamics-discrete element approach was used to simulate the process of air flow and particle transport in a natural coal fracture to understand the influential mechanism of negative pressure on air-leakage at the mesoscale. Experimental results show that with an increase in the absolute value of negative pressure, the air-leakage experiences three stages of increase, decrease and increase at Stage I, Stage II and Stage III, respectively. It is reported for the first time and in good agreement with field test data. From experimental and numerical results, at Stage I the air-leakage increases with the absolute value of negative pressure because there is no blockage in fractures around borehole. At Stage II, the further increased absolute value of negative pressure contributes to particles motion in fractures. It gradually leads to the formation of blockage structure composed of aggregated particles in fractures, and the decrease of fracture conductivity and air velocity. With the absolute value of negative pressure rising continuously, the contact forces between the aggregated particles increase. Therefore, the balance of the blockage structure tends to be broken, which helps to understand the air-leakage increase with the absolute value of negative pressure at Stage III. Between Stage II and Stage III, there is a valley point corresponding to the minimum air-leakage, which is important to the improvement of gas extraction performance. The contact forces on the aggregated soft particles are larger than those on the aggregated hard particles under the same negative pressure. Therefore, the blockage structure consisting of soft particles is much easier to be broken than that formed by hard particles. This explains why the absolute value of negative pressure corresponding to the valley point for hard coal model is larger than that for the soft coal model.",5,5,12
Natural Fractures,Gas Extraction,"Lu, Yunhu; Wei, Shiming; Xia, Yang; Jin, Yan",Modeling of geomechanics and fluid flow in fractured shale reservoirs with deformable multi-continuum matrix,Shale gas; Geomechanics; Multi-continuum; Stress alteration,GAS-TRANSPORT; DISCRETE FRACTURE; POROSITY MODEL; POROUS-MEDIA; SIMULATION; REDUCTION; DIFFUSION; IMPACT,"The Efficient development of shale reservoirs becomes increasingly dependent upon infill wells in China to stabilize the gas production. The accurate calculation of dynamic evolution of stress field is important for the design of fracturing and infill wells. The extraction of gas flow results in stress-sensitive and significantly alters the original in-situ stress field, which brings difficulties on geomechanical design for fracturing treatment. Hitherto, the main factors that affect the principal stress alteration is unclear, especially when considering the interference between fractures and wells. Besides, the transport mechanisms of shale gas flow are complex, which bring difficulties in the modeling of deformable multi-continuum. In this paper, an adaptive model that couples multi-continuum matrix and discrete fractures is developed. According to the effective stress coefficients of matrix pores and natural fractures, the total deformation is decomposed into two parts: matrix pore pressure depletion induced deformation and natural fracture pressure depletion induced deformation. The model is then validated to simulate hydromechanical coupling processes in fractured-shale reservoirs during the production period. Sensitivity analysis of stress alteration is also performed to study the alteration angle of the minimum horizontal principal stress during production. The modeling results show that the pressure depletion in natural fractures is the fastest, which dominates the shale deformation. Besides, the gas desorption in organic matters enlarges the alteration angle of the minimum horizontal principal stress during production. Finally, we find the difference between adsorption rate and desorption rate, instead of the total adsorbed gas amount, determines the adsorbed gas production.",5,5,1
Natural Fractures,Mobility Ratio,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Natural Fractures,Mobility Ratio,"Li, Qingyu; Du, Xin; Tang, Qingjun; Xu, Yandong; Li, Peichao; Lu, Detang",A novel well test model for fractured vuggy carbonate reservoirs with the vertical bead-on-a-string structure,Fractured vuggy carbonate reservoirs; Vertical bead on a string structure; Well test; Type curves; Dimensionless gravity effect coefficient,PRESSURE-TRANSIENT; HORIZONTAL WELL; FLOW BEHAVIOR,"The bead-on-a-string structure has been widely observed in many fractured vuggy carbonate reservoirs, especially in Shunbei oilfield, northwestern China. To date, there are still no appropriate well test methods for analyzing these reservoirs with the vertical bead-on-a-string structure. This paper proposes a new theoretical well test model, which considers the gravity effect and the natural fractures connecting the vuggs, to analyze this kind of reservoirs. First, we establish the mathematical model of fractured vuggy reservoirs with the vertical bead-on-a-string structure. With the different outer boundary conditions, Laplace transform and inversion are employed to solve the well test model. Then, the type curves for the well test model are plotted and discussed. It is found that the gravity effect can be equivalent to a type of constant pressure boundary condition. Take the three-region-two-cave as an example, type curves can be divided into nine distinct flow regimes, including wellbore storage, skin, linear flow I and II, transition flow I and II, vug storage I and II, and boundary flow. The transition flow and vug storage period are named as the vug storage effect. Subsequently, the effects of relevant parameters are studied. It is concluded that the depth of the drop during vug storage effect increases with increasing dimensionless vug storage constant C-vD and dimensionless vug height z(D2)-z(D1); the greater dimensionless gravity effect coefficient G(D) leads to the smaller equivalent boundary distance of the constant pressure boundary condition; the smaller the mobility ratio M-12, the earlier the appearance of the second linear flow regime; the larger the storage ratio omega(12), the more distinct the vug storage effect. Finally, two field case studies are carried out by using the proposed method. The locations and volumes of the caves are estimated, which shows that the proposed theoretical well test model has a great potential of obtaining the formation and cave parameters accurately. However, there is not available data that enable an accurate description of the locations and volumes of the caves by now, the proposed model still needs further field verifications.",4,4,4
Natural Fractures,Wettability Alteration,"Quainoo, Ato Kwamena; Negash, Berihun Mamo; Bavoh, Cornelius B.; Idris, Alamin",Natural amino acids as potential swelling and dispersion inhibitors for montmorillonite-rich shale formations,Reactive days; Clay swelling and dispersion; Clay stabilizers; Natural amino acids; COSMO-RS Simulation; Activity coefficient and hydrogen bonding,DRILLING-FLUIDS; IONIC LIQUID; COSMO-RS; FILTRATION PROPERTIES; HIGH-PERFORMANCE; WATER; HYDRATE; BENTONITE; BEHAVIOR; METHANE,"In this paper, the destabilization inhibition potentials and mechanisms of Alanine, Arginine, and Proline on montmorillonite clay were investigated. A swelling test was done using an M4600 HPHT Linear swell meter at 1000 psi, 25 degrees C, and 2 wt% inhibitor solutions. Shear rates and temperatures in the range of 0.01 s(-1) to 1000 s(-1) and 25 degrees C - 50 degrees C, respectively, were applied on a high-precision Discovery Hybrid Rheometer to investigate the effect of the amino acids on the suspension's theology. Also, the inhibitors' neutralization and surface modification properties were determined via zeta potential, wettability alteration, and FTIR analyses using the nano zeta sizer, goniometer, and the spectrometer respectively. Furthermore, COSMO-RS was employed to study the hydrogen bonding interactions of amino acids and water. Upon completion, Proline displayed the best inhibition performance reducing the swelling of the montmorillonite by 22.5%, whiles KCl only showed a 17.8% reduction. Also, the rheological tests confirmed that the amino acids positively enhanced the base fluid properties. In addition, Proline, Alanine, and Arginine altered the surface of the clay mineral by 89%, 64%, and 38%, respectively, when compared to the base fluid. This made their clay surfaces less hydrophilic and thus, reduced the attraction between water molecules and the clay mineral. Furthermore, the simulation results showed that amino acids easily form hydrogen bonds with water, thus preventing high amounts of water from saturating the clay mineral, resulting in a significant reduction of swelling in the clay during fracturing. The superior performance of amino acids especially Proline in stabilizing montmorillonite clays, over KCl, makes them suitable candidates to consider in the development of low cost, and eco-friendly clay stabilizers.",6,6,5
Natural Fractures,Wettability Alteration,"Andersen, Pal O.; Ahmed, Sameer",Simulation study of wettability alteration enhanced oil recovery during co-current spontaneous imbibition,Co-current spontaneous imbibition; Enhanced oil recovery; Wettability alteration; Molecular diffusion; Adsorption,COUNTER-CURRENT IMBIBITION; MIXTURE THEORY APPROACH; POROUS-MEDIA; WATER; MODEL; MECHANISM; VISCOSITY; WET; DYNAMICS; DRAINAGE,"Naturally fractured reservoirs are highly dependent on capillary forces to recover hydrocarbons during water injection. Water can spontaneously imbibe and expel oil if positive capillary forces exist; purely counter-current if all sides of the matrix blocks are exposed to water; and predominantly co-current with some counter-current production if the blocks are exposed to water and oil simultaneously. The latter is referred to as a co-current spontaneous imbibition (SI) setup. Wettability alteration (WA) has been identified as a key mechanism to improve oil recovery from naturally fractured reservoirs, however almost all experimental and modeling studies on WA during SI have focused on counter-current SI. Our review indicates limited systematic experimental work on co-current SI using nonzero initial saturation, mixed wettability or WA processes and This modeling study will investigate enhanced oil recovery by WA during co-current SI where a brine with a general WA component imbibes and causes the system to become more water-wet. We model a 1D oil-saturated core exposed to water at one end (inlet) and oil at the other end (outlet), thus facilitating co-current SI. The core is initially preferentially (not strongly) oil-wet with low SI potential. The component is both transported by the imbibing brine and diffuses towards the imbibition front. Adsorption of the component is assumed to improve the water-wetness of the porous medium and hence the SI potential. The model is parameterized using consistent capillary pressure and relative permeabilities from previous history matching of brine-dependent porous disc experiments. The behavior of co-current SI at mixed-wet state is examined and compared to that of literature strongly water-wet behavior. Both secondary and tertiary enhanced recovery by SI with WA component is then considered in the simulations. Important parameters such as mobility ratio (as via oil viscosity), capillary back pressure, WA component concentration, adsorption and time of WA component exposure are investigated. Under mixed-wet conditions, favorable and unfavorable mobility ratios do not limit oil production as can be the case for strongly wetted media at unfavorable mobility ratio. This is due to oil preserving mobility at all obtained saturations. A third or more of the total production was counter-current, which is high compared to strongly wetted media. It was shown that half the oil could be produced counter-currently as an upper limit. High oil mobility is preserved in the twophase region near the inlet and was found to ensure a high minimum fraction of countercurrent production. Twice as much of the incremental oil from WA was produced counter-currently as co-currently, explained by increased oil relative permeability in the WA affected inlet region. Sensitivity analysis revealed that an opposite shift would reduce the incremental counter-current production despite raised local capillary forces. Capillary back pressure resists oil production at the inlet without limiting water from imbibing. As a result, capillary back pressure had significant impact on co-current SI simulations with fixed and changing wettability. The trends discovered in this study, both for mixed-wet and wettability alternating systems, are hoped to inspire future experimental measurements.",5,5,2
Reservoir Quality,Rock Typing,"Lin, Miruo; Xi, Kelai; Cao, Yingchang; Liu, Quyang; Zhang, Zehan; Li, Ke","Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin",Shale oil reservoir; Petrographic features; Diagenetic alteration; Heterogeneity of reservoirs in shale strata,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; BOHAI BAY BASIN; RESERVOIR QUALITY; SANDSTONE RESERVOIRS; JIYANG DEPRESSION; SEDIMENTARY-ROCKS; JIMSAR SAG; LITHOFACIES CLASSIFICATION; ORGANIC GEOCHEMISTRY,"Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation.",5,5,10
Reservoir Quality,Rock Typing,"Shalaby, Mohamed Ragab","Petrophysical characteristics and hydraulic flow units of reservoir rocks: Case study from the Khatatba Formation, Qasr field, North Western Desert, Egypt",Reservoir characterization; Porosity; Permeability; Flow zone indicator; Winland r35; Reservoir quality index,PORE-SIZE DISTRIBUTION; JURASSIC SOURCE ROCKS; SHOUSHAN BASIN; SANDSTONE RESERVOIR; OIL-FIELD; GEOCHEMICAL CHARACTERIZATION; DEPOSITIONAL ENVIRONMENT; NUBIA SANDSTONE; TARANAKI BASIN; SHUSHAN BASIN,"The reservoir characteristics and hydraulic flow unit properties of the Khatatba Formation in Qasr field, Western Desert, Egypt have been investigated. Several methods have been used to analyze and characterize the sandstone of the Khatatba Formation. Petrophysical parameters related to porosity and permeability have been considered together with some other important factors: reservoir quality index (RQI), flow zone indicator (FZI), and normalized porosity index (NPI). A study of the petrographic descriptions has been included to interpret the rock types and lithofacies. Moreover, displacement pressure, threshold pressure, and the Winland equation are used to understand and explain the pore geometry and pore throat diameter. Analysis of samples from three different wells indicates that this sandstone can be classified into three rock types with distinctive lithotypes and hydraulic flow units. Rock type I (flow unit-1), representing the data from the Qasr-3 well, possesses the best storage capacity with good porosity and very good permeability (max. value 14%, and 818 mD respectively). Coarse to very coarse grain sandstone is observed while all pore spaces are interpreted as megapores. The highest flow zone indicator has an average value of 15 mu m and an average reservoir quality index of 2.08 mu m. The capillary pressure and saturation curves show the lowest displacement pressure with a maximum pore throat diameter (Winland r35) of 34 mu m, which affirm the presence of mega pores with higher permeability routes. Rock type II (flow unit-2), representing the data from the Qasr-5 well, is the second-best for storage capacity with average FZI and RQI of 6.3 and 1.07 mu m, respectively. It is a medium-grained sandstone with very good porosity (max 16.45%), while the permeability is lower than that of type I (max 448 mD). The pore spaces are interpreted as a combination of megapores and macropores, while the max. pore throat radius (r35) is recorded as 17 mu m. Data from the Qasr-6 well reveal that this is the poorest quality reservoir (flow unit-3). It comprises fine-grained sandstone with the lowest average porosity and permeability of 9% and 16 mD, respectively. The average FZI and RQI also show lower values of 2.9 and 0.31 mu m. Most of the pore spaces have been categorized as macropores with some (a few percent) being categorized as mesopores so that the r35 value shows the lowest of 5.6 mu m. It is concluded that the grain size and lithotypes of the sandstone affect the reservoir quality and control the petrophysical properties and hydrocarbon potential.",5,5,3
Reservoir Quality,Rock Typing,"Zahmatkesh, Iman; Kadkhodaie, Ali; Soleimani, Bahman; Azarpour, Moslem","Integration of well log-derived facies and 3D seismic attributes for seismic facies mapping: A case study from mansuri oil field, SW Iran",Seismic facies analysis; Seismic attributes; Well log facies; Reservoir quality; Asmari reservoir; Supervised neural network,MULTIATTRIBUTE TRANSFORMS; GAS-FIELD; CLASSIFICATION; RESERVOIR; CARBONATE; MACHINE; IDENTIFICATION; PARAMETERS; EXAMPLE; PART,"The recognition and mapping of rock facies is a pivotal step in reliable reservoir characterization and planning development operations. The present study aimed to present a practical workflow by integrating threedimensional (3D) seismic attributes and well-log facies analysis to determine the spatial distribution of electrofacies rock types of the Oligo-Miocene Asmari reservoir in Mansuri oilfield located in the southwestern part of Iran. The workflow begins with integrating well logs, core data, and geological information from the selected ?key wells? to build an electrofacies model, which could help reservoir facies to be classified and estimated in the cored and uncored wells, respectively. In addition, a group of 3D seismic attribute volumes derived from amplitude, frequency, and time characteristics of the post-stacked 3D seismic data were identified to specify the heterogeneity of the vertical and lateral rock facies within the reservoir. Additionally, the seismic attributes were analyzed using unsupervised and supervised learning techniques to identify seismic facies. The extraction of the seismic facies at multiple-well locations within the 3D classified volumes demonstrated that the supervised neural network learning method, as compared to the unsupervised approach, could more accurately estimate the desired seismic facies. The results of the ultimate rock facies maps of different vertical slices in the Asmari reservoir indicated that electrofacies with good reservoir quality were best developed on the top of the reservoir, mostly with NW-SE elongation at the crest line of the structure. The applied workflow allowed the localities of the buried sand channels to be identified and mapped. Accordingly, seismic facies mapping shed light on the spatial heterogeneity and quality of the reservoir, which could be used to guide the development drilling for optimal recovering of the unswept hydrocarbons.",4,4,3
Reservoir Quality,Rock Typing,"Jiu, Bo; Huang, Wenhui; Mu, Nana; Li, Yuan","Types and controlling factors of ordovician paleokarst carbonate reservoirs in the southeastern Ordos Basin, China",Karstification; Carbonate rock; Reservoir; Dissolution; Diagenesis,THERMOCHEMICAL SULFATE REDUCTION; SICHUAN BASIN; MAJIAGOU FORMATION; DIAGENETIC ALTERATION; NATURAL-GAS; TARIM BASIN; OIL-FIELD; ORIGIN; KARST; QUALITY,"With continuous improvements in oil and gas exploration technology and the increasing demand for oil and gas resources, the focus of oil and gas exploration has shifted from deep to ultradeep reservoirs. This study targeted the carbonate karst reservoirs of the Ordovician Ma5 Member in the southeastern Ordos Basin. Based on the analysis of cores, thin sections, cathodoluminescence, scanning electron microscopy (SEM), carbon and oxygen isotopes and trace elements, we discuss the development characteristics, types and influencing factors of paleokarst reservoirs. Petrology and geochemistry show three kinds of karstification in the study area: quasicontemporaneous karst, epigenetic karst and deep burial karst. The quasi-contemporaneous and epigenetic paleokarsts were mainly controlled by freshwater, where the soluble components of the strata were preferentially dissolved. The deep burial karstification was dominated by the reaction product H2S from thermochemical sulfate reduction (TSR) between sulfate minerals and organic matter, during which hydrothermal fluid provided the required activation energy for the reaction. The observations of cores and thin sections show that the paleokarst reservoirs are composed of different kinds of dissolution pores and fractures and cemented by multistage calcite and siliceous cements. Influenced by freshwater leaching and hydrothermal fluid, the three paleokarst processes led to negative anomalies in delta O-18 and delta C-13, while the low delta Ce, low delta Eu and rare earth element (REE) partition modes confirm that the intensity of freshwater leaching was stronger than that of hydrothermal fluid. The controlling factors of the paleokarst reservoirs included acidic fluids, paleogeomorphology and paleostructure in each diagenetic stage. According to the structural background and core characteristics, we establish a development model and spatial evolution model of the paleokarst reservoirs in the southeastern Ordos Basin.",3,3,11
Reservoir Quality,Rock Typing,"Wang, Feng; Chen, Rong; Yu, Wei; Tian, Jingchun; Liang, Xiaowei; Tan, Xianfeng; Gong, Li","Characteristics of lacustrine deepwater fine-grained lithofacies and source-reservoir combination of tight oil in the triassic chang 7 member in Ordos Basin, China",Source-reservoir combination; Tight oil; Lithofacies characteristics; Fine-grained sediment; Ordos basin; Chang 7 member,YANCHANG FORMATION; TURBIDITY CURRENTS; OUTCROP ANALYSIS; VOLCANIC ASH; SANDSTONES; FACIES; DEPOSITS; ROCKS; AREA; QUALITY,"The lithofacies characteristics of fine sedimentary rocks affect the hydrocarbon generation capacity and reservoir performance of tight oil and are closely related to the sedimentary environment. On the basis of field outcrops and core observations, combined with logging data, thin section identification, grain size analysis, organic carbon analysis and physical property tests, the fine sedimentary facies of the Chang 7 Member in the Ordos Basin are studied. Nine lithofacies types are identified in the study area, including planar and trough crossbedding sandstone facies (Spt), massive bedding sandstone facies (Sm), slump deformation fine sandstone facies (Ssd), sand-mud interbedded facies (Sb), rippled siltstones facies (Fr), horizontal bedding mudstone facies (Mh), massive bedding mudstone facies (Mm), horizontal bedding shale facies (S) and tuff facies (T). Lithofacies types Spt, Ssd, Fr are developed in the gentle slope belt in the northeastern study area, which is a delta frontsemi-deep lake sedimentary environment and mainly contains underwater distributary channel and estuary dam sedimentary microfacies types. Lithofacies types such as Sm, Sb, Mh and T are developed in the southwestern steep slope zone of the study area, which is a channel-type gravity flow sedimentary environment, and sedimentary microfacies types such as near-source channels, far-source channels and leading-edge dolomites are developed. In the vertical direction, during the Chang 73 sedimentation period, the lake surface area and water depth reached their maxima, and S and Mh lithofacies developed, which were conducive to the formation of high-quality hydrocarbon source rocks for tight oil. During the Chang 72-Chang 71 sedimentation period, the lake basin shrank, and the reducibility of the water body weakened. The delta front sand body composed of Spt lithofacies in the northeast and the sandy clastic flow sand body composed of Sm in the southwest constitute the main tight oil reservoirs. High-quality hydrocarbon-generating lithofacies and favourable reservoir lithofacies are spatially superposed and developed, forming two source-reservoir combinations in the Chang 7 tight oil source-reservoir formation and near source-reservoir formation.",3,3,5
Reservoir Quality,Rock Typing,"Xi, Kelai; Cao, Yingchang; Haile, Beyene Girma; Zhu, Ning; Liu, Keyu; Wu, Songtao; Hellevang, Helge","Diagenetic variations with respect to sediment composition and paleo-fluids evolution in conglomerate reservoirs: A case study of the Triassic Baikouquan Formation in Mahu Sag, Junggar Basin, Northwestern China",Diagenetic variations; Sediment composition; Paleo-fluids evolution; Conglomerate reservoir; Mahu sag,TIGHT OIL SANDSTONES; GEOCHEMICAL CONSTRAINTS; JURASSIC SANDSTONES; YANCHANG FORMATION; MASS-TRANSFER; ORDOS BASIN; QUALITY; PREDICTION; POROSITY; SMECTITE,"Understanding reservoir heterogeneity and associated diagenesis, have a paramount importance for efficient petroleum exploration and development strategies. Diagenetic variations and factors that control these processes have, therefore, been investigated in this study using petrographic and geochemical methods, including cath-odoluminescence, scanning electron microscopy, x-ray fluorescence, electron probe microanalyses and stable isotope analysis. Mechanical compaction and chemical diagenesis trends have obviously varied as a function of rock types and geological locations. The conglomerate reservoirs with high content of tuffaceous matrix and characterized by poor sorting showed stronger compaction. The tuffaceous matrix displays a large degree of dissolution during the progressive burial diagenesis due to its thermodynamic instability. The tuffaceous matrix in Na-rich conglomerate reservoir rocks mainly transformed into analcite, while it transformed into illite in K-rich conglomerate reservoir rocks. In most conglomerate reservoirs far away from deep-rooted faults, calcite cements are indicated to have been sourced from the decarboxylation of organic matter in the interbedded mudstones. Carbonate cements in conglomerate reservoirs near the deep-rooted faults possibly formed from hydrothermal fluids or thermochemical oxidation of pre-existing methane accumulations. This study can serve us an excellent example for the control of sediment composition and paleo-fluid evolution on diagenetic variations in fan-delta conglomerate reservoirs.",3,3,4
Reservoir Quality,Rock Typing,"Kolah-kaj, Parvin; Kord, Shahin; Soleymanzadeh, Aboozar","The effect of pressure on electrical rock typing, formation resistivity factor, and cementation factor",Electrical quality index (EQI); Electrical rock typing; Cementation factor; Fluid saturation,OVERBURDEN PRESSURE; FZI-ASTERISK; FLOW UNITS; POROSITY; SATURATION,"As a key parameter in the calculation of fluid saturation, cementation factor (m) is routinely approximated using the Archie's equation. Numerous correlations and several techniques have been proposed to determine cementation factor, one of which is electrical rock typing. Besides hydraulic rock typing, which plays a significant role in modeling and numerical simulation of reservoirs, electrical rock typing refers to categorizing rocks into distinct groups based on similarity in electrical properties of the rocks. The current study focuses on the effective pressure impact on electrical rock typing. In addition, the effect of change in effective pressure due to production on petrophysical properties, and consequently rock capacity for transmitting electricity was studied. In this paper, 39 limestone samples were studied to analyze the effect of pressure on porosity (0), formation resistivity factor (F), and m. Performance of the Archie's equation under different effective pressures was further examined. Considering the fact that an increase in effective pressure causes pore and throat deformation, the pressure impact on the rock quality for transmitting electricity was scrutinized. Then, the influence of effective pressure on electrical rock typing was studied. It was discovered that due to an increase in effective pressure, F and m increase while 0 decreases. The rock quality for transmitting electricity and the effective pressure were found to be correlated through a second-order polynomial equation. It was further concluded that the electrical rock typing was affected by the changes in electrical efficiency, and the number of electrical rock types and the presence of samples in them were influenced by variations of the effective pressure. This was a noticeable point because different rock types require the adoption of different correlations for determining the parameters of the Archie's equation; therefore, realizing that each sample belongs to which rock type is essential. The findings of this study contributed to a better understanding of the impact of the effective pressure on Archie's parameters and petrophysical properties, leading to a method for determining fluid saturation under different effective pressures during the reservoir lifespan.",3,3,3
Reservoir Quality,Facies,"Kassem, Ahmed A.; Hussein, Walid S.; Radwan, Ahmed E.; Anani, Nasr; Abioui, Mohamed; Jain, Sreepat; Shehata, Amer A.",Petrographic and diagenetic study of siliciclastic Jurassic sediments from the northeastern margin of Africa: Implication for reservoir quality,Northeastern Egypt; Lithofacies; Petrography; Reservoir quality; Diagenesis,,"Northeastern Egypt is one of the most important exposures in the Middle East and North Africa to study Jurassic facies. The present study analyzes 130 thin sections from a subsurface well (Well X) in the northern Gulf of Suez, and from two surface sections at Gebel Maghara (north Sinai) and Khashm Elgalala (North Eastern Desert), Egypt for petrographic and lithofacies analyses. In the present study, detailed petrographic analysis is used as a tool to better understand the diagenetic history of the Early to Late Jurassic siliciclastic sediments; the identified diagenetic elements are inferred concerning the reservoir quality. For this, sidewall cores, scanning electron microscopy and thin sections are used to detail detrital and authigenic mineralogy; these are then used to infer the depositional framework, factors controlling reservoir characteristics, and the operating diagenetic processes. The inferred depositional paleoenvironment is a prograding and retrograding linear siliciclastic shoreline within a shallow marine carbonate platform with coal swamps and occasional cross-cutting rivers. Diagenesis, petrographical characteristics and depositional conditions are the main factors controlling continental and marine reservoir architecture. The diagenetic processes affecting siliciclastic sedimentation are near the surface, shallow to intermediate burial, and deep burial cycles with different pore fluid filling at each stage. The siliciclastic sediments have been categorized into seven depositional lithofacies - calcareous claystone (S1a), carbonaceous claystone (S1b), siltstone (S2), planar and trough cross-bedded sandstone (S3), coarse, well rounded, large scale trough cross-bedded sandstone (S4), ooid sandstone (S5) and coal (C). Grain compaction, various phases of syntaxial quartz overgrowth, carbonate cementation and replacement, creation of dissolution porosity, and clay authigenesis are the most important diagenetic processes that have affected the siliciclastic continental and marine sediments. Many different diagenetic events, both destructive and constructive, have modified porosity. The destructive events include compaction and cementation (of silica, kaolinite, ferroan dolomite, Illite, and anhydride). The constructive events include silica cementation, feldspar dissolution, and ferroan dolomite dissolution. Additionally, present data also suggest that the continental sandstones have excellent reservoir quality whereas the marine sandstones have good to very good reservoir potential. Despite the excellent reservoir quality of the continental sandstone lithofacies, the effective stratigraphic seal is leaking. The interbedded calcareous and carbonaceous claystone lithofacies may provide an excellent stratigraphic seal for these siliciclastic reservoirs. Based on these analyses, a model is proposed that can be used as a template for subsurface Jurassic reservoir characterization and reservoir discrimination.",21,21,7
Reservoir Quality,Facies,"Selim, S. S.; Wafdy, R.; Abu Khadrah, A. M.","Sedimentological analysis and reservoir quality of the early Cenomanian transgressive sandstones, northern Western desert, Egypt",Facies analysis; Bay-head delta; Reservoir heterogeneity; Reservoir quality; Transgressive sandstones; Shushan basin; Northern western desert of Egypt,INCLINED HETEROLITHIC STRATIFICATION; RESOLUTION SEQUENCE STRATIGRAPHY; CRETACEOUS MCMURRAY FORMATION; BAHARIYA FORMATION; SHORELINE TRAJECTORIES; DEPOSITIONAL SYSTEMS; FACIES ARCHITECTURE; ESTUARINE DEPOSITS; SEDIMENTARY MODEL; SHALLOW-MARINE,"Depicting depositional models of transgressive sandstone reservoirs is challenging due to their internal complexity and limited case studies. This study presents an example for transgressive sandstone reservoirs from the Bahariya Formation at Hayat-Yasser oil field, Shushan Basin (northern Western Desert, Egypt). The upper part of the Bahariya Formation accumulated in an estuarine setting as a consequence of a successive sea level rise. Detailed reservoir characterization, employing sequence stratigraphic and sedimentological approaches, revealed that the studied reservoir consists of a mixed siliciclastic-carbonate transgressive estuarine-shelf succession. Four conventional core samples of this succession at Khalda ridge (Shushan Basin), permit the analysis of their sedimentology and internal architecture (mesoscopic heterogeneities) along correlation lines parallel or slightly oblique to depositional dip. The succession consists of six backstepping parasequence sets that record the overall shift from tidal-dominated to wave-dominated estuaries/bays. The transgressive component of the parasequences sets includes bay mudstones, flood-tidal deltas, and shoreface/barrier deposits; while the regressive component includes estuarine point bars, bay head deltas, and tidal deltas. The reservoir properties show significant variation according to the facies assemblages. The tidally-dominated estuarine channels show low net-togross, as it is characterized by lenticular sandstone bodies with several lateral and vertical baffles and barriers. On the other hand, the shoreface/barrier and tidal delta sandstones show high net-to-gross and consist of amalgamated sandstone bodies with little mud barriers or baffles. Petrographically, the upper Bahariya reservoir includes intergranular and secondary porosities. The microscopic heterogeneities are mainly due to the fine grain nature, poor sorting, presence of matrix, and continuous mud barriers or baffles. Destruction of porosity, affecting the reservoir quality, occurred by silica overgrowths, ferroan calcite, grain coating chlorite, and kaolinite cementation, as well as compaction. Feldspar dissolution is the main diagenetic process responsible for the formation of secondary porosity, enhancing the reservoir quality.",5,5,0
Reservoir Quality,Facies,"Mehrabi, Hamzeh; Bahrehvar, Mohammad; Rahimpour-Bonab, Hossain","Porosity evolution in sequence stratigraphic framework: a case from Cretaceous carbonate reservoir in the Persian Gulf, southern Iran",Micrite texture; Pore evolution; Paleoexposure; Dariyan Formation; Persian Gulf,PALAEO-EXPOSURE SURFACES; SHUAIBA FORMATION; DEZFUL EMBAYMENT; MICROPOROSITY; SYSTEMS; LIMESTONES; SANDSTONE; MICRITE; HISTORY; FACIES,"Dariyan Formation (Aptian) is one of the important hydrocarbon reservoirs in the Persian Gulf. In this reservoir, porosity is controlled by various depositional and diagenetic factors. This study integrates petrographic, geochemical, petmphysical and reservoir quality data to distinguish various pore types and their evolution in two fields selected from the SE and NW Persian Gulf. Primary (depositional) and secondary (diagenetic) pore types are differentiated using the results of macroscopic (core) and microscopic (thin section and SEM) petrographic studies. Pore size distribution and reservoir importance are evaluated by MICP and porosity-permeability measurements on core-plug samples. Macroscopic pores are formed within the grain-dominated and dissolved mud-dominated facies that are located in the RST of third-order sequences, especially within the lower carbonate unit. Micropores are recorded in mud-dominated facies of middle to outer ramp settings with minor effects of meteoric dissolution. Accordingly, evolution in an open diagenetic system with high water/rock ratio is proposed for grain-supported facies, and a closed diagenetic system for mud-dominated intervals. There are close relationships between micrite micro-textures (MTCs) and reservoir properties of mud-dominated facies. A dynamic pore evolution model is presented for the Dariyan Formation that integrates all depositional and diagenetic features in sequence stratigraphic framework. This model can be used for ongoing reservoir studies of this formation in hydrocarbon fields of the Persian Gulf.",5,4,0
Reservoir Quality,Facies,"Kakemem, Umid; Jafarian, Arman; Husinec, Antun; Adabi, Mohammad Hossein; Mahmoudi, Ayoub","Facies, sequence framework, and reservoir quality along a Triassic carbonate ramp: Kangan Formation, South Pars Field, Persian Gulf Superbasin",Kangan Formation; Khuff Formation; Homoclinal ramp; Carbonate facies; Reservoir quality; Persian Gulf Superbasin; South Pars Field,UPPER DALAN FORMATION; GAS-FIELD; DEPOSITIONAL ENVIRONMENT; KHUFF SEQUENCES; ALGAL MATS; DOLOMITIZATION; STRATIGRAPHY; PLATFORM; BASIN; DIAGENESIS,"The Lower Triassic Kangan Formation of the Persian Gulf Superbasin forms one of the largest reservoirs in the South Pars/North Field, the world's largest gas field. The upper Khuff-equivalent, gas-hosting carbonate-evaporite succession was formed on a gently-sloping, homoclinal carbonate ramp in a warm, tropical aragonite sea under a hot-and-arid greenhouse climate. This study explores the impact of vertical variations in depositional facies and diagenetic features on the reservoir quality to improve the prediction of the subsurface facies and hydraulic flow unit distribution. Detailed core logging and petrographic analysis resulted in the recognition of twelve distinct carbonate-evaporite facies that are grouped into four major facies associations, from shallowest to deepest: supratidal to restricted subtidal, lagoon, carbonate shoal, and shallow mid-ramp. The facies associations are stacked into two long-term sequences K52 (58 m) and KS1 (77 m) bounded by anhydrites and/or unconformities; three higher frequency sequences (KSla, KSlb, and KSlc) can be identified within the KS1. Based on the petrophysical properties, sedimentary facies characteristics and their diagenetic modifications, five hydraulic flow units (HFUs) are identified, with the best porosity-permeability values and flow- and storage capacities in the late transgressive (TSTs) and the earliest highstand systems tracts (HSTs) of the two long-term sequences. The reservoir quality and the distribution of hydraulic flow units are a product of interactions between primary mineralogy, depositional facies and their stacking, and the early- and late-diagenetic alterations. The reservoir quality decreases in landward direction, being the lowest in the mud-supported textures of the lagoon and supratidal to restricted subtidal facies associations. The seaward improvement in reservoir quality reflects a change to grain-supported textures that formed along the tide-and wave-agitated ooid-bioclastic shoals, whereas the best reservoir quality characterizes the shallow mid-ramp open-marine facies association, where secondary porosity was improved by dissolution and dolomitization. Both the early and late diagenetic dolomitization overall improved the reservoir quality, with the dolomitization pathways controlled by the porosity and permeability heterogeneity in the original depositional facies. The results may be useful in reservoir modeling, recognition of the productive zones, and the further development of the South Pars/North Dome Field.",4,4,4
Reservoir Quality,Facies,"Zahmatkesh, Iman; Kadkhodaie, Ali; Soleimani, Bahman; Azarpour, Moslem","Integration of well log-derived facies and 3D seismic attributes for seismic facies mapping: A case study from mansuri oil field, SW Iran",Seismic facies analysis; Seismic attributes; Well log facies; Reservoir quality; Asmari reservoir; Supervised neural network,MULTIATTRIBUTE TRANSFORMS; GAS-FIELD; CLASSIFICATION; RESERVOIR; CARBONATE; MACHINE; IDENTIFICATION; PARAMETERS; EXAMPLE; PART,"The recognition and mapping of rock facies is a pivotal step in reliable reservoir characterization and planning development operations. The present study aimed to present a practical workflow by integrating threedimensional (3D) seismic attributes and well-log facies analysis to determine the spatial distribution of electrofacies rock types of the Oligo-Miocene Asmari reservoir in Mansuri oilfield located in the southwestern part of Iran. The workflow begins with integrating well logs, core data, and geological information from the selected ?key wells? to build an electrofacies model, which could help reservoir facies to be classified and estimated in the cored and uncored wells, respectively. In addition, a group of 3D seismic attribute volumes derived from amplitude, frequency, and time characteristics of the post-stacked 3D seismic data were identified to specify the heterogeneity of the vertical and lateral rock facies within the reservoir. Additionally, the seismic attributes were analyzed using unsupervised and supervised learning techniques to identify seismic facies. The extraction of the seismic facies at multiple-well locations within the 3D classified volumes demonstrated that the supervised neural network learning method, as compared to the unsupervised approach, could more accurately estimate the desired seismic facies. The results of the ultimate rock facies maps of different vertical slices in the Asmari reservoir indicated that electrofacies with good reservoir quality were best developed on the top of the reservoir, mostly with NW-SE elongation at the crest line of the structure. The applied workflow allowed the localities of the buried sand channels to be identified and mapped. Accordingly, seismic facies mapping shed light on the spatial heterogeneity and quality of the reservoir, which could be used to guide the development drilling for optimal recovering of the unswept hydrocarbons.",4,4,3
Reservoir Quality,Facies,"Yang, Peng; Zhang, Likuan; Liu, Keyu; Cao, Binfeng; Gao, Jianlei; Qiu, Guiqiang","Diagenetic history and reservoir evolution of tight sandstones in the second member of the Upper Triassic Xujiahe Formation, western Sichuan Basin, China",Tight sandstone; Diagenesis; Lithofacies; Reservoir quality; Xujiahe formation; Western sichuan basin,ANOMALOUSLY HIGH-POROSITY; GRAIN-COATING CHLORITE; HIGH-QUALITY RESERVOIR; QUARTZ CEMENTATION; 4TH MEMBER; COMPACTION PROCESSES; DEPOSITIONAL FACIES; RELATIVE IMPORTANCE; SEDIMENTARY BASINS; FORELAND BASIN,"The second member of the Upper Triassic Xujiahe Formation is an important target for tight gas exploration in the western Sichuan Basin. The diagenetic history and reservoir evolution were investigated using integrated analyses of petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), cathodoluminescence (CL), fluid inclusion microthermometry and stable carbon and oxygen isotopes. The sandstones consist mainly of litharenites, sublitharenites and feldsparthic litharenites with fine-to medium-sand grain sizes, moderate to good sorting and subangular to subrounded roundness. The reservoir properties of the sandstones are generally poor with low porosity and matrix permeability, small pore-throat radii, and high displacement pressure. Eodiagenesis is composed mainly of mechanical compaction, precipitation of siderite, stage-I quartz overgrowths, chlorite, calcite and ferroan calcite. Mesodiagenesis consists mainly of mechanical and chemical compaction, calcite and ferroan calcite precipitation, stage-II and stage-III quartz cementation, feldspar dissolution and precipitation of illite, dolomite and ankerite. Three types of sandstone lithofacies are defined according to sandstone textures and composition, diagenetic minerals, grain sizes, sorting and pore types: lithofacies I, II and III. Compaction appears to reduce the reservoir quality more significantly compared to cementation. Authigenic chlorite coats were constructive in preserving primary porosity, while carbonate cementation decreased reservoir quality. Diagenetic evolution pathways and reservoir quality prediction models for the Upper Triassic Xujiahe Formation sandstones have been proposed to shed light on the different reservoir quality evolution patterns of various sandstone lithofacies. Lithofacies I - medium and coarse-grained sandstones characterized by extensive chlorite coating, feldspar dissolution and a low content of clay matrix and cement, appears to have the best reservoir properties and may serve as a high-quality reservoir facies in these tight sandstone reservoirs.",3,3,7
Reservoir Quality,Facies,"Wang, Feng; Chen, Rong; Yu, Wei; Tian, Jingchun; Liang, Xiaowei; Tan, Xianfeng; Gong, Li","Characteristics of lacustrine deepwater fine-grained lithofacies and source-reservoir combination of tight oil in the triassic chang 7 member in Ordos Basin, China",Source-reservoir combination; Tight oil; Lithofacies characteristics; Fine-grained sediment; Ordos basin; Chang 7 member,YANCHANG FORMATION; TURBIDITY CURRENTS; OUTCROP ANALYSIS; VOLCANIC ASH; SANDSTONES; FACIES; DEPOSITS; ROCKS; AREA; QUALITY,"The lithofacies characteristics of fine sedimentary rocks affect the hydrocarbon generation capacity and reservoir performance of tight oil and are closely related to the sedimentary environment. On the basis of field outcrops and core observations, combined with logging data, thin section identification, grain size analysis, organic carbon analysis and physical property tests, the fine sedimentary facies of the Chang 7 Member in the Ordos Basin are studied. Nine lithofacies types are identified in the study area, including planar and trough crossbedding sandstone facies (Spt), massive bedding sandstone facies (Sm), slump deformation fine sandstone facies (Ssd), sand-mud interbedded facies (Sb), rippled siltstones facies (Fr), horizontal bedding mudstone facies (Mh), massive bedding mudstone facies (Mm), horizontal bedding shale facies (S) and tuff facies (T). Lithofacies types Spt, Ssd, Fr are developed in the gentle slope belt in the northeastern study area, which is a delta frontsemi-deep lake sedimentary environment and mainly contains underwater distributary channel and estuary dam sedimentary microfacies types. Lithofacies types such as Sm, Sb, Mh and T are developed in the southwestern steep slope zone of the study area, which is a channel-type gravity flow sedimentary environment, and sedimentary microfacies types such as near-source channels, far-source channels and leading-edge dolomites are developed. In the vertical direction, during the Chang 73 sedimentation period, the lake surface area and water depth reached their maxima, and S and Mh lithofacies developed, which were conducive to the formation of high-quality hydrocarbon source rocks for tight oil. During the Chang 72-Chang 71 sedimentation period, the lake basin shrank, and the reducibility of the water body weakened. The delta front sand body composed of Spt lithofacies in the northeast and the sandy clastic flow sand body composed of Sm in the southwest constitute the main tight oil reservoirs. High-quality hydrocarbon-generating lithofacies and favourable reservoir lithofacies are spatially superposed and developed, forming two source-reservoir combinations in the Chang 7 tight oil source-reservoir formation and near source-reservoir formation.",3,3,5
Reservoir Quality,Results Show,"Zeng, Fang; Dong, Chunmei; Lin, Chengyan; Wu, Yuqi; Tian, Shansi; Zhang, Xianguo; Lin, Jianli","Analyzing the effects of multi-scale pore systems on reservoir Properties-A case study on Xihu Depression, East China Sea Shelf Basin, China",Pore structure; Multi-scale pores; Contribution of pore throats to permeability; Reservoir properties; Controlling factors,LOW-PERMEABILITY RESERVOIRS; TIGHT GAS SANDSTONE; OLIGOCENE HUAGANG FORMATION; BOHAI BAY BASIN; ORDOS BASIN; FRACTAL ANALYSIS; OIL-RESERVOIRS; YANCHANG FORMATION; SCALE; NMR,"Determining the distribution and properties of multi-scale pores and the effect of these pores on reservoir properties is very significant for the analysis of the factors controlling pore structures and reservoirs quality. In this study, mercury injection porosimetry (MIP), field-emission scanning electron microscopy analysis (FE-SEM), and low-field nuclear magnetic resonance (NMR) experiments were conducted on the seven sandstone samples from Xihu Sag of the East China Sea Shelf Basin (ECSSB). The result shows that the MIP data were consistent with the other two methods so that MIP data can be used to classify pore sizes. By combining the experiment results with fractal theory, the pore size distribution can be divided into five groups: I-micro-pores, II-micro-pores, small pores, medium pores, and macro-pores. Considering the importance of pore throats size to the reservoir performance, the average throat based on the contribution of throats to permeability (D) was determined and taken as average pore throat size. Moreover, the proportions of these pores/pore throats were determined, and the effects of these pores/pore throats on reservoir parameters (porosity (1:1)), permeability (K), and irreducible/bond water saturation (Swi)) were analyzed. The results show that medium pores (2.5-25 mu m) strongly influence 1:1) and Swi, and D is the major control on permeability. In addition, the relationships of types of pores, such as primary pores and mixed pores, to the medium pores and D were analyzed in order to clarify the impact of pore textures. The results imply that the concentration and sizes of the primary pores appear to the most important factors controlling the development of medium pores and D.",13,13,10
Reservoir Quality,Results Show,"Ye, Tao; Chen, Anqing; Niu, Chengming; Wang, Qing Bing","Structural, petrophysical and lithological characterization of crystalline bedrock buried-hill reservoirs: A case study of the southern jinzhou oilfield in offshore Bohai Bay Basin, north China",Crystalline bedrock; Reservoir characteristics; Vertical zoning; Controlling factors; Reservoir development pattern; Bohai baybasin,LU FAULT ZONE; BONGOR BASIN; BASEMENT; ACCUMULATION; EVOLUTION; SUBBASIN; GNEISS; AREA,"Crystalline bedrock has always been regarded as a restricted area for hydrocarbon exploration due to its large burial depth and deficiency of primary porous. In recent years, bedrock oil and gas have been explored in several basins across the world, while the characteristics and control factors of large-scale bedrock reservoirs have not been systematically studied. Taking South of Jinzhou oil field as an example, we clarified the reservoir characteristics based on the investigation of the cores, thin sections, physical property and well loggings, and discussed the controlling factors of high quality reservoir considering lithology, fault activity and the paleotopography. The results show that although primary porous are less developed in bedrocks, the tectonic fractures, weathering fractures, pores among crushing particles and corrosion holes developed along fractures constitute rich reservoir spaces in the study area, and the average porosity can reach 6.7%. Dioritic gneiss and granitic gneiss are easier to form reservoirs than diabase for higher felsic contents and more brittleness; reservoirs along the main faults zone with strong activity are thick; in addition, high position of the paleo-topography develops thicker reservoirs due to the release of the stress and the strong weathering. Under the coupling action of weathering and tectonic activity, there developed weathered clay zone, weathered glutenite zone, weathered fracture zone, structural fracture zone, structural breccia zone and tight zone from top to bottom vertically. The present study shows that although there is no primary porosity in bedrocks, large-scale and quality reservoirs could be formed for brittle bedrocks under the coupling effects of strong tectonic activities and weathering. This recognition is of great significance for bedrock hydrocarbon exploration in the basins of high exploration degree all over the world.",5,5,2
Reservoir Quality,Results Show,"Zhu, Linqi; Ma, Yongsheng; Zhang, Chaomo; Wu, Shiguo; Zhou, Xueqing",New parameters for charactering the gas-bearing properties of shale gas,Shale gas; Free gas; Adsorbed gas; Density; Hydrogen index; Adsorbed phase -free phase volume ratio,,"The hydrocarbons contained in shale pores are mainly free gas and adsorbed gas. Accurately evaluating the reservoir free phase density/hydrogen index and adsorbed phase density/hydrogen index can reflect the reservoir properties and assist in evaluating the reservoir parameters. We propose a method for calculating the free phase density/hydrogen index and adsorbed phase density/hydrogen index by using logging curves and choose the rock density and total organic carbon (TOC) content to evaluate the above parameters with high precision. Finally, we propose qualitative and quantitative application methods for the above parameters. Based on the parameters calculated by the free phase density/hydrogen index and adsorbed phase density/hydrogen index, when the free phase porosity and saturation are high, the adsorbed phase porosity and saturation are low, and the adsorbed phase-free phase volume ratio is low, the reservoir has the highest quality. The results show that the free phase density/hydrogen index and adsorbed phase density/hydrogen index can be accurately determined and evaluated, and the applications of this method are very meaningful. This study combines the advantages of predicting the physical characteristics of free gas and adsorbed gas and the gas-bearing properties of shale gas reservoirs.",4,4,5
Reservoir Quality,Results Show,"Fu, Chunkai; Liu, Ning",Rheology and stability of nanoparticle-stabilized CO2 foam under reservoir conditions,Nanoparticle; Apparent viscosity; Foam stability; CO2 foam,ENHANCED OIL-RECOVERY; POLYMER; SURFACTANTS; BEHAVIOR; FLUIDS,"This study investigates the rheology and stability of nanoparticle-stabilized CO2 foams under reservoir conditions (high temperature and high pressure) for fracturing applications. The effects of different parameters on foam apparent viscosity and foam stability were experimentally investigated including the effects of nanoparticle concentration, salinity, foam quality (Gamma), shear rate and temperature. The power law model was applied to calculate foam apparent viscosity owing to its pseudo-plastic behavior, and the changes of foam heights over time were used to evaluate foam stability. Results showed that the CO2 foam apparent viscosity featured a mountain-shaped curve versus F, with the peak apparent viscosity obtained at 70% foam quality. The increase of salinity (up to 11%) in the continuous phase improved both foam stability and rheology. Higher nanoparticle concentration could contribute to better foam stability, but there was a threshold concentration, above which the foam apparent viscosity remained stabilized. The CO2 foam stabilized by nanoparticles displayed a shear-thickening behavior as the experiment flow rate increased from 6 mL/min to 18 mL/min. Further studies showed that as the total flow rate increased, the CO2 foam became finer-textured with better stability. Elevated temperatures could undermine foam apparent viscosity and long-term stability. The results of this study could provide guidelines as to the design of foam fracturing systems for field applications.",4,4,4
Reservoir Quality,Results Show,"Blanes de Oliveira, Lucas Abreu; Carneiro, Cleyton de Carvalho",Synthetic geochemical well logs generation using ensemble machine learning techniques for the Brazilian pre-salt reservoirs,Neutron-induced spectroscopy; Gamma ray spectroscopy; Formation evaluation; Artificial intelligence,GAMMA-RAY SPECTROSCOPY; MINERALOGY,"Geochemical logs are an essential tool for hydrocarbon reservoir characterization. The rock composition given by these logs is useful for porosity calculation, stratigraphic modeling, diagenesis estimation, and well acidification. In reduced logging operations performed in carbonate reservoirs of the Brazilian pre-salt, the geochemical tool is no longer acquired, aiming at optimization and cost reduction. This research aims the development of synthetic geochemical logs using machine learning algorithms. The database includes 22 wells with complete logging acquisition, and the input logs are natural gamma-ray, gamma-ray spectroscopy, density, photoelectric factor, neutron porosity, nuclear magnetic resonance, and sonic. The chemical elements chosen as output are Al, Ca, Fe, Mg, Na, Si, S, and Ti. Five models based on machine learning are trained using 19 wells: Support-vector machine, Multilayer perceptron, Random Forest, AdaBoost, and XGBoost. AdaBoost represents the best algorithm because, in addition to showing the best results, it allowed for a more simplified preprocessing and hyperparameter tuning. The evaluation of the models applies R-2 and root mean squared error (RMSE) in validation data and cross-validation. Robust models are acquired for Al, Ca, Fe, Mg, Si, S, and Ti, with R-2 above 0.80. Na shows R-2 slightly above 0.70. All the models have RMSE between 10(-2) to 10(-4). The most important logs during training are density, photoelectric factor, K, Th, U, and neutron porosity. Synthetic geochemical logs created for three test wells show a good agreement with acquired logs, being able to reproduce general trends of the pre-salt formations. The machine learning model is capable of substituting the acquisition of geochemical logs with high confidence, representing cost reduction, and supplying engineers and geoscientists with quality data to be used in formation evaluation.",4,4,3
Reservoir Quality,Results Show,"Lamas, L. F.; Botechia, V. E.; Schiozer, D. J.; Rocha, M. L.; Delshad, M.",Application of polymer flooding in the revitalization of a mature heavy oil field,Polymer flooding; Mature fields; Reservoir management; Revitalization of fields; Reservoir simulation,,"Polymer flooding is a chemical enhanced oil recovery that aims to improve mobility control, by increasing the viscosity of injection brine and thus reducing the mobility ratio. Starting the polymer injection as early as possible brings the best economic results because it prevents the formation of viscous fingering and sweeps more efficiently the reservoir. It is possible, however, to obtain gains with polymer flooding even after massive waterfloods. In this work, three different model-based approaches are developed to revitalize mature oilfields and tested considering the use of water and polymer as injection fluid. These strategies were tested using a synthetic reservoir model based on data from an offshore field in Brazil. The reservoir is sandstone (average permeability = 1650mD, average porosity = 20%). The oleic phase is heavy viscous oil (similar to 70 cP, 14 degrees API). The first simulation approach considered a strategy based on a standard waterflood until its economic limit. For this case, the maximum net present value (NPV) was reached after 15 years of production with a recovery factor of 25%. The revitalization strategy of this field considers an abandonment status for all wells. To emulate the time necessary to install all new facilities, all wells were assumed to be closed for six months. The first approach consists simply of reopening the injectors by changing the injection fluid to an aqueous polymer solution. The second approach has an additional degree of freedom: it allows all wells to be converted from injectors to producers and vice-versa. Finally, the third approach consists of the addition of new wells. Equations for quality maps for placing injectors and producers are presented. Using these equations, new producers and injectors could be placed at the best locations to produce the remaining oil spots. All three approaches increased the oil recovery factor. The additional oil recovery and variations in NPV were higher for the polymer flooding when compared with the standard waterflood, ensuring a longer productive life. This significant increase in oil production means that, for the selected case, producers needed to be closed in the water flooding period, due to economic performance, leaving a significant amount of oil still in the reservoir. The methodologies presented in this paper are easy to apply and can allow mature fields to economically produce more oil. The conversion of old wells by changing from producers to injectors or vice-versa allows new and creative production strategies. This can be done in onshore and dry completed offshore fields demanding small budgets and intervention times. This paper shows that it is possible to increase both the recovery factor and net present value of fields in the later stages of production life.",3,3,4
Reservoir Quality,Ordos Basin,"Zeng, Fang; Dong, Chunmei; Lin, Chengyan; Wu, Yuqi; Tian, Shansi; Zhang, Xianguo; Lin, Jianli","Analyzing the effects of multi-scale pore systems on reservoir Properties-A case study on Xihu Depression, East China Sea Shelf Basin, China",Pore structure; Multi-scale pores; Contribution of pore throats to permeability; Reservoir properties; Controlling factors,LOW-PERMEABILITY RESERVOIRS; TIGHT GAS SANDSTONE; OLIGOCENE HUAGANG FORMATION; BOHAI BAY BASIN; ORDOS BASIN; FRACTAL ANALYSIS; OIL-RESERVOIRS; YANCHANG FORMATION; SCALE; NMR,"Determining the distribution and properties of multi-scale pores and the effect of these pores on reservoir properties is very significant for the analysis of the factors controlling pore structures and reservoirs quality. In this study, mercury injection porosimetry (MIP), field-emission scanning electron microscopy analysis (FE-SEM), and low-field nuclear magnetic resonance (NMR) experiments were conducted on the seven sandstone samples from Xihu Sag of the East China Sea Shelf Basin (ECSSB). The result shows that the MIP data were consistent with the other two methods so that MIP data can be used to classify pore sizes. By combining the experiment results with fractal theory, the pore size distribution can be divided into five groups: I-micro-pores, II-micro-pores, small pores, medium pores, and macro-pores. Considering the importance of pore throats size to the reservoir performance, the average throat based on the contribution of throats to permeability (D) was determined and taken as average pore throat size. Moreover, the proportions of these pores/pore throats were determined, and the effects of these pores/pore throats on reservoir parameters (porosity (1:1)), permeability (K), and irreducible/bond water saturation (Swi)) were analyzed. The results show that medium pores (2.5-25 mu m) strongly influence 1:1) and Swi, and D is the major control on permeability. In addition, the relationships of types of pores, such as primary pores and mixed pores, to the medium pores and D were analyzed in order to clarify the impact of pore textures. The results imply that the concentration and sizes of the primary pores appear to the most important factors controlling the development of medium pores and D.",13,13,10
Reservoir Quality,Ordos Basin,"Jiu, Bo; Huang, Wenhui; Mu, Nana; Li, Yuan","Types and controlling factors of ordovician paleokarst carbonate reservoirs in the southeastern Ordos Basin, China",Karstification; Carbonate rock; Reservoir; Dissolution; Diagenesis,THERMOCHEMICAL SULFATE REDUCTION; SICHUAN BASIN; MAJIAGOU FORMATION; DIAGENETIC ALTERATION; NATURAL-GAS; TARIM BASIN; OIL-FIELD; ORIGIN; KARST; QUALITY,"With continuous improvements in oil and gas exploration technology and the increasing demand for oil and gas resources, the focus of oil and gas exploration has shifted from deep to ultradeep reservoirs. This study targeted the carbonate karst reservoirs of the Ordovician Ma5 Member in the southeastern Ordos Basin. Based on the analysis of cores, thin sections, cathodoluminescence, scanning electron microscopy (SEM), carbon and oxygen isotopes and trace elements, we discuss the development characteristics, types and influencing factors of paleokarst reservoirs. Petrology and geochemistry show three kinds of karstification in the study area: quasicontemporaneous karst, epigenetic karst and deep burial karst. The quasi-contemporaneous and epigenetic paleokarsts were mainly controlled by freshwater, where the soluble components of the strata were preferentially dissolved. The deep burial karstification was dominated by the reaction product H2S from thermochemical sulfate reduction (TSR) between sulfate minerals and organic matter, during which hydrothermal fluid provided the required activation energy for the reaction. The observations of cores and thin sections show that the paleokarst reservoirs are composed of different kinds of dissolution pores and fractures and cemented by multistage calcite and siliceous cements. Influenced by freshwater leaching and hydrothermal fluid, the three paleokarst processes led to negative anomalies in delta O-18 and delta C-13, while the low delta Ce, low delta Eu and rare earth element (REE) partition modes confirm that the intensity of freshwater leaching was stronger than that of hydrothermal fluid. The controlling factors of the paleokarst reservoirs included acidic fluids, paleogeomorphology and paleostructure in each diagenetic stage. According to the structural background and core characteristics, we establish a development model and spatial evolution model of the paleokarst reservoirs in the southeastern Ordos Basin.",3,3,11
Reservoir Quality,Ordos Basin,"Wang, Feng; Chen, Rong; Yu, Wei; Tian, Jingchun; Liang, Xiaowei; Tan, Xianfeng; Gong, Li","Characteristics of lacustrine deepwater fine-grained lithofacies and source-reservoir combination of tight oil in the triassic chang 7 member in Ordos Basin, China",Source-reservoir combination; Tight oil; Lithofacies characteristics; Fine-grained sediment; Ordos basin; Chang 7 member,YANCHANG FORMATION; TURBIDITY CURRENTS; OUTCROP ANALYSIS; VOLCANIC ASH; SANDSTONES; FACIES; DEPOSITS; ROCKS; AREA; QUALITY,"The lithofacies characteristics of fine sedimentary rocks affect the hydrocarbon generation capacity and reservoir performance of tight oil and are closely related to the sedimentary environment. On the basis of field outcrops and core observations, combined with logging data, thin section identification, grain size analysis, organic carbon analysis and physical property tests, the fine sedimentary facies of the Chang 7 Member in the Ordos Basin are studied. Nine lithofacies types are identified in the study area, including planar and trough crossbedding sandstone facies (Spt), massive bedding sandstone facies (Sm), slump deformation fine sandstone facies (Ssd), sand-mud interbedded facies (Sb), rippled siltstones facies (Fr), horizontal bedding mudstone facies (Mh), massive bedding mudstone facies (Mm), horizontal bedding shale facies (S) and tuff facies (T). Lithofacies types Spt, Ssd, Fr are developed in the gentle slope belt in the northeastern study area, which is a delta frontsemi-deep lake sedimentary environment and mainly contains underwater distributary channel and estuary dam sedimentary microfacies types. Lithofacies types such as Sm, Sb, Mh and T are developed in the southwestern steep slope zone of the study area, which is a channel-type gravity flow sedimentary environment, and sedimentary microfacies types such as near-source channels, far-source channels and leading-edge dolomites are developed. In the vertical direction, during the Chang 73 sedimentation period, the lake surface area and water depth reached their maxima, and S and Mh lithofacies developed, which were conducive to the formation of high-quality hydrocarbon source rocks for tight oil. During the Chang 72-Chang 71 sedimentation period, the lake basin shrank, and the reducibility of the water body weakened. The delta front sand body composed of Spt lithofacies in the northeast and the sandy clastic flow sand body composed of Sm in the southwest constitute the main tight oil reservoirs. High-quality hydrocarbon-generating lithofacies and favourable reservoir lithofacies are spatially superposed and developed, forming two source-reservoir combinations in the Chang 7 tight oil source-reservoir formation and near source-reservoir formation.",3,3,5
Reservoir Quality,Ordos Basin,"Xi, Kelai; Cao, Yingchang; Haile, Beyene Girma; Zhu, Ning; Liu, Keyu; Wu, Songtao; Hellevang, Helge","Diagenetic variations with respect to sediment composition and paleo-fluids evolution in conglomerate reservoirs: A case study of the Triassic Baikouquan Formation in Mahu Sag, Junggar Basin, Northwestern China",Diagenetic variations; Sediment composition; Paleo-fluids evolution; Conglomerate reservoir; Mahu sag,TIGHT OIL SANDSTONES; GEOCHEMICAL CONSTRAINTS; JURASSIC SANDSTONES; YANCHANG FORMATION; MASS-TRANSFER; ORDOS BASIN; QUALITY; PREDICTION; POROSITY; SMECTITE,"Understanding reservoir heterogeneity and associated diagenesis, have a paramount importance for efficient petroleum exploration and development strategies. Diagenetic variations and factors that control these processes have, therefore, been investigated in this study using petrographic and geochemical methods, including cath-odoluminescence, scanning electron microscopy, x-ray fluorescence, electron probe microanalyses and stable isotope analysis. Mechanical compaction and chemical diagenesis trends have obviously varied as a function of rock types and geological locations. The conglomerate reservoirs with high content of tuffaceous matrix and characterized by poor sorting showed stronger compaction. The tuffaceous matrix displays a large degree of dissolution during the progressive burial diagenesis due to its thermodynamic instability. The tuffaceous matrix in Na-rich conglomerate reservoir rocks mainly transformed into analcite, while it transformed into illite in K-rich conglomerate reservoir rocks. In most conglomerate reservoirs far away from deep-rooted faults, calcite cements are indicated to have been sourced from the decarboxylation of organic matter in the interbedded mudstones. Carbonate cements in conglomerate reservoirs near the deep-rooted faults possibly formed from hydrothermal fluids or thermochemical oxidation of pre-existing methane accumulations. This study can serve us an excellent example for the control of sediment composition and paleo-fluid evolution on diagenetic variations in fan-delta conglomerate reservoirs.",3,3,4
Reservoir Quality,Feldspar Dissolution,"Kassem, Ahmed A.; Hussein, Walid S.; Radwan, Ahmed E.; Anani, Nasr; Abioui, Mohamed; Jain, Sreepat; Shehata, Amer A.",Petrographic and diagenetic study of siliciclastic Jurassic sediments from the northeastern margin of Africa: Implication for reservoir quality,Northeastern Egypt; Lithofacies; Petrography; Reservoir quality; Diagenesis,,"Northeastern Egypt is one of the most important exposures in the Middle East and North Africa to study Jurassic facies. The present study analyzes 130 thin sections from a subsurface well (Well X) in the northern Gulf of Suez, and from two surface sections at Gebel Maghara (north Sinai) and Khashm Elgalala (North Eastern Desert), Egypt for petrographic and lithofacies analyses. In the present study, detailed petrographic analysis is used as a tool to better understand the diagenetic history of the Early to Late Jurassic siliciclastic sediments; the identified diagenetic elements are inferred concerning the reservoir quality. For this, sidewall cores, scanning electron microscopy and thin sections are used to detail detrital and authigenic mineralogy; these are then used to infer the depositional framework, factors controlling reservoir characteristics, and the operating diagenetic processes. The inferred depositional paleoenvironment is a prograding and retrograding linear siliciclastic shoreline within a shallow marine carbonate platform with coal swamps and occasional cross-cutting rivers. Diagenesis, petrographical characteristics and depositional conditions are the main factors controlling continental and marine reservoir architecture. The diagenetic processes affecting siliciclastic sedimentation are near the surface, shallow to intermediate burial, and deep burial cycles with different pore fluid filling at each stage. The siliciclastic sediments have been categorized into seven depositional lithofacies - calcareous claystone (S1a), carbonaceous claystone (S1b), siltstone (S2), planar and trough cross-bedded sandstone (S3), coarse, well rounded, large scale trough cross-bedded sandstone (S4), ooid sandstone (S5) and coal (C). Grain compaction, various phases of syntaxial quartz overgrowth, carbonate cementation and replacement, creation of dissolution porosity, and clay authigenesis are the most important diagenetic processes that have affected the siliciclastic continental and marine sediments. Many different diagenetic events, both destructive and constructive, have modified porosity. The destructive events include compaction and cementation (of silica, kaolinite, ferroan dolomite, Illite, and anhydride). The constructive events include silica cementation, feldspar dissolution, and ferroan dolomite dissolution. Additionally, present data also suggest that the continental sandstones have excellent reservoir quality whereas the marine sandstones have good to very good reservoir potential. Despite the excellent reservoir quality of the continental sandstone lithofacies, the effective stratigraphic seal is leaking. The interbedded calcareous and carbonaceous claystone lithofacies may provide an excellent stratigraphic seal for these siliciclastic reservoirs. Based on these analyses, a model is proposed that can be used as a template for subsurface Jurassic reservoir characterization and reservoir discrimination.",21,21,7
Reservoir Quality,Feldspar Dissolution,"Lin, Miruo; Xi, Kelai; Cao, Yingchang; Liu, Quyang; Zhang, Zehan; Li, Ke","Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin",Shale oil reservoir; Petrographic features; Diagenetic alteration; Heterogeneity of reservoirs in shale strata,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; BOHAI BAY BASIN; RESERVOIR QUALITY; SANDSTONE RESERVOIRS; JIYANG DEPRESSION; SEDIMENTARY-ROCKS; JIMSAR SAG; LITHOFACIES CLASSIFICATION; ORGANIC GEOCHEMISTRY,"Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation.",5,5,10
Reservoir Quality,Feldspar Dissolution,"Selim, S. S.; Wafdy, R.; Abu Khadrah, A. M.","Sedimentological analysis and reservoir quality of the early Cenomanian transgressive sandstones, northern Western desert, Egypt",Facies analysis; Bay-head delta; Reservoir heterogeneity; Reservoir quality; Transgressive sandstones; Shushan basin; Northern western desert of Egypt,INCLINED HETEROLITHIC STRATIFICATION; RESOLUTION SEQUENCE STRATIGRAPHY; CRETACEOUS MCMURRAY FORMATION; BAHARIYA FORMATION; SHORELINE TRAJECTORIES; DEPOSITIONAL SYSTEMS; FACIES ARCHITECTURE; ESTUARINE DEPOSITS; SEDIMENTARY MODEL; SHALLOW-MARINE,"Depicting depositional models of transgressive sandstone reservoirs is challenging due to their internal complexity and limited case studies. This study presents an example for transgressive sandstone reservoirs from the Bahariya Formation at Hayat-Yasser oil field, Shushan Basin (northern Western Desert, Egypt). The upper part of the Bahariya Formation accumulated in an estuarine setting as a consequence of a successive sea level rise. Detailed reservoir characterization, employing sequence stratigraphic and sedimentological approaches, revealed that the studied reservoir consists of a mixed siliciclastic-carbonate transgressive estuarine-shelf succession. Four conventional core samples of this succession at Khalda ridge (Shushan Basin), permit the analysis of their sedimentology and internal architecture (mesoscopic heterogeneities) along correlation lines parallel or slightly oblique to depositional dip. The succession consists of six backstepping parasequence sets that record the overall shift from tidal-dominated to wave-dominated estuaries/bays. The transgressive component of the parasequences sets includes bay mudstones, flood-tidal deltas, and shoreface/barrier deposits; while the regressive component includes estuarine point bars, bay head deltas, and tidal deltas. The reservoir properties show significant variation according to the facies assemblages. The tidally-dominated estuarine channels show low net-togross, as it is characterized by lenticular sandstone bodies with several lateral and vertical baffles and barriers. On the other hand, the shoreface/barrier and tidal delta sandstones show high net-to-gross and consist of amalgamated sandstone bodies with little mud barriers or baffles. Petrographically, the upper Bahariya reservoir includes intergranular and secondary porosities. The microscopic heterogeneities are mainly due to the fine grain nature, poor sorting, presence of matrix, and continuous mud barriers or baffles. Destruction of porosity, affecting the reservoir quality, occurred by silica overgrowths, ferroan calcite, grain coating chlorite, and kaolinite cementation, as well as compaction. Feldspar dissolution is the main diagenetic process responsible for the formation of secondary porosity, enhancing the reservoir quality.",5,5,0
Reservoir Quality,Feldspar Dissolution,"Yang, Peng; Zhang, Likuan; Liu, Keyu; Cao, Binfeng; Gao, Jianlei; Qiu, Guiqiang","Diagenetic history and reservoir evolution of tight sandstones in the second member of the Upper Triassic Xujiahe Formation, western Sichuan Basin, China",Tight sandstone; Diagenesis; Lithofacies; Reservoir quality; Xujiahe formation; Western sichuan basin,ANOMALOUSLY HIGH-POROSITY; GRAIN-COATING CHLORITE; HIGH-QUALITY RESERVOIR; QUARTZ CEMENTATION; 4TH MEMBER; COMPACTION PROCESSES; DEPOSITIONAL FACIES; RELATIVE IMPORTANCE; SEDIMENTARY BASINS; FORELAND BASIN,"The second member of the Upper Triassic Xujiahe Formation is an important target for tight gas exploration in the western Sichuan Basin. The diagenetic history and reservoir evolution were investigated using integrated analyses of petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), cathodoluminescence (CL), fluid inclusion microthermometry and stable carbon and oxygen isotopes. The sandstones consist mainly of litharenites, sublitharenites and feldsparthic litharenites with fine-to medium-sand grain sizes, moderate to good sorting and subangular to subrounded roundness. The reservoir properties of the sandstones are generally poor with low porosity and matrix permeability, small pore-throat radii, and high displacement pressure. Eodiagenesis is composed mainly of mechanical compaction, precipitation of siderite, stage-I quartz overgrowths, chlorite, calcite and ferroan calcite. Mesodiagenesis consists mainly of mechanical and chemical compaction, calcite and ferroan calcite precipitation, stage-II and stage-III quartz cementation, feldspar dissolution and precipitation of illite, dolomite and ankerite. Three types of sandstone lithofacies are defined according to sandstone textures and composition, diagenetic minerals, grain sizes, sorting and pore types: lithofacies I, II and III. Compaction appears to reduce the reservoir quality more significantly compared to cementation. Authigenic chlorite coats were constructive in preserving primary porosity, while carbonate cementation decreased reservoir quality. Diagenetic evolution pathways and reservoir quality prediction models for the Upper Triassic Xujiahe Formation sandstones have been proposed to shed light on the different reservoir quality evolution patterns of various sandstone lithofacies. Lithofacies I - medium and coarse-grained sandstones characterized by extensive chlorite coating, feldspar dissolution and a low content of clay matrix and cement, appears to have the best reservoir properties and may serve as a high-quality reservoir facies in these tight sandstone reservoirs.",3,3,7
Reservoir Quality,Well Logs,"Blanes de Oliveira, Lucas Abreu; Carneiro, Cleyton de Carvalho",Synthetic geochemical well logs generation using ensemble machine learning techniques for the Brazilian pre-salt reservoirs,Neutron-induced spectroscopy; Gamma ray spectroscopy; Formation evaluation; Artificial intelligence,GAMMA-RAY SPECTROSCOPY; MINERALOGY,"Geochemical logs are an essential tool for hydrocarbon reservoir characterization. The rock composition given by these logs is useful for porosity calculation, stratigraphic modeling, diagenesis estimation, and well acidification. In reduced logging operations performed in carbonate reservoirs of the Brazilian pre-salt, the geochemical tool is no longer acquired, aiming at optimization and cost reduction. This research aims the development of synthetic geochemical logs using machine learning algorithms. The database includes 22 wells with complete logging acquisition, and the input logs are natural gamma-ray, gamma-ray spectroscopy, density, photoelectric factor, neutron porosity, nuclear magnetic resonance, and sonic. The chemical elements chosen as output are Al, Ca, Fe, Mg, Na, Si, S, and Ti. Five models based on machine learning are trained using 19 wells: Support-vector machine, Multilayer perceptron, Random Forest, AdaBoost, and XGBoost. AdaBoost represents the best algorithm because, in addition to showing the best results, it allowed for a more simplified preprocessing and hyperparameter tuning. The evaluation of the models applies R-2 and root mean squared error (RMSE) in validation data and cross-validation. Robust models are acquired for Al, Ca, Fe, Mg, Si, S, and Ti, with R-2 above 0.80. Na shows R-2 slightly above 0.70. All the models have RMSE between 10(-2) to 10(-4). The most important logs during training are density, photoelectric factor, K, Th, U, and neutron porosity. Synthetic geochemical logs created for three test wells show a good agreement with acquired logs, being able to reproduce general trends of the pre-salt formations. The machine learning model is capable of substituting the acquisition of geochemical logs with high confidence, representing cost reduction, and supplying engineers and geoscientists with quality data to be used in formation evaluation.",4,4,3
Reservoir Quality,Well Logs,"Zahmatkesh, Iman; Kadkhodaie, Ali; Soleimani, Bahman; Azarpour, Moslem","Integration of well log-derived facies and 3D seismic attributes for seismic facies mapping: A case study from mansuri oil field, SW Iran",Seismic facies analysis; Seismic attributes; Well log facies; Reservoir quality; Asmari reservoir; Supervised neural network,MULTIATTRIBUTE TRANSFORMS; GAS-FIELD; CLASSIFICATION; RESERVOIR; CARBONATE; MACHINE; IDENTIFICATION; PARAMETERS; EXAMPLE; PART,"The recognition and mapping of rock facies is a pivotal step in reliable reservoir characterization and planning development operations. The present study aimed to present a practical workflow by integrating threedimensional (3D) seismic attributes and well-log facies analysis to determine the spatial distribution of electrofacies rock types of the Oligo-Miocene Asmari reservoir in Mansuri oilfield located in the southwestern part of Iran. The workflow begins with integrating well logs, core data, and geological information from the selected ?key wells? to build an electrofacies model, which could help reservoir facies to be classified and estimated in the cored and uncored wells, respectively. In addition, a group of 3D seismic attribute volumes derived from amplitude, frequency, and time characteristics of the post-stacked 3D seismic data were identified to specify the heterogeneity of the vertical and lateral rock facies within the reservoir. Additionally, the seismic attributes were analyzed using unsupervised and supervised learning techniques to identify seismic facies. The extraction of the seismic facies at multiple-well locations within the 3D classified volumes demonstrated that the supervised neural network learning method, as compared to the unsupervised approach, could more accurately estimate the desired seismic facies. The results of the ultimate rock facies maps of different vertical slices in the Asmari reservoir indicated that electrofacies with good reservoir quality were best developed on the top of the reservoir, mostly with NW-SE elongation at the crest line of the structure. The applied workflow allowed the localities of the buried sand channels to be identified and mapped. Accordingly, seismic facies mapping shed light on the spatial heterogeneity and quality of the reservoir, which could be used to guide the development drilling for optimal recovering of the unswept hydrocarbons.",4,4,3
Reservoir Quality,Well Logs,"Tatsipie, Nelson R. K.; Sheng, James J.",Generating pseudo well logs for a part of the upper Bakken using recurrent neural networks,Well logs; Recurrent neural networks; Gamma ray,,"To develop a reservoir, we need to understand the distribution of key reservoir properties. Those formation properties are mostly derived from well log data. However, obtaining well log data is so expensive that the data we acquire is never sufficient. Therefore, we need to create pseudo data from real measured data. One approach is to generate synthetic well logs using recurrent neural networks (RNNs). Though relatively nascent, it is proven that RNNs allow for the generation of well logs with reasonable accuracy at a fraction of the price. Currently, gamma ray is the most cultivated well log in the E&P process today (owing to its decisive role during drilling operations and affordable price). All the same, a more extensive log suite is required to comprehend the producibility and frackability of hydrocarbon reservoirs like shale reservoirs. In this study, an upper Bakken database of 97 wells which contain gamma ray, bulk density, photoelectric index, density porosity, neutron porosity, true resistivity, compressional and shear slowness was used to develop deep learning models apt to creating synthetic logs for another set of 40 wells in the upper Bakken. The latter wells only had measured gamma ray. Using petroleum engineering concepts and RNNs, data-driven models capable of generating the remaining logs were created. The data-driven models were validated using wells with logs that have been removed from the database to serve as blind validation wells. The performance of the models (5-10 Mean Average Percentage Error and R-squared of 0.6-0.8) suggests the workflow described in this study is a viable way to maximize the value of a gamma ray log. With the ability to generate logs of similar quality for all wells in a shale asset (starting only with gamma ray), superior reservoir evaluation and thus improved reservoir management can be achieved.",4,4,1
Reservoir Quality,Egypt,"Kassem, Ahmed A.; Hussein, Walid S.; Radwan, Ahmed E.; Anani, Nasr; Abioui, Mohamed; Jain, Sreepat; Shehata, Amer A.",Petrographic and diagenetic study of siliciclastic Jurassic sediments from the northeastern margin of Africa: Implication for reservoir quality,Northeastern Egypt; Lithofacies; Petrography; Reservoir quality; Diagenesis,,"Northeastern Egypt is one of the most important exposures in the Middle East and North Africa to study Jurassic facies. The present study analyzes 130 thin sections from a subsurface well (Well X) in the northern Gulf of Suez, and from two surface sections at Gebel Maghara (north Sinai) and Khashm Elgalala (North Eastern Desert), Egypt for petrographic and lithofacies analyses. In the present study, detailed petrographic analysis is used as a tool to better understand the diagenetic history of the Early to Late Jurassic siliciclastic sediments; the identified diagenetic elements are inferred concerning the reservoir quality. For this, sidewall cores, scanning electron microscopy and thin sections are used to detail detrital and authigenic mineralogy; these are then used to infer the depositional framework, factors controlling reservoir characteristics, and the operating diagenetic processes. The inferred depositional paleoenvironment is a prograding and retrograding linear siliciclastic shoreline within a shallow marine carbonate platform with coal swamps and occasional cross-cutting rivers. Diagenesis, petrographical characteristics and depositional conditions are the main factors controlling continental and marine reservoir architecture. The diagenetic processes affecting siliciclastic sedimentation are near the surface, shallow to intermediate burial, and deep burial cycles with different pore fluid filling at each stage. The siliciclastic sediments have been categorized into seven depositional lithofacies - calcareous claystone (S1a), carbonaceous claystone (S1b), siltstone (S2), planar and trough cross-bedded sandstone (S3), coarse, well rounded, large scale trough cross-bedded sandstone (S4), ooid sandstone (S5) and coal (C). Grain compaction, various phases of syntaxial quartz overgrowth, carbonate cementation and replacement, creation of dissolution porosity, and clay authigenesis are the most important diagenetic processes that have affected the siliciclastic continental and marine sediments. Many different diagenetic events, both destructive and constructive, have modified porosity. The destructive events include compaction and cementation (of silica, kaolinite, ferroan dolomite, Illite, and anhydride). The constructive events include silica cementation, feldspar dissolution, and ferroan dolomite dissolution. Additionally, present data also suggest that the continental sandstones have excellent reservoir quality whereas the marine sandstones have good to very good reservoir potential. Despite the excellent reservoir quality of the continental sandstone lithofacies, the effective stratigraphic seal is leaking. The interbedded calcareous and carbonaceous claystone lithofacies may provide an excellent stratigraphic seal for these siliciclastic reservoirs. Based on these analyses, a model is proposed that can be used as a template for subsurface Jurassic reservoir characterization and reservoir discrimination.",21,21,7
Reservoir Quality,Egypt,"Shalaby, Mohamed Ragab","Petrophysical characteristics and hydraulic flow units of reservoir rocks: Case study from the Khatatba Formation, Qasr field, North Western Desert, Egypt",Reservoir characterization; Porosity; Permeability; Flow zone indicator; Winland r35; Reservoir quality index,PORE-SIZE DISTRIBUTION; JURASSIC SOURCE ROCKS; SHOUSHAN BASIN; SANDSTONE RESERVOIR; OIL-FIELD; GEOCHEMICAL CHARACTERIZATION; DEPOSITIONAL ENVIRONMENT; NUBIA SANDSTONE; TARANAKI BASIN; SHUSHAN BASIN,"The reservoir characteristics and hydraulic flow unit properties of the Khatatba Formation in Qasr field, Western Desert, Egypt have been investigated. Several methods have been used to analyze and characterize the sandstone of the Khatatba Formation. Petrophysical parameters related to porosity and permeability have been considered together with some other important factors: reservoir quality index (RQI), flow zone indicator (FZI), and normalized porosity index (NPI). A study of the petrographic descriptions has been included to interpret the rock types and lithofacies. Moreover, displacement pressure, threshold pressure, and the Winland equation are used to understand and explain the pore geometry and pore throat diameter. Analysis of samples from three different wells indicates that this sandstone can be classified into three rock types with distinctive lithotypes and hydraulic flow units. Rock type I (flow unit-1), representing the data from the Qasr-3 well, possesses the best storage capacity with good porosity and very good permeability (max. value 14%, and 818 mD respectively). Coarse to very coarse grain sandstone is observed while all pore spaces are interpreted as megapores. The highest flow zone indicator has an average value of 15 mu m and an average reservoir quality index of 2.08 mu m. The capillary pressure and saturation curves show the lowest displacement pressure with a maximum pore throat diameter (Winland r35) of 34 mu m, which affirm the presence of mega pores with higher permeability routes. Rock type II (flow unit-2), representing the data from the Qasr-5 well, is the second-best for storage capacity with average FZI and RQI of 6.3 and 1.07 mu m, respectively. It is a medium-grained sandstone with very good porosity (max 16.45%), while the permeability is lower than that of type I (max 448 mD). The pore spaces are interpreted as a combination of megapores and macropores, while the max. pore throat radius (r35) is recorded as 17 mu m. Data from the Qasr-6 well reveal that this is the poorest quality reservoir (flow unit-3). It comprises fine-grained sandstone with the lowest average porosity and permeability of 9% and 16 mD, respectively. The average FZI and RQI also show lower values of 2.9 and 0.31 mu m. Most of the pore spaces have been categorized as macropores with some (a few percent) being categorized as mesopores so that the r35 value shows the lowest of 5.6 mu m. It is concluded that the grain size and lithotypes of the sandstone affect the reservoir quality and control the petrophysical properties and hydrocarbon potential.",5,5,3
Reservoir Quality,Egypt,"Selim, S. S.; Wafdy, R.; Abu Khadrah, A. M.","Sedimentological analysis and reservoir quality of the early Cenomanian transgressive sandstones, northern Western desert, Egypt",Facies analysis; Bay-head delta; Reservoir heterogeneity; Reservoir quality; Transgressive sandstones; Shushan basin; Northern western desert of Egypt,INCLINED HETEROLITHIC STRATIFICATION; RESOLUTION SEQUENCE STRATIGRAPHY; CRETACEOUS MCMURRAY FORMATION; BAHARIYA FORMATION; SHORELINE TRAJECTORIES; DEPOSITIONAL SYSTEMS; FACIES ARCHITECTURE; ESTUARINE DEPOSITS; SEDIMENTARY MODEL; SHALLOW-MARINE,"Depicting depositional models of transgressive sandstone reservoirs is challenging due to their internal complexity and limited case studies. This study presents an example for transgressive sandstone reservoirs from the Bahariya Formation at Hayat-Yasser oil field, Shushan Basin (northern Western Desert, Egypt). The upper part of the Bahariya Formation accumulated in an estuarine setting as a consequence of a successive sea level rise. Detailed reservoir characterization, employing sequence stratigraphic and sedimentological approaches, revealed that the studied reservoir consists of a mixed siliciclastic-carbonate transgressive estuarine-shelf succession. Four conventional core samples of this succession at Khalda ridge (Shushan Basin), permit the analysis of their sedimentology and internal architecture (mesoscopic heterogeneities) along correlation lines parallel or slightly oblique to depositional dip. The succession consists of six backstepping parasequence sets that record the overall shift from tidal-dominated to wave-dominated estuaries/bays. The transgressive component of the parasequences sets includes bay mudstones, flood-tidal deltas, and shoreface/barrier deposits; while the regressive component includes estuarine point bars, bay head deltas, and tidal deltas. The reservoir properties show significant variation according to the facies assemblages. The tidally-dominated estuarine channels show low net-togross, as it is characterized by lenticular sandstone bodies with several lateral and vertical baffles and barriers. On the other hand, the shoreface/barrier and tidal delta sandstones show high net-to-gross and consist of amalgamated sandstone bodies with little mud barriers or baffles. Petrographically, the upper Bahariya reservoir includes intergranular and secondary porosities. The microscopic heterogeneities are mainly due to the fine grain nature, poor sorting, presence of matrix, and continuous mud barriers or baffles. Destruction of porosity, affecting the reservoir quality, occurred by silica overgrowths, ferroan calcite, grain coating chlorite, and kaolinite cementation, as well as compaction. Feldspar dissolution is the main diagenetic process responsible for the formation of secondary porosity, enhancing the reservoir quality.",5,5,0
Reservoir Quality,Producers,"Lin, Miruo; Xi, Kelai; Cao, Yingchang; Liu, Quyang; Zhang, Zehan; Li, Ke","Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin",Shale oil reservoir; Petrographic features; Diagenetic alteration; Heterogeneity of reservoirs in shale strata,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; BOHAI BAY BASIN; RESERVOIR QUALITY; SANDSTONE RESERVOIRS; JIYANG DEPRESSION; SEDIMENTARY-ROCKS; JIMSAR SAG; LITHOFACIES CLASSIFICATION; ORGANIC GEOCHEMISTRY,"Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation.",5,5,10
Reservoir Quality,Producers,"Pinto, Helen; Wang, Xin; Gates, Ian",On the ratio of energy produced to energy injected in SAGD: Long-term consequences of early stage operational decisions,Steam-assisted gravity drainage; Energy efficiency; Thermal recovery; Energy produced versus energy injected (EPEI); Time-limited operator influence,,"Steam-Assisted Gravity Drainage (SAGD) is a recovery process used to extract bitumen from underground reservoirs. The efficiency of SAGD is determined by the volume of steam injected (reflecting cost and greenhouse gas emissions) relative to the volume of oil recovered (revenue). Another way to look at this relationship is as a ratio of cumulative energy produced to energy injected (EPEI). First described in this study, EPEI ratios offer a novel perspective on SAGD because they reduce the inter-well comparison bias caused by operational choices such as steam temperature, steam quality and well length. There are numerous studies on SAGD from an experimental, analytical or numerical simulation perspective, but all require assumptions and constraints specified in advance, and can only return an approximation of field performance. Studies that work exclusively with field data have typically been used for prediction modeling only. In contrast, this study employs a novel methodology by working within the existing constraints and operational choices of SAGD field wells to infer the number of steam-oil performance relationships present, and how long they last. One by one, we eliminate parameters that cannot cause the performance differences seen in the field using only deductive reasoning and multi-parameter sensitivity analysis, and arrive at possible reasons for the performance relationships found. 1520 SAGD well pairs in Alberta, Canada are used, which is more than 90% of the wells in Alberta over the last 20 years, and to the best of our knowledge, the largest field well set of any SAGD study to date. This comprehensive data set ensures that findings are applicable across the industry. Results reveal a new and surprising finding that the EPEI ratio is set during the first few months on production, and is very difficult to change thereafter. Hence, operators have a short, time-limited opportunity to influence each well's recovery ratio (and therefore its profitability and greenhouse gas emissions). This reflects the importance of process start-up and the first few months after start-up when the near well region of the reservoir is conditioned. Finally, the stability of the EPEI ratio permits a simple, new model capable of predicting cumulative recovery months in advance.",4,4,0
Reservoir Quality,Producers,"Lamas, L. F.; Botechia, V. E.; Schiozer, D. J.; Rocha, M. L.; Delshad, M.",Application of polymer flooding in the revitalization of a mature heavy oil field,Polymer flooding; Mature fields; Reservoir management; Revitalization of fields; Reservoir simulation,,"Polymer flooding is a chemical enhanced oil recovery that aims to improve mobility control, by increasing the viscosity of injection brine and thus reducing the mobility ratio. Starting the polymer injection as early as possible brings the best economic results because it prevents the formation of viscous fingering and sweeps more efficiently the reservoir. It is possible, however, to obtain gains with polymer flooding even after massive waterfloods. In this work, three different model-based approaches are developed to revitalize mature oilfields and tested considering the use of water and polymer as injection fluid. These strategies were tested using a synthetic reservoir model based on data from an offshore field in Brazil. The reservoir is sandstone (average permeability = 1650mD, average porosity = 20%). The oleic phase is heavy viscous oil (similar to 70 cP, 14 degrees API). The first simulation approach considered a strategy based on a standard waterflood until its economic limit. For this case, the maximum net present value (NPV) was reached after 15 years of production with a recovery factor of 25%. The revitalization strategy of this field considers an abandonment status for all wells. To emulate the time necessary to install all new facilities, all wells were assumed to be closed for six months. The first approach consists simply of reopening the injectors by changing the injection fluid to an aqueous polymer solution. The second approach has an additional degree of freedom: it allows all wells to be converted from injectors to producers and vice-versa. Finally, the third approach consists of the addition of new wells. Equations for quality maps for placing injectors and producers are presented. Using these equations, new producers and injectors could be placed at the best locations to produce the remaining oil spots. All three approaches increased the oil recovery factor. The additional oil recovery and variations in NPV were higher for the polymer flooding when compared with the standard waterflood, ensuring a longer productive life. This significant increase in oil production means that, for the selected case, producers needed to be closed in the water flooding period, due to economic performance, leaving a significant amount of oil still in the reservoir. The methodologies presented in this paper are easy to apply and can allow mature fields to economically produce more oil. The conversion of old wells by changing from producers to injectors or vice-versa allows new and creative production strategies. This can be done in onshore and dry completed offshore fields demanding small budgets and intervention times. This paper shows that it is possible to increase both the recovery factor and net present value of fields in the later stages of production life.",3,3,4
Reservoir Quality,CO2 Foam,"Fu, Chunkai; Liu, Ning",Rheology and stability of nanoparticle-stabilized CO2 foam under reservoir conditions,Nanoparticle; Apparent viscosity; Foam stability; CO2 foam,ENHANCED OIL-RECOVERY; POLYMER; SURFACTANTS; BEHAVIOR; FLUIDS,"This study investigates the rheology and stability of nanoparticle-stabilized CO2 foams under reservoir conditions (high temperature and high pressure) for fracturing applications. The effects of different parameters on foam apparent viscosity and foam stability were experimentally investigated including the effects of nanoparticle concentration, salinity, foam quality (Gamma), shear rate and temperature. The power law model was applied to calculate foam apparent viscosity owing to its pseudo-plastic behavior, and the changes of foam heights over time were used to evaluate foam stability. Results showed that the CO2 foam apparent viscosity featured a mountain-shaped curve versus F, with the peak apparent viscosity obtained at 70% foam quality. The increase of salinity (up to 11%) in the continuous phase improved both foam stability and rheology. Higher nanoparticle concentration could contribute to better foam stability, but there was a threshold concentration, above which the foam apparent viscosity remained stabilized. The CO2 foam stabilized by nanoparticles displayed a shear-thickening behavior as the experiment flow rate increased from 6 mL/min to 18 mL/min. Further studies showed that as the total flow rate increased, the CO2 foam became finer-textured with better stability. Elevated temperatures could undermine foam apparent viscosity and long-term stability. The results of this study could provide guidelines as to the design of foam fracturing systems for field applications.",4,4,4
Reservoir Quality,CO2 Foam,"Ahmed, S.; Alameri, W.; Ahmed, W. W.; Khan, S. A.",Rheological behavior of scCO(2)-Foam for improved hydrocarbon recovery: Experimental and deep learning approach,,REAL-TIME PREDICTION; FRACTURING FLUID; SHALE-GAS; DRILLING-FLUIDS; FOAM STABILITY; OIL; PERFORMANCE; VISCOSITY; TEMPERATURE; PRESSURE,"CO2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO2 foam is a key factor to control the efficiency of fracturing process that is strongly influenced by different process parameters such as foam quality, temperature, pressure, and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO2 foams by varying different process variables. CO2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (<1.8%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO2 foam projects for fracturing unconventional reservoirs.",3,3,5
Reservoir Quality,Persian Gulf,"Mehrabi, Hamzeh; Bahrehvar, Mohammad; Rahimpour-Bonab, Hossain","Porosity evolution in sequence stratigraphic framework: a case from Cretaceous carbonate reservoir in the Persian Gulf, southern Iran",Micrite texture; Pore evolution; Paleoexposure; Dariyan Formation; Persian Gulf,PALAEO-EXPOSURE SURFACES; SHUAIBA FORMATION; DEZFUL EMBAYMENT; MICROPOROSITY; SYSTEMS; LIMESTONES; SANDSTONE; MICRITE; HISTORY; FACIES,"Dariyan Formation (Aptian) is one of the important hydrocarbon reservoirs in the Persian Gulf. In this reservoir, porosity is controlled by various depositional and diagenetic factors. This study integrates petrographic, geochemical, petmphysical and reservoir quality data to distinguish various pore types and their evolution in two fields selected from the SE and NW Persian Gulf. Primary (depositional) and secondary (diagenetic) pore types are differentiated using the results of macroscopic (core) and microscopic (thin section and SEM) petrographic studies. Pore size distribution and reservoir importance are evaluated by MICP and porosity-permeability measurements on core-plug samples. Macroscopic pores are formed within the grain-dominated and dissolved mud-dominated facies that are located in the RST of third-order sequences, especially within the lower carbonate unit. Micropores are recorded in mud-dominated facies of middle to outer ramp settings with minor effects of meteoric dissolution. Accordingly, evolution in an open diagenetic system with high water/rock ratio is proposed for grain-supported facies, and a closed diagenetic system for mud-dominated intervals. There are close relationships between micrite micro-textures (MTCs) and reservoir properties of mud-dominated facies. A dynamic pore evolution model is presented for the Dariyan Formation that integrates all depositional and diagenetic features in sequence stratigraphic framework. This model can be used for ongoing reservoir studies of this formation in hydrocarbon fields of the Persian Gulf.",5,4,0
Reservoir Quality,Persian Gulf,"Kakemem, Umid; Jafarian, Arman; Husinec, Antun; Adabi, Mohammad Hossein; Mahmoudi, Ayoub","Facies, sequence framework, and reservoir quality along a Triassic carbonate ramp: Kangan Formation, South Pars Field, Persian Gulf Superbasin",Kangan Formation; Khuff Formation; Homoclinal ramp; Carbonate facies; Reservoir quality; Persian Gulf Superbasin; South Pars Field,UPPER DALAN FORMATION; GAS-FIELD; DEPOSITIONAL ENVIRONMENT; KHUFF SEQUENCES; ALGAL MATS; DOLOMITIZATION; STRATIGRAPHY; PLATFORM; BASIN; DIAGENESIS,"The Lower Triassic Kangan Formation of the Persian Gulf Superbasin forms one of the largest reservoirs in the South Pars/North Field, the world's largest gas field. The upper Khuff-equivalent, gas-hosting carbonate-evaporite succession was formed on a gently-sloping, homoclinal carbonate ramp in a warm, tropical aragonite sea under a hot-and-arid greenhouse climate. This study explores the impact of vertical variations in depositional facies and diagenetic features on the reservoir quality to improve the prediction of the subsurface facies and hydraulic flow unit distribution. Detailed core logging and petrographic analysis resulted in the recognition of twelve distinct carbonate-evaporite facies that are grouped into four major facies associations, from shallowest to deepest: supratidal to restricted subtidal, lagoon, carbonate shoal, and shallow mid-ramp. The facies associations are stacked into two long-term sequences K52 (58 m) and KS1 (77 m) bounded by anhydrites and/or unconformities; three higher frequency sequences (KSla, KSlb, and KSlc) can be identified within the KS1. Based on the petrophysical properties, sedimentary facies characteristics and their diagenetic modifications, five hydraulic flow units (HFUs) are identified, with the best porosity-permeability values and flow- and storage capacities in the late transgressive (TSTs) and the earliest highstand systems tracts (HSTs) of the two long-term sequences. The reservoir quality and the distribution of hydraulic flow units are a product of interactions between primary mineralogy, depositional facies and their stacking, and the early- and late-diagenetic alterations. The reservoir quality decreases in landward direction, being the lowest in the mud-supported textures of the lagoon and supratidal to restricted subtidal facies associations. The seaward improvement in reservoir quality reflects a change to grain-supported textures that formed along the tide-and wave-agitated ooid-bioclastic shoals, whereas the best reservoir quality characterizes the shallow mid-ramp open-marine facies association, where secondary porosity was improved by dissolution and dolomitization. Both the early and late diagenetic dolomitization overall improved the reservoir quality, with the dolomitization pathways controlled by the porosity and permeability heterogeneity in the original depositional facies. The results may be useful in reservoir modeling, recognition of the productive zones, and the further development of the South Pars/North Dome Field.",4,4,4
Reservoir Quality,Western Desert,"Shalaby, Mohamed Ragab","Petrophysical characteristics and hydraulic flow units of reservoir rocks: Case study from the Khatatba Formation, Qasr field, North Western Desert, Egypt",Reservoir characterization; Porosity; Permeability; Flow zone indicator; Winland r35; Reservoir quality index,PORE-SIZE DISTRIBUTION; JURASSIC SOURCE ROCKS; SHOUSHAN BASIN; SANDSTONE RESERVOIR; OIL-FIELD; GEOCHEMICAL CHARACTERIZATION; DEPOSITIONAL ENVIRONMENT; NUBIA SANDSTONE; TARANAKI BASIN; SHUSHAN BASIN,"The reservoir characteristics and hydraulic flow unit properties of the Khatatba Formation in Qasr field, Western Desert, Egypt have been investigated. Several methods have been used to analyze and characterize the sandstone of the Khatatba Formation. Petrophysical parameters related to porosity and permeability have been considered together with some other important factors: reservoir quality index (RQI), flow zone indicator (FZI), and normalized porosity index (NPI). A study of the petrographic descriptions has been included to interpret the rock types and lithofacies. Moreover, displacement pressure, threshold pressure, and the Winland equation are used to understand and explain the pore geometry and pore throat diameter. Analysis of samples from three different wells indicates that this sandstone can be classified into three rock types with distinctive lithotypes and hydraulic flow units. Rock type I (flow unit-1), representing the data from the Qasr-3 well, possesses the best storage capacity with good porosity and very good permeability (max. value 14%, and 818 mD respectively). Coarse to very coarse grain sandstone is observed while all pore spaces are interpreted as megapores. The highest flow zone indicator has an average value of 15 mu m and an average reservoir quality index of 2.08 mu m. The capillary pressure and saturation curves show the lowest displacement pressure with a maximum pore throat diameter (Winland r35) of 34 mu m, which affirm the presence of mega pores with higher permeability routes. Rock type II (flow unit-2), representing the data from the Qasr-5 well, is the second-best for storage capacity with average FZI and RQI of 6.3 and 1.07 mu m, respectively. It is a medium-grained sandstone with very good porosity (max 16.45%), while the permeability is lower than that of type I (max 448 mD). The pore spaces are interpreted as a combination of megapores and macropores, while the max. pore throat radius (r35) is recorded as 17 mu m. Data from the Qasr-6 well reveal that this is the poorest quality reservoir (flow unit-3). It comprises fine-grained sandstone with the lowest average porosity and permeability of 9% and 16 mD, respectively. The average FZI and RQI also show lower values of 2.9 and 0.31 mu m. Most of the pore spaces have been categorized as macropores with some (a few percent) being categorized as mesopores so that the r35 value shows the lowest of 5.6 mu m. It is concluded that the grain size and lithotypes of the sandstone affect the reservoir quality and control the petrophysical properties and hydrocarbon potential.",5,5,3
Reservoir Quality,Western Desert,"Selim, S. S.; Wafdy, R.; Abu Khadrah, A. M.","Sedimentological analysis and reservoir quality of the early Cenomanian transgressive sandstones, northern Western desert, Egypt",Facies analysis; Bay-head delta; Reservoir heterogeneity; Reservoir quality; Transgressive sandstones; Shushan basin; Northern western desert of Egypt,INCLINED HETEROLITHIC STRATIFICATION; RESOLUTION SEQUENCE STRATIGRAPHY; CRETACEOUS MCMURRAY FORMATION; BAHARIYA FORMATION; SHORELINE TRAJECTORIES; DEPOSITIONAL SYSTEMS; FACIES ARCHITECTURE; ESTUARINE DEPOSITS; SEDIMENTARY MODEL; SHALLOW-MARINE,"Depicting depositional models of transgressive sandstone reservoirs is challenging due to their internal complexity and limited case studies. This study presents an example for transgressive sandstone reservoirs from the Bahariya Formation at Hayat-Yasser oil field, Shushan Basin (northern Western Desert, Egypt). The upper part of the Bahariya Formation accumulated in an estuarine setting as a consequence of a successive sea level rise. Detailed reservoir characterization, employing sequence stratigraphic and sedimentological approaches, revealed that the studied reservoir consists of a mixed siliciclastic-carbonate transgressive estuarine-shelf succession. Four conventional core samples of this succession at Khalda ridge (Shushan Basin), permit the analysis of their sedimentology and internal architecture (mesoscopic heterogeneities) along correlation lines parallel or slightly oblique to depositional dip. The succession consists of six backstepping parasequence sets that record the overall shift from tidal-dominated to wave-dominated estuaries/bays. The transgressive component of the parasequences sets includes bay mudstones, flood-tidal deltas, and shoreface/barrier deposits; while the regressive component includes estuarine point bars, bay head deltas, and tidal deltas. The reservoir properties show significant variation according to the facies assemblages. The tidally-dominated estuarine channels show low net-togross, as it is characterized by lenticular sandstone bodies with several lateral and vertical baffles and barriers. On the other hand, the shoreface/barrier and tidal delta sandstones show high net-to-gross and consist of amalgamated sandstone bodies with little mud barriers or baffles. Petrographically, the upper Bahariya reservoir includes intergranular and secondary porosities. The microscopic heterogeneities are mainly due to the fine grain nature, poor sorting, presence of matrix, and continuous mud barriers or baffles. Destruction of porosity, affecting the reservoir quality, occurred by silica overgrowths, ferroan calcite, grain coating chlorite, and kaolinite cementation, as well as compaction. Feldspar dissolution is the main diagenetic process responsible for the formation of secondary porosity, enhancing the reservoir quality.",5,5,0
Reservoir Quality,Sichuan Basin,"Jiu, Bo; Huang, Wenhui; Mu, Nana; Li, Yuan","Types and controlling factors of ordovician paleokarst carbonate reservoirs in the southeastern Ordos Basin, China",Karstification; Carbonate rock; Reservoir; Dissolution; Diagenesis,THERMOCHEMICAL SULFATE REDUCTION; SICHUAN BASIN; MAJIAGOU FORMATION; DIAGENETIC ALTERATION; NATURAL-GAS; TARIM BASIN; OIL-FIELD; ORIGIN; KARST; QUALITY,"With continuous improvements in oil and gas exploration technology and the increasing demand for oil and gas resources, the focus of oil and gas exploration has shifted from deep to ultradeep reservoirs. This study targeted the carbonate karst reservoirs of the Ordovician Ma5 Member in the southeastern Ordos Basin. Based on the analysis of cores, thin sections, cathodoluminescence, scanning electron microscopy (SEM), carbon and oxygen isotopes and trace elements, we discuss the development characteristics, types and influencing factors of paleokarst reservoirs. Petrology and geochemistry show three kinds of karstification in the study area: quasicontemporaneous karst, epigenetic karst and deep burial karst. The quasi-contemporaneous and epigenetic paleokarsts were mainly controlled by freshwater, where the soluble components of the strata were preferentially dissolved. The deep burial karstification was dominated by the reaction product H2S from thermochemical sulfate reduction (TSR) between sulfate minerals and organic matter, during which hydrothermal fluid provided the required activation energy for the reaction. The observations of cores and thin sections show that the paleokarst reservoirs are composed of different kinds of dissolution pores and fractures and cemented by multistage calcite and siliceous cements. Influenced by freshwater leaching and hydrothermal fluid, the three paleokarst processes led to negative anomalies in delta O-18 and delta C-13, while the low delta Ce, low delta Eu and rare earth element (REE) partition modes confirm that the intensity of freshwater leaching was stronger than that of hydrothermal fluid. The controlling factors of the paleokarst reservoirs included acidic fluids, paleogeomorphology and paleostructure in each diagenetic stage. According to the structural background and core characteristics, we establish a development model and spatial evolution model of the paleokarst reservoirs in the southeastern Ordos Basin.",3,3,11
Reservoir Quality,Sichuan Basin,"Yang, Peng; Zhang, Likuan; Liu, Keyu; Cao, Binfeng; Gao, Jianlei; Qiu, Guiqiang","Diagenetic history and reservoir evolution of tight sandstones in the second member of the Upper Triassic Xujiahe Formation, western Sichuan Basin, China",Tight sandstone; Diagenesis; Lithofacies; Reservoir quality; Xujiahe formation; Western sichuan basin,ANOMALOUSLY HIGH-POROSITY; GRAIN-COATING CHLORITE; HIGH-QUALITY RESERVOIR; QUARTZ CEMENTATION; 4TH MEMBER; COMPACTION PROCESSES; DEPOSITIONAL FACIES; RELATIVE IMPORTANCE; SEDIMENTARY BASINS; FORELAND BASIN,"The second member of the Upper Triassic Xujiahe Formation is an important target for tight gas exploration in the western Sichuan Basin. The diagenetic history and reservoir evolution were investigated using integrated analyses of petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), cathodoluminescence (CL), fluid inclusion microthermometry and stable carbon and oxygen isotopes. The sandstones consist mainly of litharenites, sublitharenites and feldsparthic litharenites with fine-to medium-sand grain sizes, moderate to good sorting and subangular to subrounded roundness. The reservoir properties of the sandstones are generally poor with low porosity and matrix permeability, small pore-throat radii, and high displacement pressure. Eodiagenesis is composed mainly of mechanical compaction, precipitation of siderite, stage-I quartz overgrowths, chlorite, calcite and ferroan calcite. Mesodiagenesis consists mainly of mechanical and chemical compaction, calcite and ferroan calcite precipitation, stage-II and stage-III quartz cementation, feldspar dissolution and precipitation of illite, dolomite and ankerite. Three types of sandstone lithofacies are defined according to sandstone textures and composition, diagenetic minerals, grain sizes, sorting and pore types: lithofacies I, II and III. Compaction appears to reduce the reservoir quality more significantly compared to cementation. Authigenic chlorite coats were constructive in preserving primary porosity, while carbonate cementation decreased reservoir quality. Diagenetic evolution pathways and reservoir quality prediction models for the Upper Triassic Xujiahe Formation sandstones have been proposed to shed light on the different reservoir quality evolution patterns of various sandstone lithofacies. Lithofacies I - medium and coarse-grained sandstones characterized by extensive chlorite coating, feldspar dissolution and a low content of clay matrix and cement, appears to have the best reservoir properties and may serve as a high-quality reservoir facies in these tight sandstone reservoirs.",3,3,7
Drilling Fluid,Fracture,"Magzoub, Musaab, I; Shamlooh, Mohamed; Salehi, Saeed; Hussein, Ibnelwaleed; Nasser, Mustafa S.",Gelation kinetics of PAM/PEI based drilling mud for lost circulation applications,Lost circulation; Gelation kinetics; Polyacrylamide; Polyethylenimine; Crosslinking; Rheology,,"The problem of lost circulation is a direct consequence of the presence of fractures or high permeability. Lost circulation material (LCM) is used to treat the loss that occurs or proactively strengthen the wellbore of the potential loss zones. The polyacrylamide (PAM)/Polyethylenimine (PEI) cross-linkable polymer gel is proven to work best in zone-sealing and plugging applications. In addition to their thermal stability, the fact that these gels are flexible gives them the advantage of deforming and sealing-off multiple and complex near wellbore fractures. The primary objective of this study is to investigate the gelation kinetics of the PAM/PEI cross-linkable polymer to be used in drilling fluids formulations to enhance wellbore stability and strength. Different combinations of polymers and crosslinkers were evaluated; potential polymers were screened for gelation kinetics and gel strength in typical drilling mud formulations. The gelation time of the polymer-based drilling mud formulation is determined in salt-free and in saline systems. The results on rheological properties and gelation kinetics were used to prepare a gelling mud formulation using PAM/PEI cross-linkable polymer as LCM. The produced gel was thermally stable under high-temperature-high-pressure reservoir conditions, which will result in enhanced wellbore strengthening.",5,5,3
Drilling Fluid,Fracture,"Freire Soares, Andreia Silveira; Furtado de Sousa, Ana Maria; Calcada, Luis Americo; Scheid, Claudia Mirian; Costa Marques, Monica Regina",Study of materials to combat loss of circulation in fractures and static filtration,Circulation loss materials; Rheology; Clay swelling; Drilling fluid; Factorial design,RHEOLOGICAL PARAMETERS; DRILLING-FLUID; PRESSURE-DROP; BENTONITE; WEIGHT; PARTICLES; IMPACT,"For the obstruction and reinforcement of permeable rocks (pores and or fractures), materials to combat loss of circulation (LCMs) are commonly used in the drilling fluid. LCMs, when forming bridges, support and seal rocks, with the objective of preventing drilling fluid from reaching the reservoir. In this study, drilling fluid formulations were developed using full four-level factorial design (DOE), with a central point (4 <^> 2 + 3) in order to evaluate the effect of drilling fluid components on their rheological properties and in the loss of circulation. The tested fluids were prepared using carboxymethylcellulose polymer (CMC), bentonite (BT) as a thickener, and the materials used to combat loss of circulation were used with diatomaceous earth (DE) and hydrogel (HG). The density and pH of all fluids were adjusted to approximately approximate to 1.14 g/cm(-3) and 8.5, respectively, being named F (CMC)BT-DE-HG. The filtration experiments were performed in a HTHP (high temperature, high pressure) filtration cell and the fracture was sealed in a physical simulator, called Fracture Flow Simulator (SEF). The rheological data were adjusted using the Herschel Bulkley model. The incorporation of LCMs in the drilling fluid improved the rheological properties. The results indicated that the investigated factors CMC, BT and HG had the main effects in combating the loss of circulation in the fracture and filtration phases. Diatomaceous earth was not significant in filtration and fracture tests. Finally, based on rheological tests, it can be inferred that the interaction of HG*CMC and BT*CMC is highly significant in combating loss of circulation. The fluid with lower DE level showed superior performance, as it sealed the fracture in 1 min of testing and a low volume of filtrate was observed in the test.",4,4,5
Drilling Fluid,Fracture,"Lai, Jin; Chen, Kangjun; Xin, Yi; Wu, Xingneng; Chen, Xu; Yang, Kefu; Song, Qiuqiang; Wang, Guiwen; Ding, Xiujian","Fracture characterization and detection in the deep Cambrian dolostones in the Tarim Basin, China: Insights from borehole image and sonic logs",Fractures; In-situ stress; Dolostones; Dissolution; Well log expression; Tarim basin,LOWER ORDOVICIAN CARBONATES; TRIASSIC YANCHANG FORMATION; ORDOS BASIN; DOLOMITE RESERVOIRS; NW CHINA; SICHUAN BASIN; HYDROTHERMAL ALTERATION; FORMATION MECHANISM; DENSITY-ESTIMATION; SHALE RESERVOIRS,"Characterization and detection of natural fractures using well logs in ancient deeply buried dolostones with low matrix porosity are very difficult. Core description, thin section analysis, conventional well logs, borehole image and sonic logs are used to document distribution of fractures in deep Cambrian dolostones in the Tarim Basin, China. The SHmax (maximum horizontal stress) direction is determined from drilling induced fractures, borehole breakouts and shear wave birefringence. Natural fractures with various attributes (open to partly open to closed) and orientation (including dip angles) are recognized. Natural fractures are classified into closed fractures, partly closed fractures, vuggy fractures and open fractures, and they can be further classified into high angle fractures, low-medium dip angle fractures, and low angle or horizontal fractures. Natural fractures are mainly associated with the more brittle rocks (dolograinstone, fine-medium-coarse crystalline dolostones), while fractures in dolomicrites and evaporitic gypsums-bearing dolostones are rare. Open to closed fractures are recognized as dark to bright sine waves on image logs, and the presences of open fractures cause minor deviations on the DEN logs, but significant deviations in resistivity values, while AC will be significantly increased in front of fractures. The energy of sonic full-waveforms will be strongly attenuated in front of open fractures. Fractures with strike parallel to the SHmax tend to have large aperture and good connectivity, and are suggested to enhance hydrocarbon productivity. Dolostones adjacent to the deep faults are heavily fractured, and fractures act as the hydrothermal fluid flow pathways, facilitating dissolution process. The abundance of vuggy fractures, and enlargement of the pre-existing microfractures support that fractures had enhanced dissolution. The dissolution along fracture surfaces helps increase fracture porosity. The results of this study about subsurface fracture patterns and their distributions are important for the hydrocarbon exploration and production in the Cambrian dolostones in the Tarim Basin.",4,6,4
Drilling Fluid,Fracture,"Hashemizadeh, Abbas; Maaref, Ahmad; Shateri, Mohammadhadi; Larestani, Aydin; Hemmati-Sarapardeh, Abdolhossein","Experimental measurement and modeling of water-based drilling mud density using adaptive boosting decision tree, support vector machine, and K-nearest neighbors: A case study from the South Pars gas field",Drilling mud density; Support vector regression; K-nearest neighbors; Decision tree; Adaptive boosting; Bayesian ridge regression,REAL-TIME PREDICTION; RHEOLOGICAL PROPERTIES; FLUID DENSITY; VISCOSITY,"Exact determination of drilling mud weight in order to prevent fracture pressure and at the same time overcoming pore pressure is a key parameter in the drilling of oil and gas wells. Accurate design of drilling mud weight increases drilling safety, reduces mud loss, and also the duration of drilling operations. In this study, five efficient artificial intelligent models including Bayesian ridge regression (BRR), K-nearest neighbors (KNN), support vector machine (SVM), decision tree (DT), and Adaptive Boosting Regressor with Decision Tree (ABRDT) were proposed for estimating mud weight based on a databank of 817 data points from five wells in the South Pars gas field. Variables influencing mud weight include true vertical depth (TVD), hole size, inclination, funnel viscosity, yield point (YP), plastic viscosity (PV), gel strength (measured at 10th second, 10th minute, and 30th minute), API fluid loss (FL), mud type (seawater, KCl-polymer, and salt-polymer), and formation lithology. According to the statistical analysis, the proposed ABR-DT and DT were the most accurate approaches that could predict mud weight with average absolute percent relative errors (AARE) of 0.5159% and 0.7560%, respectively. The accuracy of the models was ranked as: ABR-DT > DT > SVM > KNN > BRR. The sensitivity analysis showed that the predicted mud density is highly influenced by the values of plastic viscosity and true vertical depth. Lastly, the Leverage approach confirmed the validity of the employed data and the applicability area of the proposed ABR-DT model.",3,3,5
Drilling Fluid,Fracture,"Zhai, Xiaopeng; Chen, Hui; Lou, Yishan; Wu, Huimei",Prediction and control model of shale induced fracture leakage pressure,Shale gas; Leakage rate; Induced fracture; Leakage pressure; Critical value of fracture's width,,"Fractures gradually open under the action of fluid pressure in drilling shale gas reservoirs because of the existence of shale natural fractures, which leads to the leakage of expansible fractures. Induced fracture leakage is difficult to find and control in the early stage of drilling, resulting in great economic losses. The current model of induced fracture leakage pressure model is based on takes rock fracture criterion, which can only be used to judge whether the fracture is fractures created or not but cannot analyze the influence of fracture width change on leakage pressure after natural fracture of shale cracking. In addition, the model cannot control the occurrence of leakage. In this paper, the calculation method of fracture's width change under induced pressure is established. According to the field leakage rate data, a dynamic model of leakage pressure is established based on the parameters of time, leakage rate, fracture's width, fluid viscosity, and wellbore radius. The model is applied to calculate the dynamic change of leakage pressure on the Sichuan Shale Gas Field site and control the induced fracture's change to control leakage. Results show the following observations. (i) The fracture's width and leakage velocity of induced fracture increase with the increase of leakage pressure. Blocking the leakage when any leakage is found on the site is not advisable because it can increase the fracture's width artificially and increase leakage. (ii) The critical value of the fracture's width may cause severe leakage. When the leakage's differential pressure remains unchanged, the relationship between the fracture's width and leakage velocity refers to the power exponent change. The method of controlling the leakage pressure and reducing the fracture's width that is less than the critical leakage fracture degree is adopted for the leakage of the shale gas drilling in the Longmaxi Formation field Jiaoshiba, which effectively reduces the leakage amount. Taking a particular project, for example, controlling leakage pressure of induced fracture is given to verify the feasibility of the method.",3,4,4
Drilling Fluid,Nanoparticles,"Perumalsamy, Jayachandran; Gupta, Pawan; Sangwai, Jitendra S.",Performance evaluation of esters and graphene nanoparticles as an additives on the rheological and lubrication properties of water-based drilling mud,Ester; Lubricity; Graphene nano-particle; Rheology; Water-based mud,FLUIDS; ENHANCEMENT; POLYMER,"In the practice of drilling horizontal, directional, and unstable well profiles, the friction produced by bit balling, wellbore instability, cavings, and dog-legs resulted in excessive torque and drag. The friction along with high torque and drag, which results from the drill string, casing, and wellbore contact, leads to pipe stucks, overpulls during tripping-outs, and even closure of the oil and gas well. Heat generated from metal contact between casing and drill string is the cause of wear of drill string and casing. Oil-based drilling fluids are identified to produce minimum friction and torque than that of water-based drilling fluid/mud (WBM). However, the use of oil-based drilling fluids is becoming obsolete due to stringent environmental regulations. Therefore, it is critical to identify and design a water-based drilling mud with lubricant additives that are environmentally friendly, cost-effective, and give better lubrication similar to oil-based and synthetic-based drilling fluid. The objective of this study is to investigate the effect of two additives PC60 (the product of the reaction of glycerol + tall oil fatty acid) and graphene nanoparticles on the rheological and lubrication properties of water-based drilling fluid. All together total 14 drilling fluid samples have been prepared for the detailed analysis. Extensive experimental work has been done to study the effect of lubricant additives (PC60 and graphene nanoparticles) on the rheology and lubrication of various WBMs with different additive concentrations (1, 2, and 3% by volume) at 30, 60, and 90 degrees C. All samples were investigated for their rheology, viscoelastic behavior, and lubrication properties before and after hot rolling. The experimental data generated in this work have been successfully utilized to find various fitting parameter for the Bingham plastic rheological model, followed by a discussion on foaming tendency of the samples and effect of pH on the rheological stability of drilling fluid. Subsequently, a relationship between the coefficient of friction (in the presence of different lubricant additives in the mud) and rheological properties (plastic viscosity and yield point) of different drilling fluid samples have been proposed.",5,5,12
Drilling Fluid,Nanoparticles,"Kamali, Fahime; Saboori, Rahmatallah; Sabbaghi, Samad",Fe3O4-CMC nanocomposite performance evaluation as rheology modifier and fluid loss control characteristic additives in water-based drilling fluid,Fe3O4; Carboxymethyl cellulose; Nanocomposite; Filtration; Rheology; Drilling fluid,FILTRATION PROPERTIES; CARBOXYMETHYL CELLULOSE; THERMAL-CONDUCTIVITY; OXIDE NANOPARTICLES; MUD; TEMPERATURE; IMPROVEMENT; BEHAVIOR; OIL,"In drilling operations, there has been a considerable amount of attention to the drilling fluid formulation and characteristics. In recent years, the utilization of nanocomposite as an additive exhibited a promising improvement in the water-based drilling fluid rheological properties. The conventional additives have a lot of deficiencies such as being expensive, complicated synthesis methods, and not having desirable rheology properties. To eliminate the deficiencies, an investigation on the efficacy of Fe3O4- carboxymethyl cellulose (CMC) nanocomposite on the rheological and filtration characteristics as an additive in the water-based drilling fluid are carried out in this study. The nanocomposite was synthesized by the co-precipitation method and Fouriertransform infrared spectroscopy, X-ray diffraction, scanning electron microscopy, and energy dispersive x-ray was employed for characterization. Then, the nanocomposite with different ratio was utilized as an additive to drilling fluid and the rheological and filtration properties of fluid was measured for both deionized water and salty water. The results show that by adding 57% of 1:3 Fe3O4-CMC nanocomposite ratio to basic drilling fluid, in addition to considerable improvement in the viscosity, the filtration volume and cake thickness decreased noticeably. This formulation depicts non-Newtonian rheological behavior which could be illustrated properly by Herschel-Bulkley rheological model. Thus, exploitation of Fe3O4-CMC nanocomposite as an additive in waterbased drilling fluid for fluid loss control would have advantageous due to its distinctive properties like enhanced resistance to water penetration and enhanced viscosity in both deionized water and salty water. In addition, the Fe3O4-CMC nanocomposite has superior properties such as uncomplicated synthesis method and being financially available in comparison to conventional additives.",4,4,4
Drilling Fluid,Nanoparticles,"Edalatfar, Maryam; Yazdani, Farshad; Salehi, Mahsa Baghban",Synthesis and identification of ZnTiO3 nanoparticles as a rheology modifier additive in water-based drilling mud,Water-based drilling fluid; ZnTiO3 nanoparticles; KCl effect; Rheology,ZNO NANOFLUIDS; BENTONITE; FLUIDS; NANOCOMPOSITE; TEMPERATURE; FORMULATION; CUO,"Performing drilling operations to explore and exploit oil and gas reservoirs by injection wells is one of the most essential pillars of the oil industry. Hence, the improvement of drilling mud properties has a particular role. In this research, a laboratory study was carried out on the effect of nano additive on rheological properties of drilling mud. The ZnTiO3 nanoparticles were synthesized and analyzed by XRD, EDX, and SEM to identify and verify the structure of particles in the nanoscale. Then, the effect of adding nanoparticles to water-base mud is discussed. To determine the rheological behavior of the mud, the viscosity tests were applied. To study the operational conditions on the performance of mud containing nanoparticles, the rheological tests were performed on samples containing 0, 0.5, and 1 wt% of ZnTiO3 nanoparticles in the presence of 0, 2, 4 wt% of KCl salt at 25 degrees C and 90 degrees C. The results indicated that the addition of 1 wt% ZnTiO3 nanoparticles, even in the presence of 2 and 4% salt, could increase water-based mud viscosity up to 34.88% and 37.73%, at 25 degrees C and 32.16% and 30.76% at 90 degrees C, respectively. It was well able to maintain the shear-thinning behavior of mud contained nanoparticles at different shear rates. The optimum sample was finalized based on a rheological study with 5 wt % bentonite, 2 wt% salt, and 1 wt% ZnTiO3 nanoparticles. Performing filtration test on the optimal sample, using a filter press machine based on the American Petroleum Association Standard, it was confirmed that the addition of 1 wt% ZnTiO3 nanoparticles to mud was reduced the volume of fluid loss by about 7.7%. Finally, all results of mud samples viscosity were fitted with plastic Bingham, Herschel-Bulkley, and Power-law models. Through Herschel-Bulkley, and Power-law models could reasonably predict the rheological behavior of mud contained nanoparticles.",4,4,1
Drilling Fluid,Nanoparticles,"Zhang, Rui; Bo, Kehao; Liu, Zehua",A method of sizing plugging nanoparticles to prevent water invasion for shale wellbore stability based on CFD-DEM simulation,Plugging shale pores; Nanoparticles; Shale wellbore instability; CFD-DEM; Particles selection method,DISCRETE ELEMENT SIMULATION; FORMATION DAMAGE; MICROPARTICLE; MODEL; OIL,"Plugging shale pores and throats with nanoparticles is an efficient and economic method of preventing water invasion to sustain shale wellbore stability. The nanoparticles size distribution is the key factor affecting plugging performance. Currently, the selection of nanoparticle size is usually based on empirical plugging rules and qualitative evaluation experiments. Experimental evaluations only can reflect the macroscopic plugging performance, but cannot reveal the microscopic plugging mechanism. In addition, the experiment for shale pores plugging is complicated and costly. Thus, it is very meaningful to propose a new method for sizing plugging nanoparticles based on simulation. The essence of particles plugging process actually is the interactions of particle-particle, particle-rock and particle-fluid. In this paper, the thought of discrete element method is adopted and the plugging nanoparticles are treated as discrete elements. A coupled computational fluid dynamics-discrete element method (CFD-DEM) model is constructed to describe the motion behaviors of nanoparticles (discrete elements) in the process of plugging shale pores. In this model, taking into account the flow action of drilling fluid and the nanoscale effect of nanoparticles, the major considered forces include inter-particle forces (i.e. elastic contact force, friction force and Van der Waals force), hydrodynamic forces (i.e. drag force, Magnus force, buoyancy force and pressure gradient force) and gravitational force. Furthermore, a plugging criterion is established to check the particles plugging status through monitoring the microscopic movements of nanoparticles. Moreover, three evaluation indexes (i.e. porosity reduction of shale, permeability and porosity of external plugging layer, plugging ratio) are proposed to evaluate the macroscopic plugging performances of nanoparticles. Based on the constructed computational model, microscopic plugging criterion and macroscopic plugging performance evaluation indexes, a novel method of sizing plugging nanoparticles to prevent water invasion for shale wellbore stability is developed. In addition, the validation of the method is conducted and the results are similar to the previous results of plugging experiments. The proposed method can give support to the selection of plugging nanoparticles size through obtaining the microscopic plugging behaviors and macroscopic plugging performances of nanoparticles. And it can also be regarded as a fundamental method to study other kinds of particles plugging problems, such as formation damage and optimization of lost circulation materials.",3,4,5
Drilling Fluid,Degrees C.,"Perumalsamy, Jayachandran; Gupta, Pawan; Sangwai, Jitendra S.",Performance evaluation of esters and graphene nanoparticles as an additives on the rheological and lubrication properties of water-based drilling mud,Ester; Lubricity; Graphene nano-particle; Rheology; Water-based mud,FLUIDS; ENHANCEMENT; POLYMER,"In the practice of drilling horizontal, directional, and unstable well profiles, the friction produced by bit balling, wellbore instability, cavings, and dog-legs resulted in excessive torque and drag. The friction along with high torque and drag, which results from the drill string, casing, and wellbore contact, leads to pipe stucks, overpulls during tripping-outs, and even closure of the oil and gas well. Heat generated from metal contact between casing and drill string is the cause of wear of drill string and casing. Oil-based drilling fluids are identified to produce minimum friction and torque than that of water-based drilling fluid/mud (WBM). However, the use of oil-based drilling fluids is becoming obsolete due to stringent environmental regulations. Therefore, it is critical to identify and design a water-based drilling mud with lubricant additives that are environmentally friendly, cost-effective, and give better lubrication similar to oil-based and synthetic-based drilling fluid. The objective of this study is to investigate the effect of two additives PC60 (the product of the reaction of glycerol + tall oil fatty acid) and graphene nanoparticles on the rheological and lubrication properties of water-based drilling fluid. All together total 14 drilling fluid samples have been prepared for the detailed analysis. Extensive experimental work has been done to study the effect of lubricant additives (PC60 and graphene nanoparticles) on the rheology and lubrication of various WBMs with different additive concentrations (1, 2, and 3% by volume) at 30, 60, and 90 degrees C. All samples were investigated for their rheology, viscoelastic behavior, and lubrication properties before and after hot rolling. The experimental data generated in this work have been successfully utilized to find various fitting parameter for the Bingham plastic rheological model, followed by a discussion on foaming tendency of the samples and effect of pH on the rheological stability of drilling fluid. Subsequently, a relationship between the coefficient of friction (in the presence of different lubricant additives in the mud) and rheological properties (plastic viscosity and yield point) of different drilling fluid samples have been proposed.",5,5,12
Drilling Fluid,Degrees C.,"Ansari, Manizheh; Turney, Damon E.; Morris, Jeffrey; Banerjee, Sanjoy",Investigations of rheology and a link to microstructure of oil-based drilling fluids,Oil-based drilling fluid; Rheology; Microstructure; Yield stress fluids,YIELD-STRESS; ORGANO-MONTMORILLONITE,"Towards establishing a first-principles physical link between the field-behavior and microstructure of oil-based drilling fluid (OBDF), we study rheology of an OBDF and its variation with different contents of water, clay viscosifier, or barite weighting agent during steady and dynamic rheological phenomena, and develop a ""cryo-preserved"" experimental methodology towards in-situ microscopy. Rheological data was collected for shear rate ramps between 0.0001 s and 1 and 1000 s(-1), under temperatures ranging from 10 degrees C to 60 degrees C, with three water/oil ratios, and multiple OBDF compositions. Oscillatory and constant shear rate measurements showed elastic and loss modulus co-dominate when stress is below -1 Pa, but above a similar to 1 Pa ""apparent yield-stress"" the fluid microstructure reorganizes, elasticity decreases, and the flow follows a viscosity-dominated shear-thinning Herschel-Bulkley behavior. Signs of thixotropy are seen in increasing vs. decreasing flow curves when in the elastic regime, and elasticity shows time-dependency. Clay particles created elasticity more so than the other ingredients. Elimination of water, clay, or barite caused an approximately equal reduction of viscosity Elimination of water also led to elastic modulus dominating over viscous modulus for a longer range of strain in the linear-elastic pre-yield state, likely due to water droplets having a shorter length scale over which yield-stress is broken than does a water-free mixture. Elimination of barite had a similar but lesser effect on elasticity. Cryological scanning electron microscopy (Cryo-SEM) and cryological x-ray spectroscopy (Cryo-EDS) methods show promise for future work to identify the spatial microstructure of the OBDF at nanometer to micrometer scales in a ""cryo-preserved"" state that approximates an in-situ like state. Chemical identification of individual phases within the mixture components is achieved via a quantitative elemental method. Water droplets, base oil, and barite are identifiable and future methods for in-situ imaging of sheared OBDFs is proposed.",4,4,3
Drilling Fluid,Degrees C.,"Mussa, Agostinho; Kalkreuth, Wolfgang; Pimentel Mizusaki, Ana Maria; Bicca, Marcos Muller; Bojesen-Koefoed, Jorgen A.","Geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation",Parnaiba basin; Pimenteiras formation; Hydrocarbon generation; Geochemistry; Petrology; Palynofacies,,"The Paleozoic-Mesozoic Parnaiba Basin is an intraplate volcano-sedimentary basin from which the Pimenteiras Formation (Devonian) has potential for hydrocarbon generation, mainly natural gas. The thermal influence of igneous intrusions contributes to hydrocarbon generation in the basin. This present paper provides a geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation using geochemical and petrographic parameters. A total of 60 shale samples of the Pimenteiras Formation from three wells underwent analysis for TOC content, Rock-Eval pyrolysis, x-ray diffraction, organic petrology and palynofacies. The TOC content varies from 1.54 to 16.60 wt%, with the variations being related to different conditions of accumulation and preservation of the organic matter. The S-1 values range between 4.20 and 51.43 mg HC/g rock, with an average of 14.9 mg HC/g rock, and S-2 varies between 3.41 and 16.28 mg HC/g rock, with an average of 7.3 mg HC/g rock, showing very good to excellent source rock potential. The low Tmax values with an average of 430 degrees C indicate immaturity despite the high S-1 and S-2 values. The high S-1 values can be related to natural impregnation or contamination by drilling fluids. The HI vs Tmax plot showing the presence of kerogen type II and III, with potential for oil and gas generation. The mineral assemblage is associated with diagenetic or thermal processes (illite) and oxidation conditions (hematite and pyrite). The talc and chlorite can be related to metamorphism and provenance, while the calcite and gypsum indicate evaporitic conditions. The vitrinite reflectance varies between 0.31 and 0.67% Rrandom (average of 0.55% Rrandom). Thus, the samples can be classified as immature and mature and are consistent with Tmax values. The palynological records show a significant presence of phytoclasts and variations of palynomorphs along with the sequences from top to bottom, suggesting a transitional depositional environment (marine and continental) associated with the Devonian transgressive-regressive cycles. The data reinforce that the Pimenteiras Formation has the potential for hydrocarbon generation, mainly gas.",4,4,2
Drilling Fluid,Degrees C.,"Edalatfar, Maryam; Yazdani, Farshad; Salehi, Mahsa Baghban",Synthesis and identification of ZnTiO3 nanoparticles as a rheology modifier additive in water-based drilling mud,Water-based drilling fluid; ZnTiO3 nanoparticles; KCl effect; Rheology,ZNO NANOFLUIDS; BENTONITE; FLUIDS; NANOCOMPOSITE; TEMPERATURE; FORMULATION; CUO,"Performing drilling operations to explore and exploit oil and gas reservoirs by injection wells is one of the most essential pillars of the oil industry. Hence, the improvement of drilling mud properties has a particular role. In this research, a laboratory study was carried out on the effect of nano additive on rheological properties of drilling mud. The ZnTiO3 nanoparticles were synthesized and analyzed by XRD, EDX, and SEM to identify and verify the structure of particles in the nanoscale. Then, the effect of adding nanoparticles to water-base mud is discussed. To determine the rheological behavior of the mud, the viscosity tests were applied. To study the operational conditions on the performance of mud containing nanoparticles, the rheological tests were performed on samples containing 0, 0.5, and 1 wt% of ZnTiO3 nanoparticles in the presence of 0, 2, 4 wt% of KCl salt at 25 degrees C and 90 degrees C. The results indicated that the addition of 1 wt% ZnTiO3 nanoparticles, even in the presence of 2 and 4% salt, could increase water-based mud viscosity up to 34.88% and 37.73%, at 25 degrees C and 32.16% and 30.76% at 90 degrees C, respectively. It was well able to maintain the shear-thinning behavior of mud contained nanoparticles at different shear rates. The optimum sample was finalized based on a rheological study with 5 wt % bentonite, 2 wt% salt, and 1 wt% ZnTiO3 nanoparticles. Performing filtration test on the optimal sample, using a filter press machine based on the American Petroleum Association Standard, it was confirmed that the addition of 1 wt% ZnTiO3 nanoparticles to mud was reduced the volume of fluid loss by about 7.7%. Finally, all results of mud samples viscosity were fitted with plastic Bingham, Herschel-Bulkley, and Power-law models. Through Herschel-Bulkley, and Power-law models could reasonably predict the rheological behavior of mud contained nanoparticles.",4,4,1
Drilling Fluid,Lost Circulation,"Sabah, Mohammad; Mehrad, Mohammad; Ashrafi, Seyed Babak; Wood, David A.; Fathi, Shadi",Hybrid machine learning algorithms to enhance lost-circulation prediction and management in the Marun oil field,Lost circulation while drilling; Multilayer perception; Least square support vector machine; Evolutionary algorithms; Marun oil field,ARTIFICIAL NEURAL-NETWORKS; SUPPORT VECTOR MACHINE; MULTILAYER PERCEPTRON; OPTIMIZATION; MODELS; RESERVOIR; ASMARI,"Drilling fluid loss of circulation is a challenging issue to resolve for many oil and gas wells as drilling progresses. It imposes enormous expenses on drilling industry. One of the common practices to solve this problem or make it less severe is introducing various loss circulation materials (LCM) into the circulating drilling fluid. The ability to predict the amount of mud loss before drilling a particular formation would provide engineers with invaluable information to assist them in selecting appropriate LCM properties such as particle size distribution. In this study, a number of heuristic search algorithms including genetic algorithm (GA), particle swarm size (PSO), and cuckoo search algorithm (COA) are combined with two machine-learning techniques namely multilayer perception (MLP) neural network and least square support vector machine (LSSVM) to present different hybrid algorithms in prediction of lost circulation. The established database consists of 2820 cases (datasets) extracted from available drilling reports of 305 drilled wells in the Marun oil field. These datasets are associated with drilling operation variables, formation specifications, and drilling mud characteristics which totally include 18 input variables and 1 output. Pre-processing of data involves filtering with Savitzky-Golay (SG) filter and ranking features using wrapper method. Results show that hybrid intelligent models are highly capable of predicting lost circulation before drilling a certain formation. Furthermore, LSSVM-COA and LSSVM-PSO achieve coefficients of determination of 0.9424 and 0.9391, respectively, making them the two most accurate models. GA cannot match the prediction performance of the other two algorithms in enhancing machine-learning techniques for this purpose. MLP-GA with a coefficient of determination (R-2) and RMSE of 0.9304 and 25.26 (bbl/hr), respectively, yields the weakest prediction performance. Hybrid intelligent models, coupling optimizers and machine learning algorithms show themselves to be superior to applying standalone machine-learning methodologies for predicting loss of circulation.",13,13,6
Drilling Fluid,Lost Circulation,"Magzoub, Musaab, I; Shamlooh, Mohamed; Salehi, Saeed; Hussein, Ibnelwaleed; Nasser, Mustafa S.",Gelation kinetics of PAM/PEI based drilling mud for lost circulation applications,Lost circulation; Gelation kinetics; Polyacrylamide; Polyethylenimine; Crosslinking; Rheology,,"The problem of lost circulation is a direct consequence of the presence of fractures or high permeability. Lost circulation material (LCM) is used to treat the loss that occurs or proactively strengthen the wellbore of the potential loss zones. The polyacrylamide (PAM)/Polyethylenimine (PEI) cross-linkable polymer gel is proven to work best in zone-sealing and plugging applications. In addition to their thermal stability, the fact that these gels are flexible gives them the advantage of deforming and sealing-off multiple and complex near wellbore fractures. The primary objective of this study is to investigate the gelation kinetics of the PAM/PEI cross-linkable polymer to be used in drilling fluids formulations to enhance wellbore stability and strength. Different combinations of polymers and crosslinkers were evaluated; potential polymers were screened for gelation kinetics and gel strength in typical drilling mud formulations. The gelation time of the polymer-based drilling mud formulation is determined in salt-free and in saline systems. The results on rheological properties and gelation kinetics were used to prepare a gelling mud formulation using PAM/PEI cross-linkable polymer as LCM. The produced gel was thermally stable under high-temperature-high-pressure reservoir conditions, which will result in enhanced wellbore strengthening.",5,5,3
Drilling Fluid,Lost Circulation,"Zhang, Rui; Bo, Kehao; Liu, Zehua",A method of sizing plugging nanoparticles to prevent water invasion for shale wellbore stability based on CFD-DEM simulation,Plugging shale pores; Nanoparticles; Shale wellbore instability; CFD-DEM; Particles selection method,DISCRETE ELEMENT SIMULATION; FORMATION DAMAGE; MICROPARTICLE; MODEL; OIL,"Plugging shale pores and throats with nanoparticles is an efficient and economic method of preventing water invasion to sustain shale wellbore stability. The nanoparticles size distribution is the key factor affecting plugging performance. Currently, the selection of nanoparticle size is usually based on empirical plugging rules and qualitative evaluation experiments. Experimental evaluations only can reflect the macroscopic plugging performance, but cannot reveal the microscopic plugging mechanism. In addition, the experiment for shale pores plugging is complicated and costly. Thus, it is very meaningful to propose a new method for sizing plugging nanoparticles based on simulation. The essence of particles plugging process actually is the interactions of particle-particle, particle-rock and particle-fluid. In this paper, the thought of discrete element method is adopted and the plugging nanoparticles are treated as discrete elements. A coupled computational fluid dynamics-discrete element method (CFD-DEM) model is constructed to describe the motion behaviors of nanoparticles (discrete elements) in the process of plugging shale pores. In this model, taking into account the flow action of drilling fluid and the nanoscale effect of nanoparticles, the major considered forces include inter-particle forces (i.e. elastic contact force, friction force and Van der Waals force), hydrodynamic forces (i.e. drag force, Magnus force, buoyancy force and pressure gradient force) and gravitational force. Furthermore, a plugging criterion is established to check the particles plugging status through monitoring the microscopic movements of nanoparticles. Moreover, three evaluation indexes (i.e. porosity reduction of shale, permeability and porosity of external plugging layer, plugging ratio) are proposed to evaluate the macroscopic plugging performances of nanoparticles. Based on the constructed computational model, microscopic plugging criterion and macroscopic plugging performance evaluation indexes, a novel method of sizing plugging nanoparticles to prevent water invasion for shale wellbore stability is developed. In addition, the validation of the method is conducted and the results are similar to the previous results of plugging experiments. The proposed method can give support to the selection of plugging nanoparticles size through obtaining the microscopic plugging behaviors and macroscopic plugging performances of nanoparticles. And it can also be regarded as a fundamental method to study other kinds of particles plugging problems, such as formation damage and optimization of lost circulation materials.",3,4,5
Drilling Fluid,Plugging,"Magzoub, Musaab, I; Shamlooh, Mohamed; Salehi, Saeed; Hussein, Ibnelwaleed; Nasser, Mustafa S.",Gelation kinetics of PAM/PEI based drilling mud for lost circulation applications,Lost circulation; Gelation kinetics; Polyacrylamide; Polyethylenimine; Crosslinking; Rheology,,"The problem of lost circulation is a direct consequence of the presence of fractures or high permeability. Lost circulation material (LCM) is used to treat the loss that occurs or proactively strengthen the wellbore of the potential loss zones. The polyacrylamide (PAM)/Polyethylenimine (PEI) cross-linkable polymer gel is proven to work best in zone-sealing and plugging applications. In addition to their thermal stability, the fact that these gels are flexible gives them the advantage of deforming and sealing-off multiple and complex near wellbore fractures. The primary objective of this study is to investigate the gelation kinetics of the PAM/PEI cross-linkable polymer to be used in drilling fluids formulations to enhance wellbore stability and strength. Different combinations of polymers and crosslinkers were evaluated; potential polymers were screened for gelation kinetics and gel strength in typical drilling mud formulations. The gelation time of the polymer-based drilling mud formulation is determined in salt-free and in saline systems. The results on rheological properties and gelation kinetics were used to prepare a gelling mud formulation using PAM/PEI cross-linkable polymer as LCM. The produced gel was thermally stable under high-temperature-high-pressure reservoir conditions, which will result in enhanced wellbore strengthening.",5,5,3
Drilling Fluid,Plugging,"Zhang, Rui; Bo, Kehao; Liu, Zehua",A method of sizing plugging nanoparticles to prevent water invasion for shale wellbore stability based on CFD-DEM simulation,Plugging shale pores; Nanoparticles; Shale wellbore instability; CFD-DEM; Particles selection method,DISCRETE ELEMENT SIMULATION; FORMATION DAMAGE; MICROPARTICLE; MODEL; OIL,"Plugging shale pores and throats with nanoparticles is an efficient and economic method of preventing water invasion to sustain shale wellbore stability. The nanoparticles size distribution is the key factor affecting plugging performance. Currently, the selection of nanoparticle size is usually based on empirical plugging rules and qualitative evaluation experiments. Experimental evaluations only can reflect the macroscopic plugging performance, but cannot reveal the microscopic plugging mechanism. In addition, the experiment for shale pores plugging is complicated and costly. Thus, it is very meaningful to propose a new method for sizing plugging nanoparticles based on simulation. The essence of particles plugging process actually is the interactions of particle-particle, particle-rock and particle-fluid. In this paper, the thought of discrete element method is adopted and the plugging nanoparticles are treated as discrete elements. A coupled computational fluid dynamics-discrete element method (CFD-DEM) model is constructed to describe the motion behaviors of nanoparticles (discrete elements) in the process of plugging shale pores. In this model, taking into account the flow action of drilling fluid and the nanoscale effect of nanoparticles, the major considered forces include inter-particle forces (i.e. elastic contact force, friction force and Van der Waals force), hydrodynamic forces (i.e. drag force, Magnus force, buoyancy force and pressure gradient force) and gravitational force. Furthermore, a plugging criterion is established to check the particles plugging status through monitoring the microscopic movements of nanoparticles. Moreover, three evaluation indexes (i.e. porosity reduction of shale, permeability and porosity of external plugging layer, plugging ratio) are proposed to evaluate the macroscopic plugging performances of nanoparticles. Based on the constructed computational model, microscopic plugging criterion and macroscopic plugging performance evaluation indexes, a novel method of sizing plugging nanoparticles to prevent water invasion for shale wellbore stability is developed. In addition, the validation of the method is conducted and the results are similar to the previous results of plugging experiments. The proposed method can give support to the selection of plugging nanoparticles size through obtaining the microscopic plugging behaviors and macroscopic plugging performances of nanoparticles. And it can also be regarded as a fundamental method to study other kinds of particles plugging problems, such as formation damage and optimization of lost circulation materials.",3,4,5
Drilling Fluid,Cuttings,"Awad, Abdelrahman M.; Hussein, Ibnelwaleed A.; Nasser, Mustafa S.; Karami, Hamidreza; Ahmed, Ramadan",CFD modeling of particle settling in drilling fluids: Impact of fluid rheology and particle characteristics,Particle settling; Cuttings shape; Drilling fluid; Aspect ratio; Drag coefficient; Particle size distribution,,"The settling of drilling cuttings is important for the drilling and clean-out operations. The current article provides a Computational Fluid Dynamics (CFD) modeling study of particle settling behavior during the drilling operations, with a special focus on the impact of fluid rheology, flow regime, particle size and shape on the settling rate. The Eulerian-Lagrangian method are adopted to track particle trajectories in a shear-thinning fluid under quiescent conditions. The rheological properties of the drilling fluids are described by different rheological models. Settling of spherical and ellipsoidal cuttings, with various aspect ratios, is studied for particles with a diameter ranging between 2 and 6 mm. The settling behavior is predicted for particles with narrow (0.5-2 mm), medium (0.5-6 mm) and broad (0.5-10 mm) particle size distributions (PSD). Applying a non-Newtonian powerlaw model at low shear rates, where the fluid is in the Newtonian regime, resulted in 11-19% over-prediction of settling velocities as compared to the experimental data. On the other hand, ignoring the particle-induced shear rate by assuming a Newtonian fluid behavior in the transition regime showed 8-10% difference between the estimated and experimental settling rates. Therefore, the CFD computations of settling rates suggest that Cross and Carreau models provide more accurate predictions than a simple power-law model. The selection of the suitable rheological model is a key factor in predicting settling in drilling fluids. This is more important for small particles where the Newtonian behavior is dominant and particle-induced shear rate is low. Ellipsoidal cuttings exhibited significantly greater resistance to settling as compared to spherical particles, mainly due to the increased drag force. Further, the terminal settling velocity of ellipsoidal cuttings consistently increased with the particle aspect ratio. Cuttings with broad PSD showed similar to 32 times higher settling velocity than particles with narrow PSD. CFD results are validated with experimental measurements. Moreover, results for settling of non-spherical particles are validated with an empirical correlation. Agreement of experimental and theoretical predictions is observed when the fluid and flow regimes are well identified and described.",4,4,9
Drilling Fluid,Cuttings,"Wang, Shuyan; Wang, Yulin; Wang, Ruichen; Yuan, Zihan; Chen, Yujia; Shao, Baoli; Ma, Yimei",Simulation study on cutting transport in a horizontal well with hydraulic pulsed jet technology,Hydraulic pulsed jet technology; Cuttings migration; Horizontal well; Numerical simulation,DRILL PIPE ROTATION; NUMERICAL-ANALYSIS; STRING VIBRATION; PENETRATION RATE; KINETIC-THEORY; FLOW-FIELD; CFD; MODEL; FLUID; EFFICIENCY,"The hydraulic pulse jet is a high-efficiency drilling technology to improve the efficiency of bottom-hole cuttings removal by enhancing the down-hole flow of cuttings. In this paper, an Eulerian-Eulerian two-fluid model on the basis of the kinetic theory of granular flow is applied to simulate the flow behavior of cuttings and drilling fluid in a horizontal well with hydraulic pulsed jet technology. The influences of pulse jet velocity, amplitude, and frequency on hydrodynamic characteristics are analyzed. Increasing the pulse jet velocity can generate higher pressure and crossflow velocity in the bottom-hole area, quickly carry the cuttings out of the bottom-hole area, and form the cuttings bed near the outlet. The improvement of the amplitude of the pulsed jet can form a remarkable and deep jet penetration in the bottom-hole area, which has a positive effect on the cuttings migration at the bottom-hole area and destruction of the cuttings bed in the annulus. For a given average jet velocity in this paper, the optimal value of amplitude is a half of the average jet velocity. The pulse jet frequency has little effect on cuttings migration in the bottom-hole area, while a higher pulse jet frequency can effectively reduce the height of the cuttings bed in the annulus.",3,3,7
Drilling Fluid,Horizontal Stresses,"Mohamadian, Nima; Ghorbani, Hamzeh; Wood, David A.; Mehrad, Mohammad; Davoodi, Shadfar; Rashidi, Sina; Soleimanian, Alireza; Shahvand, Amirafzal Kiani",A geomechanical approach to casing collapse prediction in oil and gas wells aided by machine learning,Hybrid multi-layer perceptron's; Wellbore casing collapse; Maximum horizontal stress; Poisson's ratio; Gachsaran formation; Geomechanical sub-surface model,EMPIRICAL RELATIONS; CREEP-BEHAVIOR; FLOW RATES; RESERVOIRS; MECHANISM; NETWORKS; STRENGTH; FAILURE; ROCK,"The casing-collapse hazard is one that drilling engineers seek to mitigate with careful well design and operating procedures. However, certain rock formations and their fluid pressure and stress conditions are more prone to casing-collapse risks than others. The Gachsaran Formation in south west Iran, is one such formation, central to oil and gas resource exploration and development in the Zagros region and consisting of complex alternations of anhydrite, marl and salt. The casing-collapse incidents in this formation have resulted over decades in substantial lost production and remedial costs to mitigate the issues surrounding wells with failed casing string. High and vertically-varying horizontal stresses across the Gachsaran formation are the challenge to predict and overcome. This study investigates casing collapse in wellbores from an established petroleum geomechanics perspective to develop and compare two hybrid neural-network models, multilayer perceptron's tuned, respectively, with a genetic algorithm (MLP-GA) and a particle swarm algorithm (MLP-PSO). These machine-learning algorithms are configured to predict Poisson's ratio (theta) and maximum horizontal stress (sigma(H)) from available well-log input data. A large dataset from three wellbores drilled though the Gachsaran Formation in the Marun oil field, the second largest in Iran, is used to construct and validate the hybrid MLP models. In the first step, 22323 data records from a collapsed wellbore are divided into training (15626 records; 70%) and independent testing subsets (6697 records; 30%). In the next step, in order to test whether the suggested algorithms could be generalized, the data sets of the other two wells in the field were tested. Those tests confirmed that the algorithms achieved high prediction accuracy for Poisson's ratio and maximum horizontal stress in other wellbores.",14,14,10
Drilling Fluid,Horizontal Stresses,"Lai, Jin; Chen, Kangjun; Xin, Yi; Wu, Xingneng; Chen, Xu; Yang, Kefu; Song, Qiuqiang; Wang, Guiwen; Ding, Xiujian","Fracture characterization and detection in the deep Cambrian dolostones in the Tarim Basin, China: Insights from borehole image and sonic logs",Fractures; In-situ stress; Dolostones; Dissolution; Well log expression; Tarim basin,LOWER ORDOVICIAN CARBONATES; TRIASSIC YANCHANG FORMATION; ORDOS BASIN; DOLOMITE RESERVOIRS; NW CHINA; SICHUAN BASIN; HYDROTHERMAL ALTERATION; FORMATION MECHANISM; DENSITY-ESTIMATION; SHALE RESERVOIRS,"Characterization and detection of natural fractures using well logs in ancient deeply buried dolostones with low matrix porosity are very difficult. Core description, thin section analysis, conventional well logs, borehole image and sonic logs are used to document distribution of fractures in deep Cambrian dolostones in the Tarim Basin, China. The SHmax (maximum horizontal stress) direction is determined from drilling induced fractures, borehole breakouts and shear wave birefringence. Natural fractures with various attributes (open to partly open to closed) and orientation (including dip angles) are recognized. Natural fractures are classified into closed fractures, partly closed fractures, vuggy fractures and open fractures, and they can be further classified into high angle fractures, low-medium dip angle fractures, and low angle or horizontal fractures. Natural fractures are mainly associated with the more brittle rocks (dolograinstone, fine-medium-coarse crystalline dolostones), while fractures in dolomicrites and evaporitic gypsums-bearing dolostones are rare. Open to closed fractures are recognized as dark to bright sine waves on image logs, and the presences of open fractures cause minor deviations on the DEN logs, but significant deviations in resistivity values, while AC will be significantly increased in front of fractures. The energy of sonic full-waveforms will be strongly attenuated in front of open fractures. Fractures with strike parallel to the SHmax tend to have large aperture and good connectivity, and are suggested to enhance hydrocarbon productivity. Dolostones adjacent to the deep faults are heavily fractured, and fractures act as the hydrothermal fluid flow pathways, facilitating dissolution process. The abundance of vuggy fractures, and enlargement of the pre-existing microfractures support that fractures had enhanced dissolution. The dissolution along fracture surfaces helps increase fracture porosity. The results of this study about subsurface fracture patterns and their distributions are important for the hydrocarbon exploration and production in the Cambrian dolostones in the Tarim Basin.",4,6,4
Drilling Fluid,"Loss Modulus,Microstructure","Murtaza, Mobeen; Tariq, Zeeshan; Zhou, Xianmin; Al-Shehri, Dhafer; Mahmoud, Mohamed; Kamal, Muhammad Shahzad",Okra as an environment-friendly fluid loss control additive for drilling fluids: Experimental & modeling studies,Drilling fluids; Viscosifier; Fluid loss controller; ANN; Okra,BENTONITE DISPERSIONS; SILICA,"Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. It is also environment friendly and available in abundance, especially in tropical and subtropical regions. To the best of our knowledge, this is the first report on the application of the okra solution as a fluid loss control additive in drilling fluids. The okra powder was characterized by X-ray fluorescence, Fourier-transform infrared spectroscopy, and scanning electron microscopy. The thermal stability of okra was tested using thermal gravimetric analysis. The microstructure stability of the okra-based solution was analyzed using shear and loss modulus. The okra powder was used in different concentrations (0.25, 0.5, & 1) wt% in a clay free water-based drilling fluid formulation. The experimental study revealed that the addition of 1 wt% okra solution could reduce 20% fluid loss. The okra showed comparable performance compared to the conventional fluid loss control additive, starch. The main advantage was that okra has less impact on rheological properties compared to starch. TGA analysis of okra powder showed that it has strong thermal stability. The pH test showed that okra powder could not affect the pH of the solution. The shear and loss modulus tests revealed that the water-based drilling fluid samples with higher okra powder concentrations could develop a more stable microstructure. Overall, the experimental results suggest that okra containing drilling fluids can be used as an alternate solution to starch in drilling fluids without compromising other drilling fluids' properties. A Machine Learning (ML)-based rheological model was also developed to predict the rheological properties of okra-based drilling fluid formulations. The proposed ML model can predict the rheological properties of Okra-based drilling fluids with high accuracy.",4,4,5
Drilling Fluid,"Loss Modulus,Microstructure","Ansari, Manizheh; Turney, Damon E.; Morris, Jeffrey; Banerjee, Sanjoy",Investigations of rheology and a link to microstructure of oil-based drilling fluids,Oil-based drilling fluid; Rheology; Microstructure; Yield stress fluids,YIELD-STRESS; ORGANO-MONTMORILLONITE,"Towards establishing a first-principles physical link between the field-behavior and microstructure of oil-based drilling fluid (OBDF), we study rheology of an OBDF and its variation with different contents of water, clay viscosifier, or barite weighting agent during steady and dynamic rheological phenomena, and develop a ""cryo-preserved"" experimental methodology towards in-situ microscopy. Rheological data was collected for shear rate ramps between 0.0001 s and 1 and 1000 s(-1), under temperatures ranging from 10 degrees C to 60 degrees C, with three water/oil ratios, and multiple OBDF compositions. Oscillatory and constant shear rate measurements showed elastic and loss modulus co-dominate when stress is below -1 Pa, but above a similar to 1 Pa ""apparent yield-stress"" the fluid microstructure reorganizes, elasticity decreases, and the flow follows a viscosity-dominated shear-thinning Herschel-Bulkley behavior. Signs of thixotropy are seen in increasing vs. decreasing flow curves when in the elastic regime, and elasticity shows time-dependency. Clay particles created elasticity more so than the other ingredients. Elimination of water, clay, or barite caused an approximately equal reduction of viscosity Elimination of water also led to elastic modulus dominating over viscous modulus for a longer range of strain in the linear-elastic pre-yield state, likely due to water droplets having a shorter length scale over which yield-stress is broken than does a water-free mixture. Elimination of barite had a similar but lesser effect on elasticity. Cryological scanning electron microscopy (Cryo-SEM) and cryological x-ray spectroscopy (Cryo-EDS) methods show promise for future work to identify the spatial microstructure of the OBDF at nanometer to micrometer scales in a ""cryo-preserved"" state that approximates an in-situ like state. Chemical identification of individual phases within the mixture components is achieved via a quantitative elemental method. Water droplets, base oil, and barite are identifiable and future methods for in-situ imaging of sheared OBDFs is proposed.",4,4,3
Drilling Fluid,Thermal Stability,"Magzoub, Musaab, I; Shamlooh, Mohamed; Salehi, Saeed; Hussein, Ibnelwaleed; Nasser, Mustafa S.",Gelation kinetics of PAM/PEI based drilling mud for lost circulation applications,Lost circulation; Gelation kinetics; Polyacrylamide; Polyethylenimine; Crosslinking; Rheology,,"The problem of lost circulation is a direct consequence of the presence of fractures or high permeability. Lost circulation material (LCM) is used to treat the loss that occurs or proactively strengthen the wellbore of the potential loss zones. The polyacrylamide (PAM)/Polyethylenimine (PEI) cross-linkable polymer gel is proven to work best in zone-sealing and plugging applications. In addition to their thermal stability, the fact that these gels are flexible gives them the advantage of deforming and sealing-off multiple and complex near wellbore fractures. The primary objective of this study is to investigate the gelation kinetics of the PAM/PEI cross-linkable polymer to be used in drilling fluids formulations to enhance wellbore stability and strength. Different combinations of polymers and crosslinkers were evaluated; potential polymers were screened for gelation kinetics and gel strength in typical drilling mud formulations. The gelation time of the polymer-based drilling mud formulation is determined in salt-free and in saline systems. The results on rheological properties and gelation kinetics were used to prepare a gelling mud formulation using PAM/PEI cross-linkable polymer as LCM. The produced gel was thermally stable under high-temperature-high-pressure reservoir conditions, which will result in enhanced wellbore strengthening.",5,5,3
Drilling Fluid,Thermal Stability,"Murtaza, Mobeen; Tariq, Zeeshan; Zhou, Xianmin; Al-Shehri, Dhafer; Mahmoud, Mohamed; Kamal, Muhammad Shahzad",Okra as an environment-friendly fluid loss control additive for drilling fluids: Experimental & modeling studies,Drilling fluids; Viscosifier; Fluid loss controller; ANN; Okra,BENTONITE DISPERSIONS; SILICA,"Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. It is also environment friendly and available in abundance, especially in tropical and subtropical regions. To the best of our knowledge, this is the first report on the application of the okra solution as a fluid loss control additive in drilling fluids. The okra powder was characterized by X-ray fluorescence, Fourier-transform infrared spectroscopy, and scanning electron microscopy. The thermal stability of okra was tested using thermal gravimetric analysis. The microstructure stability of the okra-based solution was analyzed using shear and loss modulus. The okra powder was used in different concentrations (0.25, 0.5, & 1) wt% in a clay free water-based drilling fluid formulation. The experimental study revealed that the addition of 1 wt% okra solution could reduce 20% fluid loss. The okra showed comparable performance compared to the conventional fluid loss control additive, starch. The main advantage was that okra has less impact on rheological properties compared to starch. TGA analysis of okra powder showed that it has strong thermal stability. The pH test showed that okra powder could not affect the pH of the solution. The shear and loss modulus tests revealed that the water-based drilling fluid samples with higher okra powder concentrations could develop a more stable microstructure. Overall, the experimental results suggest that okra containing drilling fluids can be used as an alternate solution to starch in drilling fluids without compromising other drilling fluids' properties. A Machine Learning (ML)-based rheological model was also developed to predict the rheological properties of okra-based drilling fluid formulations. The proposed ML model can predict the rheological properties of Okra-based drilling fluids with high accuracy.",4,4,5
Drilling Fluid,Addition of 1 Wt,"Murtaza, Mobeen; Tariq, Zeeshan; Zhou, Xianmin; Al-Shehri, Dhafer; Mahmoud, Mohamed; Kamal, Muhammad Shahzad",Okra as an environment-friendly fluid loss control additive for drilling fluids: Experimental & modeling studies,Drilling fluids; Viscosifier; Fluid loss controller; ANN; Okra,BENTONITE DISPERSIONS; SILICA,"Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. It is also environment friendly and available in abundance, especially in tropical and subtropical regions. To the best of our knowledge, this is the first report on the application of the okra solution as a fluid loss control additive in drilling fluids. The okra powder was characterized by X-ray fluorescence, Fourier-transform infrared spectroscopy, and scanning electron microscopy. The thermal stability of okra was tested using thermal gravimetric analysis. The microstructure stability of the okra-based solution was analyzed using shear and loss modulus. The okra powder was used in different concentrations (0.25, 0.5, & 1) wt% in a clay free water-based drilling fluid formulation. The experimental study revealed that the addition of 1 wt% okra solution could reduce 20% fluid loss. The okra showed comparable performance compared to the conventional fluid loss control additive, starch. The main advantage was that okra has less impact on rheological properties compared to starch. TGA analysis of okra powder showed that it has strong thermal stability. The pH test showed that okra powder could not affect the pH of the solution. The shear and loss modulus tests revealed that the water-based drilling fluid samples with higher okra powder concentrations could develop a more stable microstructure. Overall, the experimental results suggest that okra containing drilling fluids can be used as an alternate solution to starch in drilling fluids without compromising other drilling fluids' properties. A Machine Learning (ML)-based rheological model was also developed to predict the rheological properties of okra-based drilling fluid formulations. The proposed ML model can predict the rheological properties of Okra-based drilling fluids with high accuracy.",4,4,5
Drilling Fluid,Addition of 1 Wt,"Edalatfar, Maryam; Yazdani, Farshad; Salehi, Mahsa Baghban",Synthesis and identification of ZnTiO3 nanoparticles as a rheology modifier additive in water-based drilling mud,Water-based drilling fluid; ZnTiO3 nanoparticles; KCl effect; Rheology,ZNO NANOFLUIDS; BENTONITE; FLUIDS; NANOCOMPOSITE; TEMPERATURE; FORMULATION; CUO,"Performing drilling operations to explore and exploit oil and gas reservoirs by injection wells is one of the most essential pillars of the oil industry. Hence, the improvement of drilling mud properties has a particular role. In this research, a laboratory study was carried out on the effect of nano additive on rheological properties of drilling mud. The ZnTiO3 nanoparticles were synthesized and analyzed by XRD, EDX, and SEM to identify and verify the structure of particles in the nanoscale. Then, the effect of adding nanoparticles to water-base mud is discussed. To determine the rheological behavior of the mud, the viscosity tests were applied. To study the operational conditions on the performance of mud containing nanoparticles, the rheological tests were performed on samples containing 0, 0.5, and 1 wt% of ZnTiO3 nanoparticles in the presence of 0, 2, 4 wt% of KCl salt at 25 degrees C and 90 degrees C. The results indicated that the addition of 1 wt% ZnTiO3 nanoparticles, even in the presence of 2 and 4% salt, could increase water-based mud viscosity up to 34.88% and 37.73%, at 25 degrees C and 32.16% and 30.76% at 90 degrees C, respectively. It was well able to maintain the shear-thinning behavior of mud contained nanoparticles at different shear rates. The optimum sample was finalized based on a rheological study with 5 wt % bentonite, 2 wt% salt, and 1 wt% ZnTiO3 nanoparticles. Performing filtration test on the optimal sample, using a filter press machine based on the American Petroleum Association Standard, it was confirmed that the addition of 1 wt% ZnTiO3 nanoparticles to mud was reduced the volume of fluid loss by about 7.7%. Finally, all results of mud samples viscosity were fitted with plastic Bingham, Herschel-Bulkley, and Power-law models. Through Herschel-Bulkley, and Power-law models could reasonably predict the rheological behavior of mud contained nanoparticles.",4,4,1
Drilling Fluid,Infrared Spectroscopy,"Murtaza, Mobeen; Tariq, Zeeshan; Zhou, Xianmin; Al-Shehri, Dhafer; Mahmoud, Mohamed; Kamal, Muhammad Shahzad",Okra as an environment-friendly fluid loss control additive for drilling fluids: Experimental & modeling studies,Drilling fluids; Viscosifier; Fluid loss controller; ANN; Okra,BENTONITE DISPERSIONS; SILICA,"Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. It is also environment friendly and available in abundance, especially in tropical and subtropical regions. To the best of our knowledge, this is the first report on the application of the okra solution as a fluid loss control additive in drilling fluids. The okra powder was characterized by X-ray fluorescence, Fourier-transform infrared spectroscopy, and scanning electron microscopy. The thermal stability of okra was tested using thermal gravimetric analysis. The microstructure stability of the okra-based solution was analyzed using shear and loss modulus. The okra powder was used in different concentrations (0.25, 0.5, & 1) wt% in a clay free water-based drilling fluid formulation. The experimental study revealed that the addition of 1 wt% okra solution could reduce 20% fluid loss. The okra showed comparable performance compared to the conventional fluid loss control additive, starch. The main advantage was that okra has less impact on rheological properties compared to starch. TGA analysis of okra powder showed that it has strong thermal stability. The pH test showed that okra powder could not affect the pH of the solution. The shear and loss modulus tests revealed that the water-based drilling fluid samples with higher okra powder concentrations could develop a more stable microstructure. Overall, the experimental results suggest that okra containing drilling fluids can be used as an alternate solution to starch in drilling fluids without compromising other drilling fluids' properties. A Machine Learning (ML)-based rheological model was also developed to predict the rheological properties of okra-based drilling fluid formulations. The proposed ML model can predict the rheological properties of Okra-based drilling fluids with high accuracy.",4,4,5
Drilling Fluid,Infrared Spectroscopy,"Kamali, Fahime; Saboori, Rahmatallah; Sabbaghi, Samad",Fe3O4-CMC nanocomposite performance evaluation as rheology modifier and fluid loss control characteristic additives in water-based drilling fluid,Fe3O4; Carboxymethyl cellulose; Nanocomposite; Filtration; Rheology; Drilling fluid,FILTRATION PROPERTIES; CARBOXYMETHYL CELLULOSE; THERMAL-CONDUCTIVITY; OXIDE NANOPARTICLES; MUD; TEMPERATURE; IMPROVEMENT; BEHAVIOR; OIL,"In drilling operations, there has been a considerable amount of attention to the drilling fluid formulation and characteristics. In recent years, the utilization of nanocomposite as an additive exhibited a promising improvement in the water-based drilling fluid rheological properties. The conventional additives have a lot of deficiencies such as being expensive, complicated synthesis methods, and not having desirable rheology properties. To eliminate the deficiencies, an investigation on the efficacy of Fe3O4- carboxymethyl cellulose (CMC) nanocomposite on the rheological and filtration characteristics as an additive in the water-based drilling fluid are carried out in this study. The nanocomposite was synthesized by the co-precipitation method and Fouriertransform infrared spectroscopy, X-ray diffraction, scanning electron microscopy, and energy dispersive x-ray was employed for characterization. Then, the nanocomposite with different ratio was utilized as an additive to drilling fluid and the rheological and filtration properties of fluid was measured for both deionized water and salty water. The results show that by adding 57% of 1:3 Fe3O4-CMC nanocomposite ratio to basic drilling fluid, in addition to considerable improvement in the viscosity, the filtration volume and cake thickness decreased noticeably. This formulation depicts non-Newtonian rheological behavior which could be illustrated properly by Herschel-Bulkley rheological model. Thus, exploitation of Fe3O4-CMC nanocomposite as an additive in waterbased drilling fluid for fluid loss control would have advantageous due to its distinctive properties like enhanced resistance to water penetration and enhanced viscosity in both deionized water and salty water. In addition, the Fe3O4-CMC nanocomposite has superior properties such as uncomplicated synthesis method and being financially available in comparison to conventional additives.",4,4,4
Drilling Fluid,Environment,"Murtaza, Mobeen; Tariq, Zeeshan; Zhou, Xianmin; Al-Shehri, Dhafer; Mahmoud, Mohamed; Kamal, Muhammad Shahzad",Okra as an environment-friendly fluid loss control additive for drilling fluids: Experimental & modeling studies,Drilling fluids; Viscosifier; Fluid loss controller; ANN; Okra,BENTONITE DISPERSIONS; SILICA,"Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. It is also environment friendly and available in abundance, especially in tropical and subtropical regions. To the best of our knowledge, this is the first report on the application of the okra solution as a fluid loss control additive in drilling fluids. The okra powder was characterized by X-ray fluorescence, Fourier-transform infrared spectroscopy, and scanning electron microscopy. The thermal stability of okra was tested using thermal gravimetric analysis. The microstructure stability of the okra-based solution was analyzed using shear and loss modulus. The okra powder was used in different concentrations (0.25, 0.5, & 1) wt% in a clay free water-based drilling fluid formulation. The experimental study revealed that the addition of 1 wt% okra solution could reduce 20% fluid loss. The okra showed comparable performance compared to the conventional fluid loss control additive, starch. The main advantage was that okra has less impact on rheological properties compared to starch. TGA analysis of okra powder showed that it has strong thermal stability. The pH test showed that okra powder could not affect the pH of the solution. The shear and loss modulus tests revealed that the water-based drilling fluid samples with higher okra powder concentrations could develop a more stable microstructure. Overall, the experimental results suggest that okra containing drilling fluids can be used as an alternate solution to starch in drilling fluids without compromising other drilling fluids' properties. A Machine Learning (ML)-based rheological model was also developed to predict the rheological properties of okra-based drilling fluid formulations. The proposed ML model can predict the rheological properties of Okra-based drilling fluids with high accuracy.",4,4,5
Drilling Fluid,Environment,"Mussa, Agostinho; Kalkreuth, Wolfgang; Pimentel Mizusaki, Ana Maria; Bicca, Marcos Muller; Bojesen-Koefoed, Jorgen A.","Geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation",Parnaiba basin; Pimenteiras formation; Hydrocarbon generation; Geochemistry; Petrology; Palynofacies,,"The Paleozoic-Mesozoic Parnaiba Basin is an intraplate volcano-sedimentary basin from which the Pimenteiras Formation (Devonian) has potential for hydrocarbon generation, mainly natural gas. The thermal influence of igneous intrusions contributes to hydrocarbon generation in the basin. This present paper provides a geochemical characterization of the organic matter in the Devonian Pimenteiras Formation, Parnaiba Basin, Brazil - Implications for depositional environment and the potential of hydrocarbon generation using geochemical and petrographic parameters. A total of 60 shale samples of the Pimenteiras Formation from three wells underwent analysis for TOC content, Rock-Eval pyrolysis, x-ray diffraction, organic petrology and palynofacies. The TOC content varies from 1.54 to 16.60 wt%, with the variations being related to different conditions of accumulation and preservation of the organic matter. The S-1 values range between 4.20 and 51.43 mg HC/g rock, with an average of 14.9 mg HC/g rock, and S-2 varies between 3.41 and 16.28 mg HC/g rock, with an average of 7.3 mg HC/g rock, showing very good to excellent source rock potential. The low Tmax values with an average of 430 degrees C indicate immaturity despite the high S-1 and S-2 values. The high S-1 values can be related to natural impregnation or contamination by drilling fluids. The HI vs Tmax plot showing the presence of kerogen type II and III, with potential for oil and gas generation. The mineral assemblage is associated with diagenetic or thermal processes (illite) and oxidation conditions (hematite and pyrite). The talc and chlorite can be related to metamorphism and provenance, while the calcite and gypsum indicate evaporitic conditions. The vitrinite reflectance varies between 0.31 and 0.67% Rrandom (average of 0.55% Rrandom). Thus, the samples can be classified as immature and mature and are consistent with Tmax values. The palynological records show a significant presence of phytoclasts and variations of palynomorphs along with the sequences from top to bottom, suggesting a transitional depositional environment (marine and continental) associated with the Devonian transgressive-regressive cycles. The data reinforce that the Pimenteiras Formation has the potential for hydrocarbon generation, mainly gas.",4,4,2
Drilling Fluid,Concentration,"Perumalsamy, Jayachandran; Gupta, Pawan; Sangwai, Jitendra S.",Performance evaluation of esters and graphene nanoparticles as an additives on the rheological and lubrication properties of water-based drilling mud,Ester; Lubricity; Graphene nano-particle; Rheology; Water-based mud,FLUIDS; ENHANCEMENT; POLYMER,"In the practice of drilling horizontal, directional, and unstable well profiles, the friction produced by bit balling, wellbore instability, cavings, and dog-legs resulted in excessive torque and drag. The friction along with high torque and drag, which results from the drill string, casing, and wellbore contact, leads to pipe stucks, overpulls during tripping-outs, and even closure of the oil and gas well. Heat generated from metal contact between casing and drill string is the cause of wear of drill string and casing. Oil-based drilling fluids are identified to produce minimum friction and torque than that of water-based drilling fluid/mud (WBM). However, the use of oil-based drilling fluids is becoming obsolete due to stringent environmental regulations. Therefore, it is critical to identify and design a water-based drilling mud with lubricant additives that are environmentally friendly, cost-effective, and give better lubrication similar to oil-based and synthetic-based drilling fluid. The objective of this study is to investigate the effect of two additives PC60 (the product of the reaction of glycerol + tall oil fatty acid) and graphene nanoparticles on the rheological and lubrication properties of water-based drilling fluid. All together total 14 drilling fluid samples have been prepared for the detailed analysis. Extensive experimental work has been done to study the effect of lubricant additives (PC60 and graphene nanoparticles) on the rheology and lubrication of various WBMs with different additive concentrations (1, 2, and 3% by volume) at 30, 60, and 90 degrees C. All samples were investigated for their rheology, viscoelastic behavior, and lubrication properties before and after hot rolling. The experimental data generated in this work have been successfully utilized to find various fitting parameter for the Bingham plastic rheological model, followed by a discussion on foaming tendency of the samples and effect of pH on the rheological stability of drilling fluid. Subsequently, a relationship between the coefficient of friction (in the presence of different lubricant additives in the mud) and rheological properties (plastic viscosity and yield point) of different drilling fluid samples have been proposed.",5,5,12
Drilling Fluid,Concentration,"Murtaza, Mobeen; Tariq, Zeeshan; Zhou, Xianmin; Al-Shehri, Dhafer; Mahmoud, Mohamed; Kamal, Muhammad Shahzad",Okra as an environment-friendly fluid loss control additive for drilling fluids: Experimental & modeling studies,Drilling fluids; Viscosifier; Fluid loss controller; ANN; Okra,BENTONITE DISPERSIONS; SILICA,"Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. It is also environment friendly and available in abundance, especially in tropical and subtropical regions. To the best of our knowledge, this is the first report on the application of the okra solution as a fluid loss control additive in drilling fluids. The okra powder was characterized by X-ray fluorescence, Fourier-transform infrared spectroscopy, and scanning electron microscopy. The thermal stability of okra was tested using thermal gravimetric analysis. The microstructure stability of the okra-based solution was analyzed using shear and loss modulus. The okra powder was used in different concentrations (0.25, 0.5, & 1) wt% in a clay free water-based drilling fluid formulation. The experimental study revealed that the addition of 1 wt% okra solution could reduce 20% fluid loss. The okra showed comparable performance compared to the conventional fluid loss control additive, starch. The main advantage was that okra has less impact on rheological properties compared to starch. TGA analysis of okra powder showed that it has strong thermal stability. The pH test showed that okra powder could not affect the pH of the solution. The shear and loss modulus tests revealed that the water-based drilling fluid samples with higher okra powder concentrations could develop a more stable microstructure. Overall, the experimental results suggest that okra containing drilling fluids can be used as an alternate solution to starch in drilling fluids without compromising other drilling fluids' properties. A Machine Learning (ML)-based rheological model was also developed to predict the rheological properties of okra-based drilling fluid formulations. The proposed ML model can predict the rheological properties of Okra-based drilling fluids with high accuracy.",4,4,5
Coalbed Methane,Coal Seam,"Chen, Shida; Tang, Dazhen; Tao, Shu; Liu, Pengcheng; Mathews, Jonathan P.","Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China",In situ stress; Permeability; Gas distribution; Productivity; Hydraulic fracture; Depth,DEPENDENT PERMEABILITY; LABORATORY MEASUREMENT; SEDIMENTARY CONTROL; HORIZONTAL STRESS; CBM DEVELOPMENT; BEARING SYSTEM; PORE PRESSURE; ORDOS BASIN; RESERVOIR; PROVINCE,"With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m3/t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500-800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.471.71 MPa/100 m). Overall, the stress release zone at depths of 500-800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production.",22,22,26
Coalbed Methane,Coal Seam,"Wang, Haitao; Kou, Zuhao; Guo, Jingjing; Chen, Zhuoting",A semi-analytical model for the transient pressure behaviors of a multiple fractured well in a coal seam gas reservoir,Coalbed methane; Multiple transportation mechanisms; Radial hydraulic fractures; Stimulated reservoir volume; Well test,HORIZONTAL WELLS; SHALE GAS; VERTICAL WELL; FLOW-RATE; PERMEABILITY; PERFORMANCE; ADSORPTION,"Multiple radial fractures can be generated in unconventional gas reservoirs after stimulation treatments such as hydraulic refracturing, high-energy gas fracturing, and explosive fracturing. This study presents a semi-analytical model to simulate the bottom-hole pressure (BHP) performances of a fractured well with multiple radial hydraulic fractures (MRHF) in a stress-sensitive coal seam gas reservoir. The adsorption-desorption and diffusion for fluid in reservoirs are considered. The continuous line-source function associated with discretization method in a composite coalbed gas reservoir is applied in Laplace domain. By means of Stehfest numerical inversion algorithm and Gauss elimination, the transient pressure responses in the well bottom are obtained and discussed. The results demonstrate that, from type curves, the main flow regimes for the proposed model in the coalbed gas reservoir are bilinear flow between adjacent radial hydraulic fractures, linear flow between adjacent radial hydraulic fractures, pseudo radial flow in stimulated region, and radial flow in un-stimulated region. Moreover, an obvious ""hump"" appears between the bilinear flow regime and the linear flow regime in stimulated region, which represents the interference between adjacent radial hydraulic fractures. The impacts of the ratio of permeability in stimulated region to that in un-stimulated region, the radius of stimulated reservoir volume (SRV), the permeability modulus, and the properties of hydraulic fractures on the transient pressure responses in well bottom are analyzed. The findings obtained in this study can pave the way for the quantitative understanding of the transient performances of multiple fractured vertical wells in unconventional reservoirs.",15,15,16
Coalbed Methane,Coal Seam,"Chen, Shida; Tao, Shu; Tian, Wenguang; Tang, Dazhen; Zhang, Biao; Liu, Pengcheng","Hydrogeological control on the accumulation and production of coalbed methane in the Anze Block, southern Qinshui Basin, China",Hydrogeological conditions; Coalbed methane; Aquifer; Accumulation and production,STABLE-ISOTOPE GEOCHEMISTRY; POWDER RIVER-BASIN; IN-SITU STRESS; ORDOS BASIN; GEOLOGICAL CONDITIONS; HYDROLOGICAL CONTROLS; PRODUCTION WATERS; FANZHUANG BLOCK; CARBON-ISOTOPE; KEY FACTORS,"This study of geological and hydrogeological conditions in the coal-bearing Shanxi and Taiyuan formations in the Anze Block, southern Qinshui Basin, reveals the water-flow direction, hydrodynamic units, special tectonic units and their influence on the accumulation and production of coalbed methane. Water composition variation, hydrogen and oxygen isotopes, and total dissolved solids were used to analyze the type and source of the co-produced water, the connection between the coalbed methane wells and aquifers, the flow direction of groundwater, and to characterize water-rock interactions. Coal seam No. 3 in the Shanxi Formation is less affected by external water, while coal seam No. 15 in the Taiyuan Formation has a hydraulic connection with the roof K2 limestone aquifers. Due to the differences in the hydrodynamic units, structural uplift, and faults, the gas content of coal seam No. 15 is higher than that of coal seam No. 3. Hydrostratigraphic cross sections were built to characterize the coalbed methane accumulation in coal seams No. 3 and No. 15. The hydrodynamic units and the water-conducting faults or collapse columns are the main factors affecting the gas content, and gas and water production rates in the Anze Block.",14,13,11
Coalbed Methane,Coal Seam,"Zhong, Jianyu; Ge, Zhaolong; Lu, Yiyu; Zhou, Zhe; Zheng, Jingwei",Prediction of fracture initiation pressure in multiple failure hydraulic fracturing modes: Three-dimensional stress model considering borehole deformation,Hydraulic fracturing; Fracture initiation pressure; Three-dimensional stress; Borehole deformation; Coal seam weak plane; Multiple failure modes,,"Hydraulic fracturing technology has been widely used as the main method of exploiting coalbed methane (CBM). The core of this technology is the accurate prediction of the fracture initiation pressure. As the exploitation depth increases, the influence of the in-situ stress obviously increases. Because the existing model of calculating the fracture initiation pressure ignores the influence of in-situ stress on the extraction borehole (CBM well) deformation, and the fracture initiation failure mode is single, the fracture initiation pressure of hydraulic fracturing cannot be accurately predicted in the field. In this study, a new model for predicting the fracture initiation pressure in hydraulic fracturing under a three-dimensional stress state was established. For the first time, the deformation of a circular borehole is related to the in-situ stress, and the size of the elliptical borehole can be accurately obtained after deformation. Eleven fracture initiation failure modes for the hydraulic fracturing of coal seams are proposed. The fracture initiation pressure of each failure mode was calculated in MATLAB, and the fracture initiation pressure of the shear failure of the rho z plane (a) was the smallest. The effects of the horizontal maximum principal stress, horizontal minimum principal stress, vertical intermediate principal stress, coal seam dip angle, horizontal azimuth of borehole, and gas pressure on the fracturing pressure were investigated using the proposed model. The coal seam dip angle exerted the greatest influence, and a new hydraulic fracturing construction procedure is proposed: the pump pressure should be gradually increased from the minimum initiation pressure according to the fracture initiation pressure gradient required by each failure mode. A field hydraulic fracturing test was conducted, and the experimental results are in good agreement with the theoretical calculation results. The maximum error was 5.5%, which validates the proposed theoretical model. The accuracy of the proposed theoretical model in the calculation of the fracture initiation pressure increased by 364.4% compared with the classical hydraulic fracturing theory. The results obtained by this study can provide more precise guidance to hydraulic fracturing projects.",6,6,14
Coalbed Methane,Gas Content,"Chen, Shida; Tang, Dazhen; Tao, Shu; Liu, Pengcheng; Mathews, Jonathan P.","Implications of the in situ stress distribution for coalbed methane zonation and hydraulic fracturing in multiple seams, western Guizhou, China",In situ stress; Permeability; Gas distribution; Productivity; Hydraulic fracture; Depth,DEPENDENT PERMEABILITY; LABORATORY MEASUREMENT; SEDIMENTARY CONTROL; HORIZONTAL STRESS; CBM DEVELOPMENT; BEARING SYSTEM; PORE PRESSURE; ORDOS BASIN; RESERVOIR; PROVINCE,"With 59 sets of well testing data from 32 wells, 70 coal seam gas data from 9 wells, and production data from 17 wells, the in situ stress distribution within depths of 136-1244 m and its implications for coal permeability (0.0001-1.56 mD), gas content (5-22 m3/t) and gas productivity in western Guizhou were investigated. Three major depth intervals with different stress regimes were identified. At depths of 800-1244 m, the horizontal stresses increased to high values with depth due to the compressional zone near the axis of the syncline. Permeability changes with depth were consistent with the effective stress variations. The 500-800 m depth interval with a normal faulting stress regime was favorable for good permeability (0.008-0.57 mD, mean 0.2 mD) and a stable pressure gradient (approximately 1 MPa/100 m), and the gas content generally increased with depth to a peak value at 800 m. For the 200-500 m and 800-1244 m depth intervals, extremely low permeability (0.0001-0.17 mD, mean 0.03 mD) resulted in discontinuous changes in gas content and pressure gradient (0.471.71 MPa/100 m). Overall, the stress release zone at depths of 500-800 m was favorable for coalbed methane extraction, which agreed with the measured production data. Low horizontal stress anisotropy in western Guizhou contributes to complex hydraulic fracture networks, individual seam fracturing with low proppant concentration and high fracturing fluid volume is suggested for multilayer commingled production.",22,22,26
Coalbed Methane,Gas Content,"Chen, Shida; Tao, Shu; Tian, Wenguang; Tang, Dazhen; Zhang, Biao; Liu, Pengcheng","Hydrogeological control on the accumulation and production of coalbed methane in the Anze Block, southern Qinshui Basin, China",Hydrogeological conditions; Coalbed methane; Aquifer; Accumulation and production,STABLE-ISOTOPE GEOCHEMISTRY; POWDER RIVER-BASIN; IN-SITU STRESS; ORDOS BASIN; GEOLOGICAL CONDITIONS; HYDROLOGICAL CONTROLS; PRODUCTION WATERS; FANZHUANG BLOCK; CARBON-ISOTOPE; KEY FACTORS,"This study of geological and hydrogeological conditions in the coal-bearing Shanxi and Taiyuan formations in the Anze Block, southern Qinshui Basin, reveals the water-flow direction, hydrodynamic units, special tectonic units and their influence on the accumulation and production of coalbed methane. Water composition variation, hydrogen and oxygen isotopes, and total dissolved solids were used to analyze the type and source of the co-produced water, the connection between the coalbed methane wells and aquifers, the flow direction of groundwater, and to characterize water-rock interactions. Coal seam No. 3 in the Shanxi Formation is less affected by external water, while coal seam No. 15 in the Taiyuan Formation has a hydraulic connection with the roof K2 limestone aquifers. Due to the differences in the hydrodynamic units, structural uplift, and faults, the gas content of coal seam No. 15 is higher than that of coal seam No. 3. Hydrostratigraphic cross sections were built to characterize the coalbed methane accumulation in coal seams No. 3 and No. 15. The hydrodynamic units and the water-conducting faults or collapse columns are the main factors affecting the gas content, and gas and water production rates in the Anze Block.",14,13,11
Coalbed Methane,Gas Content,"Zheng, Sijian; Yao, Yanbin; Liu, Dameng; Cai, Yidong; Liu, Yong",Quantitative characterization of multiphase methane in coals using the NMR relaxation method,Nuclear magnetic resonance (NMR); Coalbed methane (CBM); Methane adsorption capacity; Volumetric method; Free methane,NUCLEAR-MAGNETIC-RESONANCE; LOW-FIELD NMR; MERCURY INTRUSION POROSIMETRY; RAY COMPUTED-TOMOGRAPHY; PORE-SIZE DISTRIBUTIONS; ADSORPTION CAPACITY; GAS-ADSORPTION; PERMEABILITY; DIFFUSION; POROSITY,"The gas content test for coalbed methane (CBM) reservoirs consists of measurements of lost, desorbed and residual gas, and it is a crucial parameter for evaluation of such reservoirs and optimization of favorable zones. The desorbed and residual methane contents are non-simultaneously determined by on-site desorption test, which is both time-consuming and susceptible to a volume effect - leading to a large variation in the results. Conventionally, adsorbed methane content is indirectly estimated by a volumetric method, which has the shortcoming of being unable to directly measure in-situ adsorbed gas content. Thus, it is important to develop an effective and convenient method for quantitative characterization of multiphase methane in coals using a single technique. In this study, we performed a series of nuclear magnetic resonance (NMR) adsorption measurements on 15 subbituminous coals and anthracites. The transverse relaxation time (T-2) distributions of methane are measured for three peaks: P1 (T-2 = 0.1-8 ms), P2 (T-2 = 10-300 ms), and P3(T-2 = 300-2000 ms), corresponding to adsorbed methane in the coal matrix, free methane within larger pores, and lastly free methane in the space between the sample and the sample cell, respectively. In this study, the NMR calibration coefficient of free methane (Kfree-methane) is set to 3.44 x 10(-1) cm(3) /p.u., regardless of the coal rank. In contrast, the NMR adsorbed methane calibration coefficient (Kadsorbed-methane) varies substantially in coals of different ranks, but show little difference in coals with the same coal rank. We suggest the Kadsorbed-methane of 3.2 x 10(-2) cm(3)/p.u., 2.3 x 10(-2) cm(3)/p.u. and 3.6 x 10(-2) cm(3)/p.u., corresponding to low-, medium- and high-rank coals, respectively, for estimating the adsorbed methane content. Using these calibration coefficients, multiphase methane can be quantitatively estimated using the NMR measurement alone. The method is applicable both in the laboratory and in the field, for desorbed and residual gas quantification.",5,5,15
Coalbed Methane,Gas Content,"Lu, Yuejian; Liu, Dameng; Cai, Yidong; Li, Qian; Zhou, Yingfang",Spontaneous imbibition in coal with in-situ dynamic micro-CT imaging,Coalbed methane; Spontaneous imbibition; X-ray; Relative permeability,PORE-FRACTURE NETWORKS; MERCURY INTRUSION POROSIMETRY; RELATIVE PERMEABILITY; WATER IMBIBITION; POROUS-MEDIA; LOW-RANK; GAS; SHALE; SORPTION; METHANE,"The gas/fluid flowing behavior and fluid distribution under capillary forces in porous media are essential for evaluating the pore-fracture characteristics of coal. Capillary force is crucial for flow-back efficiency after hydraulic fracturing during enhanced coalbed methane (CBM) production. In this work, in situ dynamic X-ray micro-computed tomography (X-ray mu-CT), field emission scanning electron microscopy (FE-SEM) combined with mercury intrusion porosimetry (MIP) were used on two coal samples of different wettability to explore the behavior of spontaneous imbibition. The results show that both pore-fracture and mineral content could affect the imbibition behavior of coal, which the former has played a major role. The spontaneous imbibition process can be divided into 4 stages to reveal fluid flow characteristics by the fluid distribution at different time steps. The gas relative permeability of coal attenuates exponentially with imbibition time result for capillary force based on fractal theory (the gas relative permeability reduces its value from 0.72 mD to 0.01 mD for WD, 0.5 mD to 0.08 mD for WZX). A low flow-back rate of fracturing fluid would lead to severe permeability damage. The longer the return drainage time, the more severe the permeability damage.",3,3,37
Coalbed Methane,Treatment,"Huang, Qiming; Wu, Bing; Liu, Yu; Guo, Zhiguo; Wang, Gang; Sun, Lulu",Experimental and simulation investigations of the impact of polyacrylamide on CBM ad-/desorption,Slickwater; Coalbed methane; Polyacrylamide; Adsorption; Desorption,PORE STRUCTURE; FRACTURING FLUID; CO2 SORPTION; COAL; ADSORPTION; METHANE; CARBON; DIFFUSION; PRESSURE; NITROGEN,"Slickwater is commonly used during hydraulic fracturing in coalbed gas well, which is often prepared with polyacrylamide as the friction reducer. To investigate the impact of polyacrylamide on CBM ad-/desorption after a fracturing operation, slickwater with different concentrations of polyacrylamide were prepared and used to treat Illinois coal samples. Both isothermal ad-/desorption experiments and molecular simulations were conducted to investigate the impact of slickwater. Nuclear magnetic resonance measurements were performed to analyse the evolution of surface functional groups of coal during slickwater treatment. The results show that there is no significant chemical reaction between the coal component and polyacrylamide. Because of the porosity of the polyacrylamide coating adhered onto the surface of the pore, polyacrylamide has a significant sorption capacity of methane. The methane sorption amount of the 'coal-slickwater' system is higher than that of raw coal. However, with the increase of the amount of residue entering the pores, the porous structure of the polyacrylamide coating becomes denser, blocking some pores and the pore surface area is reduced; thus, the overall sorption capacity of the 'coal-polyacrylamide' system decreases.",16,16,17
Coalbed Methane,Treatment,"Wang, Haitao; Kou, Zuhao; Guo, Jingjing; Chen, Zhuoting",A semi-analytical model for the transient pressure behaviors of a multiple fractured well in a coal seam gas reservoir,Coalbed methane; Multiple transportation mechanisms; Radial hydraulic fractures; Stimulated reservoir volume; Well test,HORIZONTAL WELLS; SHALE GAS; VERTICAL WELL; FLOW-RATE; PERMEABILITY; PERFORMANCE; ADSORPTION,"Multiple radial fractures can be generated in unconventional gas reservoirs after stimulation treatments such as hydraulic refracturing, high-energy gas fracturing, and explosive fracturing. This study presents a semi-analytical model to simulate the bottom-hole pressure (BHP) performances of a fractured well with multiple radial hydraulic fractures (MRHF) in a stress-sensitive coal seam gas reservoir. The adsorption-desorption and diffusion for fluid in reservoirs are considered. The continuous line-source function associated with discretization method in a composite coalbed gas reservoir is applied in Laplace domain. By means of Stehfest numerical inversion algorithm and Gauss elimination, the transient pressure responses in the well bottom are obtained and discussed. The results demonstrate that, from type curves, the main flow regimes for the proposed model in the coalbed gas reservoir are bilinear flow between adjacent radial hydraulic fractures, linear flow between adjacent radial hydraulic fractures, pseudo radial flow in stimulated region, and radial flow in un-stimulated region. Moreover, an obvious ""hump"" appears between the bilinear flow regime and the linear flow regime in stimulated region, which represents the interference between adjacent radial hydraulic fractures. The impacts of the ratio of permeability in stimulated region to that in un-stimulated region, the radius of stimulated reservoir volume (SRV), the permeability modulus, and the properties of hydraulic fractures on the transient pressure responses in well bottom are analyzed. The findings obtained in this study can pave the way for the quantitative understanding of the transient performances of multiple fractured vertical wells in unconventional reservoirs.",15,15,16
Coalbed Methane,Treatment,"Liu, Zhengshuai; Liu, Dameng; Cai, Yidong; Qiu, Yongkai","Permeability, mineral and pore characteristics of coals response to acid treatment by NMR and QEMSCAN: Insights into acid sensitivity mechanism",Acid sensitivity; Mineral dissolution; Precipitation generation; Ions concentration; Particles migration,ULTRA CLEAN-COAL; HIGH-RANK COALS; GEOCHEMICAL COMPOSITIONS; VELOCITY SENSITIVITY; STRESS SENSITIVITY; LIGNITE RESERVOIR; DAMAGE MECHANISM; INNER-MONGOLIA; METHANE; DEMINERALIZATION,"The sensitivity of coal reservoir is an essential reason decreasing the coalbed methane (CBM) production during the CBM development. Whether the acid sensitivity is a negative or positive effect on the coal reservoir needs further discussion. In this work, the core flooding experiments with different acids treatment were conducted to investigate the acid sensitivity mechanism, combining with X-ray diffraction (XRD), inductively coupled plasma mass spectrometry (ICP-MS), nuclear magnetic resonance (NMR) and quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN) methods. The results of core flooding show that the permeability damage is about 13%, 66% and 58% after 3% hydrochloric acid (HCL) treatment, 3% fluoric acid (HF) treatment and 3%HCL+3%HF treatment, respectively. The mineral distributions before and after 3%HCL+3%HF treatment obtained by QEMSCAN reveal the dissolution of carbonates, the generation of new precipitations and the mobilization of coal particles. The effect of acid on pore structure obtained by NMR indicates that the pore size between 7.5 nm and 110 nm decreases after 3%HCL treatment, while the pore size over 18 nm decreases after 3% HF treatment. The porosity analyzed by QEMSCAN increases at the inlet side and decreases at the outlet side, suggesting the pore structure at the outlet of core is more vulnerable. Moreover, the potential chemical reactions between minerals and acids are deduced by analyzing the results of XRD and the variation of ions' concentration. The siderite, ankerite, dolomite, chlorite in coals are dissolved by HCL or HF and some of the quartz and kaolinite are dissolved by HF. The fluorite and sellaite were generated after HF treatment. In short, evaluating the effect of acid on the coal reservoir needs to consider the dissolution of minerals, generation of new precipitates and migration of particles.",8,8,9
Coalbed Methane,Treatment,"Liu, Peng; Liu, Ang; Zhong, Fangxiang; Jiang, Yongdong; Li, Jiajun",Pore/fracture structure and gas permeability alterations induced by ultrasound treatment in coal and its application to enhanced coalbed methane recovery,Ultrasound treatment; Coal structure; Gas permeability; CBM recovery,ADSORPTION CAPACITY; MOISTURE-CONTENT; BITUMINOUS COAL; CO2 INJECTION; TEMPERATURE; STRESS; IMPACT; PORES; TRANSDUCERS; MODEL,"Ultrasonic treatment is a highly potential method for reservoir permeability modification in enhanced coalbed methane recovery. Quantitative evaluations of ultrasonic induced changes in structure and permeability in coal are of great interest for potential field applications of ultrasound technology. In this study the scanning electron microscope (SEM) and low-temperature liquid nitrogen (LTLN) were used to examine the ultrasound induced alterations in coal pore/fracture, and further measured gas permeability in coal by coupling the ultrasound field and external stress. The SEM images show that ultrasound treatment can extend the original pore/fracture, increase the connectivity and remove barriers in gas seepage channel in coal. The LTLN data reveals that with the ultrasonic treatment (25 kHz, 18 kW, 2 h), the maximum N2adsorption quantity of the tested samples increased by 106.5%-258.4%, and the average pore diameter increased by 37.06%-81.40%; the specific surface area increased by 94.80%-118.15%, and the total pore volume increased by 87.12%-252.55%. It implies that coal pores in size ranging from 1 nm to 100 nm can be remarkably improved by ultrasonic treatment, which is significant beneficial to promote gas desorption/diffusion within coal matrix. Permeability tests demonstrate that gas permeability in stressed coal increased by 29.3%-57.1% with the implement of ultrasound field (25 kHz, 18 kW, 30 min). Ultrasonic performance on permeability improvement is proportional to the treatment time, but the function of ultrasonic fracturing has time threshold effect, and after a certain period of treatment, the ultrasonic fracturing performance becomes very limited in stressed coal.",6,6,16
Coalbed Methane,Dynamics,"Wang, Dengke; Zeng, Fanchao; Wei, Jianping; Zhang, Hongtu; Wu, Yan; Wei, Qiang",Quantitative analysis of fracture dynamic evolution in coal subjected to uniaxial and triaxial compression loads based on industrial CT and fractal theory,Industrial CT; Fracture dynamic evolution; Three-dimensional fracture reconstruction; Uniaxial and triaxial compression; Fractal dimension,RAY COMPUTED-TOMOGRAPHY; PORE STRUCTURE; ACOUSTIC-EMISSION; CONFINING PRESSURES; RANK COAL; PERMEABILITY; DIMENSION; GAS; BASIN; RECONSTRUCTION,"The dynamic evolution characteristics of fractures in coal under different compressive loads are of great significance to the recovery of coalbed methane (CBM). In this paper, the X-ray computer tomography (CT) detections of coal samples under uniaxial and triaxial compressive loading conditions were performed by using a developed triaxial in situ rig and an industrial CT scanner. The image processing technique, three-dimensional reconstruction method and statistical principles were employed to describe two-dimensional and three-dimensional fracture evolution in coal under uniaxial and triaxial compressive loads. The results showed that the developed triaxial in situ rig has an enough scanning resolution and is suitable to carry out CT scanning inspections under uniaxial and triaxial compressive loads for porous materials of coal and rock. The two-dimensional cross-sectional CT images effectively reflect the dynamic evolution of two-dimensional fractures during the deformation of coal. Confining pressure and minerals have a significant effect on fracture propagation in coal. The evolution characteristics of three-dimensional fractures can be clearly revealed by the reconstructed three-dimensional digital fracture models of coal. Euler number effectively reflects the fracture connectivity in coal at different deformation stages. During the deformation of coal, the fracture volume, fracture rate, fracture density and fracture connectivity mainly undergo a slow decrease stage, a slow increase stage and a sharp increase stage, display a good linear correlation with fractal dimension, and quantitatively characterize the evolution process of the three-dimensional fractures in coal. The fractal dimension calculated by the box-counting method effectively mirrors fracture propagation and fracture geometric complexity and can be employed to uncover the fracture dynamic evolution in coal under different compressive loading conditions.",7,7,32
Coalbed Methane,Dynamics,"Lu, Yuejian; Liu, Dameng; Cai, Yidong; Li, Qian; Zhou, Yingfang",Spontaneous imbibition in coal with in-situ dynamic micro-CT imaging,Coalbed methane; Spontaneous imbibition; X-ray; Relative permeability,PORE-FRACTURE NETWORKS; MERCURY INTRUSION POROSIMETRY; RELATIVE PERMEABILITY; WATER IMBIBITION; POROUS-MEDIA; LOW-RANK; GAS; SHALE; SORPTION; METHANE,"The gas/fluid flowing behavior and fluid distribution under capillary forces in porous media are essential for evaluating the pore-fracture characteristics of coal. Capillary force is crucial for flow-back efficiency after hydraulic fracturing during enhanced coalbed methane (CBM) production. In this work, in situ dynamic X-ray micro-computed tomography (X-ray mu-CT), field emission scanning electron microscopy (FE-SEM) combined with mercury intrusion porosimetry (MIP) were used on two coal samples of different wettability to explore the behavior of spontaneous imbibition. The results show that both pore-fracture and mineral content could affect the imbibition behavior of coal, which the former has played a major role. The spontaneous imbibition process can be divided into 4 stages to reveal fluid flow characteristics by the fluid distribution at different time steps. The gas relative permeability of coal attenuates exponentially with imbibition time result for capillary force based on fractal theory (the gas relative permeability reduces its value from 0.72 mD to 0.01 mD for WD, 0.5 mD to 0.08 mD for WZX). A low flow-back rate of fracturing fluid would lead to severe permeability damage. The longer the return drainage time, the more severe the permeability damage.",3,3,37
Coalbed Methane,Dynamics,"Shi, Juntai; Jia, Yanran; Wu, Jiayi; Xu, Fengyin; Sun, Zheng; Liu, Chengyuan; Meng, Ye; Xiong, Xianyue; Liu, Cheng",Dynamic performance prediction of coalbed methane wells under the control of bottom-hole pressure and casing pressure,Coalbed methane; Dynamic performance analysis; Bottom-hole pressure; Casing pressure; Liquid level; Low permeability,PRODUCTIVITY MODEL; LOW PERMEABILITY; FRACTURED WELL; ORDOS BASIN; GAS; RESERVOIRS; EQUATIONS; FLOW; PROPAGATION; TRANSPORT,"In the early production stage of coalbed methane (CBM) wells, especially in low permeability reservoirs, the method of shutting in casing annulus is usually adopted. However, the current commercial numerical simulation software fails to predict the dynamic performance of CBM wells under the control of both bottom-hole pressure and casing pressure. In this work, the calculation models of wellbore-pressure distribution and formation pressure distribution are derived firstly. Then, the above two models are coupled with several CBM dynamic performance analysis (CBMDPA) models developed in our previous researches, including pressure propagation model, water/gas productivity equations, dynamic permeability model, and material balance equation. A new CBMDPA program is developed with the coupling model, which can simulate the dynamic production performance of CBM wells after inputting the basic reservoir and fluid parameters, casing pressure, and bottom-hole pressure. Next, the newly developed CBMDPA program is validated against four field cases in China, and excellent agreements are obtained. The inputs of our CBMDPA program include casing pressure, bottom-hole pressure, and some deterministic and uncertain reservoir and fluid parameters. By adjusting the uncertain parameters, the gas production history can be fitted, and the uncertainty on the determination of reservoir properties can be addressed. On this basis, the future gas production is predicted using the determined parameters and the scheduled bottom-hole pressure and casing pressure. Finally, the influence of casing pressure on gas production is studied. Results show that high casing pressure has detrimental impact on the maximum daily gas production, while, it plays a positive role to achieve great desorption area, which will further prolong the stable gas production period. Under the high casing pressure of 2.5 MPa, the maximum daily production is decreased by about 54%, but the stable production stage is prolonged to more than 3000 days. It indicates that an appropriate range for casing pressure is favorable, considering both the accumulative gas production and the desorption area. For the case with representative properties from Muai block, the casing pressure is suggested to be 1-2 MPa, and the range between 1 MPa and 1.5 MPa is recommended for Hancheng block.",3,3,4
Coalbed Methane,Acid,"Liu, Zhengshuai; Liu, Dameng; Cai, Yidong; Qiu, Yongkai","Permeability, mineral and pore characteristics of coals response to acid treatment by NMR and QEMSCAN: Insights into acid sensitivity mechanism",Acid sensitivity; Mineral dissolution; Precipitation generation; Ions concentration; Particles migration,ULTRA CLEAN-COAL; HIGH-RANK COALS; GEOCHEMICAL COMPOSITIONS; VELOCITY SENSITIVITY; STRESS SENSITIVITY; LIGNITE RESERVOIR; DAMAGE MECHANISM; INNER-MONGOLIA; METHANE; DEMINERALIZATION,"The sensitivity of coal reservoir is an essential reason decreasing the coalbed methane (CBM) production during the CBM development. Whether the acid sensitivity is a negative or positive effect on the coal reservoir needs further discussion. In this work, the core flooding experiments with different acids treatment were conducted to investigate the acid sensitivity mechanism, combining with X-ray diffraction (XRD), inductively coupled plasma mass spectrometry (ICP-MS), nuclear magnetic resonance (NMR) and quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN) methods. The results of core flooding show that the permeability damage is about 13%, 66% and 58% after 3% hydrochloric acid (HCL) treatment, 3% fluoric acid (HF) treatment and 3%HCL+3%HF treatment, respectively. The mineral distributions before and after 3%HCL+3%HF treatment obtained by QEMSCAN reveal the dissolution of carbonates, the generation of new precipitations and the mobilization of coal particles. The effect of acid on pore structure obtained by NMR indicates that the pore size between 7.5 nm and 110 nm decreases after 3%HCL treatment, while the pore size over 18 nm decreases after 3% HF treatment. The porosity analyzed by QEMSCAN increases at the inlet side and decreases at the outlet side, suggesting the pore structure at the outlet of core is more vulnerable. Moreover, the potential chemical reactions between minerals and acids are deduced by analyzing the results of XRD and the variation of ions' concentration. The siderite, ankerite, dolomite, chlorite in coals are dissolved by HCL or HF and some of the quartz and kaolinite are dissolved by HF. The fluorite and sellaite were generated after HF treatment. In short, evaluating the effect of acid on the coal reservoir needs to consider the dissolution of minerals, generation of new precipitates and migration of particles.",8,8,9
Coalbed Methane,Acid,"Chen, Shuya; Xie, Kunzhi; Shi, Yanping; Li, Zishuo; Yang, Xianyu; Cai, Jihua",Chelating agent-introduced unconventional compound acid for enhancing coal permeability,Organic acid; Chelating agent; Fluoroboric acid; Acid stimulation; Coalbed methane,,"The low permeability of coalbed methane (CBM) reservoirs can be attributed to cementing minerals, which make it difficult for water/gas to flow in the pores and fractures. Acid stimulation is considered a promising method to enhance coal permeability by dissolving these inorganic minerals. Laboratory experiments were carried out to investigate the interactions between acids and coal samples from the Qinshui Basin. XRD and SEM-EDS analyses showed that these coal samples contained a large amount of clay minerals, and some carbonates, pyrite, etc. Considering the complexity of the mineral concentration, three kinds of acids (organic acids, chelating agents, and fluoroboric acid) were optimized via static leaching tests, ICP-OES, etc. Based on the results, out of the four chelating agents, HEDTA showed the highest chelating amount for Ca2+ (380.38 mg/g) and Fe3+ (476.4 mg/g), and 1 wt% HEDTA (pH = 2) yielded the highest dissolution rate. For the organic acids, the dissolution rate decreased with an increase in acid concentration because of the common ion effect. The dissolution rate with 2.5 wt% OA-1 was 8.02% while that with 20w% HCl was only 7%. In addition, 639 mg/L Ca was detected in the 5 wt % OA-1 leachate, which was higher than that for the 5 wt% HC1 (575 mg/L). Afterward, orthogonal methods were used to optimize the compound acid system which consisted of 1.5 wt% HEDTA +4 wt% OA-1 + 5 wt% HBF4. According to the core-flooding test results, after acid injection for approximately 100 PV (pore volume), the porosity of coal core sample increased from 3.36% to 4.95%, and the permeability increased 3.29 times. In general, previous studies have been limited to the conventional acids (HCl and mud acid), yet the drawbacks such as clay breakage, migration, and precipitation cannot be neglected. Accordingly, this paper proposed a set of chelating agent-introduced compound acid and it shows great promise in the application of enhanced CBM recovery.",5,5,6
Coalbed Methane,Strain,"Wang, Zhenzhi; Fu, Xuehai; Hao, Ming; Li, Guofu; Pan, Jienan; Niu, Qinghe; Zhou, He",Experimental insights into the adsorption-desorption of CH4/N-2 and induced strain for medium-rank coals,N-2-ECBM; Binary mixed gases; Adsorption strain characteristics; Medium-rank coal; Anisotropic characteristics,GAS-ADSORPTION; COMPETITIVE ADSORPTION; METHANE ADSORPTION; PERMEABILITY; DEFORMATION; SIMULATION; DIFFUSION; EVOLUTION; NITROGEN; SORPTION,"To support the understanding of the effect of N-2-enhanced coalbed methane (N-2-ECBM) application on medium-rank coals, four coal samples from Shanxi Province were selected to test the porosity, mechanical properties and strain induced by binary gas adsorption-desorption. The results show that the desorption hysteresis is weakened with increasing N-2 fraction and is strengthened with increasing CH4 fraction, indicating that increasing the N-2 fraction can reduce the selectivity of coal to CH4. The critical desorption pressure of a mixed gas increases in a high N-2 fraction environment, promoting the desorption of CH4 and enhancing its recovery. This research clarifies the anisotropic strain characteristics induced by the adsorption-desorption of CH4/N-2 and provides reliable data for anisotropic permeability numerical simulations in the N-2-ECBM process. Swelling and shrinkage volume strain are negative-exponentially related to the N-2 fraction, and the volume shrinkage strain is close to the volume swelling strain given a N-2 fraction of 50%. There exists a polynomial relationship between the volume swelling/shrinking strain and adsorption capacity, which has a potential predictive effect on the volume strain variation in coal during N-2-ECBM. The analysis of the adsorption volume swelling strain rate and desorption volume shrinkage strain rate indicates that the N-2 fraction and micropore volume are the main factors controlling volume deformation. The volume strain decreases with increasing elastic modulus, but nitrogen injection weakens the effect of the elastic modulus on the strain. In this study, the desorption percentage increased and the volume swelling strain decreased with increasing nitrogen fraction. Nitrogen injection and sealing have a positive effect on methane desorption and the optimal N-2 fraction should be greater than 50%. This work provides a reference for improving coalbed methane production.",3,3,12
Coalbed Methane,Strain,"Gao, Zheng; Li, Bobo; Li, Jianhua; Wang, Bin; Ren, Chonghong; Xu, Jiang; Chen, Shuai",Coal permeability related to matrix-fracture interaction at different temperatures and stresses,Coal permeability; Temperature; Stress; Boundary conditions; Matrix; Fracture interaction,MODEL DEVELOPMENT; GAS INTERACTIONS; PORE PRESSURE; THERMAL-STIMULATION; METHANE ADSORPTION; CO2 PERMEABILITY; ANTHRACITE COAL; INDUCED STRAIN; SICHUAN BASIN; EVOLUTION,"Heat injection is considered to be an effective technique to increase Coalbed methane (CBM) production, which indicates the important role of temperature in gas flow. In this paper, two different experimental schemes have been designed, and the seepage tests concerning variable effective stress and variable pore pressure have been carried out respectively under different temperature conditions. A permeability model that considered the combined effect of temperature and stress was developed, and further extended so that it could be applied under other boundary conditions. An effective deformation factor f(m) was introduced to characterize the contribution of the change of coal matrix width to the change of fracture width, and the relationship between f(m) and temperature, under three boundary conditions, was quantitatively analyzed. Under constant pore pressure, the increase of effective stress will reduce the permeability. Under constant effective stress, an increase of pore pressure will lead to the decrease in permeability. Temperature would affect the permeability characteristics of coal from physical and chemical aspects, which were mainly manifested as inhibition, and this effect significantly weakened during the high stress stage. In terms of model matching, the permeability model results from each boundary condition were in good agreement with the measured results. In addition, the effective deformation factor f(m) increased exponentially over temperature under different boundary conditions. It is thought that these findings would provide a theoretical basis for the further study of coal matrix-fracture interaction, and CBM exploitation.",3,3,12
Pump,Fracture,"Zhu, Guangyou; Milkov, Alexei, V; Li, Jingfei; Xue, Nan; Chen, Yongquan; Hu, Jianfeng; Li, Tingting; Zhang, Zhiyao; Chen, Zhiyong","Deepest oil in Asia: Characteristics of petroleum system in the Tarim basin, China",Oil; Tarim basin; Cambrian; Ultra-deep,,"The petroleum exploration well Luntan-1 (LT1) located in the Tabei Uplift, Tarim Basin, China reached vertical depth 8882 m and is now the deepest well in Asia. A significant petroleum flow (134 m(3) of oil and 45,900 m(3) of gas) was obtained from the Cambrian Wusongger Formation perforated in the interval 8203-8260 m, with a pressure of 90.8 Mpa and interval logging temperature is 162 degrees C. The well LT-1 is the deepest producer of oil from Paleozoic reservoirs in the world. According to the analysis of the effect of acidizing fracturing reservoir reconstruction, the Lower Cambrian Wusongger Formation has low pump stop pressure, large pressure drop, fast deceleration, and good reservoirs and the lithology are limestone dolomite, lime-bearing dolomite, and dolomite. The source rock is the Lower Cambrian Yuertusi shale containing significant amount of total organic carbon (2-30 wt%) and located in the late oil/early gas maturity window (vitrinite reflectance 1.4-1.7%). Through GC x GC-TOFMS analysis of this oil showed low concentration of diamondoids, which indicates lack of thermal cracking of oil to gas. Thiadiamondoids, typically indicative of thermochemical sulfate reduction, were not detected. Using kinetic calculations, we estimated the temperature threshold for thermal cracking of well LT1 oil to gas at similar to 210-220 degrees C. Based on the thermal evolution and burial history of the Tarim Basin, the depth threshold for the disappearance of liquid oil is similar to 9000 m. Low geothermal gradient (19.6 degrees C/km) and rapid subsidence after petroleum accumulation jointly contribute to the preservation of liquid petroleum in ultra-deep strata in the Tarim Basin. Our findings suggest that the favorable exploration area in ultra-deep, high-temperature and high-pressure Cambrian reservoirs in the Tarim Basin exceeds 20,000 km(2) and may contain over 1 billion tons of oil resources. Furthermore, the significant discovery of oil in the well LT1 provides important insights for global exploration of Paleozoic ultra-deep oil.",10,11,7
Pump,Fracture,"Zhong, Jianyu; Ge, Zhaolong; Lu, Yiyu; Zhou, Zhe; Zheng, Jingwei",Prediction of fracture initiation pressure in multiple failure hydraulic fracturing modes: Three-dimensional stress model considering borehole deformation,Hydraulic fracturing; Fracture initiation pressure; Three-dimensional stress; Borehole deformation; Coal seam weak plane; Multiple failure modes,,"Hydraulic fracturing technology has been widely used as the main method of exploiting coalbed methane (CBM). The core of this technology is the accurate prediction of the fracture initiation pressure. As the exploitation depth increases, the influence of the in-situ stress obviously increases. Because the existing model of calculating the fracture initiation pressure ignores the influence of in-situ stress on the extraction borehole (CBM well) deformation, and the fracture initiation failure mode is single, the fracture initiation pressure of hydraulic fracturing cannot be accurately predicted in the field. In this study, a new model for predicting the fracture initiation pressure in hydraulic fracturing under a three-dimensional stress state was established. For the first time, the deformation of a circular borehole is related to the in-situ stress, and the size of the elliptical borehole can be accurately obtained after deformation. Eleven fracture initiation failure modes for the hydraulic fracturing of coal seams are proposed. The fracture initiation pressure of each failure mode was calculated in MATLAB, and the fracture initiation pressure of the shear failure of the rho z plane (a) was the smallest. The effects of the horizontal maximum principal stress, horizontal minimum principal stress, vertical intermediate principal stress, coal seam dip angle, horizontal azimuth of borehole, and gas pressure on the fracturing pressure were investigated using the proposed model. The coal seam dip angle exerted the greatest influence, and a new hydraulic fracturing construction procedure is proposed: the pump pressure should be gradually increased from the minimum initiation pressure according to the fracture initiation pressure gradient required by each failure mode. A field hydraulic fracturing test was conducted, and the experimental results are in good agreement with the theoretical calculation results. The maximum error was 5.5%, which validates the proposed theoretical model. The accuracy of the proposed theoretical model in the calculation of the fracture initiation pressure increased by 364.4% compared with the classical hydraulic fracturing theory. The results obtained by this study can provide more precise guidance to hydraulic fracturing projects.",6,6,14
Pump,Fracture,"Xiao, Hui; Li, Zhenming; He, Siyuan; Lu, Xinqian; Liu, Pingli; Li, Jun",Experimental study on proppant diversion transportation and multi-size proppant distribution in complex fracture networks,Experimental study; Multistage fracture networks; Proppant diversion transportation; Proppant separation; Proppant distribution,,"Proppant transportation in fracture networks is significant for hydraulic fracture design and evaluation. Previous studies on proppant placement in complex fracture networks had shortcomings in terms of proppant diversion transportation, proppant distribution in a secondary fracture, and proppant distribution with different particle sizes. This experimental study was conducted on proppant diversion transportation and distribution in complex fracture networks based on the visualization proppant placement model. The findings revealed that the critical proppant diversion time rapidly decreased with the increase in the pumping rate. When the pumping rate was lower than 2.5 m(3)/h, no proppant diversion transportation was found in the second- and third-branch fractures. The smaller-sized proppant particles (100 mesh) were distributed mainly in the fracture located far away from the wellbore or the major fracture. More smaller-sized proppant particles were distributed in the deeper fracture when the difference between the proppant particle sizes was large. Increasing the pumping times increased the transport of proppant particles to deeper fractures. However, the increase in the amplitude was larger in 100-mesh proppant particles than in 30/50-mesh proppant particles. Smaller-sized proppant particles were more easily transported to branch fractures, thus increasing the proppant placement efficiency. The experimental findings can be used to optimize the parameters of the stimulated reservoir volume fracturing to improve the effectiveness of fracture networks.",4,4,13
Pump,Fracture,"Yan, Yan; Guan, Zhichuan; Zhang, Bo; Chen, Weiqing",Numerical investigation of debonding extent development of cementing interfaces during hydraulic fracturing through perforation cluster,Hydraulic fracturing; Perforation; Cohesive zone method; Cement debonding; Well integrity,PLASTIC-DAMAGE MODEL; SHEATH INTEGRITY; ZONAL ISOLATION; SIMULATION; PROPAGATION; STRENGTH; FAILURE; DRIVEN; WELLS,"The perforation will damage the sealing integrity of cement sheath/cementing interfaces around the hole more or less, especially the debonding of cementing interfaces may lead to the fluid channeling during hydraulic fracturing. In this work, a laboratory experiment were used to verify the cohesive zone method (CZM) for simulating the debonding extent of casing/cement interface from a single hole during hydraulic fracturing. Then the debonding degree of cementing interfaces through perforation cluster during fracturing was investigated by using CZM. The numerical analysis results showed that the axial debonding length of the cement/formation interface is longer than which of casing/cement interface under the same working conditions. When the debonding zone around the perforation holes connected to each other, the cement/formation interface debonded faster than that of the casing/cement interface under the pressure of fracturing. The parameter sensitivity analysis shows that it is beneficial to diminish the debonding extent of cementing interfaces by reducing the viscosity of fracturing fluid and the pump pressure. The reliability of CZM method was validated by means of the peak values of critical failure pressure and casing displacement during lab scale fracturing experiment. Improving interfacial bonding strength and reducing the elastic modulus of the cement sheath can effectively promote wellbore integrity during hydraulic fracturing. This work can be used to evaluate the sealing performance of the cement sheath under the hydraulic fracturing and to provide guidance for fracturing planning.",4,4,7
Pump,Fracture,"Zhu, Haiwen; Zhu, Jianjun; Lin, Zimo; Zhao, Qingqi; Rutter, Risa; Zhang, Hong-Quan",Performance degradation and wearing of Electrical Submersible Pump (ESP) with gas-liquid-solid flow: Experiments and mechanistic modeling,,,"Electrical Submersible Pump (ESP), one of the most profitable artificial lift methods in the petroleum industry, is sensitive to flow conditions, especially under solid-particle flow. Compared to the sand produced from the unconsolidated sandstone, the proppant backflow in hydraulic fractured wells is more erosive to ESPs due to its higher hardness and larger diameter. As a result, the pump geometry is jeopardized, and the boosting pressure is affected. Therefore, the sand-water-air tests were conducted in this study to investigate the performance degradation and wearing damage in ESPs. For the first time, a semi-mechanistic model based on Achard law was proposed to predict the abrasion damage in the second flow passage of an ESP. A new mechanistic model was established to predict pump boosting pressure and describe the pump leakage effect under gas-liquid flow conditions. Considering the rotational effect, the leakage flow rate was calculated in three stage seal clearances, skirt ring, balance ring, and inter-stage. The change of the clearance calculated by the proposed abrasion equation agrees well with the experimental measurement. With the original and eroded pump geometries, the predicted ESP two-phase boosting pressure matches the measured pump curves, while the flow pattern transition from bubbly flow to intermittent flow is also captured.",3,3,4
Pump,ESP,"Yang, Yang; Zhou, Ling; Shi, Weidong; He, Zhaoming; Han, Yong; Xiao, Yu",Interstage difference of pressure pulsation in a three-stage electrical submersible pump,Electrical submersible pump; Unsteady flow; Pressure pulsation; Numerical simulation,MODEL; FLOW; SIMULATION; VISCOSITY; VOLUTE,"Electrical Submersible Pumps (ESPs) are the key equipment for oil exploration. The hydraulic noise and vibration inside ESP are mainly induced by the internal pressure pulsation, which is an important reference index for ESPs' operational stability. The mechanism and characteristics of pressure pulsation in multistage pump is not clear until now, which is more complex and difficult than a single stage pump. In this study, based on numerical simulation and experiment measurement, the inter-stage difference of internal flow field distribution and the pressure pulsation characteristics inside a typical three-stage ESP was investigated. The numerical predictions results show a good agreement with the experiment results. Then a comparative analysis of the flow fields inside the impellers, diffusers and chambers under different flow conditions was performed. The results show that the dynamic and static interference between impeller and diffuser is the direct cause of pressure pulsations within the ESP. It found that although the geometry of the ESP is the same, the pressure pulsations within it are not identical. The pressure pulsation signal has a cascading phenomenon to a certain extent. The amplitude and phase of pressure fluctuations have interstage difference due to the coupling of pressure filed among stages. When the number of stages is high, the pressure pulsations caused by the interference phenomenon can seriously threaten the operational stability of ESP by inducing vibration and noise. This work can enhance the understanding of inter-stage flow field differences inside ESP, and provide useful insight on the subsequent improvements of ESPs' operational stability.",44,44,14
Pump,ESP,"Vieira Bulgarelli, Natan Augusto; Biazussi, Jorge Luiz; Verde, William Monte; Perles, Carlos Eduardo; de Castro, Marcelo Souza; Bannwart, Antonio Carlos",Experimental investigation on the performance of Electrical Submersible Pump (ESP) operating with unstable water/oil emulsions,Electrical submersible pump; Water/oil emulsion flow; Effective viscosity; Unstable emulsion; Phase inversion,CRUDE-OIL-EMULSIONS; PHASE INVERSION; FLOW; EMULSIFICATION; POINT,"Electrical Submersible Pump (ESP) is one of the most commonly used artificial lift methods in petroleum production, due to its capacity to operate in several conditions with two or three-phase flows. When the ESP operates with emulsion flow, its performance is degraded, and operational instabilities occur. Therefore, this paper aims to carefully investigate phase inversion and to present, by the first time, the effective viscosity of unstable mineral oil/water emulsions, within the ESP. The first part of this work analyzes the phase inversion phenomenon for two oil types in three viscosities, five ESP rotational speeds, and three mixture flow rates. Logistic functions were fitted using the dimensionless head as a water cut function to determine the phase inversion within the ESP. The continuous phase inversion model, developed for emulsion pipe flow, did not present a satisfactory agreement to flow conditions tested. An indirect method to determine the emulsion effective viscosity within the ESP was proposed, which was obtained from the water/oil emulsion performance curves. The viscous performance data were used to determine the parameters of a dimensionless head empirical model for the tested ESP. Thus, the calculated values were compared with the effective viscosity obtained with oil and water emulsions, as well as the ESP performance, operating with emulsion and oil, which provides similar values for low rotational speeds. The different behavior of the effective viscosity between the pipeline flow and within the ESP was observed for water-in-oil emulsions and may be related to the high centrifugal field in the ESP.",6,6,0
Pump,ESP,"Zhu, Haiwen; Zhu, Jianjun; Lin, Zimo; Zhao, Qingqi; Rutter, Risa; Zhang, Hong-Quan",Performance degradation and wearing of Electrical Submersible Pump (ESP) with gas-liquid-solid flow: Experiments and mechanistic modeling,,,"Electrical Submersible Pump (ESP), one of the most profitable artificial lift methods in the petroleum industry, is sensitive to flow conditions, especially under solid-particle flow. Compared to the sand produced from the unconsolidated sandstone, the proppant backflow in hydraulic fractured wells is more erosive to ESPs due to its higher hardness and larger diameter. As a result, the pump geometry is jeopardized, and the boosting pressure is affected. Therefore, the sand-water-air tests were conducted in this study to investigate the performance degradation and wearing damage in ESPs. For the first time, a semi-mechanistic model based on Achard law was proposed to predict the abrasion damage in the second flow passage of an ESP. A new mechanistic model was established to predict pump boosting pressure and describe the pump leakage effect under gas-liquid flow conditions. Considering the rotational effect, the leakage flow rate was calculated in three stage seal clearances, skirt ring, balance ring, and inter-stage. The change of the clearance calculated by the proposed abrasion equation agrees well with the experimental measurement. With the original and eroded pump geometries, the predicted ESP two-phase boosting pressure matches the measured pump curves, while the flow pattern transition from bubbly flow to intermittent flow is also captured.",3,3,4
Pump,Drilling,"Peng, Nian; Ma, Tianshou; Chen, Ping; Liu, Yang",Pore pressure evaluation of formation testing while drilling under supercharged conditions,Pore pressure; Formation evaluation; Formation testing while drilling; Supercharging; Pressure response,PREDICTION,"Formation Testing While Drilling (FTWD) to evaluate pore pressure has significantly progressed in geo-energy exploitation. However, with the increasing number of unconventional reservoirs, this technology is facing some challenges owing to the common occurrence of supercharging in the vicinity of boreholes. The pressure response of FTWD under supercharged conditions is different from that of non-supercharged; thus, conventional methods - such as Pressure DrawDown (PDD), Pressure BuildUp (PBU), and Formation Rate Analysis (FRA) - cannot be used to determine the original pore pressure. In this paper, a new mathematical model of the FTWD pressure response under supercharged conditions is proposed by considering the time-dependent filter cake, supercharging, skin, geometry, and storage effects. The calculated results indicated that when the formation permeability was lower than 5 mD, the supercharging effect on the pressure response of FTWD cannot be neglected. The pressure response curve of FTWD under supercharged conditions only includes three segments: the fast pressure drawdown stage, pressure buildup stage, and recovered pressure decreasing stage. It is also found that the pressure response in the later stage is independent of the withdraw withdrawal pumping modes and the pressure response curves are nearly the same. Based on the pressure response characteristics, a novel method to evaluate the original pore pressure was proposed. Case studies show that the proposed method can obtain the correct virgin pore pressure after a few iterations and the relative error is lower than 0.2%. Compared with conventional methods, this method is more accurate and saves time; thus, it can be used to evaluate the original pore pressure of FTWD under supercharged conditions.",4,4,5
Pump,Drilling,"Alali, Ammar M.; Abughaban, Mahmoud F.; Aman, Beshir M.; Ravela, Sai",Hybrid data driven drilling and rate of penetration optimization,ROP; Optimization; Data-driven; Machine learning; Drilling mechanics; Real time adjustments,PREDICTION; INVERSION; ROP,"Optimizing the drilling process for cost and efficiency requires faster drilling with a higher rate of penetration (ROP). A high ROP usually indicates fast and cost-efficient drilling operations; however, high ROPs may induce unintended events, which may lead to nonproductive time (NPT). In this paper, the proposed hybrid, data-driven optimization system aims to improve the drilling process, maximize the ROP, and minimize NPT. This two-phase system leverages existing drilling data (Phase One) and real-time adjustments (Phase Two) to optimize drilling efficiency through the adjustment of controllable dynamic drilling parameters; weight on bit (WOB), pump flow rate (GPM), and rotary speed (RPM). In the first phase, geological data is queried to generate a model of drilling best practices in a certain field with attention to ROP and NPT. After the top-rated wells are identified, the model recommends adjustments to the controllable dynamic drilling parameters (WOB, GPM, RPM) and produces a cross-plot for each ROP. The optimum ROP parameter for each well is subsequently calculated as a conditioned mean based on proximity to the well as an Inverse Distance Weighting (IDW) interpolation. This phase is completed prior to any drilling activity. The second phase considers the model produced in phase one to run an automated drill-off test. The model directs the driller to deviate for controllable parameters WOB and RPM by a small percentage (0-5%), in a Constrained Random Search (CRS) way. These deviations allow the driller to explore new drilling conditions in small increments; the data is then compiled into a heat-map function of ROP and the model is updated to reflect optimum drilling parameters. The adjustments resulted in faster, safer ROP with a potential 22%+ improvement in efficiency and 15-20% cost-reduction. Lastly, to characterize the relationship between the controllable dynamic parameters (WOB, RPM, GPM) to the ROP, an ANN based empirical relationship was derived.",3,3,8
Pump,Drilling,"Chen, Guo; Yan, Zhidan; Gao, Tingzheng; Sun, Hehui; Li, GuoLin; Wang, Junfei",Study on model-based pump noise suppression method of mud pulse signal,Model-based denoising; Pump noise; Kalman filter; Mud pulse transmission; Measurement while drilling/logging while drilling,,"Mud pulse telemetry system plays a critical role in modern oil drilling engineering. However, the valid signal is complicated to be obtained because of the main disturbing of pump noises, especially in ultra-deep drilling operations. Therefore, four model-based noise suppression plans for the mud pulse signal pump are mainly proposed in this paper. First, three kinds of pump noise state-space models (linear time-invariant model, linear time-varying model, and nonlinear model) are constructed based on the detailed analysis of the pump noise characteristics. Then, the standard Kalman filter based on the linear system and the extended Kalman filter and unscented Kalman filter algorithm adopting the nonlinear system are respectively used to reconstruct and filter the pump noise. Moreover, the wavelet threshold denoising method based on a new power threshold function is specifically adopted to filter residual random noise after the removal of pump noise. Simultaneously, several noise-containing mud pulse signals with different SNRs (Signal-to-Noise Ratios) in the stable/unstable pump noise states were simulated. Besides, the noise suppression capability experiments of the four plans are deeply conducted. The results indicate that all the four plans can suppress and even remove the stable or unstable pump noise from the original signals: plan 1 and plan 2 have similar denoising effect, which can improve the SNR of signals with stable and unstable pump noise of different intensities by approximately 5-25 dB and 5-14 dB; while the plan 3 can increase the SNR of signals by about 4-20 dB and 2-8 dB; and plan 4 can increase that by about 4-20 dB and 1-8 dB, respectively. Under the comprehensive consideration of denoising ability, computation intensity and convergence speed, it is suggested that plan 1 integrating the time-invariant linear model and the standard Kalman filtering reveals superior performance. Furthermore, using the processing method consisting of plan 1 and wavelet threshold denoising method, the SNRs of the denoised signals can reach 6-7 dB even if the original SNR is as low as 30 dB. The proposed method is applied to the actual deep well mud pulse signal processing. The effective downhole pulse transmission waveform is successfully obtained, providing a highly reliable input signal for subsequent data restoration and contributing to an essential and practical significance for improving mud pulse transmission quality.",3,3,4
Pump,Real Time,"Alali, Ammar M.; Abughaban, Mahmoud F.; Aman, Beshir M.; Ravela, Sai",Hybrid data driven drilling and rate of penetration optimization,ROP; Optimization; Data-driven; Machine learning; Drilling mechanics; Real time adjustments,PREDICTION; INVERSION; ROP,"Optimizing the drilling process for cost and efficiency requires faster drilling with a higher rate of penetration (ROP). A high ROP usually indicates fast and cost-efficient drilling operations; however, high ROPs may induce unintended events, which may lead to nonproductive time (NPT). In this paper, the proposed hybrid, data-driven optimization system aims to improve the drilling process, maximize the ROP, and minimize NPT. This two-phase system leverages existing drilling data (Phase One) and real-time adjustments (Phase Two) to optimize drilling efficiency through the adjustment of controllable dynamic drilling parameters; weight on bit (WOB), pump flow rate (GPM), and rotary speed (RPM). In the first phase, geological data is queried to generate a model of drilling best practices in a certain field with attention to ROP and NPT. After the top-rated wells are identified, the model recommends adjustments to the controllable dynamic drilling parameters (WOB, GPM, RPM) and produces a cross-plot for each ROP. The optimum ROP parameter for each well is subsequently calculated as a conditioned mean based on proximity to the well as an Inverse Distance Weighting (IDW) interpolation. This phase is completed prior to any drilling activity. The second phase considers the model produced in phase one to run an automated drill-off test. The model directs the driller to deviate for controllable parameters WOB and RPM by a small percentage (0-5%), in a Constrained Random Search (CRS) way. These deviations allow the driller to explore new drilling conditions in small increments; the data is then compiled into a heat-map function of ROP and the model is updated to reflect optimum drilling parameters. The adjustments resulted in faster, safer ROP with a potential 22%+ improvement in efficiency and 15-20% cost-reduction. Lastly, to characterize the relationship between the controllable dynamic parameters (WOB, RPM, GPM) to the ROP, an ANN based empirical relationship was derived.",3,3,8
Pump,Real Time,"Zhang, Ruichao; Yin, Yuqiong; Xiao, Liangfei; Chen, Dechun",A real-time diagnosis method of reservoir-wellbore-surface conditions in sucker-rod pump wells based on multidata combination analysis,Dynamometer card; Power vs. position plot; Working condition diagnosis; Dynamic fluid level; Fluid production; Real time,PRESSURE; PREDICTION; SYSTEM,"This paper proposes a real-time diagnosis method that addresses the limitations of traditional ""dynamometer cards"" used for sucker-rod pump performance analysis. The ""power vs. position plots"" are proposed to demonstrate an improved diagnostic method for rod pump performance. On this basis, the working condition diagnosis plate of the sucker-rod pump well is created. The eigenvalues of dynamometer cards and ""power vs. position plots"" under different working conditions are extracted, and a combined diagnosis model based on feature recognition is established. The model not only diagnoses the wellbore condition but also the surface condition, which improves the diagnosis effect and expands the diagnosis range. In addition, considering the surface dynamometer card as the known condition, the one-dimensional damping wave equation is used to solve the downhole pump dynamometer card. By analyzing the change law of the pump-load slope-time relationship curve, the opening and closing points of the pump valve are accurately extracted, and the load difference between the upstroke and downstroke, and the effective stroke of the downhole pump dynamometer card are determined. On this basis, a calculation model of the dynamic fluid level and fluid production is established to determine the change in reservoir energy and analyze the supply and discharge relationship of the sucker-rod pump wells. Combined with the online collection of the surface dynamometer cards and ""power vs. position plots,"" the real-time diagnosis of oil well production systems can be realized. This can effectively improve the timeliness of sucker-rod pump performance analysis, reduce production management costs, and improve the production efficiency and benefits of the oilfield.",3,3,3
Pump,Proppant,"Xiao, Hui; Li, Zhenming; He, Siyuan; Lu, Xinqian; Liu, Pingli; Li, Jun",Experimental study on proppant diversion transportation and multi-size proppant distribution in complex fracture networks,Experimental study; Multistage fracture networks; Proppant diversion transportation; Proppant separation; Proppant distribution,,"Proppant transportation in fracture networks is significant for hydraulic fracture design and evaluation. Previous studies on proppant placement in complex fracture networks had shortcomings in terms of proppant diversion transportation, proppant distribution in a secondary fracture, and proppant distribution with different particle sizes. This experimental study was conducted on proppant diversion transportation and distribution in complex fracture networks based on the visualization proppant placement model. The findings revealed that the critical proppant diversion time rapidly decreased with the increase in the pumping rate. When the pumping rate was lower than 2.5 m(3)/h, no proppant diversion transportation was found in the second- and third-branch fractures. The smaller-sized proppant particles (100 mesh) were distributed mainly in the fracture located far away from the wellbore or the major fracture. More smaller-sized proppant particles were distributed in the deeper fracture when the difference between the proppant particle sizes was large. Increasing the pumping times increased the transport of proppant particles to deeper fractures. However, the increase in the amplitude was larger in 100-mesh proppant particles than in 30/50-mesh proppant particles. Smaller-sized proppant particles were more easily transported to branch fractures, thus increasing the proppant placement efficiency. The experimental findings can be used to optimize the parameters of the stimulated reservoir volume fracturing to improve the effectiveness of fracture networks.",4,4,13
Pump,Proppant,"Zhu, Haiwen; Zhu, Jianjun; Lin, Zimo; Zhao, Qingqi; Rutter, Risa; Zhang, Hong-Quan",Performance degradation and wearing of Electrical Submersible Pump (ESP) with gas-liquid-solid flow: Experiments and mechanistic modeling,,,"Electrical Submersible Pump (ESP), one of the most profitable artificial lift methods in the petroleum industry, is sensitive to flow conditions, especially under solid-particle flow. Compared to the sand produced from the unconsolidated sandstone, the proppant backflow in hydraulic fractured wells is more erosive to ESPs due to its higher hardness and larger diameter. As a result, the pump geometry is jeopardized, and the boosting pressure is affected. Therefore, the sand-water-air tests were conducted in this study to investigate the performance degradation and wearing damage in ESPs. For the first time, a semi-mechanistic model based on Achard law was proposed to predict the abrasion damage in the second flow passage of an ESP. A new mechanistic model was established to predict pump boosting pressure and describe the pump leakage effect under gas-liquid flow conditions. Considering the rotational effect, the leakage flow rate was calculated in three stage seal clearances, skirt ring, balance ring, and inter-stage. The change of the clearance calculated by the proposed abrasion equation agrees well with the experimental measurement. With the original and eroded pump geometries, the predicted ESP two-phase boosting pressure matches the measured pump curves, while the flow pattern transition from bubbly flow to intermittent flow is also captured.",3,3,4
Pump,Flow Pattern,"He, Denghui; Zhao, Lin; Chang, Zhuang; Zhang, Zhenduo; Guo, Pengcheng; Bai, Bofeng",On the performance of a centrifugal pump under bubble inflow: Effect of gas-liquid distribution in the impeller,Bubble flow; Centrifugal pump; Flow pattern; Surging; Pressure increment; Efficiency,FLOW PATTERNS; AIR,"Determining the characteristics of gas-liquid two-phase flow in centrifugal pumps is essential for a better understanding of pump performance. In this study, a visualization investigation was performed to determine the effect of the gas-liquid distribution in the impeller on the performance of a centrifugal pump with a closed impeller. Emphasis was placed on the influences of the inlet gas volume fraction (IGVF), flow rate, and rotational speed on the gas-liquid distribution in the impeller and, thus, on the surging characteristics of the pump. The correlation mechanism between the distribution of the gas-liquid phase in the impeller and the surging characteristics of the pump was revealed. Finally, several surging prediction models were examined. The results show that the gas-liquid two-phase distribution in the impeller has an immediate impact on the pressure increment and efficiency of the pump. The increase in IGVF directly induced pump surging by changing the flow pattern in the impeller. Surging occurred when the flow pattern changed from gas pocket flow to segregated flow. It was also found that pump surging could be eliminated by adjusting the flow rate and increasing the rotational speed, which changed the flow pattern inside the impeller. Compared with the experimental results, the critical IGVF obtained by the existing surging prediction model exhibits some deviation. The surging prediction model dedicated to the volute centrifugal pump requires further investigation. The results reported here can provide better insight into the performance of volute-type centrifugal pumps and provide a reference for developing corresponding surging prediction models.",4,4,6
Pump,Flow Pattern,"Zhu, Haiwen; Zhu, Jianjun; Lin, Zimo; Zhao, Qingqi; Rutter, Risa; Zhang, Hong-Quan",Performance degradation and wearing of Electrical Submersible Pump (ESP) with gas-liquid-solid flow: Experiments and mechanistic modeling,,,"Electrical Submersible Pump (ESP), one of the most profitable artificial lift methods in the petroleum industry, is sensitive to flow conditions, especially under solid-particle flow. Compared to the sand produced from the unconsolidated sandstone, the proppant backflow in hydraulic fractured wells is more erosive to ESPs due to its higher hardness and larger diameter. As a result, the pump geometry is jeopardized, and the boosting pressure is affected. Therefore, the sand-water-air tests were conducted in this study to investigate the performance degradation and wearing damage in ESPs. For the first time, a semi-mechanistic model based on Achard law was proposed to predict the abrasion damage in the second flow passage of an ESP. A new mechanistic model was established to predict pump boosting pressure and describe the pump leakage effect under gas-liquid flow conditions. Considering the rotational effect, the leakage flow rate was calculated in three stage seal clearances, skirt ring, balance ring, and inter-stage. The change of the clearance calculated by the proposed abrasion equation agrees well with the experimental measurement. With the original and eroded pump geometries, the predicted ESP two-phase boosting pressure matches the measured pump curves, while the flow pattern transition from bubbly flow to intermittent flow is also captured.",3,3,4
Pump,Rod Pump,"Chen, Lu; Gao, Xianwen; Li, Xiangyu",Using the motor power and XGBoost to diagnose working states of a sucker rod pump,Sucker rod pump; Diagnosis; Motor power; Extreme gradient boost,,"In oilfiled production, the dynamometer cards are usually used to diagnose the downhole conditions of the pumping well. They record changes in the rod load versus rod displacement. However, the measurement has deficiencies such as poor real-time performance and high maintenance costs. Aiming at the problems, a novel method based on motor power for fault detection of the sucker rod pump is proposed in this paper. In this method, the motor power curves of seven working states are obtained by transforming the dynamometer cards into motor power curves. The characteristics of the motor power curves under different working states are analyzed combining with the theoretical motor power curve. Furthermore, the novel sixteen features are extracted in time and frequency domains with the analysis of the working mechanism of the sucker rod pump. Subsequently, the Extreme Gradient Boosting (XGBoost) algorithm, machine learning algorithm, is employed to classify and identify working states of the sucker rod pumps. At last, this paper uses the dataset collected from the oil field to corroborate the proposed method. The experimental results showing the proposed method gives 98% correct diagnosis, proves a higher accuracy to SVM and KNN. Moreover, the final engineering practice also proves the effectiveness of the method proposed in this paper.",3,3,6
Pump,Rod Pump,"Zhang, Ruichao; Yin, Yuqiong; Xiao, Liangfei; Chen, Dechun",A real-time diagnosis method of reservoir-wellbore-surface conditions in sucker-rod pump wells based on multidata combination analysis,Dynamometer card; Power vs. position plot; Working condition diagnosis; Dynamic fluid level; Fluid production; Real time,PRESSURE; PREDICTION; SYSTEM,"This paper proposes a real-time diagnosis method that addresses the limitations of traditional ""dynamometer cards"" used for sucker-rod pump performance analysis. The ""power vs. position plots"" are proposed to demonstrate an improved diagnostic method for rod pump performance. On this basis, the working condition diagnosis plate of the sucker-rod pump well is created. The eigenvalues of dynamometer cards and ""power vs. position plots"" under different working conditions are extracted, and a combined diagnosis model based on feature recognition is established. The model not only diagnoses the wellbore condition but also the surface condition, which improves the diagnosis effect and expands the diagnosis range. In addition, considering the surface dynamometer card as the known condition, the one-dimensional damping wave equation is used to solve the downhole pump dynamometer card. By analyzing the change law of the pump-load slope-time relationship curve, the opening and closing points of the pump valve are accurately extracted, and the load difference between the upstroke and downstroke, and the effective stroke of the downhole pump dynamometer card are determined. On this basis, a calculation model of the dynamic fluid level and fluid production is established to determine the change in reservoir energy and analyze the supply and discharge relationship of the sucker-rod pump wells. Combined with the online collection of the surface dynamometer cards and ""power vs. position plots,"" the real-time diagnosis of oil well production systems can be realized. This can effectively improve the timeliness of sucker-rod pump performance analysis, reduce production management costs, and improve the production efficiency and benefits of the oilfield.",3,3,3
Corrosion,,"Lu, Hongfang; Iseley, Tom; Matthews, John; Liao, Wei; Azimi, Mohammadamin",An ensemble model based on relevance vector machine and multi-objective salp swarm algorithm for predicting burst pressure of corroded pipelines,Corroded pipeline; Burst pressure; Prediction; Relevance vector machine; Multi-objective salp swarm algorithm; Machine learning,API X70 PIPE; FAILURE PRESSURE; PROBABILISTIC ANALYSIS; INTEGRITY ASSESSMENT; CORROSION DEFECTS; STRENGTH; STEEL; DEPTH; LOAD,"Burst pressure is the key to the design of pressure pipelines, and its accurate prediction is of considerable significance to pipeline safety and integrity management. Due to the different corrosion forms of different pipelines, the traditional empirical formula is difficult to predict the burst pressure with high accuracy. This paper proposes an ensemble data-driven model that can train the model based on existing pipeline parameters, corrosion characteristics, and burst pressure data. The trained model can be used to predict the burst pressure of pipelines with other pipeline parameters and corrosion characteristics. In the ensemble model design, a more advanced machine learning model, relevance vector machine, is used as the basic predictor. Multi-objective salp swarm algorithm is utilized to optimize the relevance vector machine, to improve the prediction accuracy and stability. The proposed model is applied to three datasets with different features and inputs. The results reveal that the average absolute percent errors of the proposed model in the three datasets are 3.724%, 1.788%, and 4.133%, respectively, and the standard deviations of the percentage errors are 9.07%, 2.36%, and 5.42%, respectively, which are all in a low level. The results indicate that the proposed model has high prediction accuracy and stability in different datasets, even when the data amount is small. Moreover, the Diebold-Mariano test implies that the proposed model's prediction performance is better than benchmark models, and much better than the model without the optimizer or with the single-objective optimizer.",9,9,5
Corrosion,,"Elgaddafi, Rida; Ahmed, Ramadan; Shah, Subhash",Corrosion of carbon steel in CO2 saturated brine at elevated temperatures,Corrosion; Carbon dioxide; Brine; Temperature; Salt concentration; Carbon steel,HIGH-PRESSURE; MILD-STEEL; DIOXIDE CORROSION; MECHANISTIC MODEL; SODIUM-CHLORIDE; THERMODYNAMIC PROPERTIES; CR STEELS; PART 1; IRON; BEHAVIOR,"One of the main challenges in oil and gas wells is ensuring wellbore and casing integrity in a CO2 saturated brine environment. The integrity of a well casing relies on its mechanical properties and corrosion resistance to harsh downhole conditions. This paper discloses the results of a mathematical modeling study and experimental investigation conducted to understand the corrosion behavior of carbon steel (AISI 1045 Medium Carbon steel) in CO2 saturated brine. Corrosion experiments were carried out at 0.83 MPa varying temperature and CO2 partial pressure (CPP). To prepare test fluid, 1 wt % NaCl was added to deionized water and thoroughly mixed. The Weight loss (WL) and Linear polarization resistance (LPR) techniques were employed for investigating corrosion. A comprehensive corrosion model is formulated to predict corrosion in a CO2 environment containing high-salt concentration. Results indicate a strong impact of temperature on CO2 corrosion in brine environment. At low CPPs (P-CO2 <= 0.41 MPa), the pick corrosion rate was noted at 43 degrees C. Furthermore, the influence of NaCl content on corrosion was strongly affected by CO2 concentration. The model is predominantly in agreement with existing corrosion measurements and it predicts the inhibiting effect of salt in CO2 corrosion.",7,7,5
Corrosion,,"Ye, Tao; Chen, Anqing; Niu, Chengming; Wang, Qing Bing","Structural, petrophysical and lithological characterization of crystalline bedrock buried-hill reservoirs: A case study of the southern jinzhou oilfield in offshore Bohai Bay Basin, north China",Crystalline bedrock; Reservoir characteristics; Vertical zoning; Controlling factors; Reservoir development pattern; Bohai baybasin,LU FAULT ZONE; BONGOR BASIN; BASEMENT; ACCUMULATION; EVOLUTION; SUBBASIN; GNEISS; AREA,"Crystalline bedrock has always been regarded as a restricted area for hydrocarbon exploration due to its large burial depth and deficiency of primary porous. In recent years, bedrock oil and gas have been explored in several basins across the world, while the characteristics and control factors of large-scale bedrock reservoirs have not been systematically studied. Taking South of Jinzhou oil field as an example, we clarified the reservoir characteristics based on the investigation of the cores, thin sections, physical property and well loggings, and discussed the controlling factors of high quality reservoir considering lithology, fault activity and the paleotopography. The results show that although primary porous are less developed in bedrocks, the tectonic fractures, weathering fractures, pores among crushing particles and corrosion holes developed along fractures constitute rich reservoir spaces in the study area, and the average porosity can reach 6.7%. Dioritic gneiss and granitic gneiss are easier to form reservoirs than diabase for higher felsic contents and more brittleness; reservoirs along the main faults zone with strong activity are thick; in addition, high position of the paleo-topography develops thicker reservoirs due to the release of the stress and the strong weathering. Under the coupling action of weathering and tectonic activity, there developed weathered clay zone, weathered glutenite zone, weathered fracture zone, structural fracture zone, structural breccia zone and tight zone from top to bottom vertically. The present study shows that although there is no primary porosity in bedrocks, large-scale and quality reservoirs could be formed for brittle bedrocks under the coupling effects of strong tectonic activities and weathering. This recognition is of great significance for bedrock hydrocarbon exploration in the basins of high exploration degree all over the world.",5,5,2
Corrosion,,"Santos, B. A. F.; Serenario, M. E. D.; Souza, R. C.; Oliveira, J. R.; Vaz, G. L.; Gomes, J. A. C. P.; Bueno, A. H. S.",The electrolyte renewal effect on the corrosion mechanisms of API X65 carbon steel under sweet and sour environments,Carbon steel; CO2; EIS; SEM; XRD; high temperature corrosion,,"Sweet and sour services are the most common media found inside the pipelines of petroleum industry. They are one of the main causes of degradation by corrosion that lead to several financial and environmental losses worldwide. They also are responsible for the formation of corrosion products that might play a protective feature on the metal surface diminishing the corrosive processes. However, conditions in the field are not necessarily favourable for the precipitation of protective structures given the physicochemical dynamism inside the pipes. Then, the need to address this issue that occurs inside the tubes becomes crucial for the correct assessment of the development of protective corrosion products hence to give a more realistic approach to the lab conditions. Therefore, this paper presents a methodology to investigate the electrolyte renewal effects on API X65 carbon steel corrosion under CO2 and H2S (thiosulfate) environments at 4,5 bar of pressure, temperatures of 90 degrees C and 120 degrees C over 150 h. Electrochemical techniques (LPR and EIS), weight loss and characterizations were conducted in two different average pH, 3,3 and 4,5. The proposed methodology was capable to delay the development of protective scales in renewed media. The corrosion rates were higher for conditions with electrolyte renewal and higher temperature. FeCO3 formation was favoured at high pH and 120 degrees C whilst FeS structures were dominant at 90 degrees C. Sulphides were more cracked and uneven in renewed media whereas carbonate crystals presented higher anchorage to the substrate and were able to develop in sizeable diameters. Unrenewed media presented the best electrochemical responses.",5,5,1
Corrosion,,"Saini, Sunny; Banerjee, Jyotirmay",Recurrence analysis of pressure signals for identification of intermittent flow sub-regimes,Intermittent flow; Plug; Slug; Flow visualization; Pressure signal; Recurrence analysis,2-PHASE FLOW; SLUG FLOW; PATTERN TRANSITION; PIPE DIAMETER; PREDICTION; CORROSION; PLUG,"Recurrence analysis of pressure signals measured from the pipe wall simultaneously with flow visualization is used to depict a methodology for identifying intermittent flow sub-regimes through opaque pipes. Pressure signal alone is not sufficient to differentiate two-phase flow regimes in an opaque pipe. Hence, the phase space trajectory of pressure signals is used to develop a recurrence plot for each sub-regime. It is observed that a homogeneously dispersed type of recurrence plot is obtained for plug flow which changes to a checkerboard-like structure for the slug flow pattern. This depicts the chaotic nature of slug flow. The chaos increases with further increase in gas superficial Reynolds number when aeration in slug flow enhances, leading to highly aerated slug flow. It is established that the recurrence plot and recurrence quantification parameters change as the flow transits from plug to less aerated slug and highly aerated slug regime. Thus the recurrence analysis of pressure signals has shown potentials to be used as a technique to identify different intermittent flow sub-regimes.",5,5,0
Corrosion,,"Ge, Meng-Ru; Miao, Si-Jia; Liu, Jin-Feng; Gang, Hong-Ze; Yang, Shi-Zhong; Mu, Bo-Zhong",Laboratory studies on a novel salt-tolerant and alkali-free flooding system composed of a biopolymer and a bio-based surfactant for oil recovery,Biopolymer/surfactant formula; Ultra-low interfacial tension; Enhanced oil recovery; Salt-tolerant; Alkali-free,HIGH-TEMPERATURE; WELAN GUM; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSIONS; NONIONIC SURFACTANT; ASSOCIATING POLYMER; AQUEOUS WELAN; XANTHAN GUM; STRAIN; POLYSACCHARIDES,"Alkali/surfactant/polymer (ASP) flooding is one of the most effective tertiary oil recovery technologies. However, the formation of an alkali scale potentially results in the reduction of the formation permeability and pipeline corrosion, which affect its industrial application. Recently, the surfactant/polymer (SP) flooding system in the absence of alkali has received increasing attention. Here, we screened a high-yielding strain, which is capable of producing salt-tolerant biopolymer. The results of rheological properties evaluation showed that this biopolymer possessed a stable viscosity at high salinities (up to 200 g/L NaCl, 100 g/L Ca2+, and 100 g/L Mg2+) and a wide range of pH (4-11), indicating its superior salt and pH resistance. Based on these properties, a novel salt-tolerant and alkali-free binary flooding system was constructed with this biopolymer and bio-based surfactant newly synthesized in our lab. The ultra-low interfacial tension (IFT) between crude oil and the binary system containing 0.5 wt % biopolymer and 1.00 g/L surfactant could be achieved in the presence of 100 g/L NaCl or 400 mg/L Ca2+. Moreover, it exhibited good resistance to oil sands adsorption, excellent anti-dilution, and ageing stability. These results indicate that the biopolymer produced by the Kosakonia oryzae strain possessed great potential in the construction of an alkali-free SP system for enhanced oil recovery (EOR) in high salinity and high temperature oil reservoirs.",4,4,5
Corrosion,,"Dong, Baojun; Zeng, Dezhi; Yu, Zhiming; Cai, LeLe; Yu, Huiyong; Shi, ShanZhi; Tian, Gang; Yi, Yonggang",Major corrosion influence factors analysis in the production well of CO2 flooding and the optimization of relative anti-corrosion measures,CO2 corrosion; Corrosion influence factors; Anti-Corrosion measures; Corrosion inhibitor; Corrosion-resistant alloys; CO2 flooding,,"Major corrosion influence factors in the production well of CO2 flooding in Xinjiang oilfield were investigated, and corresponding anticorrosion measures (relating to corrosion inhibitors and corrosion-resistant alloys) had been contrasted in order to select a most suitable scheme to solve the tubing corrosion issue. The results showed that the corrosion of N80 steel in liquid phase was mainly affected by temperature, while in gas phase by temperature and CO2 partial pressure. As to the corrosion of 3Cr steel, in liquid phase, the influencing factors were temperature and chloride concentration, and in gas phase, it was mainly affected by temperature. The safe service life of N80 and P110 steel in liquid phase were less than 8 years, whereas that of 9Cr and 13Cr steel both exceeded 30 years. In gas phase, the safe service life of N80 and P110 steel were 11.65 years and 16.55 years respectively, while that of 3Cr, 9Cr and 13Cr steel were more than 30 years. Suitable for production well in CO2 flooding, No.6 corrosion inhibitor was selected. The corrosion rate of tubing could be controlled within 0.076 mm/y by adding 1000 ppm corrosion inhibitor. 9Cr steel was recommended to be used as the tubing of new production wells for CO2 flooding, and, for old wells, the method of continuous filling corrosion inhibitor was recommended to resist corrosion.",3,4,9
Corrosion,,"Almubarak, Tariq; Ng, Jun Hong; Ramanathan, Raja; Nasr-El-Din, Hisham A.",Chelating agents for oilfield stimulation: Lessons learned and future outlook,Chelating agent; Carbonate acidizing; Sandstone acidizing; Iron control; Chemistry; Aminopolycarboxylic acid,MATRIX ACID STIMULATION; HYDROFLUORIC-ACID; FORMATION DAMAGE; EDTA COMPLEXES; SANDSTONE; DISSOLUTION; ADSORPTION; PRECIPITATION; DEGRADATION; REACTIVITY,"Chelating agents were introduced because of the several issues associated with inorganic acids during oilfield stimulation. Carbonate and sandstone rocks have been stimulated using different kinds of acid systems and there is an engaging debate on chelating agents as an effective acid system. Several shortcomings of inorganic acid systems need to be addressed by chelating agents in order to be its constructive replacement. The complex nature of these chelating agents led to accelerated research and developmental efforts in understanding its applicability at different environmental conditions. The past two decades of research in chelating agents for oilfield stimulation has resulted in researchers branching out in several directions to realize the potential of this acid system. There is a requirement to link these branches and provide a holistic view of the lessons learned during this time. Various researchers have also provided guidance for future work that is commonly disregarded. This paper provides a nexus of the research conducted in this field and could direct plans for future research. Hydrochloric acid for carbonate acidizing and mud acid for sandstone damage removal have been found to cause issues such as face dissolution, reaction product precipitation, chemical incompatibility, high corrosion rates, toxic gas generation, emulsion issues, amongst many others. The recent interest in chelating agents led to researchers conducting tests to understand its interactions with the formation rock and other oilfield fluids. Experiments such as coreflooding, corrosion tests, compatibility, Inductively Coupled Plasma (ICP), Environmental Scanning Electron Microscope (ESEM), and X-Ray Diffraction (XRD) helped in highlighting the advantages of chelating agents. From these studies, researchers were able to find synergistic blends that could help improve traditional treatment practices. Mechanisms of chelating agent reactions with sandstone and carbonate rock were elucidated in this work. The future outlook of chelating agents' application lies in making the treatment more cost-effective, environmentally friendly, and target focused. Chemical formulations must be designed to take advantage of hightemperature stability, low reprecipitation potential, low sludging tendency, high dissolving capacity, high iron controlling potential, and low corrosion rates offered by chelating agents. Some field experiences were noted, which could encourage operators to perform more such treatments in the future. The reader of this review article would gain knowledge of the complex chemistry of chelating agents and describes the research done for acid stimulation and iron control. Through the process of review, the paper also connects the wealth of research in this field and provides a measured guidance for technology development to promote the use of chelating agents in the industry. It can help future researchers in academics or the industry to enhance the quality of research.",3,3,3
Corrosion,,"Verma, Chandrabhan; Alrefaee, Salhah Hamed; Quraishi, M. A.; Ebenso, Eno E.; Hussain, Chaudhery Mustansar","Environmental, safety and economic risks of Covid-19 pandemic in petroleum industries: A prospective",Covid-19; Petroleum industries; Liquid petroleum; Corrosion failure; Top-of-Line corrosion and Bottom-of-Line corrosion,CORROSION,"Because of the Covid-19 pandemic, worldwide consumption of petroleum fuels is reduced due to complete or partial lockdown in most of the countries. The abridged expenditure of liquid fuels imposes pressure on petroleum refinery industries for their processing, storage and transport. Prolonged storage of crude and purified petroleum can cause several corrosion failure problems that can adversely affect the efficiency, storage and transport efficiency of the petroleum refineries. Some of the major corrosion failures encountered because of the prolonged storage are Top-of-Line Corrosion (TLC), Bottom-of-Line Corrosion (BLC), Bottom-of- Storage Tank Corrosion (BSTC), Liquid-Air interface corrosion (LAIC): Differential Aeration Corrosion (DAC). Generally, TLC is attributed due to condensation of water-droplets on the inner-wall of the transport pipelines and closed storage tanks. BLC is accredited due contamination of solid deposits, rusts and scales on the bottom of the transport pipelines and closed storage tanks. DAC is attributed due to the formation of differential aeration cells at the interface of liquid petroleum and open air. Present prospective aims to describe the adverse effect of prolonged storage of petroleum fluids because of Covid-19 pandemic.",3,3,3
Fractal Dimension,,"Wang, Dengke; Zeng, Fanchao; Wei, Jianping; Zhang, Hongtu; Wu, Yan; Wei, Qiang",Quantitative analysis of fracture dynamic evolution in coal subjected to uniaxial and triaxial compression loads based on industrial CT and fractal theory,Industrial CT; Fracture dynamic evolution; Three-dimensional fracture reconstruction; Uniaxial and triaxial compression; Fractal dimension,RAY COMPUTED-TOMOGRAPHY; PORE STRUCTURE; ACOUSTIC-EMISSION; CONFINING PRESSURES; RANK COAL; PERMEABILITY; DIMENSION; GAS; BASIN; RECONSTRUCTION,"The dynamic evolution characteristics of fractures in coal under different compressive loads are of great significance to the recovery of coalbed methane (CBM). In this paper, the X-ray computer tomography (CT) detections of coal samples under uniaxial and triaxial compressive loading conditions were performed by using a developed triaxial in situ rig and an industrial CT scanner. The image processing technique, three-dimensional reconstruction method and statistical principles were employed to describe two-dimensional and three-dimensional fracture evolution in coal under uniaxial and triaxial compressive loads. The results showed that the developed triaxial in situ rig has an enough scanning resolution and is suitable to carry out CT scanning inspections under uniaxial and triaxial compressive loads for porous materials of coal and rock. The two-dimensional cross-sectional CT images effectively reflect the dynamic evolution of two-dimensional fractures during the deformation of coal. Confining pressure and minerals have a significant effect on fracture propagation in coal. The evolution characteristics of three-dimensional fractures can be clearly revealed by the reconstructed three-dimensional digital fracture models of coal. Euler number effectively reflects the fracture connectivity in coal at different deformation stages. During the deformation of coal, the fracture volume, fracture rate, fracture density and fracture connectivity mainly undergo a slow decrease stage, a slow increase stage and a sharp increase stage, display a good linear correlation with fractal dimension, and quantitatively characterize the evolution process of the three-dimensional fractures in coal. The fractal dimension calculated by the box-counting method effectively mirrors fracture propagation and fracture geometric complexity and can be employed to uncover the fracture dynamic evolution in coal under different compressive loading conditions.",7,7,32
Fractal Dimension,,"Yang, Bing; Wang, Haizhu; Wang, Bin; Shen, Zhonghou; Zheng, Yong; Jia, Zhaoyang; Yan, Wanjuan",Digital quantification of fracture in full-scale rock using micro-CT images: A fracturing experiment with N-2 and CO2,Supercritical CO2; Fracturing laboratory experiment; CT scanning; Fracture reconstruction; Quantitative fracture analysis,SUPERCRITICAL CARBON-DIOXIDE; INITIATION PRESSURE; SHALE GAS; WATER; FLUIDS; PROPAGATION; OIL; SKELETONIZATION; PERMEABILITY; EXTENSION,"How to effectively and cleanly exploit unconventional resources is currently being widely concerned. Due to the unavoidable limitations of water-based fracturing, CO2 and N-2 etc., are regarded as alternative fluids for some specific reservoirs such as the arid area or high clay swelling formation. To investigate the characteristics of fracture induced by nonaqueous fluid in unconventional fight formation, fracturing experiments on fight sandstone using different fluid of water, N-2, liquid CO2 (L-CO2) and supercritical CO2 (SC-CO2) were conducted. A novel fracture analysis approach based on CT scanning is also proposed to quantitatively analyze the micromorphology of fractures including fracture network pattern, fractal dimension (FD), aperture, area ratio (AR) and fracture volume etc. Results show that water and N-2 can only induce a relatively simple fracture pattern. Whereas, fractures induced by CO2-based fluid have more complex fracture geometry with many fracture branches and various propagation orientations. Quantitative analysis based on image processing and fracture reconstruction algorithm indicates that the CO2-based fluid has up to 4.4 times larger fracture-induced capacity and can create fracture with up to 2.6 times higher complexity and 23.4% higher roughness than that generated by water-based fracturing. Comparing to SC-CO2, L-CO2 and water, N-2 has the least fracture-induced capacity (83% of water) and produces more smooth and uniform fractures. On the other hand, the distributions of deviation angle suggest that fracture propagation is not only influenced by stress state, but also significantly affected by the original bedding plane. This experimental study proposes a precise and effective approach for fracture characteristic quantification, which can be further implemented into fracture simulation model. It also provides theoretical reference and guidance for field operation of waterless fracturing in development of unconventional oil and gas.",6,6,12
Fractal Dimension,,"Zhou, Junping; Yang, Kang; Zhou, Lei; Jiang, Yongdong; Xian, Xuefu; Zhang, Chengpeng; Tian, Shifeng; Fan, Maolin; Lu, Zhaohui",Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure,Shale reservoir; Supercritical carbon dioxide fracturing; Carbon dioxide sequestration; Mechanical alteration; Carbon dioxide-water-shale interaction,SUPERCRITICAL CO2 TREATMENT; PORE STRUCTURE; CARBON-DIOXIDE; FRACTAL ANALYSIS; MULTIFRACTAL CHARACTERISTICS; ADSORPTION BEHAVIORS; FAILURE MECHANISMS; GAS; NMR; WATER,"CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D-1 and pore volume fractal dimensions D-2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO(2), and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D-1 and D-2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.",5,6,24
Fractal Dimension,,"Yang, Yu; Wang, Dong; Yang, Jingyi; Wang, Bin; Liu, Tao",Fractal analysis of CT images of tight sandstone with anisotropy and permeability prediction,Digital rock analysis; Fractal geometry; Heterogeneous porous media; Permeability,PORE STRUCTURE; POROUS-MEDIA; MODEL; INVESTIGATE; RESERVOIRS; FLOW; SEM,"For developing unconventional oil and gas resources, it is necessary to quantify the heterogeneity embodied in both pore-size distribution (PSD) and pore spatial distribution, on the basis of which the relationship between the seepage characteristics and the microstructure of heterogeneous porous media could then be clarified. In this work, micro computed tomography (mu CT) and image processing technology were applied to characterise matrix pore structure in tight sandstone. Fractal theory was used to investigate the image-based heterogeneity of tight porous media. On the basis of the verification that the PSD of the tight rock is statistically self-similar at a certain scale, we investigated the relationships between porosity and fractal dimension, and between 2D and 3D fractal dimensions, respectively. The results showed that the pore structure characteristic parameters with anisotropy, i. e., the ratio of the minimum pore size to the maximum pore size lambda max/lambda min and a proportionality constant CKT, could be obtained by liner fitting fractal dimension and porosity. Moreover, the 2D PSD characteristics of the 'standard cross section' were consistent with the 3D PSD characteristics of pore network. A fractal permeability model was established by treating the connected pores in the matrix as a bundle of conical micropipes. The permeability values predicted by the proposed model agreed well with those predicted by finite volume method simulation under the condition where irreducible pores were removed. A sensitivity analysis indicated that increasing the heterogeneity of the PSD and pore spatial distribution reduced the flow capacity of the matrix, particularly for low-porosity porous media.",5,4,13
Fractal Dimension,,"Wang, Lei; Guo, Yintong; Zhou, Jun; Yang, Hanzhi; Yang, Chunhe; Xiao, Jialin","Rock mechanical characteristics of deep marine shale in southern China, a case study in Dingshan block",Deep formation; Shale gas; Mechanical characteristic; Post-peak curve; Failure mode; Fractal dimension,ANISOTROPIC PROPERTIES; BRITTLENESS; STRENGTH; HETEROGENEITY; ENERGY,"The success of commercial exploitation of shale gas has already been achieved in middle-shallow layers of China. But more than 65% of shale gas resources is buried in deep formation (vertical depth >= 3500 m), which has not been effectively developed yet. Deep buried depth is the source of a series of challenges. To clarify the influence of buried depth on mechanical characteristics of shale, tri-axial compression tests considering high confining pressures (80 MPa) are conducted with core samples collected from the gas bearing section of a deep marine shale gas well. The results show that the peak deviatoric stress significantly increases with the growth of confining pressure and exhibits an obvious declining trend from bottom to top in longitudinal profile, whereas Young's modulus and Poisson's ratio were all relatively insensitive to buried depth. Unlike conventional smooth tri-axial test curves, many of the post-peak curves are in ""step-like"" shape, and their corresponding failure patterns are always multi-fractures, all of which are originated from the activation of bedding planes or natural fractures during yielding process and are indications of high brittleness. However, the proportion of specimens with these features decreases from 66.7% to 22.2%, with the confining pressure increased from 30 MPa to 80 MPa. As most of existed indices could not properly describe the brittle characteristic of this type of deep marine shale, a new brittleness index (BI) is proposed by quantifying the complexity of ""step-like"" post-peak curves in fractal dimension. It is demonstrated that BI could effectively capture the influence of confining pressure on brittleness and distinguish those more brittle layers. Owing to the great reduction of brittleness and fracture complexity under high confining pressure, the fracking network in deep formation might be sparser than that in middle-shallow layer at field scale, leading to the poor performance of past fracking deep wells.",5,5,1
Fractal Dimension,,"He, Houfeng; Liu, Pengcheng; Xu, Liang; Hao, Shengye; Qiu, Xinyu; Shan, Ce; Zhou, Yanglei","Pore structure representations based on nitrogen adsorption experiments and an FHH fractal model: Case study of the block Z shales in the Ordos Basin, China",Ordos basin; Shale; Nitrogen adsorption; Pore size distribution; FHH model,SIZE DISTRIBUTION; SURFACE-AREA; DISTRIBUTIONS; N-2,"Shale oil/gas is a crucial development in the exploitation of unconventional reservoirs. However, owing to the small pore size and complicated structure, finding an inexpensive and accurate method of accurately representing the pore structure has become an important issue. This paper summarizes and compares the current popular shale pore structure research methods and investigates three rock samples from well Z-1 and two rock samples from well Z-2 in block Z in the Ordos Basin, China. The components of the shale were analyzed using Xray diffraction. In addition to the Brunauer-Emmett-Teller theory, there are also the Barrett, Joyner, and Halenda theoriesfor mesopores and the Horvath and Kawazoe method for macropore. Based on these theories, the pore size distribution was analyzed using nitrogen adsorption experiments at low temperatures. According to the fractal model of Frenkel-Halsey-Hill, the characteristics of the shale pore structure were studied. The fractal dimension values of single and bilinear segments fitted by double logarithm curves were applied to describe the fractal features of the pores, and the differences were compared. The relationship between the fractal characteristics and the pore parameters was analyzed. The outcomes of the tests indicate that the shale is mainly comprised of kaolinite, illite, and quartz, and the N2 adsorption curves are type IV. There are hysteresis loops, which indicate the occurrence of multi-layer adsorption. The fractal analysis revealed that the shales have significant fractal characteristics, which are chiefly affected by the mesopores and macropores. Otherwise, the fractal dimension values of the single line segment D and the bilinear segments D1 and D2 generally consistently represent the fractal pore features. Relationships were found between the pore parameters and the fractal dimensions.",4,3,12
Fractal Dimension,,"Zhang, Yao; Chai, Junrui; Cao, Cheng; Shang, Tao","Combined influences of shear displacement, roughness, and pressure gradient on nonlinear flow in self-affine fractures",Shear displacement; Roughness; Pressure gradient; Nonlinear flow; Weierstrass-Mandelbrot function,CONSERVATIVE SOLUTE TRANSPORT; FLUID-FLOW; HYDRAULIC CHARACTERISTICS; SURFACE-ROUGHNESS; WALLED FRACTURES; ROCK FRACTURE; CUBIC LAW; MODEL; CONDUCTIVITY; PERMEABILITY,"This study numerically investigated the nonlinear flow behaviors under the combined influences of shear displacement, roughness, and pressure gradient. Two-dimensional (2D) self-affine fractures with five fractal dimensions (1.1-1.5) were generated by the Weierstrass-Mandelbrot (W-M) function. Different conditions with six shear displacements (0.5-3.0 mm) and five pressure gradients (1-100 kPa/m) were applied to each model and the nonlinear flow behaviors were investigated based on microscopic descriptions and macroscopic characterizations. The results show that shear displacement coupled with the effect of high roughness can easily lead to heterogeneous void spaces and emergence of eddies. The flow rate of unmated rough fractures is always larger than that of mated rough fractures due to the effects of geometries and eddies, while this situation may be reversed in relatively smooth fractures. Rougher fractures correspond to lower flow rates under the same conditions and many eddies still exist although the fractures are mated. Increasing the pressure gradient can accelerate the development of eddies in rough fractures, while when the pressure gradient exceeds a certain value, its effect is restrained by apertures. In general, increasing the shear displacement and roughness can enhance the proportion of the quadratic term in Forchheimer's law. However, not all fractures were satisfied with these points. Increasing the shear displacement from 2.5 mm to 3.0 mm in the fracture with fractal dimension of 1.1 and increasing the fractal dimension from 1.4 to 1.5 at the shear displacement of 1.0 mm both decreased the proportion of the quadratic term. The ratio of the mechanical aperture to the hydraulic aperture (E/e) varies between 1.0 and 2.8, and its relationship with the Reynolds number (Re) can be described by a power function for the fractures with the fractal dimension of 1.1-1.4 (or JRC = 0.3-18). The relationship of E/e versus Re is strongly dependent on the fracture roughness, and for a given roughness the relationship is almost the same under different shear displacements and pressure gradients. However, this phenomenon is no longer valid as the fracture becomes rougher. The results of this study can deeply advance the understanding of nonlinear flow in rough fractures and its dependence on shear displacement, roughness, pressure gradient, and especially their combined influences under high Re.",4,5,7
Fractal Dimension,,"Xie, Jing; Gao, Mingzhong; Zhang, Ru; Liu, Junjun; Liu, Yiting; Yang, Bengao; Wang, Mingyao; Wang, Fei",Fluid flow characteristics of cross-fractures with two branch fractures of different roughness controlled by fractal dimension: An experimental study,Cross-fracture; Fluid flow; Fractal dimension; Pressure-drop loss,PERMEABILITY MODEL; COAL; DAMAGE; EVOLUTION; APERTURE; SEEPAGE,"The cross-fracture is one of the basic units of rock fracture network in the deep energy exploitation. The scientific evaluation of the fluid flow behavior of a cross-fracture is a key link in the description of the fluid flow behavior of deep fractured reservoirs. Based on the Weierstrass-Mandelbrot function and combined with 3D printing technology, numbers of cross-fracture models with different roughness levels controlled by the fractal dimension are developed. A new calculation method of the pressure-drop loss coefficient is proposed, and the competitive flow diversion behavior and fluid flow state of the two branch fractures are examined with different water head ratio. The results show that the roughness difference between the cross-fracture branches is the important factor controlling the phenomenon of competitive flow diversion. Cross-flow confluence will result in a notable pressure-drop loss, and with increasing fractal dimension of the branch fracture, a larger pressure-drop loss occurs, and the rough branch fracture obtains a larger flow rate proportion. Besides, the water head ratio condition of the inlets is another important factor for the cross fracture flow. When the pressure ratio between the rough inlet and smooth outlet equals 1, the pressure-drop loss is at its maximum, and the flow rate proportion of the rough branch fracture is at its minimum, and Re gradually increases while Eu clearly decreases with increasing water pressure. When the pressure ratio between the rough inlet and smooth outlet is not equal to 1, the pressure-drop loss, the competitive flow diversion ability of the branch fracture, Re and Eu will greatly change with increasing water head ratio. The results can provide new insights into the flow through a fractured reservoir.",3,3,27
Thermal Conductivity,,"Su, Kaiming; Chen, Shijia; Hou, Yuting; Zhang, Haifeng; Zhang, Xiaolei; Zhang, Wenxuan; Liu, Guanglin; Hu, Cong; Han, Meimei","Geochemical characteristics, origin of the Chang 8 oil and natural gas in the southwestern Ordos Basin, China",Petroleum geochemistry; Organic maturity; Oil and gas genesis; Biodegradation; Yanchang formation; Southwestern ordos basin,,"Petroleum exploration in the Ordos Basin gradually expanded to the edge of the basin, but encountered difficulties on the southwestern edge. Compared with mature exploration areas inside the basin, the nature of reservoir fluids in the southwestern area is more complex. In order to better understand the oil/gas system in this area, this study conducted a detailed research on the geochemical characteristics of potential source rocks and reservoir fluids in this area. The results show that although the Chang 7 oil group in the study area developed thicker mudstone and has a high abundance of organic matter, the low degree of thermal evolution limits its hydrocarbon production. The Chang 8 oil in the study area is the result of lateral migration of products from mature source rocks inside the basin, which can be explained by the similar biomarker characteristics and gradually changing nitrogen compounds between them. Anaerobic biodegradation is an important factor that complicates the fluid properties in the study area. It not only thickens part of the oil, but also produces secondary biogenic natural gas, mainly methane.",5,5,10
Thermal Conductivity,,"Adjei, Stephen; Elkatatny, Salaheldin",Overview of the lightweight oil-well cement mechanical properties for shallow wells,Compressive strength; Shallow wells; Lightweight; Oil-well cement; Mechanical properties,EXPANDED PERLITE; SILICA FUME; THERMAL-CONDUCTIVITY; COMPRESSIVE STRENGTH; CONCRETE; VERMICULITE; METAKAOLIN; PERFORMANCE; AGGREGATE; HYDRATION,"Lightweight oil-well cement eliminates the need for the much expensive and problematic multi-stage cementing approach for isolating shallow intervals. However, the generally low compressive strength of lightweight cement in comparison to the neat cement recipes has been a major concern for operators who consider compressive strength the most important parameter. lightweight cement exhibit other desirable mechanical properties that affect the long-term integrity of the cement sheath. The objective of this review is to present laboratory and field investigations on the performance of different lightweight systems. According to field and laboratory investigations, a high compressive strength should not be of much concern, especially for shallow and weak formations where compressive strength higher than the formation can be deleterious. A minimum compressive strength of 50 psi is sufficient to support the casing. About 250-1000 psi is adequate to meet the requirement of many operations. Besides, foamed, perlite, zeolite, gilsonite, and microsphere-based cement exhibit adequate early age compressive strength and more important mechanical properties such as high tensile strength, low Young modulus, and high Poisson ratio which increase cement elasticity. With the enhancement in the mechanical performance of lightweight cement containing metakaolin and vermiculite, both calcined clays, it is recommend to inverstigate the use of calcined bentonite clay as supplementary cementitious material.",5,5,7
Thermal Conductivity,,"Kamali, Fahime; Saboori, Rahmatallah; Sabbaghi, Samad",Fe3O4-CMC nanocomposite performance evaluation as rheology modifier and fluid loss control characteristic additives in water-based drilling fluid,Fe3O4; Carboxymethyl cellulose; Nanocomposite; Filtration; Rheology; Drilling fluid,FILTRATION PROPERTIES; CARBOXYMETHYL CELLULOSE; THERMAL-CONDUCTIVITY; OXIDE NANOPARTICLES; MUD; TEMPERATURE; IMPROVEMENT; BEHAVIOR; OIL,"In drilling operations, there has been a considerable amount of attention to the drilling fluid formulation and characteristics. In recent years, the utilization of nanocomposite as an additive exhibited a promising improvement in the water-based drilling fluid rheological properties. The conventional additives have a lot of deficiencies such as being expensive, complicated synthesis methods, and not having desirable rheology properties. To eliminate the deficiencies, an investigation on the efficacy of Fe3O4- carboxymethyl cellulose (CMC) nanocomposite on the rheological and filtration characteristics as an additive in the water-based drilling fluid are carried out in this study. The nanocomposite was synthesized by the co-precipitation method and Fouriertransform infrared spectroscopy, X-ray diffraction, scanning electron microscopy, and energy dispersive x-ray was employed for characterization. Then, the nanocomposite with different ratio was utilized as an additive to drilling fluid and the rheological and filtration properties of fluid was measured for both deionized water and salty water. The results show that by adding 57% of 1:3 Fe3O4-CMC nanocomposite ratio to basic drilling fluid, in addition to considerable improvement in the viscosity, the filtration volume and cake thickness decreased noticeably. This formulation depicts non-Newtonian rheological behavior which could be illustrated properly by Herschel-Bulkley rheological model. Thus, exploitation of Fe3O4-CMC nanocomposite as an additive in waterbased drilling fluid for fluid loss control would have advantageous due to its distinctive properties like enhanced resistance to water penetration and enhanced viscosity in both deionized water and salty water. In addition, the Fe3O4-CMC nanocomposite has superior properties such as uncomplicated synthesis method and being financially available in comparison to conventional additives.",4,4,4
Thermal Conductivity,,"Liu, Yong; Guo, Xinhui; Wei, Jianping; Zhang, Huidong",Application of supercritical carbon dioxide jet: A parametric study using numerical simulation model,Coal bed methane; Coal breakage; Drilling; Supercritical carbon dioxide jets; Impact pressure,,"Defining the structure of a supercritical carbon dioxide (SC-CO2) jet flow field is a critical component of establishing a theoretical basis for its application. This study investigates the influence of pressure ratio on the wave features of an SC-CO2 jet flow field using a new numerical simulation model and flow field visualization experiments. To assess the characteristics of the SC-CO2 flow field and predict the distribution of temperature and pressure, a computational model based on constant pressure specific heat capacity and thermal conductivity of SC-CO2 was established, and the user-defined function (UDF) feature available in ANSYS Fluent software was used. The results demonstrated that the temperature and pressure of the SC-CO2 jet flow field could be accurately predicted by the numerical simulation model proposed in this research, and the wave features of the flow field could be visualized by both the numerical simulation contours and the experiments. The wave features, which resulted from different pressure ratios, were found be a function of the structure of the Laval nozzle at a constant inlet pressure. The pressure ratio could be controlled by the nozzle structure and accurately describe the wave features of the SC-CO2 jet flow field. In this study, an optimal pressure ratio of 1.31 was used and the flow field structure corresponding to the maximum jet impact force could be satisfactorily described by the optimal pressure ratio.",3,3,13
Thermal Conductivity,,"Wang, Jiaqi; He, Jiale; Lv, Xin; Ge, Kun; Cheng, Chuanxiao; Dong, Hongsheng",Numerical analysis of the gas recovery performance in hydrate reservoirs with various parameters by stepwise depressurization,Natural gas hydrate; Stepwise depressurization; Reservoir characteristics; Sensitivity analysis,METHANE HYDRATE; THERMAL-STIMULATION; DISSOCIATION; ENERGY; HEAT; PERMEABILITY,"Natural gas hydrates have drawn worldwide attention as a significant clean energy source in the 21st century. Depressurization is known to be the most effective method for hydrate exploitation owing to its feasibility and economic benefits. Recently, stepwise depressurization has received extensive attention owing to its advantages of effective prevention of ice generation and hydrate reformation during gas recovery. In this work, we optimized the 2-D simulator to model the evolution of temperature, pressure, hydrate saturation, and gas production behavior in hydrate sediments during decomposition process via stepwise depressurization. The effect of various reservoir characteristics on gas production was analyzed by introducing the sensitivity factor. The results demonstrated that higher specific heat capacity of the reservoir would promote gas production in the early stage of the reaction; however, this effect is reversed in the later stage. A higher thermal conductivity of the hydrate cores can dramatically enhance the gas production rate; however, this advantage is weakened with increasing thermal conductivity. Reducing the gas relative permeability hinders the hydrate decomposition process, and the water relative permeability has minimal effect on gas production. Based on the sensitivity analysis, the thermal conductivity and gas relative permeability are the main factors affecting hydrate decomposition.",3,3,9
Thermal Conductivity,,"Li, Haoting; Wang, Shuyan; Wang, Ruichen; Liu, Yang; Shao, Baoli; Yuan, Zihan; Chen, Yujia; Ma, Yimei",Simulation on flow behavior of particles and its effect on heat transfer in porous media,Porous media; Discrete element method (DEM); Heat transfer; Migration and deposition; Numerical simulation,THERMAL-CONDUCTIVITY; DEPOSITION; CONVECTION; TRANSPORT; MODEL,"Mastering flow and heat transfer of fluids in porous media is significant in the development of oilfield. A three-dimensional porous model with anisotropic pore structure is developed, and flow and heat transfer behaviors of particles are simulated using CFD-DEM method incorporating with the coupled convective-conductive heat flow model. The interphase forces including drag force, lubricating force and thermophoretic force are considered comprehensively. Comparisons of the predicted results are also made and in a good agreement with the classical experimental results by Rimon. Simulation results show that the temperature in porous media rises along with the mixing and contact between particles and liquid. The migration of moving particles is restricted in pore spacing, and thus narrows the apertures of fluid channel, increases the local instantaneous liquid velocity. Moving particles are preferred to decelerate and deposit at a low porosity. The velocities of particles and frequency of collision increase while contact force and granular temperature decrease with an increase of porosity. With the increase of particle temperature, the temperature gradient around hot particles enlarges and the number of trapped particles goes up affected by thermophoretic force. The intensity of convection heat decreases at lower liquid velocity, and the heat conduction between particles is regarded as the main heat transfer mechanism.",3,4,4
Thermal Conductivity,,"Tatar, Amin; Mohammadi, Saba; Soleymanzadeh, Aboozar; Kord, Shahin",Predictive mixing law models of rock thermal conductivity: Applicability analysis,Thermal conductivity; Mixing model; Geometric mean,THERMOPHYSICAL PROPERTIES; FLUID; PRINCIPLES; POROSITY,"Thermal conductivity is defined as the ability of a material to conduct the heat. Rock thermal conductivity is influenced by several parameters such as mineral composition, geometrical factors, porosity, and saturation condition. Value of the rock thermal conductivity is necessary in all thermal processes in petroleum engineering such as thermal methods of enhanced oil recovery. Laboratory measurement of the thermal conductivity of rock samples is time-consuming and expensive. Therefore, a large number of correlations and models have been presented to predict the rock thermal conductivity. These correlations and models are divided into three categories, i.e. mixing models, empirical and semi-empirical correlations, and theoretical models. In this paper, it was attempted to investigate 15 different predictive mixing models of rock thermal conductivity and examine their applications for different rock types and different saturation conditions using 159 collected data points. Validity and applicability of these predictive models were discussed using graphical and statistical error analysis. Results indicated that geometric mean model and Albert model can provide an accurate estimation of rock thermal conductivity with average absolute relative deviation (AARD) of 11.58% and 13.87%, respectively. Moreover, the applicability of each model was evaluated for different conditions of rock type and saturation. This evaluation revealed that Walsh, Alishaev, and Zimmerman models are more accurate than geometric mean model and Albert model for some specific conditions of rock type and saturation. Indeed, Walsh model is the best predictive thermal conductivity model for air saturated crystalline rocks, Alishaev model is the best model for predicting thermal conductivity of water saturated crystalline rocks and Zimmerman model provides the best estimation of the thermal conductivity of water saturated dolomite rocks. It should be noted that structural properties, which affect the rock thermal conductivity, are not considered in the mixing models which is the main limitation of this type of predictive models.",3,3,2
Barnett Shale,,"Teng, Juan; Deng, Hucheng; Liu, Bei; Chen, Wenling; Fu, Meiyan; Xia, Yu; Yu, Hanze","Insights of the pore system of lacustrine shales from immature to late mature with the aid of petrology, mineralogy and porosimetry: A case study of the Triassic Yanchang Formation of the Ordos Basin, North China",pore evolution; pore size distribution; organic-matter pores; thermal maturation; lacustrine shale; Ordos Basin,CHANG 7 MEMBER; NORTHEASTERN BRITISH-COLUMBIA; MATURATION GRADIENT INSIGHTS; NANOMETER-SCALE PORES; ORGANIC-MATTER; ROCK PROPERTIES; GAS-ADSORPTION; BARNETT SHALE; ALBANY SHALE; MECHANICAL COMPACTION,"The study of pore network evolution is an important aspect of tight shale reservoir characterization. Pore spaces in shales consist of three major types: interparticle pores and intraparticle pores associated with mineral matrix and organic-matter pores. In this study, the evolution of pore networks for each pore type in lacustrine shales during thermal maturation was studied based on a suite of 19 Triassic Yanchang Formation shale samples from the Ordos Basin across a maturation gradient from immature to late mature (vitrinite reflectance (R-o) from 0.36 to 1.30%). The results show that different pore types follow systematic evolutions during thermal maturation and that the evolution of pore type and pore size is critically controlled by multiple diagenetic processes such as mechanical compaction, cementation, mineral dissolution, clay mineral transformation, and organic matter thermal maturation. Specifically, at immature and early mature stages (R-o < 0.55%), pores associated with mineral matrix are abundant and have moderate pore sizes. Interparticle pores exhibit preferential orientation along clay platelets. At the mature stage (0.55% < R-o < 1.15%), pores associated with mineral matrix have the smallest size, and interparticle pores become less common and show reduced preferential orientation because of mechanical compaction and cementation. Organic-matter pores start to develop at a maturity level of R-o 0.77% and higher. The total porosity and BET specific surface area show minimum values at R-o 1.12%, mainly because pre-existing matrix-related pores are destroyed by mechanical compaction and filled by migrated bitumen and liquid hydrocarbons, and then they increase when R-o exceeds 1.12%, which likely results from the development of secondary organic-matter nanopores due to the generation and expulsion of gaseous hydrocarbons. An increase in pore size of matrix-related pores at the late mature stage (1.15% < R-o < 1.30%) could be a result of dissolution by organic acid generated during organic matter thermal maturation.",7,9,5
Barnett Shale,,"Lin, Miruo; Xi, Kelai; Cao, Yingchang; Liu, Quyang; Zhang, Zehan; Li, Ke","Petrographic features and diagenetic alteration in the shale strata of the Permian Lucaogou Formation, Jimusar sag, Junggar Basin",Shale oil reservoir; Petrographic features; Diagenetic alteration; Heterogeneity of reservoirs in shale strata,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; BOHAI BAY BASIN; RESERVOIR QUALITY; SANDSTONE RESERVOIRS; JIYANG DEPRESSION; SEDIMENTARY-ROCKS; JIMSAR SAG; LITHOFACIES CLASSIFICATION; ORGANIC GEOCHEMISTRY,"Reservoir quality is the key parameter controlling shale oil enrichment. However, the complicated lithofacies, which control diagenesis, result in reservoir heterogeneity in the shale strata, creating challenges for reservoir prediction. Combining with the detail analysis of inorganic and organic geochemistry, characteristics of the main lithofacies and diagenetic alteration were investigated in Permian Lucaogou Formation, Jimusar sag, Junggar Basin. Laminated rocks with laminae combinations containing pyroclastic and terrigenous clastic laminae, terrigenous clastic and dolomite laminae, and pyroclastic and carbonate laminae were identified. Massive rocks mainly includes dolomicrite, dolomitic tuff, silt dolostone, dolomitic siltstone, and tuffaceous siltstone. Feldspar dissolution and carbonate cementation were the two dominant diagenetic types, further causing heterogeneity of the shale oil reservoirs. Feldspar dissolution generally occurred in laminated rocks containing pyroclastic laminae with low content of carbonate minerals (PL1), as well as in their adjacent interbedded siltstones. Carbonate cementation generally occurred in laminated rocks containing carbonate laminae, as well as in their adjacent interbedded siltstones. Whether in laminated and massive rocks, sparry carbonate crystals were also precipitated adjacent to organic matter and in microfractures. In the burial processes, enriched transition metal elements of V and Ti in pyroclastic laminae promote catalytic pyrolysis of organic matter. Abundant CO2 produced during the catalytic pyrolysis promoted feldspar dissolution. Dissolution of sedimentary carbonate minerals by organic acids and CO2 provided the material sources for secondary carbonate cements. It promoted the recrystallization and re-precipitation of sparry carbonate crystals adjacent to organic matter and in the terrigenous clastic laminae or interbedded siltstones. Ca2+, Mg2+ Sr2+, Fe2+, and Mn2+ produced by the transformation of smectite to illite in the pyroclastic laminae also provided Ca source for secondary carbonate cements. External diagenetic fluids providing materials along microfractures is another genesis of carbonate cements in the Permian Lucaogou Formation.",5,5,10
Barnett Shale,,"Sun, Jian; Xiao, Xianming; Cheng, Peng; Wang, Maolin; Tian, Hui","The relationship between oil generation, expulsion and retention of lacustrine shales: Based on pyrolysis simulation experiments",Shale; Simulation experiment; Kerogen type; Maturity; Oil generation and expulsion; Oil retention; Oil expulsion efficiency,SOURCE ROCKS IMPLICATIONS; INDIVIDUAL N-ALKANES; PETROLEUM GENERATION; HYDROCARBON EXPULSION; HYDROUS PYROLYSIS; GAS GENERATION; KINETIC-PARAMETERS; WATER-PRESSURE; BARNETT SHALE; ORGANIC PETROLOGY,"The oil expulsion efficiency of shales is restricted by quite a few geological and geochemical factors, resulting in a great challenge to be evaluated quantitatively. In this paper, a semi-open pyrolysis simulation experiment based on a gold tube system was applied to simulate the oil generation and expulsion of seven lacustrine shale core samples with low maturities (Ro between 0.54% and 0.68%) and different kerogen types (types I and II) taken from the Shengli Oilfield, eastern China, and the corresponding seven suits of artificially matured sub-samples with a Ro range of 0.70-1.35% were obtained. The evolution of oil generation and oil expulsion, and their coupling relationships with oil retention for these samples with increasing maturity were investigated. The results show that the main stage of oil expulsion of these shales lags significantly behind the main stages of both oil generation and oil retention, with a corresponding Ro range of 0.80-0.90%, 0.70-0.85% and 0.65-0.82%, respectively. The oil expulsion efficiencies of these shales are not only constrained by their maturities, but also affected by their kerogen types and TOC contents. The shales with greater petroleum potentials and/or greater TOC contents have greater oil expulsion efficiencies. There is a good positive correlation between the retained oil and the total oil (i.e., the generated oil) for these shales as their Ro <= 0.98%, and this relationship is not significantly influenced by their kerogen types and maturities. The results may provide an alternative way for predicting the oil expulsion efficiency of natural shales according to their retained oil.",5,6,5
Barnett Shale,,"You, Jiyuan; Liu, Yiqun; Song, Shanshan; Zhou, Dingwu; Yang, Yiyao",Characteristics and controlling factors of LORS from the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin,LORS; Redox conditions; Paleoproductivity; Volcanic and hydrothermal activities; Yanchang formation; Ordos basin,GEOCHEMICAL CHARACTERISTICS; SEQUENCE STRATIGRAPHY; CHINA IMPLICATIONS; BARNETT SHALE; TRACE-METALS; DEEP-SEA; EVOLUTION; ACCUMULATION; PRODUCTIVITY; MORPHOLOGY,"Lacustrine organic-rich shale (LORS) developed in the Chang 7-3 section of the Triassic Yanchang Formation in the Ordos Basin. LORS has been proven to be a source of crude oil and tight oil, as well as a source and reservoir for shale oil in the basin. A total of 35 LORS samples were collected from Well Z233 and analysed by mineralogy and element geochemistry to reveal the characteristics and controlling factors of LORS. The following results were obtained: In the oil shale, the organic matter is composed of type I and type II kerogen, with a pre- dominance of type II. The organic matter is mature and reaches high levels of abundance. (2)Through further analysis. The values of w(U)/w(Th), w(V)/w(Cr), w(Ni)/w(Co), the size and morphology of pyrite, indicates that the lake water of the LORS deposition period in the study area is anoxic or suboxic state. the TOC of the samples was found to have significant positive correlations with the w(Mo) and w(Ba-bio) contents. Paleoproductivity can be inferred to be the key factor controlling organic matter enrichment in the LORS. (3)Volcanic and hydrothermal activities promote the development of LORS, provide nutrients needed by organisms, promote the growth of organisms, and improve paleoproductivity. Hydrothermal activity leads to the formation of an anoxic environment at the bottom of the lake, and tuff will cover the sediments, which promotes LORS preservation. This study reveals in detail paleoproductivity is the main factor in the formation of LORS during the evolution of the basin. Volcanic and hydrothermal activities promoted the increase of paleoproductivity, and finally the oil shale layers with the richest organic matter have been formed. And thereby deepens our theoretical understanding of organic matter enrichment.",5,5,4
Barnett Shale,,"Mastalerz, Maria; Drobniak, Agnieszka; Hower, James C.",Controls on reservoir properties in organic-matter-rich shales: Insights from MICP analysis,Shale; Reservoir properties; MICP; Maturity; Withdrawal efficiency,GAS-ADSORPTION; PORE STRUCTURE; CAPILLARY-PRESSURE; BARNETT SHALE; ALBANY SHALE; POROSITY; PERMEABILITY; OIL; MATURATION; ROCKS,"Mercury injection capillary pressure (MICP) analysis was used to study organic-matter-rich Devonian shales varying in maturity from marginally mature to postmature to discuss controls on drainage and imbibition in shale reservoirs. Six samples come from the New Albany Shale; their total organic carbon (TOC) ranged from 3.3 to 8.4% and vitrinite reflectance (R-o) from 0.54 to 1.42%. One Marcellus Shale sample with R-o 2.50% was used to extend the maturity range to the advanced dry gas window. Three coal samples of varying rank were also included for comparison. Porosity of the shales ranges from 1.5 to 5.0%, and MICP-derived permeability ranges from 0.17 to 9.9 mD. Injection capillary pressure curves have a range of entry pressures from 0.055 to 0.421 MPa, and no relationship of entry pressure with maturity was revealed. Maturity, however, has an influence on pore size distribution, with the higher-maturity samples having significantly lower volumes of pores with throats less than 10 nm in diameter. Withdrawal capillary pressure curves document a wide range of withdrawal efficiencies from 55% to almost 100%, and pores having throats between 3 and 50 nm in diameter play a major role in the ability of mercury to be released from the pore system. The obtained data provide valuable information about shale properties and their behavior not only in the air-mercury system but also under reservoir conditions.",5,5,3
Barnett Shale,,"Li, Pei; Zhang, Jinchuan; Rezaee, Reza; Dang, Wei; Li, Xuekai; Fauziah, Cut Aja; Nie, Haikuan; Tang, Xuan",Effects of swelling-clay and surface roughness on the wettability of transitional shale,Shale; Spontaneous imbibition; Contact angle; Wettability; Surface roughness; Clay swelling,MISSISSIPPIAN BARNETT SHALE; MIDDLE YANGTZE PLATFORM; SOUTHERN NORTH CHINA; PORE STRUCTURE; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; MULTIPHASE FLOW; SICHUAN BASIN; GAS; ADSORPTION,"Wettability in unconventional reservoirs is poorly understood. However, it plays a fundamental role in fluid-rock interactions, and an understanding of wetting behavior is essential for capillary seal assessments and hydrocarbon reserve estimation and recovery in clay-rich reservoirs. In this study, the wetting behavior of transitional Shanxi-Taiyuan shale from the southern North China basin was examined via the contact angle (CA) and spontaneous imbibition (SI) measurement methods. Under water-air-shale conditions, water-wet and neutral-wet behaviors were observed, whereas neutral-wet and oil-wet behaviors were observed under water-oil-shale conditions (Young's equation was used to convert the water-air-shale system to the water-oil-shale system). When the CA method was used, the shale was shown to be hydrophobic, whereas when the SI test was used, the shale was observed to be hydrophilic. The water-air CAs are negatively correlated with the total organic content (TOC), carbonate and clay mineral contents (excluding those of illite). Furthermore, iron-containing compounds, such as pyrite and siderite, were shown to decrease the water wetness. A linear negative correlation was found between the surface roughness and the CA value. The relationship between these parameters can be used to predict the CAs at different surface roughness values for a given sample. The contradictory wetting behaviors between the results of SI and CA methods can be explained by: (i) differences between the CAs formed under water-air-shale conditions and those formed under hydrocarbon-brine-shale conditions; (ii) differences in the surface roughness, which is dependent on the texture and mineralogy of the shale sample; and (iii) clay swelling after water sorption and the formation of microfractures due to water-rock interactions.",4,4,4
Barnett Shale,,"Xie, Xinhui; Deng, Hucheng; Fu, Meiyan; Hu, Lanxiao; He, Jianhua","Evaluation of pore structure characteristics of four types of continental shales with the aid of low-pressure nitrogen adsorption and an improved FE-SEM technique in Ordos Basin, China",Pore structure; Compositional classification; Yan-Chang #7 formation; Pore-size distribution,MISSISSIPPIAN BARNETT SHALE; TRIASSIC YANCHANG FORMATION; NORTH-CENTRAL TEXAS; FORT-WORTH BASIN; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; TRANSITIONAL SHALE; MICRO-FRACTURES; LONGMAXI SHALES; SICHUAN BASIN,"The upper Triassic continental shale of Yan-Chang #7 Formation, in Ordos Basin, China, exhibits complex geological conditions that lead to a complicated pore structure of the targeted formation. To reveal the pore structure and understand its influential factors, we first classify the shale samples into four categories according to the organic and clay contents (type #1: clay content (A) over cap > (A) over cap 52.0% and TOC (A) over cap >(A) over cap 3.0%, type #2: clay content >52% and TOC (A) over cap <<(A)over cap> 3.0%, type #3: clay content (A) over cap <<(A)over cap> 52.0% and TOC (A) over cap >(A) over cap 3.0%, type #4: clay content (A) over cap (A) over cap 52.0% and TOC (A) over cap >(A) over cap 3.0%). Then, the pore structure, total pore volume, and specific surface area are investigated by the low-pressure nitrogen adsorption analysis for each category. Next, the field-emission scanning electron microscopy analysis combined with the image processing is used to quantify the surface porosities of different types of pores and pore-size distributions of the samples. Results demonstrate that total pore volume and specific surface area are positively correlated with TOC and clay minerals (i.e., illite) but negatively correlated with brittle minerals (i.e., quartz and feldspar). Clay mineral is a major contributor to interparticle pores and micro-fractures. Higher TOC, illite, and chlorite contents lead to more pores/fractures in organic matter, while higher quartz content results in more intraparticle pores. The obtained results help to characterize the pore structure of Yan-Chang #7 Formation accurately as well as explore and exploit shale resources in this area.",4,4,2
Barnett Shale,,"Liang, Mingliang; Wang, Zongxiu; Zhang, Yu; Greenwell, Christopher H.; Li, Huijun; Yu, Yuxi; Liu, Shengxin",Experimental investigation on gas permeability in bedding shale with brittle and semi-brittle deformations under triaxial compression,Gas permeability; Shale; Triaxial compression; Stress-strain; Brittle/ semi-brittle deformation,FLUID TRANSPORT PROCESSES; LONGMAXI FORMATION SHALE; ORGANIC-RICH SHALE; BARNETT SHALE; PORE STRUCTURE; ANISOTROPIC PERMEABILITY; PETROPHYSICAL PROPERTIES; FRACTURE PERMEABILITY; CONFINING PRESSURE; DUCTILE TRANSITION,"This study investigates the stress-strain behavior, failure deformation, and change of gas permeability in shale under compressive stress induced failure. The study is based on triaxial compression of shale from Lower Silurian Longmaxi Formation, South China at different angle of bedding planes. It was found that shale behaves as a brittle materials and exhibits brittle and semi-brittle response to peak strength load at different angles of pre-exist bedding during stress compression. The gas permeability increased after failure deformation for all shale samples. However, samples under vertical and horizontal bedding angles exhibited brittle deformation and significant increase in permeability. While the samples with bedding angles of 30 degrees and 60 degrees showed semi-brittle deformation, and the permeability increased slightly after failure. These results indicate that the pre-existing structure influences the mechanical behavior of shale, which consequently affects its gas permeability. The results of this study are of great significance in shale gas exploration and development in areas of South China which has complex tectonic and pre-existing foliation structures.",3,3,9
Net Present Value,,"Wang, Lian; Li, ZhiPing; Adenutsi, Caspar Daniel; Zhang, Liang; Lai, FengPeng; Wang, KongJie",A novel multi-objective optimization method for well control parameters based on PSO-LSSVR proxy model and NSGA-II algorithm,Multi-objective optimization; Well control; Proxy model; NSGA-II,LONG-TERM; PLACEMENT; DESIGN,"Single-objective well control problems have been studied for many years as one of the most typical optimization problems by researchers worldwide. However, single-objective optimization often could not meet the needs in practical application processes leading to multi-objective optimization problems which have better adaptability in practical applications. In this study, a new method for multi-objective well controls optimization problem using support-vector regression (SVR) proxy model and non-dominated sorting genetic algorithm-II (NSGA-II) was developed. This method was named the multi-objective optimization with proxy model (MOO-PM). In the MOO-PM method, the net present value (NPV) and cumulative oil production (COP) were considered as the objective functions while the bottom hole pressure of production wells and water injection rate of injection wells were chosen as the optimization variables. To the best of our knowledge, this is the first time that SVR proxy model and NSGA-II are applied simultaneously to the optimization of well controls problems. Compared to reservoir simulation model, the SVR proxy model was computationally more efficient. This meant the large calculation time spent on reservoir simulation operation for multi-objective optimization was sharply reduced by using the SVR proxy model. Furthermore, the accuracy of the SVR proxy model was proved by comparing it to the results of simulation of optimized cases and non-optimized cases for a synthetic field as well as a real reservoir. It was concluded that MOO-PM method could obtain better results with higher efficiency.",7,7,13
Net Present Value,,"Semnani, Amir; Ostadhassan, Mehdi; Xu, Yungui; Sharifi, Mohammad; Liu, Bo",Joint optimization of constrained well placement and control parameters using teaching-learning based optimization and an inter-distance algorithm,Teaching-learning-based-optimization (TLBO); Joint optimization; Population-based global optimization,SEARCH ALGORITHM; GLOBAL SEARCH; LOCATION,"Well placement and parameter optimization (WPPO), which is a complex problem, is important in the petroleum industry. Among derivative-free methods, population-based metaheuristics global optimization algorithms have proved to be more pertinent than other methods. One should note that population based methods have drawbacks of pre-mature convergence of the algorithm which is due to poor tuning of parameters. In this study, a population-based metaheuristics global optimization method independent of parameter tuning called teachinglearning-based optimization (TLBO), has been utilized for WPPO. Particle swarm optimization (PSO) and genetic algorithm (GA) were added for comparison. Furthermore, three joint optimization of well location and parameters were implemented over a synthetic black-oil reservoir and maximization of the net present value (NPV) as the fitness function. First, joint optimization of well location and bottom-hope pressure (BHP) over fixed number of wells, followed by joint optimization of well type and BHP over fixed location of first scenario is investigated. Finally, number of production and injection wells, their location and BHP values were jointly optimized. In addition, a new algorithm was proposed to maintain an inter-distance constraint for any number of points in an ordinary n-dimensional space to avoid well interference problem. Based on the results, TLBO conferred considerable higher rate of convergence and within a fixed number of iterations, achieved NPV, 1-14% and 1-52% higher than the GA and PSO, respectively.",5,5,5
Net Present Value,,"Deng, Lichi; Pan, Yuewei",Data-driven proxy model for waterflood performance prediction and optimization using Echo State Network with Teacher Forcing in mature fields,Data-driven proxy model; Echo state network; Teacher forcing; Machine learning; Waterflood; Optimization,,"Waterflood has been widely applied across the world as the most important secondary recovery process to improve reservoir performance. The schemes applied to waterflood projects involve key decision-making which aims to maximize the net present value (NPV) for a given period, improve recovery and sweep efficiency, maintain reservoir pressure, reduce water production, and avoid water recycling. Traditionally, the preferred approach to estimate the future performance of any given waterflood project is through the numerical reservoir simulation. However, despite the great power and intuition associated with the simulation models, sometimes this potential is unachievable due to massive computational requirements. Also, in some other cases, there may exist no simulation model to begin with. To tackle these problems, data-driven proxy models are proposed. In this research, we propose a novel machine-learning-based proxy model for waterflood performance prediction and further apply it for production optimization purpose to obtain the optimal future well control. The data-driven model is realized using the Echo State Network (ESN) under the paradigm of ""Reservoir Computing"" (RC). Compared with traditional ESNs, this specific methodology includes a feedback loop from the output into the high dimensional ""reservoir"" to achieve improved prediction results for separated phase production rates. Teacher Forcing (TF) technique is used for easier incorporation of the feedback information without introducing additional recurrent loops during the training process. Furthermore, training ESN proxy models utilizes Ridge Regression, thus all calculations within have analytical solutions that guarantee much improved speed when evaluating forward model-runs, which further lowers the computational demand during the optimization process. The proposed workflow is typically more suitable for mature fields since reliable production data after breakthrough from each producer could greatly improve the training process, and it can be used under the circumstance where no reservoir model has been established. In this research, we present two test examples where we apply ESN to learn the reservoir simulation results of waterflood and further perform open-loop optimization on each of them.",5,5,2
Net Present Value,,"Kim, Joonyi; Lee, Kyungbook; Choe, Jonggeun",Efficient and robust optimization for well patterns using a PSO algorithm with a CNN-based proxy model,Proxy model; Convolutional&nbsp; neural&nbsp; network (CNN); Time of flight (TOF); Field development&nbsp; plan (FDP); Particle swarm optimization (PSO); Optimization constraints,JOINT OPTIMIZATION; PARTICLE SWARM; PLACEMENT,"One objective of the field development plan (FDP) is to optimize well patterns, that is, the number and type of well (producers or injectors) and their locations, in order to maximize net present value (NPV). Optimization cost, including reservoir simulation, is strongly needed in terms of a global solution because of countless FDP scenarios, especially robust optimization for considering geological uncertainty. To solve this problem efficiently and reliably, this study introduces a convolutional neural network (CNN)-based proxy model into particle swarm optimization (PSO). For the proxy model, three map types having the same dimension as the reservoir model were fed into the input layer, giving an NPV for a given well-pattern scenario. The first map was a well configuration map, which consists of 1, -1, and 0 for producer, injector, and no well, respectively. The second and third maps were time-of-flight (TOF) maps from producers and injectors, respectively. Because the type of input data is an image, the CNN could extract features from 3500 scenarios while training the proxy model. When the predicted NPVs from the trained CNN-based proxy model were verified for 750 test data, the coefficients of determination for the true NPVs from reservoir simulation were higher than 0.94. In addition, the proxy model was flexibly applied to various well patterns, even for different numbers of wells because it utilizes TOF maps as input data. Three points are handled in PSO-Proxy to achieve a realistic well pattern: optimization of the number of wells, well spacing constraint, and operational condition for injection wells. The optimized well pattern maximizes NPV with the optimal number of producers and injectors under the predefined maximum number of wells. In the case of well spacing, two distances, that is, the distance between the wells and the distance between a production well and reservoir boundary, are used as criteria for the solution in terms of the filter method before evaluating the NPV. For injectors, water injection is controlled by bottomhole pressure instead of a constant injection rate, which gives meaningless injection wells placed at the edge of the reservoir. When the proposed method was tested using a 2-dimensional (D) synthetic field and 3-D Egg model, its well patterns showed approximately 1.2% lower NPV than the solution from a conventional method, PSO-ECL. This was relatively small when considering that there was approximately 7.8% NPV changes in each optimization run of the PSOECL. In addition, PSO-Proxy required only 21% and 8.6% of the optimization cost of the PSO-ECL for the 2-D and 3-D cases, respectively. Therefore, the proposed method was found to enable reliable and efficient decisionmaking for FDP; further, as the reservoir complexity increases, the CNN-based proxy model should be able to reduce the optimization time dramatically.",5,5,2
Net Present Value,,"Park, Jaeyoung; Iino, Atsushi; Datta-Gupta, Akhil; Bi, Jackson; Sankaran, Sathish",Novel hybrid Fast Marching Method-based simulation workflow for rapid history matching and completion design optimization of hydraulically fractured shale wells,Completion optimization; Rapid reservoir simulation technique; Hydraulic fracture modeling; Shale reservoir,FINITE-ELEMENT SIMULATION; RESERVOIR PROPERTIES; GAS-PRODUCTION; PERMEABILITY; STRESS; FLOW; DEFORMATION; STIMULATION; PROPAGATION; INTEGRATION,"This paper introduces a novel hybrid Fast Marching Method-based simulation (FMM-Sim) workflow for rapid history matching and completion design optimization of hydraulically fractured shale wells in unconventional reservoirs. The workflow incorporates fracture propagation to model the injection phase using a 3D finite difference (FD) simulation and seamlessly transitions to FMM-Sim for the subsequent production phase modeling. A simplified physical model for pressure-dependent fracture dilation/compaction was proposed and parameterized to emulate fracture propagation. The model was validated with ABAQUS, a fully coupled fluid flow and geomechanics simulator. In the workflow, the fracture parameters such as fracture geometry and permeability are obtained as a result of the injection phase modeling. Next, they are transferred into the subsequent production phase modeling with FMM-Sim which transforms 3D reservoir simulation model into 1D simulation model leading to orders of magnitude faster computation. The workflow was successfully applied to a field case in the Delaware Basin. The injection and production well data was first history-matched using a genetic algorithm. The calibrated models provide a range of estimated ultimate recovery (EUR) and net present value (NPV) of the history-matched well. After the history matching, the calibrated fracture dilation/compaction curves were used to investigate the optimum completion design for the well. The workflow has been proposed in practical and efficient way in the sense that the entire workflow, from the fracture propagation to the subsequent production, can be performed in any 3D FD simulator. This substantially saves computation resources and manpower compared to common industry workflows. The proposed workflow which connects completion design and hydrocarbon production with efficient computation would be beneficial for field development planning and economic decision making in unconventional reservoirs.",5,5,0
Net Present Value,,"Yousefzadeh, Reza; Sharifi, Mohammad; Rafiei, Yousef",An efficient method for injection well location optimization using Fast Marching Method,Injection well location; Drainage boundary; Streamline simulation; Fast marching method; Particle swarm optimization; Function evaluation,PLACEMENT; ALGORITHM; GAS,"Well placement is one of the challenging steps in field development optimization. Finding optimal locations with fewer function evaluations and less time is crucial when dealing with giant models. In this study, we propose a method based on the combination of Fast Marching Method and Particle Swarm Optimization to decrease the number of function evaluations in optimizing the location of vertical injection wells. The idea is to restrict the optimization algorithm's search space to a region around the drainage boundary of producers. Thereby, the optimization algorithm can find good locations with fewer function evaluations compared to direct optimization. Drainage boundaries are predicted based on the diffusive time of flight (arrival time) calculated by the Fast Marching Method. First, the performance of the proposed method in predicting the drainage boundaries is evaluated by verifying the drainage boundary of four producers on two synthetic models using the fast marching method and streamline simulator which showed a good match. Next, the approach is applied to two- and threedimensional example cases, including four synthetic models and a real field case to test the robustness and efficiency of the proposed method. Results are compared with the direct optimization approach and showed that the proposed approach can provide higher Net Present Values with fewer function evaluations most of the time. Finally, a comparison between the computational efficiency of the fast marching method and streamline simulator showed that the time needed by the fast marching method to predict the drainage boundary of the wells was orders of magnitude lower than the streamline simulator.",4,4,2
Net Present Value,,"Zhang, Kai; Zhao, Xinggang; Chen, Guodong; Zhao, Mengjie; Wang, Jian; Yao, Chuanjin; Sun, Hai; Yao, Jun; Wang, Wei; Zhang, Guodong",A double-model differential evolution for constrained waterflooding production optimization,Constrained production optimization; Classification; Support vector machine (SVM); Surrogate model; Radial basis function (RBF),GLOBAL OPTIMIZATION; SVM,"Recently, evolutionary algorithms (EAs) are becoming more and more popular in oil industry. It should be noted that the existence of various state constraints largely decreases the efficiency of EAs. In this paper, a doublemodel differential evolution (CSDE) is proposed for waterflooding production optimization with nonlinear inequality constraints. There are two main stages in CSDE: 1) the boundary of feasible region is explicitly constructed by a classifier, support vector machine (SVM), to prescreen the feasible solutions from current population, and 2) the objective function is approximated by radial basis function (RBF) surrogate model which can be used to select the best individual among feasible solutions. It is worth noticing that problems with a large number of constraints can be significantly simplified by distinguishing the feasible solutions and infeasible solutions with one unique SVM classifier. To the best of our knowledge, this is the first foray to integrate SVM and RBF into evolutionary algorithm for waterflooding optimization problem. The CSDE method has been tested on three artificial cases: three-channel, PUNQ-S3 and SPE9. The test results demonstrate that CSDE algorithm can handle constraints more efficient and achieve higher net present value (NPV) compared with the original EAs and other single-model algorithms.",3,4,4
Net Present Value,,"Lamas, L. F.; Botechia, V. E.; Schiozer, D. J.; Rocha, M. L.; Delshad, M.",Application of polymer flooding in the revitalization of a mature heavy oil field,Polymer flooding; Mature fields; Reservoir management; Revitalization of fields; Reservoir simulation,,"Polymer flooding is a chemical enhanced oil recovery that aims to improve mobility control, by increasing the viscosity of injection brine and thus reducing the mobility ratio. Starting the polymer injection as early as possible brings the best economic results because it prevents the formation of viscous fingering and sweeps more efficiently the reservoir. It is possible, however, to obtain gains with polymer flooding even after massive waterfloods. In this work, three different model-based approaches are developed to revitalize mature oilfields and tested considering the use of water and polymer as injection fluid. These strategies were tested using a synthetic reservoir model based on data from an offshore field in Brazil. The reservoir is sandstone (average permeability = 1650mD, average porosity = 20%). The oleic phase is heavy viscous oil (similar to 70 cP, 14 degrees API). The first simulation approach considered a strategy based on a standard waterflood until its economic limit. For this case, the maximum net present value (NPV) was reached after 15 years of production with a recovery factor of 25%. The revitalization strategy of this field considers an abandonment status for all wells. To emulate the time necessary to install all new facilities, all wells were assumed to be closed for six months. The first approach consists simply of reopening the injectors by changing the injection fluid to an aqueous polymer solution. The second approach has an additional degree of freedom: it allows all wells to be converted from injectors to producers and vice-versa. Finally, the third approach consists of the addition of new wells. Equations for quality maps for placing injectors and producers are presented. Using these equations, new producers and injectors could be placed at the best locations to produce the remaining oil spots. All three approaches increased the oil recovery factor. The additional oil recovery and variations in NPV were higher for the polymer flooding when compared with the standard waterflood, ensuring a longer productive life. This significant increase in oil production means that, for the selected case, producers needed to be closed in the water flooding period, due to economic performance, leaving a significant amount of oil still in the reservoir. The methodologies presented in this paper are easy to apply and can allow mature fields to economically produce more oil. The conversion of old wells by changing from producers to injectors or vice-versa allows new and creative production strategies. This can be done in onshore and dry completed offshore fields demanding small budgets and intervention times. This paper shows that it is possible to increase both the recovery factor and net present value of fields in the later stages of production life.",3,3,4
Hydrate,,"Gambelli, Alberto Maria; Filipponi, Mirko; Rossi, Federico",How methane release may affect carbon dioxide storage during replacement processes in natural gas hydrate reservoirs,Natural gas hydrate; Carbon dioxide storage; CO2/CH4 replacement; CO2 capture; Gaseous phase composition,THERMAL-STIMULATION; PHASE-EQUILIBRIUM; CO2 STORAGE; RECOVERY; DISSOCIATION; DEPRESSURIZATION; VERIFICATION; EXCHANGE; ENERGY,"Methane replacement with carbon dioxide molecules in natural gas hydrate reservoirs mainly occurs in two different methods. The first is based on initial CH4 hydrate dissociation and a following CO2 hydrate formation, with all related problems for sediment deformation and so on. With the second method, the direct CO2/CH4 exchange occurs in already present cages, thus avoiding environmental problems and ensuring an exchange ratio close to 1. Because of practical difficulties in perfectly applying the second method, the initial methane release may produce a binary gaseous phase over the hydrate sediment, whose concentration may affect hydrate formation, till favouring CH4 hydrate re-formation rather than CO2 hydrate formation. The present experimental work analysed such aspect, by showing how that concentration may modify the formation trend, mainly in terms of carbon dioxide storage, and also proving the importance of thermodynamic conditions in this sense.",7,7,9
Hydrate,,"Shi, Guoyun; Song, Shangfei; Shi, Bohui; Gong, Jing; Chen, Dongliang",A new transient model for hydrate slurry flow in oil-dominated flowlines,Multiphase flow; Natural gas hydrates; Hydrate formation; Flow assurance; Transient flow simulation,NATURAL-GAS HYDRATE; NUMERICAL-SIMULATION; INTRINSIC KINETICS; SHELL-MODEL; LIQUID FLOW; MASS; AGGLOMERATION; METHANE; SYSTEMS; DISSOCIATION,"A transient simulation tool for the gas hydrate slurry flow is crucial for hydrate flow assurance in the petroleum industry. In this work, we propose a new transient model for gas hydrate slurry flow in oil-dominated flowlines. A two-fluid model and a temperature equation are used to describe the gas-slurry two-phase flow. For the modeling of particulate phase flow, number density conservation equation and diameter conservation equation of the hydrate particles are established by Eulerian approach, a momentum conservation equation is established by Lagrangian approach. Furthermore, combining with the hydrate formation model, the transient gas hydrate slurry flow in oil-dominated flowlines can be numerically simulated. This model is verified by experimental data and field data, respectively. Afterwards, it is applied to analyze the transient behavior of the gas-hydrate slurry multiphase flow upon reduced gas well production. Finally, the sensitivity analysis of effects of flowrate, initial average size of water droplets and drag force on the hydrate slurry multiphase flow is performed. These results are of great practical value to give a deeper understanding of hydrate slurry multiphase flow, and contribute to better hydrate management in the petroleum industry by using hydrate slurry flow technology.",6,6,8
Hydrate,,"Quainoo, Ato Kwamena; Negash, Berihun Mamo; Bavoh, Cornelius B.; Idris, Alamin",Natural amino acids as potential swelling and dispersion inhibitors for montmorillonite-rich shale formations,Reactive days; Clay swelling and dispersion; Clay stabilizers; Natural amino acids; COSMO-RS Simulation; Activity coefficient and hydrogen bonding,DRILLING-FLUIDS; IONIC LIQUID; COSMO-RS; FILTRATION PROPERTIES; HIGH-PERFORMANCE; WATER; HYDRATE; BENTONITE; BEHAVIOR; METHANE,"In this paper, the destabilization inhibition potentials and mechanisms of Alanine, Arginine, and Proline on montmorillonite clay were investigated. A swelling test was done using an M4600 HPHT Linear swell meter at 1000 psi, 25 degrees C, and 2 wt% inhibitor solutions. Shear rates and temperatures in the range of 0.01 s(-1) to 1000 s(-1) and 25 degrees C - 50 degrees C, respectively, were applied on a high-precision Discovery Hybrid Rheometer to investigate the effect of the amino acids on the suspension's theology. Also, the inhibitors' neutralization and surface modification properties were determined via zeta potential, wettability alteration, and FTIR analyses using the nano zeta sizer, goniometer, and the spectrometer respectively. Furthermore, COSMO-RS was employed to study the hydrogen bonding interactions of amino acids and water. Upon completion, Proline displayed the best inhibition performance reducing the swelling of the montmorillonite by 22.5%, whiles KCl only showed a 17.8% reduction. Also, the rheological tests confirmed that the amino acids positively enhanced the base fluid properties. In addition, Proline, Alanine, and Arginine altered the surface of the clay mineral by 89%, 64%, and 38%, respectively, when compared to the base fluid. This made their clay surfaces less hydrophilic and thus, reduced the attraction between water molecules and the clay mineral. Furthermore, the simulation results showed that amino acids easily form hydrogen bonds with water, thus preventing high amounts of water from saturating the clay mineral, resulting in a significant reduction of swelling in the clay during fracturing. The superior performance of amino acids especially Proline in stabilizing montmorillonite clays, over KCl, makes them suitable candidates to consider in the development of low cost, and eco-friendly clay stabilizers.",6,6,5
Hydrate,,"Kim, Sungil; Lee, Minhui; Lee, Kyungbook; Ahn, Taewoong; Lee, Jaehyoung",Data-driven estimation of three-phase saturation during gas hydrate depressurization using CT images,Gas hydrate dissociation; Core depressurization experiment three-phase saturation; Random forest; Training data; X-ray medical CT,X-RAY CT; PRESSURE; DISSOCIATION,"The purpose of this study was to determine the three-phase saturation (water; gas hydrate, GH; and gas) in real time to gain insights into the GH depressurization process. Although X-ray computed tomography (CT) can be used to investigate the density changes in the GH core during the depressurization experiment, it is hard to distinguish between water and GH due to their similar densities and the limited resolution of the CT image. To address this issue, random forest (RF) was applied to quantitatively predict the three-phase saturation: CT images were used as input data and the three-phase saturation was the output. In the previous research, a RF model was developed based on training data that only involved the five preliminary stages before the depressurization step. However, the previous RF model failed to estimate the saturation values of the CT images during the depressurization. It could not properly estimate general GH dissociation trend and the GH equilibrium pressure, neither. In this study, CT data obtained in the early and late depressurization stage were used for the training of the RF model. The proposed method can be used to reliably estimate the GH dissociation behavior. The trained RF in this study can identify the GH equilibrium at which the dissociation starts (similar to 16 MPa), which is consistent with the theoretical dissociation at a temperature and salinity of 16 degrees C and 3 wt%, respectively. The reliability of the proposed method was tested by checking if the estimated results approached zero GH saturation at the end of the GH dissociation (6 and 0 MPa). Therefore, the originality of this study is to improve RF model to reliably predict the three-phase saturation in real time during the GH depressurization by properly utilizing CT images in the depressurization stage for training RF. Based on further improvement, the proposed method could be utilized in the future to help finding adequate depressurization velocity by reliable saturation modeling and analysis of GH experiment because GH productivity depends on depressurization gradient.",6,6,3
Hydrate,,"Wu, Peng; Li, Yanghui; Wang, Le; Wang, Lei; Sun, Xiang; Liu, Weiguo; Song, Yongchen",Triaxial tests on the overconsolidated methane hydrate-bearing clayey-silty sediments,Triaxial test; Over consolidation; Methane hydrate-bearing sediment; Clayey silts; The south China Sea,MECHANICAL-PROPERTIES; CONSTITUTIVE MODEL; DISSOCIATION; BEHAVIOR; SAND; TEMPERATURES; RESERVOIR; STRENGTH,"Significant experimental efforts have been made to understand the mechanical behaviors of hydrate-bearing sediment; however, studies on the influence of over consolidation conditions on hydrate-bearing sediment are quite rare, while a series of exploratory drilling surveys for hydrate in hydrate-bearing sediment has reported that the phenomenon of over consolidation or apparent over consolidation is widespread. In this study, we present triaxial test results of influence of the over consolidation on hydrate-bearing clayey-silty sediment. The results reveal that both the tested normally consolidated and overconsolidated hydrate-bearing sediment appear to undergo strain-hardening and volumetric contraction, although the increasing over consolidation ratio would weaken the strain-hardening phenomenon and enhance the initial elastic modulus and failure strength. In addition, the increasing hydrate saturation would also increase the initial elastic modulus and failure strength and decrease the volumetric strain of the overconsolidated hydrate-bearing sediment. The mechanism controlling the influence of over consolidation on the hydrate-bearing sediment has been further investigated and discussed by scanning electron microscopy, and it is found that the over consolidation could damage a certain proportion of the cementation structure formed by the hydrate, while increasing the particle occlusion and strengthening the sediment. Under low over consolidation condition, these two mechanisms may almost counteract each other, while under high over consolidation condition, the strengthening mechanism caused by over consolidation is dominant.",4,4,19
Hydrate,,"Deka, Barasha; Barifcani, Ahmed; Al Helal, Ammar; Badi, Dana; Mahto, Vikas; Vuthaluru, Hari",Generation of methane gas hydrate equilibrium curve for the thermodynamic gas hydrate inhibitor propylene glycol,Thermodynamic hydrate inhibitors; Mono ethylene glycol; Propylene glycol; Dissociation temperature; Hydrate equilibrium curve,,"Use of thermodynamic hydrate inhibitors (THIs) for prevention of gas hydrate formation in the oil and gas field operations is a well-known and accepted process all over the world. Although glycols are reported as THIs, but only monoethylene glycol is studied in detail and applied conventionally. In this study, gas hydrate inhibition efficiency of propylene glycol is determined. The data is acquired using a stirred cryogenic PVT sapphire cell and the hydrate dissociation temperature measured at isobaric condition (constant pressure) is considered as the thermodynamic equilibrium temperature, because although dissociation temperature depends on hydrate particle size and heat flux, but, it is unlike the random nature and unpredictability of formation temperature. The key objective of this study is to establish the equilibrium condition of methane hydrate in presence of 20 wt% propylene glycol as thermodynamic inhibitor. The identification of dissociation temperature is based on visual method. The gas hydrate equilibrium curve for 20 wt% propylene glycol in methane-water system is established by determining the hydrate equilibrium dissociation temperatures for a pressure range 70-190 bar. Also performance comparison of propylene glycol with monoethylene glycol is done to gauge the inhibition efficiency of propylene glycol, the results of which have shown better inhibition efficiency of propylene glycol. Hydrate equilibrium curve of 20 wt% propylene glycol system showed an average of 10.42 degrees C deviation towards lower temperature compared to that of the system without the inhibitor. The fitted curve for hydrate dissociation temperatures showed co-efficient of determinants (R-2) value >= 0.97, suggesting the reliability of the experimental observations.",4,4,4
Hydrate,,"Wang, Jiaqi; He, Jiale; Lv, Xin; Ge, Kun; Cheng, Chuanxiao; Dong, Hongsheng",Numerical analysis of the gas recovery performance in hydrate reservoirs with various parameters by stepwise depressurization,Natural gas hydrate; Stepwise depressurization; Reservoir characteristics; Sensitivity analysis,METHANE HYDRATE; THERMAL-STIMULATION; DISSOCIATION; ENERGY; HEAT; PERMEABILITY,"Natural gas hydrates have drawn worldwide attention as a significant clean energy source in the 21st century. Depressurization is known to be the most effective method for hydrate exploitation owing to its feasibility and economic benefits. Recently, stepwise depressurization has received extensive attention owing to its advantages of effective prevention of ice generation and hydrate reformation during gas recovery. In this work, we optimized the 2-D simulator to model the evolution of temperature, pressure, hydrate saturation, and gas production behavior in hydrate sediments during decomposition process via stepwise depressurization. The effect of various reservoir characteristics on gas production was analyzed by introducing the sensitivity factor. The results demonstrated that higher specific heat capacity of the reservoir would promote gas production in the early stage of the reaction; however, this effect is reversed in the later stage. A higher thermal conductivity of the hydrate cores can dramatically enhance the gas production rate; however, this advantage is weakened with increasing thermal conductivity. Reducing the gas relative permeability hinders the hydrate decomposition process, and the water relative permeability has minimal effect on gas production. Based on the sensitivity analysis, the thermal conductivity and gas relative permeability are the main factors affecting hydrate decomposition.",3,3,9
Micro CT,,"Liu, Yishan; Dong, Xiaohu; Chen, Zhangxin; Hou, Yanan; Luo, Qilan; Chen, Yihang",A novel experimental investigation on the occurrence state of fluids in microscale pores of tight reservoirs,Tight reservoirs; Occurrence state; Recoverable capability; Microfluidic; Micro-CT; Microscale pores,METHANE ADSORPTION; PRESSURE; NANOPORES; BEHAVIOR,"Occurrence state of fluids in the microscale pores of tight reservoirs significantly affects the flow behavior and recoverability of reservoir fluid. Currently, microfluidic technique and CT (Computed Tomography) scanning have been widely applied on the reservoir pore structure evaluation and fluid flow behavior characterization due to their high resolution. In this study, combining a microfluidic chip test and a micro CT scanning test on tight rocks, the occurrence state of fluids in microscale pores is experimentally investigated. A set of tests on the microfluidic chips are performed to change the environment temperature, pore size and fluid compositions. Then, combining the results of micro CT scanning on real tight rocks and the results of microfluidic chips, the immobile and movable oil films in microscale pores can be obtained. Results indicates that the oil film thickness in microscale pores is negatively correlated with temperature and positively correlated with pore size. The effect of pore size can be neglected when it is above 15 mu m. The higher the molar weight of fluids is, the thicker the oil film is. And the proportion of immobile and movable states are also closely related to the fluid compositions.",6,5,5
Micro CT,,"Yang, Yu; Wang, Dong; Yang, Jingyi; Wang, Bin; Liu, Tao",Fractal analysis of CT images of tight sandstone with anisotropy and permeability prediction,Digital rock analysis; Fractal geometry; Heterogeneous porous media; Permeability,PORE STRUCTURE; POROUS-MEDIA; MODEL; INVESTIGATE; RESERVOIRS; FLOW; SEM,"For developing unconventional oil and gas resources, it is necessary to quantify the heterogeneity embodied in both pore-size distribution (PSD) and pore spatial distribution, on the basis of which the relationship between the seepage characteristics and the microstructure of heterogeneous porous media could then be clarified. In this work, micro computed tomography (mu CT) and image processing technology were applied to characterise matrix pore structure in tight sandstone. Fractal theory was used to investigate the image-based heterogeneity of tight porous media. On the basis of the verification that the PSD of the tight rock is statistically self-similar at a certain scale, we investigated the relationships between porosity and fractal dimension, and between 2D and 3D fractal dimensions, respectively. The results showed that the pore structure characteristic parameters with anisotropy, i. e., the ratio of the minimum pore size to the maximum pore size lambda max/lambda min and a proportionality constant CKT, could be obtained by liner fitting fractal dimension and porosity. Moreover, the 2D PSD characteristics of the 'standard cross section' were consistent with the 3D PSD characteristics of pore network. A fractal permeability model was established by treating the connected pores in the matrix as a bundle of conical micropipes. The permeability values predicted by the proposed model agreed well with those predicted by finite volume method simulation under the condition where irreducible pores were removed. A sensitivity analysis indicated that increasing the heterogeneity of the PSD and pore spatial distribution reduced the flow capacity of the matrix, particularly for low-porosity porous media.",5,4,13
Micro CT,,"Liu, Xuefeng; Yan, Jingxu; Zhang, Xiaowei; Zhang, Lingtan; Ni, Hao; Zhou, Wei; Wei, Baojun; Li, Chaoliu; Fu, Li-Yun",Numerical upscaling of multi-mineral digital rocks: Electrical conductivities of tight sandstones,Tight sandstone; Multi-mineral digital rock; Upscaling; Electrical conductivity; Numerical simulation,,"Tight sandstones usually present great variations in Archie's exponents due to their high clay contents and multi-scale pores. Conventional multi-scale digital rocks consider the effect of micro and macro pores but ignore the contribution of clay minerals to electrical conductivity, whereas traditional multi-mineral digital rocks cannot consider the contribution of micro pores. We propose an upscaling method to construct complex digital rocks for accurate estimation of electrical conductivities. Based on a 3-D grayscale image of a tight sandstone acquired by X-ray CT and a 2-D mineralogy slice imaged by energy-dispersive SEM (EDS-SEM), we reconstruct a 3-D multi-mineral digital rock that is composed of intergranular pores and mineral phases by image registration and multi-threshold segmentation. Fine mineral structures and micro pores are revealed by the multi-scale imaging technique. The effective conductivity of each mineral phase associated with a specific micro porosity is calculated by the Archie's equation or Waxman-Smits model. By assigning each voxel with the optimal conductivity according to its mineral phase, we estimate the bulk electrical conductivity of the entire digital rock by the finite element method. The contributions of fluids and clay minerals to the bulk electrical properties are implicitly incorporated into the numerical simulation without increasing computational cost. The upscaling method is validated by experimental measurements of formation factors. We investigate the effect of clay minerals and scanning resolutions on the calculated electrical conductivities with attempt to interpret variations in the cementation exponent.",4,4,4
Micro CT,,"Yoo, Hyunsang; Kim, Youngmin; Jang, Hochang; Lee, Jeonghwan",Propagation characteristics of optimum wormhole in carbonate matrix acidizing using micro X-ray CT imaging,Matrix acidizing; Carbonate rock; Micro X-ray CT; Optimum wormhole; Propagation characteristics,ACID; DISSOLUTION; RESERVOIR; DOLOMITE,"This study aims to investigate the propagation characteristics of an optimum wormhole to make an efficient acid treatment in carbonate matrix acidizing based on wormhole visualization using micro X-ray computerized tomography (CT) with high resolution. Five cases comprising 25 core-flood experiments under different experimental conditions using Indiana limestone cores were carried out at various injection rates to obtain the optimum injection rates. From the results, the optimum injection rates tended to increase with permeability but was not related to acid concentrations. The pore volume to breakthrough (PVBT), the amount of acid consumption required to breakthrough, was lower at higher permeability and acid concentration. This means that less amount of acid is consumed to generate the wormholes. Wormhole visualization with X-ray CT imaging showed that the wormhole diameters were gradually reduced along with the wormhole propagation axis in all cases. In addition, the mean of wormhole diameter tended to increase according to the higher permeability and acid concentration. The tortuosity, which is the ratio of actual wormhole length to core length, was exceeded at least 1.35 in each case. This implies that the actual flow length of the optimum wormhole is much longer than the core length. However, previous studies of wormhole propagation regarding the configuration of optimum wormhole are sparse, more intensive research would be required. Therefore, these propagation characteristics of optimum wormholes should be considered to improve the wormhole prediction model, and the wormhole prediction results would be more accurate and realistic than those of the existing models. Further study is needed to develop a new wormhole prediction model considering the propagation characteristics, such as diameter reduction and actual flow length.",4,4,0
Micro CT,,"Ali, Hassan; Soleimani, Hassan; Yahya, Noorhana; Khodapanah, Leila; Kozlowski, Gregory; Sabet, Maziyar; Demiral, Birol M. R.; Adebayo, Lawal Lanre; Hussain, Tanvir",Experimental investigation and two-phase flow simulation of oil and nanofluids on micro CT images of sandstone for wettability alteration of the system,Capillary pressure; Oil reservoir; Porous media; Permeability; Oil saturation,PORE NETWORK MODEL; POROUS-MEDIA; PERMEABILITY; TRANSPORT; WATER; MIGRATION; BRINE,"This work provides an analysis of the effect of nanofluids on the wettability of sandstone for the application of enhanced oil recovery. The wettability of sandstone with brine and nanofluids of ZnO, BiFeO3, and SrFeO3 is studied experimentally using contact angle calculations. Also, the direct simulations for the displacement of oil with brine and nanofluids are carried out on a micro-CT scanned porous sandstone structure for the measurement of capillary pressure and relative permeability. Fluid properties such as viscosity and density of the nanofluids, brine, and oil to be used in simulations were obtained using viscometer and densimeter. The experimental results show that the contact angle of crude oil on the sandstone surface has a higher value for nanofluids as 125.89 degrees for ZnO, 122.88 degrees for BiFeO3, and 104.98 for SrFeO3 as compared to brine 28.66 degrees, which means the wettability of the system changes from oil-wet to water-wet by the addition of nanofluids. The simulation results indicate that BiFeO3 nanofluid has a greater tendency to change the wettability of porous medium as compared to brine, ZnO, and SrFeO3 nanofluids, as it shows better values of relative permeability and capillary pressure.",3,3,5
Acoustic Emission,,"He, Mingming; Zhang, Zhiqiang; Zhu, Jiwei; Li, Ning; Li, Guofeng; Chen, Yunsheng",Correlation between the rockburst proneness and friction characteristics of rock materials and a new method for rockburst proneness prediction: Field demonstration,Rockburst proneness prediction; Friction characteristics; Strength ratio; Drilling log data,ENERGY-RELEASE RATE; STRAIN-ENERGY; ACOUSTIC-EMISSION; TOOTH WEAR; STRENGTH PARAMETERS; STRUCTURAL PLANES; BURST PRONENESS; ROLLER-BITS; FAILURE; DISSIPATION,"Prediction of the rockburst proneness of rock in the field is an important problem in rockburst research. In this paper, the analytical relationship between the strength ratio (the ratio of the unconfined compressive strength to the ultimate cutting strength) of rock and the friction angle is presented. A new perspective is presented for rockburst proneness considering the strength ratio and friction characteristics of rock materials. The relationships between the residual elastic energy index (the difference between the peak elastic energy density and failure energy density of the postpeak stage) and the strength ratio and friction coefficient are established to determine the rockburst proneness of rock materials. The linear relationship between the strength ratio and residual elastic energy index is obtained. A novel method is proposed to easily predict the rockburst proneness of rock materials in the field. The rockburst proneness values predicted from the proposed method for six types of rock are consistent with those obtained in the laboratory. This result shows the correlation between the rockburst proneness and friction characteristics of rock materials. The variation in the contact friction angle is similar to the variation in the residual elastic energy index along the borehole. This method is successfully applied to predict the rockburst proneness of the surrounding rock of four tunnel sections.",17,17,38
Acoustic Emission,,"Wang, Yuanyuan; Deng, Hucheng; Deng, Yong; Chen, Kangping; He, Jianhua",Study on crack dynamic evolution and damage-fracture mechanism of rock with pre-existing cracks based on acoustic emission location,Rock with preexisting cracks; Acoustic emission; Crack evolution; Damage; Fracture,,"The acoustic emission (AE) location technique is used to characterize the entire progressive failure process of rock with preexisting cracks. The mechanical properties, AE characteristics, crack dynamic propagation process, failure modes and damage-fracture evolution rules are studied for prefabricated rock samples with different crack inclination angles under uniaxial compression. The results show that the peak strength and elastic modulus first decrease and then increase with increasing crack angle. AE events exhibit different characteristics with changes in stress. In the initial compaction and elastic deformation stage, the AE activity is not obvious; when microcracks form in the rock sample, the AE count increases; after entering the crack stable growth stage, the AE activity becomes significant; during the period of unstable crack propagation to rock failure, the AE activity is extremely active. The AE location can well accurately reflect the crack initiation position, propagation direction and surface orientation in the rock. AE location can well reflect cracks initiation position, propagation direction and space surface shape in the rock. For intact samples, microcracks are first generated at the ends of the sample and extend internally along the loading direction until they coalesce and form macroscopic cracks; for precracked samples, microcracks appear first at the tips of the prefabricated crack, and extend outward at a certain angle, while the microcracks are mainly concentrated around the preexisting crack, with a small number of microcracks distributed at both ends of the sample. With increasing the crack angle, the rock failure mode changes from splitting failure to tension-shear mixed failure and finally to single shear failure. The AE positioning results are in good agreement with the observed macroscopic failure of the rock samples. The damage variable based on AE counts divides the rock damage-fracture evolution process into four stages, and the initial damage and damage rate of the rock sample with a crack angle of 45 degrees are the largest.",13,13,15
Acoustic Emission,,"Wang, Dengke; Zeng, Fanchao; Wei, Jianping; Zhang, Hongtu; Wu, Yan; Wei, Qiang",Quantitative analysis of fracture dynamic evolution in coal subjected to uniaxial and triaxial compression loads based on industrial CT and fractal theory,Industrial CT; Fracture dynamic evolution; Three-dimensional fracture reconstruction; Uniaxial and triaxial compression; Fractal dimension,RAY COMPUTED-TOMOGRAPHY; PORE STRUCTURE; ACOUSTIC-EMISSION; CONFINING PRESSURES; RANK COAL; PERMEABILITY; DIMENSION; GAS; BASIN; RECONSTRUCTION,"The dynamic evolution characteristics of fractures in coal under different compressive loads are of great significance to the recovery of coalbed methane (CBM). In this paper, the X-ray computer tomography (CT) detections of coal samples under uniaxial and triaxial compressive loading conditions were performed by using a developed triaxial in situ rig and an industrial CT scanner. The image processing technique, three-dimensional reconstruction method and statistical principles were employed to describe two-dimensional and three-dimensional fracture evolution in coal under uniaxial and triaxial compressive loads. The results showed that the developed triaxial in situ rig has an enough scanning resolution and is suitable to carry out CT scanning inspections under uniaxial and triaxial compressive loads for porous materials of coal and rock. The two-dimensional cross-sectional CT images effectively reflect the dynamic evolution of two-dimensional fractures during the deformation of coal. Confining pressure and minerals have a significant effect on fracture propagation in coal. The evolution characteristics of three-dimensional fractures can be clearly revealed by the reconstructed three-dimensional digital fracture models of coal. Euler number effectively reflects the fracture connectivity in coal at different deformation stages. During the deformation of coal, the fracture volume, fracture rate, fracture density and fracture connectivity mainly undergo a slow decrease stage, a slow increase stage and a sharp increase stage, display a good linear correlation with fractal dimension, and quantitatively characterize the evolution process of the three-dimensional fractures in coal. The fractal dimension calculated by the box-counting method effectively mirrors fracture propagation and fracture geometric complexity and can be employed to uncover the fracture dynamic evolution in coal under different compressive loading conditions.",7,7,32
Acoustic Emission,,"Zhou, Junping; Yang, Kang; Zhou, Lei; Jiang, Yongdong; Xian, Xuefu; Zhang, Chengpeng; Tian, Shifeng; Fan, Maolin; Lu, Zhaohui",Microstructure and mechanical properties alterations in shale treated via CO2/CO2-water exposure,Shale reservoir; Supercritical carbon dioxide fracturing; Carbon dioxide sequestration; Mechanical alteration; Carbon dioxide-water-shale interaction,SUPERCRITICAL CO2 TREATMENT; PORE STRUCTURE; CARBON-DIOXIDE; FRACTAL ANALYSIS; MULTIFRACTAL CHARACTERISTICS; ADSORPTION BEHAVIORS; FAILURE MECHANISMS; GAS; NMR; WATER,"CO2 injections into shale reservoirs can enhance the recovery of oil and gas, while simultaneously sequestrating CO2. However, with the injection of CO2, the microstructure and mechanical properties alteration of shales caused by CO2/CO2-water exposure is should be noticed, which is of great importance to predicting the efficiency of CO2-enhanced shale oil/gas recovery and safety of CO2 sequestration in shale reservoirs. Therefore, this study clarifies the influence of sub/super-critical CO2-water exposure on the microstructure and mechanical properties of shale. Results show that after Sub/ScCO2 and Sub/ScCO2 water exposure, the contents of carbonate and clay in shale were decreased. Additionally, the proportion of micropores and mesopores were decreased, while the proportion of macropores was increased, leading to the increase of porosity and the improvement of pore connectivity, and the decreases of the pore surface fractal dimensions D-1 and pore volume fractal dimensions D-2 in shale. The uniaxial compressive strength (UCS) and elastic modulus (E) of shale were also decreased. Acoustic emission (AE) analysis results indicated that the cracks closure stage and stable crack propagation stage was prolonged and shorten, respectively, and AE signals show obvious multifractal characteristics. ScCO2 induced greater alteration in pore structure and mechanical properties than SubCO(2), and the alterations were enhanced for CO2-water exposure. UCS and E of shale samples show a good negative correlation with porosity, and a positive correlation with D-1 and D-2. UCS in shale is positively related to the proportion of micropores and mesopores, and negatively related to the proportion of macropores, which indicated that microstructure alterations inevitably affected the macroscopic mechanical properties of shale.",5,6,24
Acoustic Emission,,"Munoz-Ibanez, Andrea; Delgado-Martin, Jordi; Herbon-Penabad, Miguel; Alvarellos-Iglesias, Jose",Acoustic emission monitoring of mode I fracture toughness tests on sandstone rocks,Acoustic emission; Rock fracture mechanics; Crack classification; AE parameter analysis,MOMENT TENSOR INVERSION; ISRM-SUGGESTED METHOD; CRACK CLASSIFICATION; CONCRETE STRUCTURES; BRITTLE ROCKS; COMPRESSION; PROPAGATION; LOCATION; GROWTH; ENERGY,"A series of mode I fracture toughness tests employing the semi-circular bend (SCB) and the pseudo-compact tension (pCT) methodologies have been performed with two sandstone types and specimens of 50 and 100 mm in diameter. The tests were complemented with the concurrent monitoring of acoustic emission (AE) activity using a multi-sensor array. With the obtained data, we compare and analyse the two testing methods, the mechanical evolution along experiments and the significance of different acoustic emission parameters. The hypocenter location of the AE events allows a better understanding of the processes occurring in the tests and the analysis of properties like amplitude or peak frequencies are valuable complements. Crack modes are assessed using a parameter-based strategy (comparison of the average frequency, AF, and rise angle, RA), and the potential of the Ib-value to discriminate cracking processes in fracture toughness tests is explored. Results show that the pCT method provides more comprehensive and detailed results, both in terms of mechanical information and acoustic emission data. We discuss the applicability of the generally accepted models of small-strain brittle material failure typically applied to compressive tests (including or not including AE data) and further methodological questions of interest when considering AE monitoring in fracture toughness tests.",3,3,22
Acoustic Emission,,"Li, Changhai; Zhao, Lun; Liu, Bo; Liu, Hangyu; Li, Jianxin; Fan, Zifei; Wang, Jincai; Li, Weiqiang; Zhao, Wenqi; Sun, Meng","Origin, distribution and implications on production of bedding-parallel fractures: A case study from the Carboniferous KT-I Formation in the NT oilfield, Precaspian Basin, Kazakhstan",Bedding-parallel fractures; Formation timing and origin; Controls; Impacts on oil production; Carbonate; NT Oilfield,DOLOMITE RESERVOIRS; ACOUSTIC-EMISSION; GROUNDWATER-FLOW; ORDOS BASIN; VEINS; SYSTEMS; PROPAGATION; DIAGENESIS; SANDSTONES; DENSITY,"Bedding-parallel fractures (BPFs) are the breakage of rocks along weakness bedding plane of stratification or foliation. At present, the research of fractures is primarily focused on high-angle structural fractures (SFs), but few systematic efforts have been made on the formation mechanism, distribution and influences on oil production of BPFs. Knowledge of attributes of BPFs in carbonate reservoirs is necessary for well-site design and reservoir waterflooding development. Observation and description of cores and image logging and laboratory measurements including cathodoluminescence (CL), fluid inclusion, acoustic emission experiments, porosity, permeability and well testing data were used to gain insight into the formation mechanism, controlling factors and impacts on oil production of BPFs. The results show that the length and aperture of BPFs range from centimeters to tens of meters and from 30 Im to 100 um respectively. BPFs are primarily shear fractures without cements in the study area. There are 3 periods of SFs in the study area and the formation timing of BPFs and the SFs of the 2nd period are simultaneous. The origin of BPFs is related to the development of thrust faults and folds. Shear BPFs were the result of interlayer sliding during the formation of anticline and thrusts under the effect of tectonic compaction. Extension BPFs formed because of the relative movement of the hanging wall and footwall of the thrust faults. Shear BPFs are more common than extension BPFs because both anticline and thrusts can result in the formation of shear BPFs. Many factors can govern the development of BPFs including structural position, rock composition and structure, distance to faults and bed thickness. The formation of BPFs is promoted by low structural position, rapid vertical changes of the rock composition, small grain size, close distances to faults and thin bed thickness. Although the aperture of low-angle BPFs is smaller than that of fractures at high angle to bedding due to the influence of overburden pressure, the low-angle BPFs can partially improve the reservoir permeability and partly enhance the initial production of individual wells.",3,3,2
Mercury Intrusion Porosimetry,,"Chen, Yufei; Jiang, Changbao; Leung, Juliana Y.; Wojtanowicz, Andrew K.; Zhang, Dongming",Multiscale characterization of shale pore-fracture system: Geological controls on gas transport and pore size classification in shale reservoirs,Gas shale; Pore size classification; Pore size distribution; Multiscale characterization; Gas transport mechanisms; Pore-fracture,NUCLEAR-MAGNETIC-RESONANCE; ORGANIC-RICH SHALES; HIGH THERMAL MATURITY; SICHUAN BASIN; ELECTRON-MICROSCOPY; MERCURY INTRUSION; LONGMAXI SHALE; MATRIX SYSTEM; POROUS-MEDIA; ADSORPTION,"A sound understanding of the pore-fracture system across all scales provides an in-depth look at the intricate gas transport mechanisms in shale reservoirs. We performed a comprehensive multiscale characterization analysis on the Longmaxi shale samples using five complementary techniques: low-temperature gas (N2) adsorption (LTGA), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), field emission scanning electron microscopy (FE-SEM), and X-ray computed tomography (CT) scanning. For pore size distribution (PSD) determination, LTGA (N2) analysis can detect small pores (2?300 nm sized), while MIP analysis is suitable for large pores or fractures ( 1000 nm), and seepage pores or fracture-pores (pore size 1000 nm). Although slippage pores dominate in terms of the total volumetric contribution of the Longmaxi shale, with a clear presence of adsorption pores, overall gas transport in shale is predominantly controlled by the seepage pores (fracture-pores), which constitute a very small portion of the total volume.",7,7,18
Mercury Intrusion Porosimetry,,"Zheng, Sijian; Yao, Yanbin; Liu, Dameng; Cai, Yidong; Liu, Yong",Quantitative characterization of multiphase methane in coals using the NMR relaxation method,Nuclear magnetic resonance (NMR); Coalbed methane (CBM); Methane adsorption capacity; Volumetric method; Free methane,NUCLEAR-MAGNETIC-RESONANCE; LOW-FIELD NMR; MERCURY INTRUSION POROSIMETRY; RAY COMPUTED-TOMOGRAPHY; PORE-SIZE DISTRIBUTIONS; ADSORPTION CAPACITY; GAS-ADSORPTION; PERMEABILITY; DIFFUSION; POROSITY,"The gas content test for coalbed methane (CBM) reservoirs consists of measurements of lost, desorbed and residual gas, and it is a crucial parameter for evaluation of such reservoirs and optimization of favorable zones. The desorbed and residual methane contents are non-simultaneously determined by on-site desorption test, which is both time-consuming and susceptible to a volume effect - leading to a large variation in the results. Conventionally, adsorbed methane content is indirectly estimated by a volumetric method, which has the shortcoming of being unable to directly measure in-situ adsorbed gas content. Thus, it is important to develop an effective and convenient method for quantitative characterization of multiphase methane in coals using a single technique. In this study, we performed a series of nuclear magnetic resonance (NMR) adsorption measurements on 15 subbituminous coals and anthracites. The transverse relaxation time (T-2) distributions of methane are measured for three peaks: P1 (T-2 = 0.1-8 ms), P2 (T-2 = 10-300 ms), and P3(T-2 = 300-2000 ms), corresponding to adsorbed methane in the coal matrix, free methane within larger pores, and lastly free methane in the space between the sample and the sample cell, respectively. In this study, the NMR calibration coefficient of free methane (Kfree-methane) is set to 3.44 x 10(-1) cm(3) /p.u., regardless of the coal rank. In contrast, the NMR adsorbed methane calibration coefficient (Kadsorbed-methane) varies substantially in coals of different ranks, but show little difference in coals with the same coal rank. We suggest the Kadsorbed-methane of 3.2 x 10(-2) cm(3)/p.u., 2.3 x 10(-2) cm(3)/p.u. and 3.6 x 10(-2) cm(3)/p.u., corresponding to low-, medium- and high-rank coals, respectively, for estimating the adsorbed methane content. Using these calibration coefficients, multiphase methane can be quantitatively estimated using the NMR measurement alone. The method is applicable both in the laboratory and in the field, for desorbed and residual gas quantification.",5,5,15
Mercury Intrusion Porosimetry,,"Song, Rui; Wang, Yao; Sun, Shuyu; Liu, Jianjun",Characterization and microfabrication of natural porous rocks: From micro-CT imaging and digital rock modelling to micro-3D-printed rock analogs,3D printing; Porous media; Digital rock modelling; Micro-CT; Petrophysics,PORE STRUCTURE CHARACTERIZATION; 3D PRINTING TECHNOLOGY; SANDSTONE; BEHAVIOR; MEDIA; FLOW; CHALLENGES; POROSITY; IMAGES; SCALE,"Tests on standard rock specimens with controlled and identical pore structure are critical to validating the analytical and numerical models. However, it is usually difficult to acquire two natural samples with the same internal structure for the destructive laboratory tests, for the sake of the heterogeneity of natural rock which is caused by the complex diagenetic processes. Three-dimensional (3D) printing technology provides an alternative approach to produce geometry-identical, features-controllable, and lab-testable analogs of natural rock from digital data in a faster and more cost-effective way. This paper presents a customized workflow of 3D-printed rock analogs from micro-CT images combining with digital rock modelling. Three types of natural rock specimens are imaged by micro-CT and processed as inputs for two types of 3D printing techniques. Rock analogs are printed at multiple magnifications from original CT volume in five curable resin materials. Petrophysical parameters of 3D-printed rock analogs are acquired through helium pycnometry (HP) and mercury intrusion porosimetry (MIP). The accuracy of 3D-printed rock analogs is evaluated by comparing the measured results with the benchmark data derived from the digital rock modelling. Both the advantages and the current challenges to reproduce the real pore structure of natural rock by the 3D-printed analogs are discussed. The results indicate that the gypsum-based printed analogs are prior to modelling the surface roughness and wettability properties to natural rock grains, while the resin-based printed analogs owe advantages on reproducing pore structure. As the first effort in literature, this study investigates the inherent relationship between digital rock and 3D-printed rock analogs via comprehensive comparison on petrophysical properties. The results approve that the 3D printing technique is a novel, feasible, and alternative approach for laboratory test to generate rock analogs from the digital model of the natural rock. However, it is still difficult to print the pore structure of the rock at the original dimension.",4,4,27
Mercury Intrusion Porosimetry,,"Huang, Hexin; Li, Rongxi; Chen, Weitao; Chen, Lei; Jiang, Zhenxue; Xiong, Fengyang; Guan, Wen; Zhang, Shaohua; Tian, Boning","Revisiting movable fluid space in tight fine-grained reservoirs: A case study from Shahejie shale in the Bohai Bay Basin, NE China",Movable fluid; Low-field nuclear magnetic resonance; Mercury intrusion porosimetry; Tight reservoir; Shale; Bohai bay basin,NUCLEAR-MAGNETIC-RESONANCE; PORE-SIZE DISTRIBUTIONS; TRIASSIC YANCHANG FORMATION; SOUTHERN SICHUAN BASIN; ORDOS BASIN; SPONTANEOUS IMBIBITION; LONGMAXI FORMATION; MERCURY INTRUSION; THROAT STRUCTURE; GAS-ADSORPTION,"Assessment of movable fluid is a key topic in production of tight formations. Evaluation of the movable fluid was usually conducted on tight sandstone formations while rarely on black organic-rich shales. To analyze the movable fluid properties in tight black shales, we document the basic geochemical and petrological features of Paleogene Shahejie shale and carry out quantitative analyses of the movable fluid properties. A modified method is proposed to estimate the pore size distribution. Results indicate that Shahejie shale is characterized by a low porosity and under-saturated of movable fluid. Further, porosity and saturation of movable fluid in shales are mainly determined by the heterogeneity of pore structure. Besides, micropores and mesopores with pore radius smaller than 6.69-18.25 nm (the lower limits are calculated for the collected samples based on the low-field Nuclear Magnetic Resonance (LF-NMR) transverse relaxation time (T2) spectra, i.e., the lower limit is different for each sample) provide substantial movable space for the fluid. Previously, relaxation rate that related to conversion from T2 spectra of porous media to pore size distributions is often regarded as constant as well as thickness of film fluid that produces pore surface relaxation. However, our work indicates that both the relaxation rate and thickness of film fluid are variables as a function of the pore radius. This study enriches the application of movable fluid properties in tight reservoirs formations, especially shales, and lays a foundation for tight porous media research using LF-NMR in future.",4,4,9
Mercury Intrusion Porosimetry,,"Qing, Fan; Yan, Jianping; Wang, Jun; Hu, Qinhong; Wang, Min; Geng, Bin; Chao, Jing","Pore structure and fluid saturation of near-oil source low-permeability turbidite sandstone of the Dongying Sag in the Bohai Bay Basin, east China",Dongying sag; Low-permeability turbidite sandstone; Pore structure; Oil saturation; Mercury intrusion porosimetry; Pore-throat radius,MAGNETIC-RESONANCE NMR; SHAHEJIE FORMATION; ORDOS BASIN; WATER SATURATION; GRAIN-SIZE; POROSITY; RESERVOIR; DEPRESSION; AREA; DIAGENESIS,"Pore structure and oil saturation are important parameters in petroleum exploration and development, and the relationship between them is closer in near-oil source reservoirs (with a short-distance migration of oil and gas) than in other reservoirs. Using epoxy-impregnated thin sections, scanning electron microscopy (SEM), conventional core analyses of porosity and permeability, mercury intrusion porosimetry, and well logging, the characteristics of the petrology, physical properties, and pore structure we studied, as well as the relationship between pore structure and fluid saturation (maximum mercury intrusion saturation S-max and oil saturation S-o) of the near-oil source low-permeability turbidite sandstone reservoirs in the Es-3 member of the Dongying Sag, Bohai Bay Basin, eastern China. The results indicate that the turbidite sandstone reservoirs are mainly composed of fine sandstone and siltstone, with porosities and permeabilities ranging from 5 to 25% and 0.1 to 40 mD, respectively, and can be classified as medium to low porosity and extra-low to ultra-low permeability reservoirs. The pore types of high-quality reservoirs are mainly dominated by intergranular pores, both primary and dissolved, probably due to the influence of the acidic fluids generated from the cracking of organic matter. The pore structure is complex with respect to the pore-throat size distribution, and the overall pore-throat radius is small. Several pore structure parameters together affect the fluid saturation distribution, among which the medium pore-throat radius (R-50) and medium saturation pressure (P-50) are especially correlated with oil saturation. Different pore structure types have different characteristics of fluid saturation distribution, and the oil-bearing grade and oil saturation of the reservoirs above the oil-water contact are typically positively correlated with pore structure. This study will help to classify the pore structure in the wellbore profile and improve the accuracy of the oil saturation calculation by well logging.",4,4,1
Mercury Intrusion Porosimetry,,"Lu, Yuejian; Liu, Dameng; Cai, Yidong; Li, Qian; Zhou, Yingfang",Spontaneous imbibition in coal with in-situ dynamic micro-CT imaging,Coalbed methane; Spontaneous imbibition; X-ray; Relative permeability,PORE-FRACTURE NETWORKS; MERCURY INTRUSION POROSIMETRY; RELATIVE PERMEABILITY; WATER IMBIBITION; POROUS-MEDIA; LOW-RANK; GAS; SHALE; SORPTION; METHANE,"The gas/fluid flowing behavior and fluid distribution under capillary forces in porous media are essential for evaluating the pore-fracture characteristics of coal. Capillary force is crucial for flow-back efficiency after hydraulic fracturing during enhanced coalbed methane (CBM) production. In this work, in situ dynamic X-ray micro-computed tomography (X-ray mu-CT), field emission scanning electron microscopy (FE-SEM) combined with mercury intrusion porosimetry (MIP) were used on two coal samples of different wettability to explore the behavior of spontaneous imbibition. The results show that both pore-fracture and mineral content could affect the imbibition behavior of coal, which the former has played a major role. The spontaneous imbibition process can be divided into 4 stages to reveal fluid flow characteristics by the fluid distribution at different time steps. The gas relative permeability of coal attenuates exponentially with imbibition time result for capillary force based on fractal theory (the gas relative permeability reduces its value from 0.72 mD to 0.01 mD for WD, 0.5 mD to 0.08 mD for WZX). A low flow-back rate of fracturing fluid would lead to severe permeability damage. The longer the return drainage time, the more severe the permeability damage.",3,3,37
Triaxial Compression,,"Wang, Dengke; Zeng, Fanchao; Wei, Jianping; Zhang, Hongtu; Wu, Yan; Wei, Qiang",Quantitative analysis of fracture dynamic evolution in coal subjected to uniaxial and triaxial compression loads based on industrial CT and fractal theory,Industrial CT; Fracture dynamic evolution; Three-dimensional fracture reconstruction; Uniaxial and triaxial compression; Fractal dimension,RAY COMPUTED-TOMOGRAPHY; PORE STRUCTURE; ACOUSTIC-EMISSION; CONFINING PRESSURES; RANK COAL; PERMEABILITY; DIMENSION; GAS; BASIN; RECONSTRUCTION,"The dynamic evolution characteristics of fractures in coal under different compressive loads are of great significance to the recovery of coalbed methane (CBM). In this paper, the X-ray computer tomography (CT) detections of coal samples under uniaxial and triaxial compressive loading conditions were performed by using a developed triaxial in situ rig and an industrial CT scanner. The image processing technique, three-dimensional reconstruction method and statistical principles were employed to describe two-dimensional and three-dimensional fracture evolution in coal under uniaxial and triaxial compressive loads. The results showed that the developed triaxial in situ rig has an enough scanning resolution and is suitable to carry out CT scanning inspections under uniaxial and triaxial compressive loads for porous materials of coal and rock. The two-dimensional cross-sectional CT images effectively reflect the dynamic evolution of two-dimensional fractures during the deformation of coal. Confining pressure and minerals have a significant effect on fracture propagation in coal. The evolution characteristics of three-dimensional fractures can be clearly revealed by the reconstructed three-dimensional digital fracture models of coal. Euler number effectively reflects the fracture connectivity in coal at different deformation stages. During the deformation of coal, the fracture volume, fracture rate, fracture density and fracture connectivity mainly undergo a slow decrease stage, a slow increase stage and a sharp increase stage, display a good linear correlation with fractal dimension, and quantitatively characterize the evolution process of the three-dimensional fractures in coal. The fractal dimension calculated by the box-counting method effectively mirrors fracture propagation and fracture geometric complexity and can be employed to uncover the fracture dynamic evolution in coal under different compressive loading conditions.",7,7,32
Triaxial Compression,,"Wang, Haoteng; He, Mingming; Pang, Fan; Chen, Yunsheng; Zhang, Zhiqiang",Energy dissipation-based method for brittleness evolution and yield strength determination of rock,Brittleness; Yield strength; Energy dissipation; Triaxial compression; Rock,,"Brittleness is one of the most important mechanical properties of rock, especially in designing an efficient fracturing method for deep production of raw petroleum and shale gas. In this study, triaxial compression tests for sedimentary, igneous and metamorphic rocks are carried out to investigate the relationship between brittleness and yield under different confining pressures. To research the yield property in the deformation and failure process of rock, the referenced brittleness index BIM is adopted to analyze the brittle evolution of rock based on the energy dissipation characteristics. The experimental results show that the BIM following increasing axial strain presents N-shaped variation in the deformation process. The two inflection points are exactly marked as the compaction point and yield point in the rock deformation process. Accordingly, the scientific linear correlation between BIM and yield and peak strength is investigated to obtain the response of brittleness to the corresponding stress values increasing under different confining pressures. Based on this correlation, a new method for determining the yield strength by considering the energy dissipation is proposed. In comparison with the fitting correlation, the estimated BIMmax values from other rock strengths are close to the correlation between yield and brittleness (error range within 10%). Accordingly, the proposed method may provide a reliable estimation of rock yield strength.",5,5,10
Triaxial Compression,,"Meng, Meng; Baldino, Silvio; Miska, Stefan",Evaluation of failure criteria under dynamic loading of the wellbore with strain rates between 10(-6) and 10(0) /s,Failure criteria; Strain rates; Grid search algorithm; Mohr failure line; Triaxial compression tests,,"Dynamic loading is very common during drilling, mining, hydraulic fracturing, and tunnel excavation. This could compromise the long-term stability and integrity of the underground constructions. Under dynamic loading, rocks usually behave differently compared to static loading. Whether the static failure criteria can be used to evaluate structure failure under dynamic loading is a question that has not been answered yet. In this paper, the triaxial compression strength data under different strain rates (between 10(-6) and 10(0)/s) for four types of rock (Bedford limestone, Bukit Timah granite, Laurentian granite, and Dry silica sand) have been used to evaluate six different failure criteria. Two methods have been implemented to obtain rock cohesion and internal friction angle, which are the grid search algorithm and the Mohr failure line method. The results show that the grid search algorithm guarantees the best performance of the failure criteria, providing the best-fit rock parameters. The more practical method of the Mohr failure line can also generate reasonable predictions if a safety factor of 1.1 is considered. Both methods show that Modified Lade is the failure criterion that provides the best performance in predicting rock failure under dynamic loading. In the petroleum industry, most of the activities causing dynamic loading of the wellbore are characterized by a magnitude of strain rate lower than 10(0)/s (even lower than 10(-3)/s). Consequently, this work shows that it is reasonable to assume that the commonly used static failure criteria, especially Modified Lade, could be selected to analyze wellbore stability under dynamic loading conditions effectively.",5,5,5
Triaxial Compression,,"Alsuwaidi, Erhamah S.; Xi, Guifen; Zimmerman, Robert W.",Mechanical characterization of Laffan and Nahr Umr anisotropic shales,Shale; Anisotropy; Jaeger plane of weakness; Offshore Abu Dhabi,,"Geomechanics-related wellbore instability has become a major source of non-productive time in highly deviated wells drilled in oil and gas fields in offshore Abu Dhabi. These wells are drilled through two highly anisotropic shale formations, namely the Laffan shale formation and the Nahr Umr shale formation. Most of the models used in the oil and gas industry do not account for the strength and elastic anisotropy of shale. Therefore, a laboratory study was conducted to examine the strength and elastic anisotropy of shales using uniaxial compression tests and triaxial compression tests. Jaeger's Plane of Weakness (JPW) model was used to understand the anisotropic failure behavior of highly laminated shales of the Laffan and Nahr Umr formations. This model assumes that for an anisotropic rock, there exists a plane of weakness that has strength properties (cohesion and angle of internal friction) different than the strength properties of the intact rock. By minimizing the Root Mean Square Error (RMSE), the experimental strength values of the samples, as measured at different orientations, were fitted to the JPW model. Elastic moduli were also measured on these shales, as a function of orientation angle. The results showed that the moduli vary with angle according to the expected tensor transformation law. Therefore, the transverse isotropy assumption is a reasonable model to be used when dealing with these laminated sedimentary rocks.",4,4,7
Triaxial Compression,,"Liang, Mingliang; Wang, Zongxiu; Zhang, Yu; Greenwell, Christopher H.; Li, Huijun; Yu, Yuxi; Liu, Shengxin",Experimental investigation on gas permeability in bedding shale with brittle and semi-brittle deformations under triaxial compression,Gas permeability; Shale; Triaxial compression; Stress-strain; Brittle/ semi-brittle deformation,FLUID TRANSPORT PROCESSES; LONGMAXI FORMATION SHALE; ORGANIC-RICH SHALE; BARNETT SHALE; PORE STRUCTURE; ANISOTROPIC PERMEABILITY; PETROPHYSICAL PROPERTIES; FRACTURE PERMEABILITY; CONFINING PRESSURE; DUCTILE TRANSITION,"This study investigates the stress-strain behavior, failure deformation, and change of gas permeability in shale under compressive stress induced failure. The study is based on triaxial compression of shale from Lower Silurian Longmaxi Formation, South China at different angle of bedding planes. It was found that shale behaves as a brittle materials and exhibits brittle and semi-brittle response to peak strength load at different angles of pre-exist bedding during stress compression. The gas permeability increased after failure deformation for all shale samples. However, samples under vertical and horizontal bedding angles exhibited brittle deformation and significant increase in permeability. While the samples with bedding angles of 30 degrees and 60 degrees showed semi-brittle deformation, and the permeability increased slightly after failure. These results indicate that the pre-existing structure influences the mechanical behavior of shale, which consequently affects its gas permeability. The results of this study are of great significance in shale gas exploration and development in areas of South China which has complex tectonic and pre-existing foliation structures.",3,3,9
Calcium Carbonate,,"Rashidi, Mohammadamin; Kalantariasl, Azim; Saboori, Rahmatallah; Haghani, Abdolhossein; Keshavarz, Alireza",Performance of environmental friendly water-based calcium carbonate nanofluid as enhanced recovery agent for sandstone oil reservoirs,Wettability alteration; EOR; Calcium carbonate; Nanofluid; Sandstone,SURFACE-ENERGY CHARACTERIZATION; WETTABILITY ALTERATION; INTERFACIAL-TENSION; NANOPARTICLES; NANOCOMPOSITE; TEMPERATURE; SIO2; STABILIZATION; INHIBITION; FORCES,"Recent studies have demonstrated great potential of nanofluids as enhanced oil recovery (EOR) agent. Many mechanisms behind increasing oil recovery inducing alteration of surface wettability toward more water wet have been proposed when displacing oil by nanofluids. In this study, the effect of calcium carbonate nanofluid on wettability alteration of sandstone rock samples was studied. Nanoparticle was synthesized by chemical precipitation method and characterized by X-ray diffraction (XRD), fourier-transform infrared spectroscopy (FTIR), field emission scanning electron microscope (FE-SEM) and dynamic light scattering (DLS). The average particle size of nanoparticles was 55.4 nm. The rock samples were aged in oil to ensure desired oil-wet conditions. The effects of nanofluid concentration and temperature on wettability change were investigated and optimum concentration of calcium carbonate nanofluid was determined. Adsorption of nanoparticles on rock surface was characterized by FE-SEM. The wettability alteration was evaluated by measuring/calculating contact angle (static, advancing and receding), surface energy, liquid area fraction, and wettability index. 2-D oil-wet glass micromodel was used to compare the performance of optimum nanofluid concentration obtained from wettability tests against normal water flooding. Results showed alteration of wettability from oil-wet to water-wet for all nanofluid concentrations. More wettability alteration was observed at higher temperature (80 degrees C) than ambient conditions (25 degrees C). Optimum nanofluid concentration (0.025 wt%) was obtained that changed contact angle from 116.41 degrees (non-treated surface) to 46.99 degrees at 25 degrees C and 28.7 degrees at 80 degrees C. Flooding oil-wet 2-D glass micromodel with optimum nanofluid concentration resulted in 20% additional ultimate recovery factor compares to normal water flooding.",5,5,6
Calcium Carbonate,,"Mahmoudpour, Maziar; Pourafshary, Peyman",Investigation of the effect of engineered water/nanofluid hybrid injection on enhanced oil recovery mechanisms in carbonate reservoirs,Engineered water; Nanoparticle; Microemulsion; Wettability alteration; Enhanced oil recovery,DETERMINING IONS CA2+; WETTABILITY ALTERATION; WATER INJECTION; CHALK; SALINITY; SEAWATER,"Changing the salinity and ionic composition of the injected water and designing ""engineered water"" (EW) is an enhanced oil recovery approach which affects the wettability of carbonate reservoirs and improves the oil recovery in many cases. Application of nanoparticles also affects oil production by various mechanisms such as altering the wettability, changing the viscosity of the oil and the injected fluid, and changing the interfacial tension. The benefits of combining these two approaches and developing a hybrid method are investigated in this paper. Experiments and measurements of different characteristics such as contact angle, zeta potential, particle size, ATR (attenuated total reflectance) analysis, ESEM (environmental scanning electron microscope) imaging, ion/nanoparticle deposition, and microemulsion formation were completed to analyze the influence of the hybrid method on rock/oil/brine interactions. Core flooding tests were also conducted to study the performance of the method to improve oil recovery. The most effective EW was selected by adjusting the concentrations of magnesium, calcium, and sulfate ions of Persian Gulf water. Nanoparticles such as SiO2, CaCO3, TiO2, and gamma Al2O3 were also studied to achieve the longest stability. Finally, the effect of combining the optimum states of engineered brine and nanoparticles on different mechanisms was investigated. Our results showed that spiking the injection brine with sulfate ions and using a hybrid method with silica nanoparticles at a concentration of 0.1 wt% provided the best effect on the enhanced oil recovery. This combination altered the wettability more than standalone methods. Also, there was a decrease in adsorption of nanoparticles on the rock surface, which controls the retention mechanism. Therefore, the presence of more nanoparticles in the fluid flow leads to the formation of microemulsions and increases in the viscosity of the injected fluid, which affects the sweep efficiency in porous media.",5,5,0
Calcium Carbonate,,"Jani, Priyesh; Imqam, Abdulmohsin",Class C fly ash-based alkali activated cement as a potential alternative cement for CO2 storage applications,Fly ash geopolymer cement; CO2; Portland cement,,"Long-term storage of carbon dioxide (CO2) inside depleted reservoirs can help reduce the impact of greenhouse gas emissions. Portland cement has been shown to degrade significantly during long-term contact with CO2. This research aims to provide a new environmentally friendly, Class C fly ash-based cement as a potential alternative to Portland cement for CO2 storage wells. This was achieved by comparing the mechanical degradation of Portland cement and Class C fly ash-based alkali-activated cement in a CO2 environment. A specially designed setup was constructed to create an in situ high pressure and high-temperature CO2 environment. Seventy-two cores of Portland cement and Class C fly ash-based cement were prepared for this study. The results show that CO2 reacted with the water in the vessel and formed carbonic acid, which reduced the water pH to 6.8. Millimeter-sized crystals of calcium carbonate (CaCO3) were observed on the surface of the Portland cement cores after the CO2 exposure. The surface of the fly ash-based alkali-activated cement cores was not substantively changed after the exposure. No significant change in density was observed for both types of cement during the 14 days of CO2 exposure. Portland cement showed a significant reduction in compressive strength, and this reduction developed as the exposure time increased. Interestingly, Class C fly ash-based cement showed no reduction in compressive strength, and only a small amount of reduction was observed after 14 days of exposure. This research compared the mechanical degradation of Portland cement and Class C fly ash-based alkali-activated cement in a high-pressure and high-temperature CO2 environment.",3,3,9
Calcium Carbonate,,"Shaik, Imran K.; Zhang, Linqi; Pradhan, Sushobhan; Kalkan, A. Kaan; Aichele, Clint P.; Bikkina, Prem K.",A parametric study of layer-by-layer deposition of CaCO3 on glass surfaces towards fabricating carbonate reservoirs on microfluidic chips,Geomaterial coating; Calcium carbonate polymorphs; Calcite; Aragonite; Vaterite,CALCIUM-CARBONATE; OIL-RECOVERY; PORE SCALE; SUBSURFACE ENERGY; VATERITE; SALINITY; TRANSFORMATION; MICROMODELS; TRANSITION; MORPHOLOGY,"Recently, geomaterial-functionalized microfluidic chips have been receiving increased attention as they facilitate material representation to mimic surface mineralogy in addition to direct visualization and quantification of multiphase flow and transport processes in a porous media. In particular, calcite-coated glass surfaces have been used to mimic the solid-fluid interactions involved in carbonate reservoirs. The coating procedure usually involves the deposition of calcium carbonate layers on a functionalized glass surface. Depending upon experimental conditions, the deposited calcium carbonate could be one or more of the three polymorphs: calcite, vaterite, and aragonite. Hence, it is essential to analyze and control the formation of the desired calcium carbonate polymorph. In this study, we transformed glass surfaces into carbonate surfaces by growing calcium carbonate particles in-situ using a layer-by-layer deposition procedure. The influences of process parameters involved in the deposition procedure on the formation of calcium carbonate polymorphs were analyzed. The parameters evaluated were: initial glass surface cleaning phase - DI water, plasma, piranha and NaOH as substrate cleaners; surface functionalization phase - DI water and chloroform as silane solvents; and calcite crystals growth phase - effect of number of coating cycles and concentration of CaCl2 and Na2CO3 solutions on the coating. After CaCO3 deposition, strategies to transform kinetically favorable vaterite to thermodynamically stable calcite are discussed. Coating uniformity, morphology, elemental atomic percentage of coating, and the CaCO3 polymorphs were examined by optical microscopy, Scanning Electron Microscopy (SEM), SEM Energy Dispersive X-Ray Spectroscopy (SEM EDS), and Raman spectroscopy, respectively.",3,3,3
Lattice Boltzmann,,"Zhao, Wen; Jia, Chengzao; Jiang, Lin; Zhang, Tao; He, Minxia; Zhang, Fan; Jiang, Zhenxue; Li, Xiangfang; Wu, Keliu","Fluid charging and hydrocarbon accumulation in the sweet spot, Ordos Basin, China",Tight gas reservoir; Fluid charging; Hydrocarbon accumulation; Sweet spot; Lattice Boltzmann,,"Although significant progress has been made in the tight gas exploration and development, there is still a limited understanding of the fluid charging and hydrocarbon accumulation in the sweet spot. In this study, a novel method is proposed to generate the stochastically constructed porous media which represents the transition region between tight surrounding sandstone and sweet spot. Based on the constructed porous media, the fluid charging and hydrocarbon accumulation processes of the tight reservoir are simulated by the lattice Boltzmann method (LBM). The numerical simulation results show that, although a piston-like pattern can be observed in field-scale simulation or laboratory experiments, at the micro-scale, due to the inherent heterogeneity of the porous media, the fluid charging pattern tends to be fingering-like. The existence of the transition region between tight surrounding sandstone and sweet spot becomes a water-bearing gas layer or even gas-bearing water layer at the top/bottom of the gas layers (sweet spot). The existence of fractures is favorable for hydrocarbon charging into the reservoir rocks, but not for the hydrocarbon accumulation due to the gas escaping through the fractures. Combined with well logging interpretation results, three typical water bodies (isolated water body, water body at the top, or bottom of the gas layer) are identified from the view of fluid charging and hydrocarbon accumulation.",6,6,3
Lattice Boltzmann,,"Jiang, M.; Xu, Z. G.; Zhou, Z. P.",Pore-scale investigation on reactive flow in porous media considering dissolution and precipitation by LBM,Dissolution and precipitation; Porous media; Lattice Boltzmann method; Volume of pixel; Multicomponent,LATTICE-BOLTZMANN; BOUNDARY-CONDITIONS; NATURAL-CONVECTION; 2-PHASE FLOW; SHALE; PERMEABILITY; SIMULATION; CO2; PARTICLES; EVOLUTION,"The reactive transport process in oil gas reservoirs is complicated due to the coupling between dissolution and precipitation. In the present study, based on lattice Boltzmann method, the coupled dissolution and precipitation process in randomly generated porous media by quartet structure generation is investigated at the scale of geological pores. The fluid velocity, temperature and concentration in porous media are solved by multicomponent flow lattice Boltzmann model, multicomponent thermal lattice Boltzmann model and mass transport lattice Boltzmann model, respectively. The solid phase is updated by volume of pixel method. The results show that the dissolution reaction rate has a positive impact on the consumption of reactants. For different precipitation reaction rates, there exists an optimal value resulting in abundant precipitate and sparse solid distribution. Reaction equilibrium constant affects reaction rates slightly but influence the solid morphology heavily. The coupled dissolution and precipitation process accelerates with the increase of Peclet number, but the precipitate produced increases with the decrease of Peclet number.",4,4,13
Lattice Boltzmann,,"Wang, Fenglan; Liu, Tong; Lei, Wenhai; Zhao, Yu; Li, Binhui; Yang, Guang; Liu, Yang; Wang, Moran",Dynamic analysis of deformation and start-up process of residual-oil droplet on wall under shear flow,Residual-oil droplet; Start-up process; Dynamic analysis; Shear flow; Lattice Boltzmann modeling,,"This study focuses on the dynamic process of deformation and start-up of an oil droplet on a wall driven by an external shear flow. A mesoscopic numerical method is developed based on the lattice Boltzmann framework for multiphase coupled with the color-gradient model. After validations of the numerical method, we performed force analyses based on the flow field, considering the pressure difference and the shear stress inside the droplet simultaneously. It was intriguing to find that the shear stress is a driving force instead of a resistance due to the interesting phenomenon that a vortex was formed inside the droplet and the direction of reaction shear stress acted by solid wall accorded with the direction of the start-up. A force-balance model was established on the basis of the force analyses to predict the yield criteria in terms of the critical capillary number and pressure difference. Finally, by comparing the flow field before and after the start-up of the droplet, it was found that the proportion of the wall applying shear driving force decreases but the values of the shear stress increase significantly after the start-up compared to before the start-up.",4,3,3
Time Consuming,,"Rashidi, Sina; Mehrad, Mohammad; Ghorbani, Hamzeh; Wood, David A.; Mohamadian, Nima; Moghadasi, Jamshid; Davoodi, Shadfar",Determination of bubble point pressure & oil formation volume factor of crude oils applying multiple hidden layers extreme learning machine algorithms,Oil formation volume factor; Bubble point pressure; Multi-layer extreme learning machine; Hybrid machine learning algorithms; Least squares support vector machine,SUPPORT VECTOR MACHINE; SHEAR-WAVE VELOCITY; PVT PROPERTIES; CORRELATION-COEFFICIENTS; RELATIVE PERMEABILITY; RESERVOIR; PREDICTION; MODEL; SYSTEMS; PERFORMANCE,"An important requirement of reservoir management is to understand the properties of reservoir fluids and dependent phase behaviors. This makes it possible to determine the properties of reservoir fluids in laboratory pressure-volume-temperature (PVT) tests. Such laboratory tests are costly and time consuming, and reservoir data are sometimes not available. When estimating the in-place fluid volumes and/or designing enhanced recovery processes information on bubble point pressure (BPP) and oil formation volume factor (OFVF) is required. Predicting these two parameters is therefore one of the priorities of reservoir engineers. It is becoming increasingly beneficial to be able to predict BPP and OFVF with efficient machine-learning algorithms based on underlying variables that are more easily measured directly in the field. In this study, a dataset of 638 data records of published crude oil fluid samples from around the world is evaluated. After filtering the dataset for outliers, 591 data records for BPP and 599 datasets for OFVF are evaluated with efficient hybrid machinelearning algorithms (multi-layer extreme learning machine ?MELM? and least squares support vector machine ? LSSVM) optimized using a genetic algorithm ?GA? and a particle swarm optimizer ?PSO? to improve their prediction performance. Four underlying variables are considered for each data record: temperature (T), solution gas oil ratio (Rs), gas specific gravity (?g) and oil gravity (API). The PSO- MELM-PSO hybrid algorithm achieved the highest prediction accuracy measured in terms of root mean square errors (RMSE) of 33.5 psi for BPP and 0.0199 for OFVF. The four-hybrid machine-learning-optimization algorithms evaluated all outperform the empirical relationships used for many decades in the oil industry to predict BPP and OFVF.",11,11,1
Time Consuming,,"Soleymanzadeh, Aboozar; Kaj, Parvin Kolah; Kord, Shahin; Monjezi, Masood",A new technique for determining water saturation based on conventional logs using dynamic electrical rock typing,Saturation exponent; Formation resistivity factor; Resistivity index; Resistivity log,PERMEABILITY; EXPONENT,"Fluid saturation in a hydrocarbon reservoir is the most significant parameter in evaluating reservoir resources. The possibility of developing a field completely depends on hydrocarbon saturation, which is normally obtained by well-known Archie's equations. Accurate determination of the hydrocarbon saturation depends on the precise estimation of the Archie's parameters, i.e. cementation factor, tortuosity factor and saturation exponent (n). Among these three parameters, experimental determination of saturation exponent is time consuming and expensive which is performed on a limited number of core samples. Although numerous correlations and methods have been presented for predicting the saturation exponent of the Archie's equation, most of them did not consider physics of electricity transmission through the pore structure of the rock. Classification of the reservoir rocks into distinct groups with the same electrical behavior can improve the precision of saturation estimation. In this paper, a new technique was presented to classify rock samples into distinct electrical rock types based on a recently defined parameter which was called dynamic electrical efficiency (eta(ele.D)). Previously, Soleymanzadeh et al. suggested a method of electrical rock typing in water zone on the basis of static electrical efficiency (eta(ele,s)). In fact, the present paper is an extension of Soleymanzadeh et al. work to apply in the hydrocarbon zone. According to the proposed method of electrical rock typing, all the rock samples with the same functionality with respect to the dynamic electrical efficiency, i.e. (eta(ele,D))(1/n), constitute an individual electrical rock type. Indeed, all the core samples with the same value of (eta(ele,D))(1/n) lie on a straight line with the slope of one in the log-log plot of S-wi versus 1/eta(1/n)(ele,s). Using this method, water saturation can be estimated throughout the reservoir depth without the need to determine saturation exponent at any depth. In order to verify the new proposed technique, electrical data from 25 core samples were used which were categorized into four distinct classes on the basis of the proposed method of electrical rock typing. High value of determination coefficients and slopes near the one confirmed the application of the proposed method. Hence, it was concluded that dynamic electrical efficiency is an appropriate tool for classifying electrical data into distinct electrical rock types. This rock typing approach and correlations between electrical core data and well log data at cored depths can be used to predict initial water saturation at uncored depths. In fact, the findings of this study can help to improve the precision of the estimation of the hydrocarbon in place.",5,5,1
Time Consuming,,"Jiang, Yun; Xu, Guoqing; Bi, He; Shi, Yang; Gao, Ying; Han, Xiuling; Zeng, Xinghang",A new method to determine surface relaxivity of tight sandstone cores based on LF-NMR and high-speed centrifugation measurements,Tight sandstone cores; Surface relaxivity; LF-NMR; High speed centrifugation; T-2 cut-off value,NUCLEAR-MAGNETIC-RESONANCE; PORE-SIZE; CAPILLARY-PRESSURE; RELAXATION; ADSORPTION; RECOMMENDATIONS; DISTRIBUTIONS; PERMEABILITY; POROSITY; SYSTEMS,"Low-field nuclear magnetic resonance (LF-NMR) T-2 spectrum commonly is converted into pore size distribution (PSD) with accurate calculation of surface relaxivity. Currently, the surface relaxivity for unconventional cores is determined indirectly using average pore radius (ARS) method or surface-to-volume ratio (SVR) method. The ARS method is time consuming, and inevitably it causes permanent damage to core samples because of the injection of mercury. In this study, we proposed a new method, the pseudo T-2 cut-off (PTC) method, instead of the ARS method to calculate the surface relaxivity of tight sandstone core samples by correlating a PTC value with the corresponding pore radius. First, we performed LF-NMR and high-speed centrifugation (HSC) measurements on four tight sandstone core samples to determine surface relaxivity using the PTC method. Then, we compared the calculated surface relaxivity using the new method with that determined using the ARS and SVR methods. Then, we converted the T-2 spectrum into PSD using appropriate surface relaxivity. Finally, we obtained residual oil distribution. The results showed that we had established an exponential correlation between the PTC value and surface relaxivity. Ultimate surface relaxivity values for tight sandstone core samples were 5.85, 2.98, 4.66, and 2.17 mu m/s. The values of rho(ARS) and rho(PTC) were close but generally larger than that of rho(SVR). We still observed a linear correlation between illite content and different surface relaxivity. Moreover, we obtained PSD in mesopores and macropores by jointly using rho(PTC) (or rho(ARS)) and rho(SVR). After centrifugation, the residual oil (62.94 wt%) was mainly distributed in the micropores (similar to 20 wt%) and mesopores (similar to 35 wt%). This study provided a nondestructive method to determine the surface relaxivity of tight sandstone cores and provided information for residual oil distribution.",3,3,2
Nanoscale Pore Structure,,"Wang, Yang; Cheng, Hongfei; Hu, Qinhong; Liu, Luofu; Jia, Langbo; Gao, Shasha; Wang, Ye","Pore structure heterogeneity of Wufeng-Longmaxi shale, Sichuan Basin, China: Evidence from gas physisorption and multifractal geometries",Multifractal; Heterogeneity; Connectivity; Gas adsorption; Pore structure; Isolated organic matter,METHANE ADSORPTION; ORDOS BASIN; ORGANIC-MATTER; N-2 ADSORPTION; FE-SEM; POROSITY; INSIGHTS; MARINE; AREA; MATURATION,"Understanding the heterogeneity of the nanoscale pore structure is critical for assessment of hydrocarbon flow and storage in porous reservoirs. Multifractal theory is a powerful method to acquire the detailed heterogeneity information of the multiple pore system. The generalized dimension spectrum and singularity spectrum are two forms to depict the multifractal feature. Hurst exponent (H) and the width of singularity spectrum (Delta alpha) are two parameters to effectively assess the pore connectivity and heterogeneity, respectively. In this study, multifractal analysis was performed on over-mature Wufeng-Longmaxi shales and their corresponding isolated organic matter (OM) via gas physisorption (CO2 and N-2) test to ascertain the pore heterogeneity and its governing factors. Micropore (diameter<2 nm) structure in bulk shale contains stronger pore heterogeneity but weaker connectivity than meso-macropore (diameter = 2-100 nm) structure. The comparison of heterogeneity features of shale versus its isolated OM reveals that micropore associated with minerals could enhance the micropore heterogeneity in bulk shale, while meso-macmpore existing in minerals could reduce the meso-macmpore heterogeneity in bulk shale. Besides, the total organic carbon content has a positive effect on the micropore heterogeneity. The micropore and meso-macmpore volume have a certain impact on the pore heterogeneity in the corresponding pore size ranges. Compared with the low-mature Bakken shale, the over-mature Wufeng-Longmaxi shale contains the stronger micropore heterogeneity but weaker meso-macmpore heterogeneity, where less difference between the micropore and meso-macropore heterogeneities was also observed. We deduced that the whole shale pore spectrum likely tends to be homogeneous along with the OM thermal maturation.",7,7,26
Nanoscale Pore Structure,,"Bai, Jiajia; Kang, Yili; Chen, Mingjun; Li, Xiangchen; You, Lijun; Chen, Zhangxin; Fang, Dazhi",Impact of water film on methane surface diffusion in gas shale organic nanopores,Surface diffusion; Gas coverage rate; Organic nanopores; Water film; Methane-water interface,PEROXIDE PRESOAKING PRIOR; ADSORPTION BEHAVIOR; TRANSPORT BEHAVIOR; UNCONVENTIONAL GAS; ANALYTICAL-MODEL; VAPOR SORPTION; PORE STRUCTURE; PRESSURE; FLOW; PERMEABILITY,"When a shale pore radius is less than 10 nm, the contribution of surface diffusion to methane transport in shale multiscale pore structure will significantly increase. It is critical to understand whether the adsorbed water film in shale nanoscale organic pores is beneficial to multiscale methane transport. Thus, a model considering the effect of a water film on methane surface diffusion is established. Furthermore, the influences of a water film on different diffusion mechanisms are discussed. The results show that, first, when water molecule enters shale organic pores, an adsorption interface changes from gas-solid to gas-water, i.e., the fractional surface coverage of gas in the surface increases so the surface diffusion ability increases; second, when a pore radius is less than 6 nm, the overall diffusion capacity of methane in pores increases, even though a water film can decrease the slip flow and Knudsen diffusion. However, when a pore radius is 8-10 nm, the apparent permeability (K-app) increases with pressure. Since a pore surface contains a water film, K-app is not always greater than that for a pore surface without water film. Our investigation shows that the impact of fracturing fluid retention in shale multiscale pore structure is not always negative for methane multiscale transport if the volume of a fracturing fluid and shut-in time are reasonable.",6,7,11
Nanoscale Pore Structure,,"Xu, Liangwei; Yang, Keji; Zhang, Lifei; Liu, Luofu; Jiang, Zhenxue; Li, Xiao","Organic-induced nanoscale pore structure and adsorption capacity variability during artificial thermal maturation: Pyrolysis study of the Mesoproterozoic Xiamaling marine shale from Zhangjiakou, Hebei, China",Xiamaling marine shale; Artificial thermal maturation; Anhydrous pyrolysis; Nanoscale pore structure evolution; Methane adsorption capacity; Evolution model,NORTHEASTERN BRITISH-COLUMBIA; NANOMETER-SCALE PORES; TIGHT GAS-RESERVOIR; METHANE ADSORPTION; HYDROUS-PYROLYSIS; II KEROGEN; CONTINENTAL SHALE; LOWER TOARCIAN; OIL-EXPULSION; SURFACE-AREA,"This research analyzed two low-maturity Mesoproterozoic Xiamaling marine shale samples with different TOC contents in Zhangjiakou of Hebei, China. Artificial anhydrous pyrolysis experiment simulated the thermal evolution process of the shale sample from low maturity to over maturity. The evolution characteristics of geochemical parameters and mineralogy of shales with the increase in maturity were investigated. A general evolution model of nanoscale pore structure and methane adsorption content (MSC) was established. Results show that hydrocarbon generation and mineral conversion promote the generation, development, combination, and rearrangement of nanoscale pores in shale samples with the increase in thermal maturation. The maturity increase helps facilitate the generation and evolution of pores in shales. Heating can promote the generation, development, and evolution of nanoscale pores, and this condition can contribute to forming large pore volume and surface area. The formation and evolution of the nanoscale pores in shale can be roughly subdivided into adjustment, development, combination, and rearrangement stages. Nanoscale pore structure parameter and MSC decrease and reach the minimum value as the temperature reaches 350 ?C in the adjustment stage. Then, they rise and reach the maximum value at approximately 650 ?C during the development stage. Finally, they decline again as the pyrolysis temperature rises at the combination and rearrangement stages. The general evolution model of nanoscale pore structure and MSC was proposed and subdivided into three stages by combining the hydrocarbon generation, mineral conversion, nanoscale pore structure, and MSC evolution of the thermal simulation shale samples. The differences in organic geochemical index, mineral characteristics, nanoscale pore structure, and MSC evolution characteristics of the simulated samples are mainly due to the difference in their TOC content.",3,3,5
Internal Gradient,,"Elsayed, Mahmoud; El-Husseiny, Ammar; Kadafur, Ibrahim; Mahmoud, Mohamed; Aljawad, Murtada Saleh; Alqubalee, Abdullah",An experimental study on the effect of magnetic field strength and internal gradient on NMR-Derived petrophysical properties of sandstones,Sandstone; Clays; Magnetic field strength; Internal gradient; T-2 relaxation time; NMR,LATTICE-RELAXATION MEASUREMENTS; PORE-SIZE DISTRIBUTIONS; SATURATED POROUS SOLIDS; RESONANCE; DIFFUSION; RESERVOIR; QUANTIFICATION; PERMEABILITY; DEPENDENCE; POROSITY,"Nuclear Magnetic Resonance (NMR) is being widely deployed as a powerful tool for estimating petrophysical properties. Compared to conventional carbonate reservoirs, sandstone reservoirs contain a high amount of paramagnetic ions (such as iron, nickel, or manganese) usually found in clays. The interpretation of NMR-derived petrophysical properties for sandstone formation can be complicated due to the paramagnetic ions which cause inhomogeneity in the magnetic field called internal gradient. Earlier studies focused on investigating the impact of clays and field strength on internal gradient, but implications for estimating NMR-derived petrophysical properties are not well understood yet. This study aims to investigate the impact of the internal gradient and magnetic field strength on the T-2 relaxation times and the NMR-derived porosity, T-2 logarithmic mean value (T-2, LM), and permeability. NMR T-2 measurements at several echo times were performed to evaluate the internal gradient for six sandstone samples characterized by variable porosity, permeability, and clay contents/mineralogy. The analysis was executed at two different operating Larmor frequencies (2 and 12 MHz), which are the most common frequencies for rock core analysis. The results show that the internal gradient magnitude increases with the increase of the paramagnetic-rich clays (Chlorite and Illite in the studied samples) while no correlation is observed with Kaolinite content. Furthermore, the internal gradient's magnitude and effect are consistently more pronounced at the 12 MHz measurements than those performed at 2 MHz. Porosity estimates from NMR are found to be independent of the internal gradient and the magnetic field strength as long as sufficiently low echo time (0.2 ms) is used. Unlike porosity, noticeable discrepancies in T-2,T-LM were reported between 2 MHz and 12 MHz measurements, with the later showing consistently lower T-2,T-LM values. The discrepancies in T-2,T-LM values result in significant differences (up to 300%) when calculating NMR-derived permeability using the same formulations for both 2 and 12 MHz data. That is, calibration done using the T2 data from 12 MHz equipment cannot be applied for permeability estimation from lower field NMR data (like logging NMR). The discrepancies between 2 and 12 MHz in terms of T-2,T-LM and derived-permeability increase exponentially as the internal gradient increases but such discrepancies diminish for tight rocks (permeability < 1 mD). This behavior of the tight sandstone samples is attributed to the relaxation regime, which is impacted by pore sizes. If pores are small enough, such as the case occasionally for shale or tight sandstone, relaxations move from a short time regime to the motionally averaged. In such a regime, the internal gradient is averaged by diffusion over the length scale, meaning that relaxation time has no dependence on echo time.",7,7,2
Internal Gradient,,"Cui, Yingzhi; Shikhov, Igor; Li, Rupeng; Liu, Shitao; Arns, Christoph H.",A numerical study of field strength and clay morphology impact on NMR transverse relaxation in sandstones,Kaolinite model; NMR transverse relaxation; Relaxation regime,PORE-SIZE DISTRIBUTIONS; MAGNETIC-FIELD; NUCLEAR MAGNETIZATION; POROUS-MEDIA; DIFFUSION; GRADIENTS; DECAY; PERMEABILITY; IMAGE; TIMES,"Nuclear magnetic resonance (NMR) relaxometry is a common technique for the petrophysical characterization of sedimentary rocks. The standard interpretation of NMR transverse relaxation responses is based on the assumptions of the fast diffusion limit, dominant surface relaxation, and weak coupling between pores, allowing an interpretation of the NMR response as pore size distribution. In general, three asymptotic relaxation regimes can be defined by comparing dephasing, structural and diffusion length scales. The shortest length scale defines the dominating relaxation regime, which is either the free diffusion, motional averaging, or localization regime. Complex mineralogy and morphology of rocks, especially due to clay minerals, may lead to the co-existence and coupling of multiple relaxation regimes in the presence of surface relaxivity heterogeneity and internal gradient effects. In this work the relationship between morphology of rocks, strength of applied magnetic field, resulting relaxation regimes and observed NMR relaxation responses is studied numerically. Limitations in the discretization of clays typical for micro-CT images are addressed by introducing a fine-scale kaolinite model based on SEM images. The model is utilized to evaluate the field-dependent mean transverse relaxation time and effective diffusion coefficient of clay regions. These effective parameters are incorporated into random-walk simulations on micro-CT images. Relaxation regimes are analysed spatially for three different types of sandstone as function of external magnetic field strength. Increase of paramagnetic clay content, field strength and echo-time increases the fraction of spins relaxing in the localization regime within macro-pores, typically being localised in the regions neighbouring clay pockets and grain surfaces. We demonstrate that a significant contribution of the localization regime to relaxation may lead to incorrect predictions of pore-size distributions and fluid typing. The prefactor of permeability correlations varies significantly due to clay effects. Accounting for these effects should enable more robust petrophysical interpretations.",5,5,6
Other topics ,,"Radwan, Ahmed E.; Trippetta, Fabio; Kassem, Ahmed A.; Kania, Maciej","Multi-scale characterization of unconventional tight carbonate reservoir: Insights from October oil filed, Gulf of Suez rift basin, Egypt",Porosity; Source rock; Carbonate; Reservoir; Eocene; Unconventional resource; Petrophysical evaluation; Tight carbonates,JURASSIC ARAB-D; CENTRAL SAUDI-ARABIA; HAMMAM FARAUN FAULT; WELL LOG DATA; PETROPHYSICAL PROPERTIES; PORE STRUCTURE; BADRI FIELD; DIAGENETIC ALTERATIONS; PETROLEUM RESERVOIRS; SANDSTONE RESERVOIRS,"The thick Eocene carbonate deposits that are newly ascribed as Radwany Formation (previously Thebes Formation) in the October basin within the Gulf of Suez region, are of particular interest for hydrocarbon exploitation. However, no efforts have been directed to investigate their petrophysical characteristics and pore system. This study aims to investigate the petrophysical characteristic, pore system and formation potentiality as a reservoir rock. Thirteen sidewall core samples and sixty thin sections from OCT-X well were studied in order to investigate the lithological characteristics, porosity network. In addition, well logging data and petrophysical and geochemical laboratories measurements including Nuclear Magnetic Resonance (NMR) porosity technique were used to define the petrophysical characteristics. The investigated work revealed that: 1) the pore system is a combination of depositional and diagenetic processes. 2) the dominant porosity types include fracture, interparticle, intra-particle and moldic porosity; NMR indicates mesopores to macropores, 3) petrophysical evaluation and geochemical analysis indicates a self-sourced unconventional reservoir based on its organic richness characteristics unconventional resource opportunity as tight carbonate reservoir, 4) the basal part of the Radwany Formation has a high potential to store hydrocarbon, and it is a potential conventional resource. 6) The linking trends between the petrophysical parameters with sediment microfacies were defined in the studied section, where a significant increasing trend line has been inferred in the direction from wackestone microfacies to packstone microfacies. Finally, the diagenetic process through time has greatly controlled the petrophysical parameters of the Rad-wany Formation. The gap between Source and Reservoir rocks has been defined based on integrated geochemical and petrophysical characteristics. The studied section has unique multiscale characterization as unconventional and conventional resource.",28,28,12
Other topics ,,"Zhu, Hongjun; Gao, Yue; Srinil, Narakorn; Bao, Yan",Mode switching and standing-travelling waves in slug flow-induced vibration of catenary riser,Catenary riser; Slug flow; Flow-induced vibration; Mode switching; Standing wave; Travelling wave,VORTEX-INDUCED VIBRATIONS; HANGING FLEXIBLE RISER; 2-PHASE FLOW; LABORATORY MEASUREMENTS; CYLINDER; PIPE; FLUID,"An experiment in a small-scale air-water test loop is performed to investigate the flow-induced vibration behaviors of a flexible catenary riser conveying slug flow over a wide range of the gas-to-liquid flow rate ratios from 1.0 to 4.5. The clamped-clamped riser model has an inner diameter of 4 mm and an aspect ratio with the length over the inner diameter of about 360. The non-intrusive high-speed cameras are employed to simultaneously capture the catenary riser dynamics and the internal unsteady slug flow characteristics. The space-time varying features of the slug flow-induced vibration are presented and discussed in terms of the response amplitudes, frequencies, modal components, and associated flow-induced forces. Slug flow properties including the translational velocities, lengths, fluctuation frequencies and pressure changes are reported. When increasing the ratio of the gas-to-liquid flow rates, experimental results highlight how a variation of the slug length and frequency contributes to a mode-switching phenomenon over time. This switching from the dominant first-mode frequency to the second-mode frequency leads to the associated transition from the standing wave to the travelling wave of the catenary riser response. The response amplitudes are amplified by the increased translational velocity and slug length, entailing the increased flow-induced momentum and gravitational forces, as the gas-to-liquid flow rate ratio is increased. Consequently, higher vibration modes participate into the riser dynamics exhibiting a strong multi-mode competition.",7,7,12
Other topics ,,"Liu, Weiji; Zhu, Xiaohua; Lv, YanXin; Tong, Hua",On the mechanism of thermally induced micro-cracking assisted rock cutting in hard formation,Rock cutting; Deep and geothermal formation; High temperature; High confining pressure; Heterogeneous,DISCRETE ELEMENT; HIGH-TEMPERATURE; SIMULATION; FAILURE; STRENGTH; BEHAVIOR; TESTS; COMPRESSION; PRESSURE; DUCTILE,"Low rate of penetration (ROP) and high drilling costs are the severe problems encountered in hard formation drilling, which heavily limit the efficient exploitation of oil and gas resources. In present study, a rock cutting model of granite using PFC2D-GBM, which considers the confining pressure, hydrostatic pressure, temperature, inter-grain and intra-grain contact failures, rock heterogeneities, is carried out to explore the mechanism of thermally induced cracking assisted rock cutting in hard formation. The research results show that, with the temperature increasing, the micro-cracks, mainly the inter-grain cracks, will be induced in intact rock due to the unequal expansion of grains. The thermally induced crack number increases linearly with increasing the treated temperature until a certain temperature, then it increases sharply deviating from the linear relationship, at last it almost keeps a constant due to the rock fully lose its strength. The cutting force decreases with increasing treated temperature, with exception of 200 degrees C without considering hydrostatic pressure and 300 degrees C with considering hydrostatic pressure. The effects of treated temperature and hydrostatic pressure on cutting force are more obviously than the confining pressure. This study leads to an enhanced understanding of thermally induced cracking assisted rock cutting mechanisms in hard formation, and provides the basis for developing the thermally induced cracking assisted rock cutting machines.",7,7,9
Other topics ,,"Jiang, Shu; Zuo, Yinhui; Yang, Meihua; Feng, Renpeng","Reconstruction of the Cenozoic tectono-thermal history of the Dongpu Depression, Bohai Bay Basin, China: Constraints from apatite fission track and vitrinite reflectance data",Maturation; Heat flow; Hydrocarbon generation; Thermal and burial histories; Cenozoic,THERMAL HISTORY; SOURCE ROCKS; EVOLUTION; INSIGHTS; EXHUMATION; APENNINES; EXTENSION; MARGIN; BORDER; MODEL,"The Dongpu Depression is an important oil-producing area in the Bohai Bay Basin, China. The exploration focus in this area has recently shifted to intervals with greater depths (>3500 m) because of decreasing hydrocarbon production at depths shallower than 3500 m. Deep petroleum resource evaluation is becoming important and the tectono-thermal history is a major part of this evaluation. In this study, Cenozoic tectono-thermal histories of the Dongpu Depression are reconstructed by coupling an inversion method of vitrinite reflectance and apatite fission track data from 13 wells. Moreover, the maturation history of the deep source rocks was modeled based on these histories. The results clearly show that the Dongpu Depression experienced two heat flow maxima during the deposition of the middle parts of the Eocene Shahejie 3 member and the Oligocene Dongying Formation, which exhibit maximum heat flow values of 70.5-77.5 mW/m2 and 64.8-70.0 mW/m2, respectively. These two periods of high heat flow are linked to the rifting events of the Dongpu Depression, corresponding to the intense rifting substage (45-38 Ma) and the later rifting substage (38-27 Ma). Tectonic subsidence analysis revealed that the Dongpu Depression experienced initial syn-rift subsidence during the Paleocene, followed by subsequent thermal subsidence since the Neogene. The maturation history indicates that these source rocks experienced only one hydrocarbon generation phase in the mid-northern sags, and experienced a hydrocarbon generation peak during the Oligocene Dongying Formation deposition.",6,6,4
Other topics ,,"Borazjani, S.; Hemmati, N.; Behr, A.; Genolet, L.; Mahani, H.; Zeinijahromi, A.; Bedrikovetsky, P.",Determining water-oil relative permeability and capillary pressure from steady-state coreflood tests,Two-phase flow; Relative permeability; Capillary pressure; Steady-state method; Transition data; Special core analysis,IMAGED FLUID DISTRIBUTIONS; FINES MIGRATION; DISPLACEMENT; COMPUTATION; PARAMETERS; EXCHANGE; MODEL; FLOW,"This study aims at the simultaneous determination of relative permeability and capillary pressure from steadystate corefloods. Besides using the measurements of pressure-drop across the core and average saturation under steady-state conditions, we use the transient data between the sequential steady states. The inverse algorithm is based on four type curves ""stabilizsation period versus water-cut"" revealed by asymptotic analysis of the transient solution near end-point saturations, and on the exponential shape of transition data histories observed by direct numerical runs. The transition measurements are approximated in the stabilisation periods by the type curves using non-linear least-square optimisation. The Corey parameters for relative permeability and capillary pressure are fitted for each interval of sequential water-cuts. The inverse solver is applied to three sets of steadystate tests in oil-wet cores, where saturation profiles during steady-state flows have been measured along with the transition data. Extensive sensitivity analysis of the inverse solutions with respect to the small perturbation of the measured data reveals the stability of obtained relative permeability and capillary pressure. The close agreement between the measured stabilised saturation profiles and those obtained by the matched-based modelling in three oil-wet cases validates the method developed.",6,6,0
Other topics ,,"Jeong, Jina; Park, Eungyu; Emelyanova, Irina; Pervukhina, Marina; Esteban, Lionel; Yun, Seong-Taek",Application of conditional generative model for sonic log estimation considering measurement uncertainty,Well-log estimation; Long short-term memory (LSTM); Bi-direction LSTM (Bi-LSTM); Conditional variational autoencoder; Probabilistic estimation; Sensitivity analysis,SHEAR-WAVE VELOCITY; WELL LOG; NEURAL-NETWORK; ROCK-PHYSICS; PREDICTION; RESERVOIR; LITHOLOGY; ALGORITHM,"Well-log data is a cost-effective means to characterize the petrophysical properties of a geological formation. Among the data, compressional- and shear-slowness (DTC and DTS, respectively) are the most reliable and have been widely applied in the interpretations. However, the availability of DTS data tends to be limited because of its high acquisition cost. This study proposes a method to reproduce or reconstruct the DTS data using other well-log data, such as gamma ray, neutron porosity, bulk density, and DTC. The developed method is based on the conditional variational autoencoder (CVAE) and effectively considers uncertainty associated with the variability of the measured data. The performance of this developed method is validated by applying the well-log data acquired from Satyr-5 and Callihoe-1 wells in the Northern Carnarvon Basin, Western Australia, and the prediction accuracy of the developed method is compared to recently developed data-driven methods (i.e., long short-term memory (LSTM) and bidirectional LSTM (bi-LSTM)). The results reveal that the developed method produces a better DTS estimation than LSTM and bi-LSTM. Furthermore, the effectiveness of the proposed method remains unaltered regardless of whether the data contain a specific trend over the depth or amount of training data are insufficient. As a further application of the developed method, an uncertainty relative to DTS estimation is quantitatively obtained from Monte-Carlo estimation, which uses a trained probability model of the developed method. Sensitivity analysis reveals the high effectiveness of DTC in improving the performance of the CVAE method. From our results, we can conclude that the proposed CVAE-based method is an effective tool for improving the efficiency and accuracy of DTS estimation.",6,6,0
Other topics ,,"Zhang, Miao; Duan, Chaochao; Li, Guofu; Fu, Xuehai; Zhong, Qiu; Liu, Huihu; Dong, Zhiyong","Determinations of the multifractal characteristics of the pore structures of low-, middle-, and high-rank coal using high-pressure mercury injection",Coalification degree; Pore structure; Multifractal behaviors; High pressure mercury injection,SIZE DISTRIBUTIONS; GAS-ADSORPTION; N-2 ADSORPTION; SHALE; POROSITY; CONNECTIVITY; DIMENSIONS; RESERVOIRS; CAPACITY; SAMPLES,"The multifractal characteristics of pore structures of low-, middle-, and high-rank coals were analyzed in this study based on the results of high-pressure mercury injection analysis and multifractal theories. The results showed that coal pore structures exhibit multifractal behavior, and were much affected by coalification degrees. For example, it was observed that the Hurst Index (H), information dimension D1, and correlation dimension D2 decreased with increases in the coalification degree. Also, the spectrum width increased, indicating greater local fluctuations of the pore size distributions (PSDs), narrower distribution intervals, enhanced heterogeneity, and reduced pore connectivity. Micropores and mesopores have opposing effects on the multifractal characteristics of pore structures. It has been found that increases in the percentage of mesopores lead to better pore connectivity and more homogeneous pore structures. In addition, increases in mineral content and Mad lead to better connectivity and more uniform pore structures. However, increases in vitrinite content results in decreased pore connectivity, and the complexity of pore structures tends to increase. Also, increases in inertinite content reduce the heterogeneity of the low value regions of the pore volumes, resulting in decreases in the complexity of the overall pore structures.",5,5,23
Other topics ,,"Bai, Yujie; Cao, Guangsheng; Nan, Xiaohan; Li, Shining; An, Hongxin; Wang, Xin; Wang, Zhe",Effect of sodium fluosilicate particles in acidification flowback fluid on emulsification stability of crude oil,Well acidification; Flowback fluid; Emulsion; Nanoparticles; Sodium fluosilicate; Oilfield sewage treatment,,"Emulsification in the flowback fluid after the acidification of oil wells is too severe to be treated by electric dehydration. To study the emulsification mechanism of acidified flowback fluid, an emulsion of acidified crude oil was prepared according to the conventional treatment process of oil-well acidification. Fine white solid particles were formed after the neutralization of residual acid by NaOH. The main component of the white solid particles was sodium fluosilicate, as determined by X-ray diffraction analysis. The particle size range was measured and observed by laser particle size analysis and scanning electron microscopy, respectively, with the smallest observed particle size being similar to 1 mu m. Then, based on the actual conditions of acidized oil wells, the drainage capacity of different solid particles in the crude oil emulsion was evaluated. The results showed that the emulsion with sodium fluosilicate particles added in the intermediate layer was the most stable, indicating that sodium fluosilicate was the main factor hindering the treatment of acidification flowback liquid. In addition, when the gum and asphaltene contents in the crude oil sample are high, the maximum voltage of the emulsion can be increased by appropriately increasing the experimental temperature, thus improving the effect of electric dehydration.",5,5,4
Other topics ,,"Li, Kun; Yin, Xingyao; Zong, Zhaoyun; Lin, Haikun",Direct estimation of discrete fluid facies and fluid indicators via a Bayesian Seismic Probabilistic Inversion and a novel exact PP-wave reflection coefficient,Fluid discrimination; Discrete facies; Bayesian probabilistic inversion; Nonlinear; Inversion; Differential evolution Markov chain Monte; Carlo model,IMPEDANCE INVERSION; JOINT ESTIMATION; ELASTIC IMPEDANCE; AVO; DISCRIMINATION; DRIVEN; DOMAIN,"Estimation of rock pore-fluid properties in subsurface reservoirs using seismic reflection data is an important topic in exploration geophysics. Prestack seismic inversion is a key approach for reservoir characterization and fluid discrimination. In this study, we propose a simultaneous estimation approach for discrete fluid facies (i.e., gas, oil, water) and continuous fluid indicators via a Bayesian seismic nonlinear inversion and the differential evolution Markov Chain Monte Carlo model. We derived one novel nonlinear exact PP-wave reflection co-efficients equation characterized by Gassmann fluid term, shear modulus and density and the equation is more accurate and suitable for large incident angles. Besides, a mixture probability model is utilized as the prior probability density function (PDF) of the model parameters in the Bayesian seismic probabilistic inversion. Furthermore, the differential evolution Markov Chain Monte Carlo (DE-MCMC) model is developed to optimize the mixture posterior PDF in Bayesian seismic inference. The discrete fluid facies is estimated via the posterior weights of each probability component directly, which can reduce the uncertainty and the accumulation errors of seismic fluid discrimination. The main advantage of the DE-MCMC seismic probabilistic inversion is that it can simulate the posterior probability density distributions of the model parameters efficiently based on the simultaneous optimization of multiple Markov chains, which is helpful for the uncertainty assessment of the inversion results and fluid discrimination. Synthetic examples are provided to demonstrate the feasibility and stability of the proposed method. Furthermore, one field case of oil-gas exploration is presented to show the practicability of this method in reservoir fluid discrimination.",5,5,2
Other topics ,,"Xu, Zhenhao; Shi, Heng; Lin, Peng; Liu, Tonghui",Integrated lithology identification based on images and elemental data from rocks,Lithology; Deep learning; Fusion identification; Image identification; Rock image; Elemental data,AUTOMATIC IDENTIFICATION; CLASSIFICATION; FACIES,"In order to realize low-cost, fast and accurate lithology identification in reservoir evaluation, stratum development potential evaluation and underground engineering construction, we propose an intelligent lithology identification method, which can achieve deep fusion of images and elemental data from rocks, and a step-wise model training method. Lithological features are extracted from both images and the rock elemental data using convolution layers and fully connected layers; those features are then concatenated and fed to the fully connected layers to achieve deep fusion. In the model training phase, the image feature extraction module of the fusion model is first trained only with images, and then the entire fusion model is trained using both the images and the rock elemental data. We also conduct reliability assessment and then compare the performance of our fusion identification model to that of an identification model that relies solely on images. The maximum accuracy (94.62%), recall (94.30%), F1-score (93.98%), and Kappa coefficient (0.94) values of the fusion method far exceed that of the image identification method. The step-wise model training method noticeably reduces the amount of rock elemental data required by the fusion model. High image similarity and smaller lithology features degrade the performance of the image identification method, while the fusion method can significantly overcome these challenges and thus greatly improve the accuracy of lithology identification. The fusion identification method is more accurate and robust than the image identification method.",4,4,25
Other topics ,,"Han, Yue; Ma, Hongling; Yang, Chunhe; Li, Huan; Yang, Jie",The mechanical behavior of rock salt under different confining pressure unloading rates during compressed air energy storage (CAES),Confining pressure unloading test; Unloading rate; Mechanical behavior; Failure; CAES,STRAIN-RATE; GAS; DILATANCY; CONSTRUCTION; TEMPERATURE; DILATION; STRENGTH; CAVERNS; JINTAN; MINE,"Compressed air energy storage (CAES) is a promising energy conversion storage technology and underground salt caverns are recognized as the appropriate storage places for it. The reduction of air during the withdrawal periods leads to the surrounding rock being unloaded, which threatens the stability of the salt cavern. To investigate the mechanical behavior of surrounding rock under different unloading rates, the confining pressure unloading tests in six unloading rates have been conducted on rock salt. Results show the rock salt undergoes volume expansion at the beginning of unloading due to the reduction of elastic compression strain. The volume strain expands rapidly beyond a threshold, i.e. accelerated strain point. The stresses at failure point and accelerated strain point show that a low unloading rate is beneficial to enhance rock strength. Nevertheless, larger inelastic strain appears in a lower unloading rate. The effect of the unloading rate on rock salt failure mode is that rapid unloading will promote crack growth. Moreover, the relationship between the unloading rate of surrounding rock and the air withdrawal rate is established. The outcome derived from the research can provide some instruction and inspiration for air withdrawal rate design in CAES.",4,4,18
Other topics ,,"Kasyap, S. S.; Senetakis, K.","Characterization of two types of shale rocks from Guizhou China through micro-indentation, statistical and machine-learning tools",Indentation; Hardness; Creep; Anisotropy; Shale,DYNAMIC MECHANICAL ANALYSIS; NANOGRANULAR NATURE; ELASTIC-MODULUS; NANOINDENTATION; HARDNESS; ANISOTROPY; STRENGTH; BEHAVIOR,"Micro-indentation tests were performed adopting the grid-type of analysis on two types of shale rocks, which are porous natural materials characterized by strong geological structural and microfabric features. Emphasis was placed on understanding the influence and linkage between these microstructural-microfabric characteristics and the mechanical properties obtained from indentation, including hardness, modulus, elastic and plastic deformation fractions, and their anisotropic and heterogeneous distribution. The indentation loading-unloading curve patterns also functioned as a way to explore this linkage besides the global variation in the mechanical properties. Statistical tools and machine learning techniques were further employed in the indentation data analysis, providing a means of quantifying the intricacies involved with the mechanical properties of the shales. The creep behavior of these porous materials was quantified and linked to the anisotropic structure and mechanical properties, providing insights into one of the most complex natural materials, as many researchers have characterized. Opposite to previously published data on transversely isotropic shale rocks with vertical axis of symmetry, especially shales with high clay and organic content, the results in the present study showed higher modulus normal to the bedding planes compared to the parallel direction, which observation was attributed to the low clay (and organic) content of the shales and the possible low depth the shales were obtained.",4,4,18
Other topics ,,"Cai, Chengzheng; Tao, Zhixiang; Ren, Keda; Liu, Shuang; Yang, Yugui; Feng, Yinrong; Su, Shanjie; Hou, Peng",Experimental investigation on the breakdown behaviours of sandstone due to liquid nitrogen fracturing,Liquid nitrogen; Fracturing; Sandstone; Breakdown pressure; Fracture pattern,,"Liquid nitrogen (LN) fracturing is an efficient technology for the development of unconventional gas resources. Due to continuous injection of cryogenic LN, the reservoir temperature decreases and then cooled rock regions are gradually generated during fracturing process. To investigate the breakdown behaviours of sandstone induced by LN fracturing, laboratory simulation experiments were performed with a self-designed setup. The experimental results showed that rising initial rock temperature greatly reduced the breakdown pressure of sandstone, whereas hardly affected the fracture complexity. Under cryogenic conditions, both the compaction and cracking effects exerted influence on the pore structure of sandstone. Thus, the change in breakdown pressure depended on which effect played a domain role. Although the cryogenic conditions probably made the breakdown pressure of sandstone increase, the fracture complexity was expected to be significantly improved. In addition, the initial rock temperature increasing played a positive role in improving the fracture complexity under cryogenic conditions. For initial or heating sandstone samples, the fracture pattern mainly presented in the form of bi-wing fractures. However, for cryogenic samples, the fracture patterns contained both local fractures and complex fractures. The former was generated with lower breakdown pressure while the latter was generated with higher breakdown pressure. Additionally, the gas leak regions were observed in cryogenic samples during LN fracturing. Under cryogenic conditions, the sandstone used was favourable to generate more complex fractures and the permeability of rock matrix in unbroken region was proved to be improved due to LN fracturing. Collectively, fracturing with LN could improve the fracture complexity and the permeability of rock, which was very beneficial for well production.",4,5,13
Other topics ,,"Pang, Mengqiang; Ba, Jing; Carcione, J. M.; Zhang, Lin; Ma, Rupeng; Wei, Yijun",Seismic identification of tight-oil reservoirs by using 3D rock-physics templates,Tight-oil reservoir; 3D rock-physics template; Crack; Clay content; Triple-porosity theory; Attenuation,,"Tight-oil reservoirs are classified as unconventional hydrocarbon resources, having a complex system of pores and cracks and low porosity/permeability. A good pore-crack connectivity is required for hydrocarbon production, but clay minerals filling the pores and throats may hinder the fluid migration. Thus, the combined effects of the pore-crack network and the presence of clay are the main factors controlling the reservoir properties and its storage capacity. In this study, a suite of cores was collected from a reservoir located in the north of the Songliao Basin (China), and establish their microstructure by scanning electron microscopy. Then, ultrasonic experiments were performed under in-situ conditions to analyze the influence of clay minerals and porosity on the elastic waves. The triple-porosity, differential-effective-medium and self-consistent theories were used to calculate the stiffness moduli by considering the effects of pores, cracks and clay minerals, and to analyze the influence of these reservoir properties on the P-wave attributes. According to attenuation, acoustic impedance and phase-velocity ratio, a multi-scale 3D rock-physics template was established. By using the ultrasonic, sonic-log and seismic data, the templates were calibrated and then the reservoir characteristics were estimated. Two 2D seismic lines were considered and the corresponding predicted reservoir properties were compared to the well-log data and the actual production reports, showing that the porosity and clay content predictions are consistent with these data, and that the oil production areas are all located within the high-cracked porous zones. The 3D rock-physics templates can effectively estimate the distribution of high-quality tight-oil reservoirs.",4,4,6
Other topics ,,"Zhang, Lei; Yu, Weichu; Ma, Peng; Zheng, Liming; Zhang, Ying",Study on long-term rheological characteristics of polymer gel and prediction of its creep fracture time,Long-term rheology; Polymer gel; Mechanical model; Conformance control; Heterogeneous oil reservoirs,,"Conformance control by using the polymer gel is an important stimulation technique of heterogeneous oil reservoirs. After operation of the conformance control, the water channeling of heterogeneous oil reservoirs can be plugged, which can force the follow-up injected water to divert into the area with high oil saturation. Thus, under the action of water injection pressure, the polymer gel is deformed. Because this is a long-term process, the ability to resist the long-term deformation and resist damage of polymer gel is important for the long-term plugging effect. However, there are few reports on the effect of long-term rheological characteristics of the polymer gel on its plugging ability. Therefore, it is of great significance to study the rheological characteristics of the polymer gel under the long-term action of a stress, which can be used to accurately predict the effective period of plugging the water channeling. In this paper, taking the Hook body and the viscous pot as the basic elements, and considering the Maxwell model and the Kelvin model as the basic models, a combined viscoelastic mechanical model of the polymer gel is established, which can be used to simulate the creep deformation of polymer gel. At the rheological damage stage of the polymer gel, the strain is increased exponentially and the mechanical parameters is decayed exponentially with time. By introducing the damage variable, based on the stress - time equivalence principle of polymer materials, the time of creep fracture of the polymer gel can be accurately calculated. Since then, the polymer gel is started to break obviously and lost its ability for plugging. This study can provide an important guidance to optimizing the scheme of conformance control and predicting the validity period.",4,4,5
Other topics ,,"Liu, Yong; Wang, Chenchen; Wei, Jianping; Chen, Changjiang",Effect of nozzle pressure ratio on pulsation frequency of air jets used in hole drilling,Air jet; Hole drilling; Nozzle pressure ratio; Pulsation frequency; Surface treatment,IMPINGEMENT; PERFORMANCE; SURFACE,"In this study, air-jet experiments were performed to investigate the effects of nozzle pressure ratios (n) on the pulsation frequency and structure of free-flow and impinging-flow fields. The experiments performed for different nozzle pressure ratios involved the collection of a series of photographs of the free-flow field structure and the measurement of the pressure distribution and pulsation frequency of the impinging-flow field. In addition, the gray values of the photographs of the free-flow field were extracted to calculate the frequency spectrum of the free-flow field. When n > 1, the free-flow field oscillated spatially along the jet axial direction, but its frequency was independent of the spatial position and depended only on the nozzle pressure ratio. With an increase in the nozzle pressure ratio, the frequency values sequentially increased, decreased, increased, and then stabilized. The pressure of the impinging-flow field depended only on the stand-off distance, and decreased rapidly with increasing stand-off distance. However, the pressure distribution of the impinging-flow field was dependent on the nozzle pressure ratios, and with an increasing nozzle pressure ratio, the pressure distribution changed from radial attenuation along the jet direction to a distribution with multiple pressure peaks in the flow field. Multiple frequencies existed in the impinging-flow field, and the overall pulsation was stronger than that of the free-flow field for the same pressure ratios.",4,4,4
Other topics ,,"Oliver, Dean S.; Fossum, Kristian; Bhakta, Tuhin; Sando, Ivar; Naevdal, Geir; Lorentzen, Rolf Johan",4D seismic history matching,Time-lapse seismic; 4D seismic; History matching,ENSEMBLE KALMAN FILTER; RESERVOIR SIMULATION; DATA ASSIMILATION; DISTANCE PARAMETERIZATION; QUANTITATIVE INTEGRATION; GRADUAL DEFORMATION; FLUID SATURATION; OIL-FIELD; ERROR; CALIBRATION,"Reservoir simulation models are used to forecast future reservoir behavior and to optimally manage reservoir production. These models require specification of hundreds of thousands of parameters, some of which may be determined from measurements along well paths, but the distance between wells can be large and the formations in which oil and gas are found are almost always heterogeneous with many geological complexities so many of the reservoir parameters are poorly constrained by well data. Additional constraints on the values of the parameters are provided by general geologic knowledge, and other constraints are provided by historical measurements of production and injection behavior. This type of information is often not sufficient to identify locations of either currently remaining oil, or to provide accurate forecasts where oil will remain at the end of project life. The repeated use of surface seismic surveys offers the promise of providing observations of locations of changes in physical properties between wells, thus reducing uncertainty in predictions of future reservoir behavior. Unfortunately, while methodologies for assimilation of 4D seismic data have demonstrated substantial value in synthetic model studies, the application to real fields has not been as successful. In this paper, we review the literature on 4D seismic history matching (SHM), focusing discussions on the aspects of the problem that make it more difficult than the more traditional production history matching. In particular, we discuss the possible choices for seismic attributes that can be used for comparison between observed or modeled attribute to determine the properties of the reservoir and the difficulty of estimating the magnitude of the noise or bias in the data. Depending on the level of matching, the bias may result from errors in the forward modeling, or errors in the inversion. Much of the practical literature has focused on methodologies for reducing the effect of bias or modeling error either through choice of attribute, or by appropriate weighting of data. Applications to field cases appear to have been at least partially successful, although quantitative assessment of the history matches and the improvements in forecast is difficult.",4,4,4
Other topics ,,"Mazen, Ahmed Z.; Rahmanian, Nejat; Mujtaba, Iqbal M.; Hassanpour, Ali",Effective mechanical specific energy: A new approach for evaluating PDC bit performance and cutters wear,Mechanical specific energy; PDC bit Performance; PDC bit Wear; Depth of cut; Bit profile,,"Predicting the PDC bit performance during drilling operation is important for the cost effectiveness of the operation. The majority of PDC bits are assessed based on their performance that are relative to offset wells. Determination of mechanical specific energy (MSE) in real time and compare it with the known MSE for a sharp bit to assess the bit life has been utilized by several operators in the past. However, MSE still cannot be used to predict the bit performance in exploration wells and also it cannot assess the bit efficiency in the inner and outer cones. A more precise approach needs to be devised and applied to improve the prediction of bit life and the decision when to pull the bit out of the hole. Effective mechanical specific energy (EMSE) developed in this work is a new wear and performance predictive model that is to measure the cutting efficiency based on number of cutters, which contact the rock as a function of weight on bit (WOB), rotary speed (RPM), torque, and depth of cut (DOC). This model modifies the previous MSE model by incorporating such parameters and including detailed design of the bit, number of blades, cutter density, cutter size, and cutting angle. Using this approach together with the analysis of rock hardness, a level of understanding of how the drilling variables influence the bit performance in the inner and outer cone is improved, and a convenient comparison of the bit condition in the frame of the standard bit record is achieved. This work presents a new simple model to predict the PDC cutters wear using actual data from three sections drilled in three oil wells in Libya. It is found that the obtained results are in well agreement with the actual dull grading shown in the bit record.",4,4,3
Other topics ,,"Taherian, Zeinab; Dehaghani, AmirHossein Saeedi; Ayatollahi, Shahab; Kharrat, Riyaz",A new insight to the assessment of asphaltene characterization by using fortier transformed infrared spectroscopy,Asphaltene characterization; Fourier-transform infrared spectroscopy; Functional groups; Aromatic compounds; IP-143,CHEMICAL-CHARACTERIZATION; HEAVY OIL; VANADIUM; DEPOSITION; PETROLEUM; NICKEL; ISLAND,"This research aims to present asphaltene fraction of oil by FTIR spectrum technique. For this purpose, three different oil samples with various SARA contents and almost identical API degrees were utilized in this research. Two asphaltenic oil samples were referred to as 'A' and 'B', and the aliphatic oil sample was named as 'C' . First of all, the asphaltene fraction was extracted through the IP-143 test. The possible chemical bonds and functional groups were identified through NMR tests. Then, the FTIR spectrums of the oil samples and the extracted corresponding asphaltene fractions were taken. The interpretations were used to find the functional groups in the FTIR of the oil samples that belong to the asphaltene fractions. Among the investigated oil samples, no asphaltene related peak with a unique assignment was observed for the FTIR for sample 'A'. The FTIR of oil sample 'C' showed amine related peaks, which belonged to the asphaltene fraction. Also, the alcohol and amine related peaks, which correspond to the asphaltene fraction, were detected in the FTIR of the oil sample 'B'. According to the oil samples' SARA contents, the ratio of the asphaltene content to the aromatic-based fraction seems to have a key role in this method. In other words, to detect the functional groups attached to the asphaltene fraction from the FTIR spectrum, the asphaltene fraction should have enough concentration compared to other aromatic-based components in the oil. The method's applicability is initially based on the specific functional groups existence in the asphaltene fraction.",4,4,2
Other topics ,,"Tian, Jian; Kang, Yili; You, Lijun; Jia, Na; Xi, Zhiyu; Luo, Pingya",Investigation on water phase trapping mechanisms in tight gas reservoirs: Pore-scale visualization observation and core-scale flooding analysis,Tight gas reservoirs; Water phase trapping; Visualization; Pore-scale; Core-scale; Damage mechanisms,FORMATION DAMAGE; BLOCKING; FLOW; FLUORIDE; IMPACT; OIL,"Water phase trapping (WPT) is one of severe formation damage issues for the safe production in tight gas reservoirs. In this work, both pore-scale and core-scale investigation of the formation process of WPT were performed. Real-time observation of the water invasion and formation of trapped gas was achieved using visualized micromodel. Meanwhile, core flooding experiments including water imbibition and drainage experiments were conducted to analyze the responses of gas permeability and water saturation changes to the formation of WPT. The micromodel visualization experiments presented an intuitive gas-water two-phase flow scenarios which revealed the microscopic mechanisms of the WPT vividly. It pointed out that snap-off and circumfluous flow are the two major mechanisms to break the bulk gas flow and generate the trapped gas during WPT formation. The results of core flooding provided a causality link between the changes of gas permeability and water saturation, which showed a macroscopic consequence to the gas flow ability caused by WPT damage. These findings will benefit a better understanding of the formation process and damage mechanisms of WPT.",3,3,10
Other topics ,,"Wen, Yiping; Lai, Nanjun; Du, Zhaofeng; Xu, Feiyan; Zhang, Xiaobin; Han, Lijuan; Yuan, Lin",Application of orthogonal experiment method in foam flooding system composition and injection parameter optimization,Foam flooding; Mobility control ability; Orthogonal experiment; Parameter optimization; Standard deviation; Entrance effect,OIL-RECOVERY; HIGH-TEMPERATURE; NITROGEN FOAM; POROUS-MEDIA; SURFACTANT; PERFORMANCE; BEHAVIOR; PERMEABILITY; GENERATION; TRANSPORT,"Excellent composition and injection parameters of foam system are essential for foam flooding to exert mobility control. This study aims to optimize foam composition and injection parameters to maximize foam mobility control. The concentrations of foaming agent and stabilizer, oil saturation, foam quality, and flow rate served as influencing factors in the orthogonal experiment method with resistance factor (RF) as the evaluation index. Results showed that cores with different permeability levels corresponded to a set of optimal injection parameters. The optimal combination scheme significantly improved mobility control relative to all test groups in the orthogonal experiment, proving the effectiveness of this method in optimizing foam flooding parameters. During the analysis of orthogonal experimental data, in addition to the method of intuitive analysis was adopted to study the influence of a single factor on the RF, the influence of multiple factors interaction on the RF was also explored. Confirmatory tests were performed on the optimal parameters of foam flooding obtained by orthogonal experiments, and the foam propagation at different positions of the core was determined. The degree of pressure fluctuation during foam flooding was measured with the standard deviation (SD), which was used to directly measure the strength of the Jamin effect during foam flooding. The RF distribution factor (DRF) was introduced to describe the uniformity of foam seepage resistance along the core axis. DRF was used to study the entrance effect on foam to establish seepage resistance. The propagation performance of foam in porous medium is crucial to maximize its mobility control. Foam injectivity in porous medium should be given attention when optimizing the injection parameters of foam flooding.",3,3,8
Other topics ,,"Feng, Runhai",Uncertainty analysis in well log classification by Bayesian long short-term memory networks,Well log classification; Uncertainty analysis; Bayesian inference; Deep learning,LITHOFACIES; PREDICTION,"As an important parameter, uncertainty can provide essential information in decision making, which is usually discarded in a typical application of deep-learning methods. Dropout, a technique to reduce overfitting and coadaption in hidden neurons, is proposed to approximate the Bayesian inference realized in deep learning. Specifically, the dropout scheme is applied not only in the training process, but also in the testing step by the trained model. This novel approach would then enable the learned networks to express uncertainty via their own parameters. The proposed method is implemented in a recurrent system, particularly, long short-term memory (LSTM) to account for the data dependency for the classification of sequential lithologies in the subsurface. The designed Bayesian LSTM (BLSTM) is applied to a real data set from the North Sea. Different combinations of dropout ratio are assigned in the weight matrices, to test its influence on the classification performance. To simulate an ensemble predictor, random samples are drawn from the trained networks according to the predefined dropout ratio during the classification process, and the model average is regarded as the final classification result. The multi-class predictive entropy can provide the uncertainty information, and its lower value is associated with more confident prediction or vice versa. The traditional LSTM is applied as a benchmark, which yields a same good quality performance with BLSTM, as measured by the Matthews correlation coefficient and confusion matrix; however, it lacks the capability to permit analyzing the uncertainty probabilistically.",3,3,6
Other topics ,,"Yao, Zongquan; Li, Shunli; Yu, Xinghe; Deleqiati, Jianatayi; Yang, Fan; Wang, Wei; Wang, Wenfeng; Akedan, Sikandier; Yang, Xintao; Zheng, Bin; Li, Ling; Gong, Ruicheng","Effects of the interaction of tectonics, eustasy, climate, and minerals on the sedimentary evolution of early-middle Jurassic in the Hongshanzui region in Junggar Basin",Sequence-stratigraphic framework; Sedimentary system; Controlling factors; Early -middle Jurassic; Hongshanzui region,FLUVIAL SYSTEM; TECTONOSEDIMENTARY EVOLUTION; CENOZOIC TECTONICS; CHINA; RECORD; TARIM; AGE,"Majority of the oilfields in the Hongshanzui region are small and complex fault block reservoirs, and the evolution of the sedimentary system under the sequence stratigrapic background has been a controversial topic. Six middle-term base-level cycles were divided, and eight types of lithofacies assemblages were recognized based on the stacking patterns and volumetric partitioning according to the core, well logs, and seismic data correlated with the field investigation of outcrops. Furthermore, the evolution of the sedimentary system under the sequence stratigraphic framework was clarified. Among the six middle-term base-levels, MSC1 belongs to the retrogradational system tract, and the sediment distribution exhibits the characteristics of ""large plain and small front."" MSC2 belongs to the transgression system tract, and the sediment distribution exhibits has the characteristics of ""small plain and large front."" In the case of MSC5 and MSC6, the sediment distribution exhibits the characteristics of ""dominant channel and repeated channel-switching."" Further, the controlling factors of tectonic, base level, climate, and minerals are discussed.This research has been applied to the exploration and development of the Hongshanzui oilfield, and a certain benefit has been achieved.",3,3,5
Other topics ,,"Dubey, Vasav; Abedi, Sara; Noshadravan, Arash",A multiscale modeling of damage accumulation and permeability variation in shale rocks under mechanical loading,Shale rocks; Multiscale; Microcrack-induced damage; LEFM; Permeability,ORGANIC-RICH SHALES; MICROMECHANICAL ANALYSIS; HYDRAULIC STIMULATION; ANISOTROPIC DAMAGE; INFORMATION-THEORY; MICROPLANE MODEL; PROPAGATION; INITIATION; MUSCOVITE; FRICTION,"This paper presents a hierarchal multiscale model to simulate the damage behavior of transversely isotropic shales, where the damage mechanism is attributed to micmcrack growth under mechanical loading. An anisotropic damage model is presented in which the state of damage is described by a scalar crack density parameter. Furthermore, a simplified permeability model is incorporated to couple the evolution of damage to permeability variation through the damage density parameter. The Maximum Entropy principle is employed to account for uncertainty in the main parameters of the multiscale model representing the subscale structural and compositional features. This probabilistic multiscale damage model provides a framework to simulate the probabilistic descriptions of poromechanical and damage properties and the subsequent variation in microcrack-induced permeability. This framework is used to simulate nonlinear stress-strain behavior in uniaxial compression tests for varying loading directions with respect to the bedding plane of transversely isotropic shale rocks. The outcome of this study includes probabilistic characteristics of stiffness degradation, crack growth, and permeability variation under different loading conditions.",3,3,5
Other topics ,,"Alipour, M.; Esatyana, E.; Sakhaee-Pour, A.; Sadooni, F. N.; Al-Kuwari, H. A.",Characterizing fracture toughness using machine learning,Machine learning; Nanoindentation; Image processing; Fracture toughness,,"The existing models for fracture toughness characterization based on nanoindentations that account for the fracture length are limited to simple (ideal) geometries that are absent in shales. The present study proposes two conceptual models to estimate the fracture length created by nanoindentations in shales. It also presents a workflow to apply the conceptual models and uses machine learning, enabling a systematic and automated analysis. The conceptual models assume that the induced fracture is in the first mode to determine the fracture toughness. In this study, fracture toughness is also determined by the energy method that relates the loaddisplacement hysteresis to the fracture toughness without restricting the fracture mode. The present study sheds light on the complexities of characterizing fracture toughness using nanoindentations and has applications in the petroleum industry. The conceptual models are appealing for formation characterization using small pieces, such as drill cuttings, when large samples (similar to 2.5 cm) required for conventional tests are unavailable. The conceptual models have applications in estimating fracture toughness when the induced fracture patterns become more complex.",3,3,5
Other topics ,,"Gan, Chao; Cao, Wei-Hua; Liu, Kang-Zhi; Wu, Min",A new spatial modeling method for 3D formation drillability field using fuzzy c-means clustering and random forest,Spatial modeling; Formation drillability; Fuzzy c-means clustering; Random forest; 3D field,,"spatial model of the 3D formation drillability field is crucial for drilling optimization in the petroleum area. In this paper, a new spatial modeling method is proposed for the 3D formation drillability field, which has two stages. In the first stage, the number of formation modes is determined according to the formation characteristics and these modes are identified by the fuzzy c-means clustering algorithm. In the second stage, random forest models are built separately for all formation modes. X, Y ground coordinates and depth coordinate are selected as the model inputs while the model output is the formation drillability. After that, these spatial 3D formation models are combined into one spatial 3D formation model for the whole drillability field. The proposed method and four compared methods (Random forest, ScatteredInterpolant, Support vector regression, and Kriging) are cross-validated and tested by using the data from eight drilling wells in the Xujiaweizi area, Northeast China. The results indicate the effectiveness of proposed method in spatial 3D formation drillability modeling.",3,3,4
Other topics ,,"Coelho, Fernando M. C.; Sepehrnoori, Kamy; Ezekoye, Ofodike A.",Coupled geochemical and compositional wellbore simulators: A case study on scaling tendencies under water evaporation and CO2 dissolution,Scale; Evaporation; Multiphase flow; Wellbore,CHEMICAL-TRACER TESTS; MODEL; FLOW,"Inorganic deposits are the result of mineral precipitation due to changes in pressure and temperature along water flow and one of the main causes of production decline in the Oil & Gas Industry, as water is usually inherent to any oil/gas production. These deposits may be present in the reservoir, wellbore, and processing facilities. Literature suggests that evaporation of water can significantly increase (if not be the main cause of) mineral precipitation and consequently scale deposition for a gas condensate well. This work aims to determine if evaporation can also play a similar role for an oil well. New achievements towards an integrated platform (called UTWELL, for wellbore simulation) are addressed; however, emphasis is given to the effects of a newly added evaporation model in the case of an offshore oil production well showing calcite precipitation. Results demonstrate that evaporation is only relevant for very small water cuts (<1%), which are characteristic of early stages of production, leading to increased ionic strength and mineral precipitation (calcite and halite). Since scale inhibitors might not be effective for this specific scenario, an alternative solution with dilution water injection is proposed and analyzed. It is estimated that, for 0.1% water cut, the injection of a dilution water flowrate triple that coming from the reservoir can practically eliminate any precipitation in the wellbore. It is also shown that UTWELL is able to match results from commercial multiphase-flow simulator OLGA with the advantage of more physically meaningful aqueous density calculation and the availability of mineral precipitation (absent in the commercial simulator). Although showing similar results for little water content (<1%), total liquid flowrate is 4% lower than when using OLGA for a 50% water cut due to its poor aqueous density calculation, and 8% lower compared with previous version of UTWELL after multiple improvements to the model.",3,3,3
Other topics ,,"Jayanthi, J. L.; Nandakumar, V",Fluid inclusion studies to determine the paleotemperature and hydrocarbon quality in petroliferous basins,Paleotemperature; API gravity; Hydrocarbon fluid inclusions; Petroliferous basins; Oil window,PETROLEUM MIGRATION; MUMBAI OFFSHORE; OIL; SEDIMENTARY; EVOLUTION; SYSTEMS,"Hydrocarbon bearing fluid inclusions (HCFIs) along with the coeval aqueous inclusions could be utilized in petroleum exploration industry for determining the paleotemperature and American Petroleum Institute's (API) gravity of oils in a basin. These parameters can indirectly yield a quick assessment on the hydrocarbon quality in a basin. Here we use fluid inclusion data as a tool to study the paleotemperature and hydrocarbon quality of two offshore basins in India (dry wells from a proven basin and non-proven basin). Towards this objective, temperature of homogenization (Th) of coeval aqueous fluid inclusion, assemblages seen associated with HCFIs and fluorescence emission features of oils in HCFIs were studied. Depthwise comparison of two basins studied are accorded with the microthermometrically obtained Th data and spectroscopically determined (fluorescence) API gravity values that gives an estimation of the paleotemperature and hydrocarbon quality. The Th and, fluorescence emission features of oils in HCFIs (leads to API gravity) presented allow us to make a qualitative assessment of oils in these basins. This study brings out the potential information stored in HCFIs/adjacent brine fluid inclusions, as a tool for determining the paleotemperature and API gravity of oils in petroliferous basins.",3,3,2
Other topics ,,"Zhong, Zhiqi; Rezaee, Reza; Esteban, Lionel; Josh, Matthew; Feng, Runhua",Determination of Archie's cementation exponent for shale reservoirs; an experimental approach,Shale; Electrical properties; Cementation exponent; Cation exchange capacity(CEC); Nuclear magnetic resonance(NMR),,"Archie's equation has been widely used in well-log interpretations for the fluid saturation calculation from electrical resistivity measurements. Though constrained standard Archie parameters are accepted in sandstone and carbonate reservoirs, the same parameters are more complex to define in Shales. Indeed, the use of standard Archie parameters on shale reservoirs proved to be inaccurate due to the heterogeneities and ultra-tight nature of those formations, and also the excessive conductivity exerted by the strong Cation Exchange Capacity (CEC) property of clays particle surfaces. This study aims to determine Archie's cementation exponent (m) from two Australian shales (oil-shale and gas shale with a maximum of 60% clay content) with the minimization of the CEC effect using high saline pore fluid. The shales were first fully saturated under hydrostatic pressure for about two weeks before conducting electrical resistivity and Nuclear Magnetic Resonance (NMR) laboratory measurements. The resistivity measurements were conducted under ambient conditions, though a small 50 psi axial pressure was added to improve sample-electrode surface contact, and under 2800 psi confining pressure to simulate the reservoir condition. NMR was measured in ambient conditions only to compute the effective porosity (excluding clay bound water volume), and to detect potential residual oil after oil removal treatment. The oil cleaning process enhances the development of micro-fractures but their effects are negligible on the NMR effective porosity (<5%). The results indicated that Archie m is stress-dependent averaging around 2.48 in ambient conditions and increasing to 2.70 in reservoir conditions, an 11% increase that is similar in both oil- and gas-shales. However, Archie m is systematically higher in oil shales despite oil cleaning (m > 3) and lower in gas shales (m < 2.55).",3,3,2
