Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Fracture,Hydraulic Fracture,"Wang, Shen; Li, Dongyin; Mitri, Hani; Li, Huamin",Numerical simulation of hydraulic fracture deflection influenced by slotted directional boreholes using XFEM with a modified rock fracture energy model,Directional hydraulic fracturing; XFEM; Slotted directional borehole; Hydraulic fracture morphology; Rock shear fracture energy,FINITE-ELEMENT-METHOD; PROPAGATION CONTROL; CRACK-GROWTH; PRESSURE; TECHNOLOGY; INITIATION; MECHANISM; MEDIA,"Directional hydraulic fracturing (DHF) has been used in conductivity improvement of oil, gas and geothermal energy reservoirs and hard rock roof breaking in coal mines. Although the new DHF method that integrates fracturing borehole and slotted directional borehole (SDB) has been recently introduced, the mechanism and effectiveness of SDB on hydraulic fracture guiding remain open issues. In this study, numerical simulation based on extended finite element method (XFEM) is performed to investigate the effect of SDB on hydraulic fracture deflection. A modified rock fracture energy model is proposed and performed by a user subroutine USDFLD with XFEM, which considers the hardening property of rock shear fracture energy as confining pressure increases. The effects of stress field and borehole line azimuth on hydraulic fracture deflection and bottomhole pressure are investigated. Hydraulic fracture morphologies of three kinds of multi-borehole fracturing technology are compared, the control mechanism of SDBs on hydraulic fracture is explained, and the bottomhole pressure relief effect, borehole spacing and potential application prospects are discussed. Result indicates that the modified model shows good accuracy and applicability in predicting hydraulic fracture propagation, and the hardening property of shear fracture energy should be considered when using XFEM and cohesive element method. The feature first drop and then rise ? of bottomhole pressure curve is an important sign that imply the hydraulic fracture propagates into the influence radius of SDB and can be used as an indicator to evaluate the effectiveness of DHF. Slot increases the influence radius of directional borehole and changes the local stress direction, thus allowing SDB-based DHF technique to be applied to the conditions where the stress difference ratio does not exceed one. When the stress difference ratio is greater than one, the pressurized SDB is more suitable.",3,3,15
Fracture,Hydraulic Fracture,"Liu, Zhao; Sun, Youhong; Guo, Wei; Li, Qiang",Reservoir-scale study of oil shale hydration swelling and thermal expansion after hydraulic fracturing,Oil shale; Hydration swelling; Thermal expansion; Reservoir permeability; Permeability reduction,GAS; BEHAVIOR; PERMEABILITY; PYROLYSIS; WATER,"Volumetric expansion is a factor limiting oil shale exploitation via in situ pyrolysis because it affects the permeability of a reservoir. Most of the existing research on hydration swelling and thermal expansion involves core-scale experiments; however, it is also important to systematically study this topic at the reservoir scale. In this study, relevant field experiments between two wells were conducted to analyze the effects and mechanisms of hydration swelling and thermal expansion on reservoir permeability. The results showed that, after full hydration, the estimated permeability decreased by nearly 24% according to Darcy's law, depicting that hydration swelling had a weak effect on reservoir permeability. The microcracks induced by hydration were considered to weaken preexisting closed fractures. However, after heating the formation in a nitrogen atmosphere, the results showed that the estimated permeability decreased by nearly 52%. Even worse, after heating in an air atmosphere, the estimated permeability decreased by nearly 68%, and the high temperature produced by the combustion was considered to intensify the degree and range of thermal expansion in the oil shale. This study serves as a reference for follow-up oil shale exploitation via in situ pyrolysis.",3,3,11
Fracture,Hydraulic Fracture,"Jiang, Jiwei; Li, Jun; Liu, Gonghui; Lian, Wei; Xi, Yan; Yang, Hongwei; Li, Wai",Numerical simulation investigation on fracture debonding failure of cement plug/casing interface in abandoned wells,Abandoned wells; Cement plug/casing interface; Wellbore integrity; Fracture debonding height; Cohesive zone method,HYDRAULIC FRACTURE; FINITE-ELEMENT; COUPLED FLOW; WELLBORE; PLUG; PROPAGATION; INTEGRITY; PRESSURE; LEAKAGE; XFEM,"The fracture debonding failure of cement plug/casing interface caused by the migration of underground fluid with pressure accumulation imposed serious challenges to wellbore integrity of abandoned wells. This paper presents an investigation with a view of quantifying the relationships between the fracture debonding height and the migration time of underground fluid. A new 3D numerical model of cement plug/casing/cement sheath/formation system based on the cohesive zone method, which was validated by microannulus experiment, was developed to simulate the fracture debonding process. And then the relationships between fracture debonding height and propagation pressure was studied. Additionally, the influence of horizontal in-situ stress, cement plug mechanical parameters, and interface properties on the fracture debonding height and development geometry were also analyzed. The results of research indicated that the minimum horizontal in-situ stress played a decisive role in controlling the fracture propagation of cement/casing interface. Debonding fracture propagated along the whole circumference of the interface with the same height for the case that the horizontal in-situ stress was uniform, while propagated along a certain circumference angle of the interface with the maximum height in the direction of maximum horizontal principal stress for the case that the horizontal in-situ stress was non-uniform. The results of numerical analysis showed that lower elastic modulus and Poisson's ratio of cement plug, higher cement plug permeability, and larger critical normal strength and critical shear strength were beneficial to decrease the fracture debonding height and reduce the risk of debonding failure of the cement plug/casing interface. Finally, some effective measures to maintain the sealing integrity of abandoned wells were proposed.",3,3,5
Fracture,Hydraulic Fracture,"Han, Songcai; Cheng, Yuanfang; Gao, Qi; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Analysis of instability mechanisms of natural fractures during the approach of a hydraulic fracture,Hydraulic fracture propagation; Numerical simulation; Induced stresses; Pore pressure; Natural fracture stability; Arrested/crossing criterion,SHALE GAS; FLUID-FLOW; PROPAGATION; BEHAVIOR; MODEL; INTERFACES; SIMULATION; CRITERION; LEAKOFF,"A fluid-driven fracture propagation model dominated by viscosity-leak-off regime was presented to investigate the mechanical stability of natural fracture (NF) when hydraulic fracture (HF) approaches. The induced stresses generated by the approaching HF were calculated by a fully coupled integro-differential equation. The pore pressure effect caused by fracturing fluid leak-off was simulated based on dual porosity medium theory. The critical failure conditions of NF were determined based on maximum tensile criterion and Barton-Bandis criterion. The sensitivity of the stability of NF to in-situ stress anisotropy, approaching angle and distance, injection rate, fracturing fluid viscosity, and NF properties was analyzed in detail. Simulation results reveal that the shearing-mode failure of NF is obviously easier than the opening-mode failure, and the shear slip zone is much larger than the tensile failure zone. As HF approaches NF non-orthogonally, the induced debonding process is unstable, and the debonding zone is asymmetric with respect to the center of NF. The tensile-induced expansion zone is primarily located in the portion of NF ahead of the HF tip, however the shear-induced slip zone can even occur on NF behind of the HF tip. Induced stresses alone have negligible effect on the stability of the NF that is unconnected to the HF. The change in pore pressure due to leak-off effect dominates the final stimulated reservoir volume during large-scale fracturing. The instability of the NF dominates the propagation trajectory of the subsequent HF. A more suitable arrested/crossing condition by extending Gu-Weng criterion was established to predict the path of HF propagation.",3,3,3
Fracture,Hydraulic Fracture,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Fracture,Hydraulic Fracture,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Fracture,Hydraulic Fracture,"Hussain, Maaruf; Amao, Abduljamiu Olalekan; Al-Ramadan, Khalid; Negara, Ardiansyah; Saleh, Tawfik A.",Non-destructive techniques for linking methodology of geochemical and mechanical properties of rock samples,Geochemical; Mechanical properties; Rock; Well,HYDRAULIC FRACTURE PROPAGATION; COMPRESSIVE STRENGTH; POROSITY; EQUOTIP; FIELD; RESERVOIR; BEHAVIOR; SHALE,"Inadequate conventional core data, increasing cost of native sampling techniques, economic downturn in the oil sector, sparse distribution of modern well log suites in horizontal wells, and data acquisition challenges are few among the reasons driving innovation in the use of drill cuttings for determining rock properties and adequate characterization of reservoir units. In this paper, we propose a rock strength proxy based on the correlation between rock strength and elemental geochemistry. The technique uses a combination of X-ray fluorescence and rebound impulse hammer measurements to establish links between the geochemical and mechanical properties of the sampled rocks. We identified five chemo-mechanical facies (CMF) that are formation specific. Furthermore, a cross-validation approach was used to build a predictive model based on acquired elemental and impulse hammer measurements. Consequently, the model was used to predict elastic property and results were encouraging with R-2 of 0.83, 0.87, and 0.89 for training, validation, and testing respectively. This proposed method was developed using core plugs retrieved from subsurface formations. It will be useful for examples in rapid assessment of drill cuttings for the determination of rock strength, especially where the only available data is elemental geochemical data.",3,3,0
Fracture,Hydraulic Fracture,"Wang, HanYi; Sharma, Mukul M.",A rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure,In-situ stress; Pore pressure; Hydraulic fracturing; RIFT; DFIT; Effective fracture volume,ELASTIC COMPLIANCES; FRACTURE-COMPLIANCE; CAPROCK INTEGRITY; CONDUCTIVITY; STIMULATION; FIELD,"Extended leak-off test (XLOT) and pump-in and flow-back test (PIFB) are commonly used during drilling operations to estimate minimum stress. These estimates are adversely affected by hoop stress and drilling mud. Diagnostic Fracture Injection Tests (DFIT) can estimate both in-situ stress and pore pressure, but it takes days or weeks to conduct the test in low permeability formations. In this study, we present a novel rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure. Our new approach not only provides an unambiguous way to estimate in-situ stress (even in naturally fractured formations where DFIT fails to do so), but also allows us to estimate pore pressure with data from a test that lasts only a few hours, in addition, the effective fracture volume can also be estimated. Both simulations and field cases are presented to demonstrate the advantages of RIFT, along with a discussion of cautions and the potential pitfalls when designing and executing RIFT.",3,3,0
Fracture,Hydraulic Fracture,"Wang, Yujie; Zhang, Zhennan",Fully hydromechanical coupled hydraulic fracture simulation considering state transition of natural fracture,Hydraulic fracture; Natural fracture; Activation; Shear dilation; Cavity; Element partition method,FLOW; PERMEABILITY,"The natural fracture in the reservoir presents different properties in the inactivated and the activated state. To model the hydromechanical behaviors of the natural fractures in the two states, the element partition method (EPM) is employed. The EPM is a fracture simulation method, which allows a crack run across an element without introducing any extra degrees of freedom. For the element containing an inactivated fracture segment, it is treated as a potential partitioned element, but its permeability is related to the normal stress to the embedded fracture. A Mohr-Coulomb type of activation criterion is developed for the inactivated fracture. Once the fracture is activated, this potential element is transformed into a partitioned element. The constitutive relation with consideration of shear dilation and the fully hydromechanical coupled equation of a partitioned element are derived. Based on this method, the activation process of a fracture and its propagation are simulated. The simulation results suggest that the present method can capture the full hydromechanical properties of a natural fracture from its inactivated to activated state. Besides the natural fracture, the randomized cavities are another type of discontinuities in some reservoir. The effect of the cavity on hydraulic fracture(HF) is also considered. It is suggested that the cavity strongly repels the HF due to the surrounding stress concentration, but whether the HF can connect with the cavity depends. If there are some cracks adjunct to the cavity, the HF may connect with the cavity through these adjunct cracks. The simulation results suggest that the present method is a simple and efficient simulation method for the HF in the complex reservoir. It can comprehensively consider the behaviors of the natural fracture and cavity.",3,3,0
Fracture,Hydraulic Fracture,"Zhao, Bochao; Panthi, Krishna; Mohanty, Kishore K.",Tracer eluting proppants for hydraulic fracture characterization,Tracer; Proppant; Fracture characterization; Polymer coating; Hydraulic fracturing,DRUG-RELEASE,"Existing fracture characterization methods (e.g., microseismic) detect fractures created during hydraulic fracturing, but cannot determine whether the fractures are propped or not. The goal of this work is to develop a tracer-eluting proppant technique that can indicate the extent of propped fractures. A polymer coating is developed for common proppants which can release a tracer after being placed in a fracture. A small slug of coated proppants can be injected at the end or middle of the regular proppant injection during hydraulic fracturing. The released tracer can be collected during flow back and be used to better understand proppant location in fracture systems. Laboratory-scale batch tracer release experiments show that the tracer release can be triggered by an increase in temperature, salinity or pH. A proof of concept experiment was conducted in a model single fracture system. The tracer was successfully detected in the flow-back fluid and the tracer concentration was accurately estimated by a numerical tracer release model. The location of the tracer eluting proppants can be estimated from the peak tracer time in the flow-back water. This technique can be used for a wide range of proppants and tracers. Different tracers can be used in different stages.",2,2,9
Fracture,Hydraulic Fracture,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Fracture,Hydraulic Fracture,"Li, Yanliang; Peng, Jianming; Zhang, Guang; Yang, Zhenglong; Li, Keke",Study on perforation performance of abrasive water jet enhanced by percussive drilling,AWJ Perforation; Percussive drilling; Perforation performance; Impact cracks,HYDRAULIC FRACTURE INITIATION; GEOTHERMAL-ENERGY; PRESSURE; TECHNOLOGY; STIMULATION; MECHANISM; IMPACT; SHALE,"Geothermal energy is abundant and has a high economic development value. Perforation would need to be utilized to establish fluid channels between the borehole and geothermal reservoirs. In the present paper, it is proposed to use percussive drilling to create impact cracks near the borehole to improve abrasive water jet (AWJ) perforation performance. Two groups of the specimen were used for experiments. One was the specimen near the borehole after conventional rotary drilling (G1), the other was the specimen near the borehole after percussive drilling (G2). The optimal parameters of AWJ perforation assisted by percussive drilling were obtained. Through evaluation of AWJ perforation performance, it was found that the perforation depth, diameter and volume of G2 were 1.5 times, 1.3 times and 2 times of the G1, respectively. Besides, there were many internal cracks in G2, which interweave with each other and form a crack network. The results indicated that the impact cracks could change the mechanical properties of the granite near the borehole, then reduce the difficulty of AWJ perforation and improve the perforation performance. All the above merits can provide important technical support for reducing the fracturing pressure, increasing fluid flow and enhancing heat exchange efficiency between geothermal reservoir and borehole.",2,2,6
Fracture,Hydraulic Fracture,"Zhang, Kunpeng; Chen, Mian; Zhou, Changlin; Dai, Yifan; Liu, Fei; Li, Jiaxin",Study of alternating acid fracturing treatment in carbonate formation based on true tri-axial experiment,Carbonate; Unconventional reservoir; Hydraulic fracturing; Reservoir stimulation; Shale oil,LIMESTONE FORMATION; PROPAGATION,"Acid fracturing is a useful technique to stimulate carbonate reservoirs. Nowadays, acid leak-off becomes a vital problem during the operation of acid fracturing. In order to encounter this issue, alternating acid fracturing has been developed. However, the fracture propagation and the interaction between hydraulic fractures and natural fractures/caves during alternating acid fracturing are ambiguous. Hence, a series of alternating acid fracturing experiments covering coupling mechanics and chemical interaction were conducted for the first time. In this study, slick water, self-generating acid, cross-linked gel, and gelled acid were used as a fracturing fluid whereas the specimens for this experiment are carbonate outcrop which excavated from Dengsi Formation. The results show that: (1) acid fracturing can reduce fracturing pressure effectively as the acid will etch and weaken the natural fractures to let them easily connecting each other; (2) different pad fluid properties will have different impacts on the acid fracturing performance; (3) the interaction of hydraulic fractures and natural filled caves can be divided into five categories, and two of them had been observed in the experiments. Moreover, a new curvature-calculation algorithm has been developed based on the 3-D scanning technology. The results have a great significance for acid fracturing design and physical simulation experiments.",2,2,4
Fracture,Hydraulic Fracture,"Zeng, Fanhui; Zhang, Yu; Guo, Jianchun; Zhang, Qiang; Chen, Zhangxin; Xiang, Jianhua; Zheng, Yunchuan",Optimized completion design for triggering a fracture network to enhance horizontal shale well production,Horizontal shale well; Completion design; Modified alternate fracturing; Fracture network; Field application,HYDRAULIC FRACTURES; PERFORATION CLUSTERS; INITIATION PRESSURE; NATURAL-FRACTURE; BARNETT SHALE; FLUID-FLOW; PROPAGATION; GROWTH; COMPLEXITY; INTERFACES,"Horizontal well drilling accompanied by multicluster fracturing is unlocking shale gas resources. It is essential to create a large-scale fracture network connecting the reservoir to the wellbore by activating the preexisting natural fractures (NFs) through well completion optimization. Coupling the geomechanical characteristics of a shale formation to achieve the maximum stimulated reservoir volume (SRV), we develop a new completion optimization pattern for a single horizontal wellbore called modified alternate fracturing. The new model is a combination of conventional simultaneous and alternate fracturing. Unlike the previous studies that mainly concentrated on predicting the quasistatic dilation of NF failure, the presented paper assesses the dynamic evolution progression of NF growth under different failure criteria. Additionally, an analysis of how the modified alternate fracturing influences the fracture network is performed. The results demonstrate that a NF may be crossed, opened or slipped by an approaching hydraulic fracture (HF), depending on the tensile or shear stresses exerted on the NF. The combination of perforation parameter optimization and injection rate real-time control is able to utilize induced stresses to form a complex fracture network. A field application reveals that the modified well completion pattern performed better than conventional simultaneous fracturing due to increasing the near-wellbore and far-field fracture complexity. In addition, no additional equipment such as bridge plugs or coiled tubingis needed during operation, reducing potential issues.",2,3,3
Fracture,Hydraulic Fracture,"Mohammed, Auwalu, I; Oyeneyin, Babs; Bartlett, Mark; Njuguna, James",Prediction of casing critical buckling during shale gas hydraulic fracturing,Casing buckling; Rock slippage; Fracturing; In-situ stresses; Shale gas wells,DEFORMATION; FIELD; SIMULATION; FAILURE; BRITTLE; STRESS; DAMAGE; WELL; SLIP,"Casing deformation during volume fracturing in shale gas horizontal wells is caused by both existing and induced stresses. These stresses jointly alter and compound the stress field around the casing leading to inefficient well stimulation as planned, lack of access into the well for recompletion, future workovers and present imminent danger of well integrity. Using two simulation scenarios, casing structural integrity was investigated in both radial and axial configurations under the mechanics of a combine system - casing, cement and formation rock. Results obtained show that time dependent rock slippage - creep during stimulation lead to an increase transverse displacement and corresponding stresses on the casing. In addition, the effect of combined loading results in significant increase in both displacements and stresses that can cause radial and axial permanent failure of the casing. This explains the lack of access into the casing during multi-stage hydraulic fracturing and future well intervention and recompletions and increased current understating of the downhole dynamics and casing structural integrity during volume fracturing. This new understanding is a major breakthrough in establishing casing health status during shale gas well stimulation.",2,2,2
Fracture,Hydraulic Fracture,"Gao, Jiajia; Li, Qian; Deng, Jingen; Tang, Hongming; Yin, Hu; Yan, Xinjiang",Initiation of hydraulically or drilling-induced tensile wall-fractures from arbitrarily inclined boreholes: Implications for constraints in the magnitudes of in-situ stresses,Fracture initiation pressure; Fracture initiation position; Fracture trace angle; Transverse hydraulically induced tensile wall-fractures; Critical borehole inclination or azimuth angles,WELL BORE BREAKOUTS; BASIN; ORIENTATION; STATE; INVERSION; FIELD; PROPAGATION; EXPLORATION; STABILITY; PRESSURE,"An accurate estimation of the magnitudes of three in-situ stresses can usefully improve the production performance of hydraulic fracturing and reduce the risk of wellbore instability. Considering two types of linear elastic stress around the non-perforated arbitrarily inclined borehole (plane strain and plane stress conditions), the theory of hydraulic fracturing, and the maximum tensile criterion, the generalized governing formulas are derived to explain the mechanism of hydraulically or drilling-induced longitudinal, oblique, and transverse tensile wall-fractures in arbitrarily inclined boreholes. These formulas provide useful implications for constraints on the magnitudes of in-situ stresses, which determine the initiation of different types of tensile wall-fractures under different faulting stress regimes. The present paper extends the initiating conditions of the common transverse tensile wall-fractures related to the works of Hossain et al. (2000) and Nelson et al. (2005). The prerequisite for the special transverse tensile wall-fractures that tensile fractures simultaneously initiated around a whole borehole wall (Huang et al., 2012) is generalized by introducing the concept of the turning locations. The formulas corresponding to the turning locations are provided under different faulting stress regimes, revealing that the work proposed by Huang et al. (2012) is only a particular case. It is found that the turning locations are related to the critical borehole inclination or azimuth angles. Overall, all the formulas in this study for longitudinal, oblique, and transverse tensile wall-fractures can be used to design hydraulic fracturing experiments and to determine the in-situ stress by using the information of drilling-induced tensile wall-fractures. Moreover, the governing formulas of the turning locations can also be used to optimize the borehole trajectory.",2,2,2
Fracture,Hydraulic Fracture,"Okesanya, Temi; Abdukarimov, Aibek; Kuru, Ergun",Generalized models for predicting the drag coefficient and settling velocity of rigid spheres in viscoelastic and viscoinelastic power-law fluids,Settling velocity; Elasticity; Non-Newtonian fluids; Particle Transport; Modeling,SPHERICAL-PARTICLES; DRILLING-FLUIDS; BED EXPANSION; ELASTICITY; CUTTINGS; FALL; FLOW,"The design and optimization of several fluid-particle transport systems often require the determination of particle settling velocity in non-Newtonian fluids. These fluid-particle transport systems are encountered in a wide variety of industrial processes including drill cuttings transport in oil and gas well drilling operations and proppant transport in hydraulic fracturing operations. Current conventional approaches to estimate settling velocity in these non-Newtonian fluids often exclude the effect of elasticity on particle settling which can lead to erroneous estimation. It is therefore imperative to devise an accurate means to mathematically account for the fluid elasticity in particle settling in viscoelastic fluids. An experimental study was conducted to measure the settling velocity of spherical particles in viscoelastic and viscoinelastic power-law type fluids. Using a semi-mechanistic approach, explicit mathematical models were developed for estimating drag coefficient and particle settling velocity in viscoelastic fluids and viscoinelastic fluids. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoelastic and viscoinelastic power-law type fluids intended at augmenting the present corpus of experimental data in literature. ii.) To develop new drag coefficient and particle Reynolds number correlations that are applicable to viscoelastic and viscoinelastic power-law type fluids and, iii.) To present a general explicit approach for predicting settling velocities of particles in viscoelastic and viscoinelastic fluids. Particle Image Shadowgraphy (PIS) was used to measure the settling velocities of the spherical particles (Specific gravity 2.5-7.7; Diameters: 0.71-4.00 mm) in Hydrolyzed Polyacrylamide and Tylose solutions of varying elastic properties. Rheological characterization of the fluids was carried out using the C-VOR Bohlin Rheometer. Experimental results from this study were combined with various data published in the literature to create an extensive database and widen the scope for empirical analysis. The database had a consistency index (k) range of 0.012-6.773 Pa.s(n) and a fluid behavior index (n) range of 0.370-0.940. New drag coefficient and Reynold number correlations for particles settling in viscoelastic and viscoinelastic power-law fluids were developed by using a semi-mechanistic approach, which also included the fluid elasticity effect quantified in terms of the longest relaxation time. The newly developed correlations and an advanced statistical modeling program (OriginPro 9.0) were used to mathematically create explicit models that can be used for predicting particle settling velocity in viscoelastic and viscoinelastic fluids. Comparative analysis showed that an increase in the fluid elasticity gave a corresponding decrease in the particle Reynolds number and dampened the particle settling velocity in viscoelastic fluids. This dampening effect can be attributed to the unique ability of elastic fluids to partially or fully regain their original structure after deformation. Furthermore, statistical analysis showed that the presented new models predict settling velocity accurately with a very low with a Percentage Mean Absolute Error of about 7.5% and 30% for viscoinelastic and viscoelastic fluids respectively. The proposed models also exhibited Root Mean Square Error (RMSE) values of 0.04 m/s and 0.009 m/s for viscoinelastic and viscoinelastic fluids respectively.",2,2,1
Fracture,Hydraulic Fracture,"Gul, Kiymet Gizem; Onur, Mustafa; Ozkan, Erdal","Linear superposition time for variable-rate, variable-pressure production from a fractured tight gas well",Perturbation method; Green's function; Superposition time; Pseudo-pressure; Tight gas well performance,FLOW,"Hydraulically fractured, tight gas wells produce under large pressure drawdowns, which may cause three-to ten-fold variations in the gas viscosity-compressibility product, particularly in the vicinity of the fracture, over the life of the production. Under such a large variation, the pseudo-pressure transformation cannot remove nonlinearity of the gas diffusion equation. The remaining nonlinearity makes the application of superposition principal questionable; specifically the linear superposition time based on linear flow, a dominant flow regime for hydraulically fractured tight gas reservoirs. Not accounting for the effect of large gas viscosity-compressibility product variations in pressure and rate transient analysis of fractured, tight gas well performances leads to misinterpretation of reservoir characteristics. In this paper, a perturbation-Green's function solution is developed for the nonlinear gas diffusion equation. Because each term in the perturbation solution represents the solution for a linearized problem, term-by-term application of the superposition principal is permitted. The semi-analytical nature of the solution also enables us to derive approximations for practical use. This paper explains the solution procedure, compares and verifies the solution with existing simulators presents variable-rate approximations in terms of new superposition time and discusses the results to provide guidelines for the analysis of fractured, tight gas well performances under large variations of viscosity and compressibility.",2,2,0
Fracture,Hydraulic Fracture,"Liu, Qingling; Tian, Shouceng; Yu, Wei; Li, Gensheng; Sheng, Mao; Sepehrnoori, Kamy; Wang, Tianyu",A semi-analytical model for simulation of multiple vertical wells with well interference,Tight oil reservoir; Semi-analytical model; Well interference; Multiple well; Fracture hit,MULTIFRACTURED HORIZONTAL WELLS; SHALE-GAS-WELLS; FLOW; FRACTURES; RESERVOIR; PRESSURE; BEHAVIOR; ROCK,"Hydraulic fracturing is widely applied to develop tight oil reservoirs, and it is significant to diagnose fracture hit to determine optimal well spacing. Pressure test is an effective method to determine fracture hit in a multi-well system. In this study, we developed a semi-analytical model to quickly identify fracture hit in multiple vertical well system in tight oil reservoir. This semi-analytical model involves several steps, i.e., prior production step of parent wells, pressure build-up step, and interference test step. The model was verified by a numerical reservoir simulator for single well and multiple wells. Then, based on the model, the well interference by fracture hit in a three-well system (two parent wells and one child well) is discussed. Results show that the developed semianalytical model could efficiently simulate the entire production process of a multi-well system, quickly diagnose fracture hit by using pressure interference test data and determine the optimal shut-in time of parent well. The practicability of model lies in that the reservoir pressure depletion by prior production of parent wells is considered. Besides, it is found shutting down the parent well is very necessary to diagnose fracture hit when the child well is infilled. When the shut-in parent well is connected to producing child well, the pressure build-up process of parent well is terminated with the bottom hole pressure reducing continuously. What is more, the shut-in time of parent wells should be sufficient to better detect the fracture hit, especially under the condition that parent wells have produced for a long time or the connectivity among wells is weak. This work can provide critical insights into understanding the mechanism of well interference by fracture hit in a multi-well system.",1,1,5
Fracture,Hydraulic Fracture,"Chen, Zhiming; Liao, Xinwei; Zeng, Lianbo",Pressure transient analysis in the child well with complex fracture geometries and fracture hits by a semi-analytical model,Unconventional reservoirs; Fracture hits; Fracture networks; Pressure transient analysis; Semi-analytical model,HORIZONTAL WELLS; SIMULATION; FLOW,"Recently, the model development of pressure transient analysis in wells with large-scale fracturing treatments has attracted more and more attention. However, a little work has involved the complex fracture networks with fracture hits. In this study, the transient pressure behaviors of a child well with complex fracture geometries and fracture hits are studied, using an efficient semi-analytical model. The semi-analytical model has the capability to simulate shale well performance by considering complex non-planar hydraulic fractures and fracture hits. The pressure transient solution of the semi-analytical model is obtained by the incorporation of nodal analysis and Laplace transforms. After the numerical verification of the proposed semi-analytical model, we apply it to analyze the pressure testing data of a child well and a parent well. Through conducting a series of history matching, the most likely fracture parameters of the child well is determined. Results show that the flow regimes of complex fracture geometries with fracture hits include wellbore storage, skin effect, fracture bilinear flow, ""fluid feed"", pseudo-boundary dominated flow, unconnected fracture (UF) impact, and pseudo radial flow. During the flow regime of UF impact, the pressure derivative curves exist a second ""V-shape"", as the UF improve the matrix permeability and the pressure depletion will be reduce once the flow reaches the UF. A case study in the Lucaogou shale oil reservoir from the Junggar Basin show that complex fracture geometries is developed along the child wellbore. After estimation, the fracture hits between the parent well and child well may via five hitting fractures. The length and conductivity of the hitting fractures are evaluated as 20 m and 120 mD.m, respectively. This work could be beneficial to performance forecast and well spacing optimization in unconventional reservoirs.",1,1,3
Fracture,Hydraulic Fracture,"Mao, Yilin; Zeidouni, Mehdi; Godefroy, Caroline; Gysen, Michel",Fracture diagnostic using distributed temperature measurements during a pause in flow-back period,Fracture diagnostic; Stimulation fluid flow-back; Hydraulic fracturing; Distributed temperature measurement,HORIZONTAL WELLS; FLUID TEMPERATURE; WELLBORE; STIMULATION; RESERVOIR; PRESSURE; MODELS,"The significant temperature difference between the fractured and non-fractured regions during the stimulation fluid flow-back period can be very useful for fracture diagnosis. The recent developments in downhole temperature monitoring systems open new possibilities to detect these temperature variations to perform production logging analyses. In this work, we derive a novel analytical solution to model the temperature signal associated with the shut-in during flow-back and production periods. The temperature behavior can infer the efficiency of each fracture. To obtain the analytical solution from an existing wellbore fluid energy balance equation, we use the Method of Characteristics with the input of a relevant thermal boundary condition. The temperature modeling results acquired from this analytical solution are validated against those from a finite element model for multiple cases. Compared to the warm-back effect in the non-fractured region after shut-in, a less significant heating effect is observed in the fractured region because of the warmer fluid away from the perforation moving into the fracture (after-flow). Detailed parametric analyses are conducted on after-flow velocity and its variation, flowing, geothermal, and inflow temperature of each fracture, surrounding temperature field, and casing radius to investigate their impacts on the wellbore fluid temperature modeling results. The inversion procedures characterize each fracture considering the exponential distribution of temperature based on the analytical solutions in fractured and non-fractured regions. Inflow fluid temperature, surrounding temperature field, and after-flow velocity of each fracture can be estimated from the measured temperature data, which present decent accuracies analyzing synthetic temperature signal. The estimations are independent on each cluster, which can be combined to analyze the entire production section. The outputs of this work can contribute to production logging, warm-back, and wellbore storage analyses to achieve successful fracture diagnostic.",1,1,2
Fracture,Hydraulic Fracture,"Moussa, Tamer; Dehghanpour, Hassan; Fu, Yingkun; Ezulike, Obinna",The use of flowback data for estimating dynamic fracture volume and its correlation with completion-design parameters: Eagle Ford cases,Initial effective fracture volume; Characteristic fracture-closure rate; Multivariate analysis; Multiple linear regression analysis; Completion design parameters; Flowback data analysis,,"Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (V-ef), and 2) investigate the existence of correlations between CDPs and V-ef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume (V-efi) using harmonic-decline (HD)model. Second, we estimate the loss in V-ef (V-loss) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast V-ef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with V-efi and FCR. The developed correlation between V-efi and CDPs shows that the gross perforated interval (GPI) has the most significant effect on V-efi. The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.",1,1,1
Fracture,Hydraulic Fracture,"Zeng, Zhengwen; Harouaka, Abdallah",A new method for assessing stage-based hydraulic fracturing quality in Wolfcamp formation of Permian Basin,Permian basin Wolfcamp formation; Largest tight oil play in the world; Slick-water hydraulic fracturing; Stage-by-stage fracturing quality; Stress-shadow effects,WELL; PERFORMANCE,"In 2018 US Geological Survey assessed Wolfcamp formation in Permian Basin at west Texas and southwest New Mexico, USA as the world's largest tight oil play that has the most technically recoverable reserves. This is the result of favorable combination of tectonic activities and the depositional environments in the Paleozoic period. Three major cycles of tectonic movements controlled the creation of Permian Basin and its sub-basins. Frequent seawater inundations and retreats caused cyclic changes in depositional environments from Pennsylvania to early Permian ages, leading to the formation of an organic rich, tight and thick formation, the highly heterogeneous Wolfcamp play. Advanced completion technology of combining horizontal drilling with multi-stage massive hydraulic fracturing is needed for the commercial development of Wolfcamp play. Successful application of advanced completion technology in Wolfcamp faces two challenges: stage-after-stage cumulative stressshadow effects and localized heterogeneity in lithofacies and reservoir quality. The ""one-for-all"" fracturing design needs to be able to fine-tune stage-by-stage based on real-time feedback from fracturing quality of previous stage. Existing methods, from production logging to micro-seismic mapping, cannot provide real-time feedback of stage-based treatment quality. We propose a new method in this paper. The new method is based on the assumption that constant density of slick-water at shut-in intervals during hydraulic fracturing allows an accurate calculation of bottom-hole pressure from surface treatment pressure and true vertical depth at each stage. Using real-time on-site monitored surface treatment pressures during shut-in intervals at the end of pad and flush injections, stage-by-stage fracturing quality are calculated. Two Wolfcamp case studies in Midland Basin at Reagan County, Texas show that the new method can be used to quantify stage-based treatment qualities. Stage-based fracturing qualities from this new method are consistent with stage-based treatment results evaluated using other methods.",1,1,1
Fracture,Hydraulic Fracture,"Artun, E.",Performance assessment and forecasting of cyclic gas injection into a hydraulically fractured well using data analytics and machine learning,Cyclic gas injection; Data analytics; Enhanced oil recovery; Hydraulically fractured wells; Machine learning; Performance forecasting,NITROGEN,"Single-well application of cyclic gas injection is a promising enhanced oil recovery method especially in fractured and depleted reservoirs. It was previously shown that presence of hydraulic/natural fractures would increase the effectiveness of this method because of the surface area of fractures that supports gas diffusion into the rock matrix. Increased pressure and changes in the physical properties of oil after injection both contribute to improved oil recovery. In this study, a comprehensive analysis of the performance-related design aspects of kcyclic injection of a mixture of N-2, CO2 and CH4 in a hydraulically-fractured well is presented. These three types of gases can contribute to different mechanisms for enhanced recovery because of their unique phase behavior. On the other hand, their costs and availability may be different which may lead to different economic benefits. For the proposed analysis, a large number of injection scenarios were run using a compositional reservoir model that represents the drainage area of a hydraulically fractured well in a low-permeability reservoir. Design parameters such as the injection rate, duration (and volume), soaking duration, economic rate limit, and injected gas composition are varied with uniformly distributed values of each parameter within pre-defined ranges. Both volumetric and economic utilization efficiency factors are analyzed as the performance indicators. Discounted values of incremental oil produced, volume of injected gas, oil price and costs of injected gas for varying project periods of 5, 10, 15 and 20 years are considered for the efficiency calculations. It is observed that the presented method can be a cost-effective enhanced recovery method for hydraulically-fractured wells depending on the proper selection of operational conditions. Injection volume should be kept below 10,000 MCF per cycle. Economic rate limit and soaking period should be optimized. While N-2 is more cost effective than other gases, it mostly provides short-term benefits. The data set is used to train a neural network that can be used to forecast the economic efficiency indicator. Results show that machine learning is an effective approach to develop accurate forecasting models. R-2 values greater than 0.90 are observed for the correlation between real and predicted values for both training and testing, regardless of design considerations of the neural network.",1,1,1
Fracture,Natural Fracture,"Khodadadi, Behayeen; Siddiqui, Mohammed Abdul Qadeer; Pirzada, Muhammad Asad; Le-Hussain, Furqan; Iglauer, Stefan; Roshan, Hamid",Direct observation of two-phase flow in deformable fractures of shales: A Utica shale example,Shale; Fracture; Microfluidic; Two-phase flow; Wettability; Utica; Deformation,DYNAMIC CONTACT-ANGLE; SURFACE WETTABILITY; CAPILLARY RISE; ROUGHNESS; ROCK; IMBIBITION; DEPENDENCE; INSIGHTS; WATER,"Despite the success of hydrocarbon production from unconventional shale reservoirs, the physical processes controlling the production are not yet fully understood. The wettability controlling the two-phase flow in deformable natural fractures of shale is among the processes that still need special attention. With the advances of optical technologies, microfluidics can now be used to observe, measure, and analyse the dynamic changes of flow in fractured systems. However, mimicking the natural wall roughness of the fractures with high precision and having flexibility to allow fracture deformation has remained challenging. We have therefore developed a new microfluidic technique to create tensile fractures in shale with subsurface representative random geometries and roughness, and then observed two-phase flow in these deformable fractures at a high resolution for Utica shale. During the two-phase flow, dynamic contact angles of water-oil in the fractures with varying apertures of 60-100 mu m were measured and analysed. Significant contact angle hysteresis was observed when oil displaced water out of the fracture and vice versa. Interestingly, water completely displaced the oil out of the fracture through spontaneous imbibition, although its contact angle in the fracture varied from 20 degrees to 90 degrees. The water velocity in the fracture was found to be correlated to the observed contact angles during the spontaneous imbibition test. The large change in the contact angle was further investigated using fluorescence tracking where patches of oil were observed to remain on the fracture wall despite its water wetness. It was then shown through further investigations that the formation of these oil patches was primarily controlled by mineral heterogeneity than wall roughness.",3,3,4
Fracture,Natural Fracture,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Fracture,Natural Fracture,"Han, Songcai; Cheng, Yuanfang; Gao, Qi; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Analysis of instability mechanisms of natural fractures during the approach of a hydraulic fracture,Hydraulic fracture propagation; Numerical simulation; Induced stresses; Pore pressure; Natural fracture stability; Arrested/crossing criterion,SHALE GAS; FLUID-FLOW; PROPAGATION; BEHAVIOR; MODEL; INTERFACES; SIMULATION; CRITERION; LEAKOFF,"A fluid-driven fracture propagation model dominated by viscosity-leak-off regime was presented to investigate the mechanical stability of natural fracture (NF) when hydraulic fracture (HF) approaches. The induced stresses generated by the approaching HF were calculated by a fully coupled integro-differential equation. The pore pressure effect caused by fracturing fluid leak-off was simulated based on dual porosity medium theory. The critical failure conditions of NF were determined based on maximum tensile criterion and Barton-Bandis criterion. The sensitivity of the stability of NF to in-situ stress anisotropy, approaching angle and distance, injection rate, fracturing fluid viscosity, and NF properties was analyzed in detail. Simulation results reveal that the shearing-mode failure of NF is obviously easier than the opening-mode failure, and the shear slip zone is much larger than the tensile failure zone. As HF approaches NF non-orthogonally, the induced debonding process is unstable, and the debonding zone is asymmetric with respect to the center of NF. The tensile-induced expansion zone is primarily located in the portion of NF ahead of the HF tip, however the shear-induced slip zone can even occur on NF behind of the HF tip. Induced stresses alone have negligible effect on the stability of the NF that is unconnected to the HF. The change in pore pressure due to leak-off effect dominates the final stimulated reservoir volume during large-scale fracturing. The instability of the NF dominates the propagation trajectory of the subsequent HF. A more suitable arrested/crossing condition by extending Gu-Weng criterion was established to predict the path of HF propagation.",3,3,3
Fracture,Natural Fracture,"Cai, Can; Kang, Yong; Yang, Yingxin; Wang, Xiaochuan; Li, Yang; Huang, Man; Wu, Jiwei",The effect of shale bedding on supercritical CO2 jet fracturing: A experimental study,Shale bedding; Supercritical carbon dioxide jet fracturing; Fracture morphology; Perforation damage,CARBON-DIOXIDE; ACOUSTIC-EMISSION; GAS; SEQUESTRATION; PRESSURE; RECOVERY; STORAGE; PROPAGATION; SATURATION; ADSORPTION,"The bedding plane of shale is related to anisotropic mechanical property, which apparently affects the shale fracturing. To investigate the influence of shale bedding on the fracture morphology and perforation damage under Supercritical Carbon Dioxide (SC-CO2) jet fracturing, the experiments were comprehensively studied via the macro fracture analysis, strain monitoring, Scanning Electron Microscope (SEM) test and Energy Dispersive Spectroscopy (EDS) test. The results demonstrated that the average Young's Modulus (YM) and Uniaxial Compressive Strength (UCS) of shale specimen with the bedding plane angle of 0 degrees is 9.37 times and 2.89 times of the shale specimen with bedding plane angle of 90 degrees, respectively. During jet fracturing, both the jet pressure and existing bedding are beneficial for fracture initiating and propagating naturally along the weak bedding planes, and shear fracture can enhance the fracture complexity. When the perforation distributes in the direction perpendicular to the bedding plane, the less strain can be obtained, and the mass loss and CO2 absorption of shale specimen significantly increase by 350% and 300%, respectively, as the jet pressure increases from 25 MPa to 50 MPa, which is larger than the shale specimen with bedding plane angle of 0 degrees. The perforation damage is explored after jet fracturing via SEM and EDS, and it is found the direction of perforation perpendicular to the bedding plane is beneficial for micro-cracks generation, and leads to 10% decline of carbon (C) and oxygen (O) elements in the samples. These studies clearly show the influence of the bedding plane angle on the fracture morphology and perforation damage, which are crucial for SC-CO2 fracturing and CO2 storage in shale reservoir.",3,3,3
Fracture,Natural Fracture,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Fracture,Natural Fracture,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Fracture,Natural Fracture,"Bouquet, Sarah; Douarche, Frederic; Roggero, Frederic; Bourbiaux, Bernard",Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization,Enhanced oil recovery; Naturally fractured reservoir; Oil-wet; Foam; Multiphase flow; Capillary pressure; Interfacial tension; Reservoir simulation; Mobility reduction; Dual-medium; Viscous forces,SIMULATION,"In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction. Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale. This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals. This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ""low-IFT"" effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.",3,3,0
Fracture,Natural Fracture,"Wang, HanYi; Sharma, Mukul M.",A rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure,In-situ stress; Pore pressure; Hydraulic fracturing; RIFT; DFIT; Effective fracture volume,ELASTIC COMPLIANCES; FRACTURE-COMPLIANCE; CAPROCK INTEGRITY; CONDUCTIVITY; STIMULATION; FIELD,"Extended leak-off test (XLOT) and pump-in and flow-back test (PIFB) are commonly used during drilling operations to estimate minimum stress. These estimates are adversely affected by hoop stress and drilling mud. Diagnostic Fracture Injection Tests (DFIT) can estimate both in-situ stress and pore pressure, but it takes days or weeks to conduct the test in low permeability formations. In this study, we present a novel rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure. Our new approach not only provides an unambiguous way to estimate in-situ stress (even in naturally fractured formations where DFIT fails to do so), but also allows us to estimate pore pressure with data from a test that lasts only a few hours, in addition, the effective fracture volume can also be estimated. Both simulations and field cases are presented to demonstrate the advantages of RIFT, along with a discussion of cautions and the potential pitfalls when designing and executing RIFT.",3,3,0
Fracture,Natural Fracture,"Wang, Yujie; Zhang, Zhennan",Fully hydromechanical coupled hydraulic fracture simulation considering state transition of natural fracture,Hydraulic fracture; Natural fracture; Activation; Shear dilation; Cavity; Element partition method,FLOW; PERMEABILITY,"The natural fracture in the reservoir presents different properties in the inactivated and the activated state. To model the hydromechanical behaviors of the natural fractures in the two states, the element partition method (EPM) is employed. The EPM is a fracture simulation method, which allows a crack run across an element without introducing any extra degrees of freedom. For the element containing an inactivated fracture segment, it is treated as a potential partitioned element, but its permeability is related to the normal stress to the embedded fracture. A Mohr-Coulomb type of activation criterion is developed for the inactivated fracture. Once the fracture is activated, this potential element is transformed into a partitioned element. The constitutive relation with consideration of shear dilation and the fully hydromechanical coupled equation of a partitioned element are derived. Based on this method, the activation process of a fracture and its propagation are simulated. The simulation results suggest that the present method can capture the full hydromechanical properties of a natural fracture from its inactivated to activated state. Besides the natural fracture, the randomized cavities are another type of discontinuities in some reservoir. The effect of the cavity on hydraulic fracture(HF) is also considered. It is suggested that the cavity strongly repels the HF due to the surrounding stress concentration, but whether the HF can connect with the cavity depends. If there are some cracks adjunct to the cavity, the HF may connect with the cavity through these adjunct cracks. The simulation results suggest that the present method is a simple and efficient simulation method for the HF in the complex reservoir. It can comprehensively consider the behaviors of the natural fracture and cavity.",3,3,0
Fracture,Natural Fracture,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Fracture,Natural Fracture,"Sie, Chao-Yu; Nguyen, Quoc P.",A pore-scale experimental study of non-aqueous foam for improving hydrocarbon miscible flooding,Non-aqueous foam; Hydrocarbon soluble foaming surfactants; Natural gas liquids flooding; Sweep efficiency; Conformance control; Microfluidics,VISCOUS OIL-RECOVERY; FRACTURED RESERVOIRS; SOLVENT INJECTION; FLOW; DISPLACEMENT; SOLUBILITY; GENERATION; DEPOSITION; MOBILITY,"Mobility control in hydrocarbon miscible flooding is crucial for commercial vitality where severe reservoir heterogeneity causes poor sweep efficiency. This study introduced a new concept of non-aqueous foam-assisted hydrocarbon miscible flooding in water-sensitive oil formations. This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and a raw mixture of NGLs (MNGLs) with a foaming additive to improve displacement and sweep efficiency. Foaming a light hydrocarbon liquid and the impact of non-aqueous foam on miscible displacement are the main focuses of this study. n-Pentane was used as a MNGLs (solvent) model for foam stability tests. Transient foam propagation and rheology were directly visualized and characterized based on the apparent gas (nitrogen) viscosity associated with foam texture and fluid saturations. Oil recovery factors were directly related to different degrees of in-situ foaming. For the injection of a solvent slug followed by a gas drive, the displacement of oil became unstable as nitrogen fingered through the solvent-oil mixing zone, resulting in a high residual liquid saturation. However, gas fingering was significantly hindered as the solvent was injected with a foaming agent. Dynamic fluid distribution indicate that the improved oil recovery could be attributed to the propagation of foam in the swept zone, which provided essential flow resistance for better displacement stability. To investigate the effect of initial gas saturation in the reservoir on flow behavior, a slug of gas was injected before solvent injection. Delayed solvent breakthrough and better sweep efficiency were observed in the presence of foam due to the reduced liquid phase mobility in preferential flow paths and the diversion of solvent into small pores by the trapped gas at the displacing front. Furthermore, it was possible to obtain stable foam flow with an apparent viscosity of 20 times greater than the solvent viscosity.",2,2,6
Fracture,Natural Fracture,"Zhang, Kunpeng; Chen, Mian; Zhou, Changlin; Dai, Yifan; Liu, Fei; Li, Jiaxin",Study of alternating acid fracturing treatment in carbonate formation based on true tri-axial experiment,Carbonate; Unconventional reservoir; Hydraulic fracturing; Reservoir stimulation; Shale oil,LIMESTONE FORMATION; PROPAGATION,"Acid fracturing is a useful technique to stimulate carbonate reservoirs. Nowadays, acid leak-off becomes a vital problem during the operation of acid fracturing. In order to encounter this issue, alternating acid fracturing has been developed. However, the fracture propagation and the interaction between hydraulic fractures and natural fractures/caves during alternating acid fracturing are ambiguous. Hence, a series of alternating acid fracturing experiments covering coupling mechanics and chemical interaction were conducted for the first time. In this study, slick water, self-generating acid, cross-linked gel, and gelled acid were used as a fracturing fluid whereas the specimens for this experiment are carbonate outcrop which excavated from Dengsi Formation. The results show that: (1) acid fracturing can reduce fracturing pressure effectively as the acid will etch and weaken the natural fractures to let them easily connecting each other; (2) different pad fluid properties will have different impacts on the acid fracturing performance; (3) the interaction of hydraulic fractures and natural filled caves can be divided into five categories, and two of them had been observed in the experiments. Moreover, a new curvature-calculation algorithm has been developed based on the 3-D scanning technology. The results have a great significance for acid fracturing design and physical simulation experiments.",2,2,4
Fracture,Natural Fracture,"Zeng, Fanhui; Zhang, Yu; Guo, Jianchun; Zhang, Qiang; Chen, Zhangxin; Xiang, Jianhua; Zheng, Yunchuan",Optimized completion design for triggering a fracture network to enhance horizontal shale well production,Horizontal shale well; Completion design; Modified alternate fracturing; Fracture network; Field application,HYDRAULIC FRACTURES; PERFORATION CLUSTERS; INITIATION PRESSURE; NATURAL-FRACTURE; BARNETT SHALE; FLUID-FLOW; PROPAGATION; GROWTH; COMPLEXITY; INTERFACES,"Horizontal well drilling accompanied by multicluster fracturing is unlocking shale gas resources. It is essential to create a large-scale fracture network connecting the reservoir to the wellbore by activating the preexisting natural fractures (NFs) through well completion optimization. Coupling the geomechanical characteristics of a shale formation to achieve the maximum stimulated reservoir volume (SRV), we develop a new completion optimization pattern for a single horizontal wellbore called modified alternate fracturing. The new model is a combination of conventional simultaneous and alternate fracturing. Unlike the previous studies that mainly concentrated on predicting the quasistatic dilation of NF failure, the presented paper assesses the dynamic evolution progression of NF growth under different failure criteria. Additionally, an analysis of how the modified alternate fracturing influences the fracture network is performed. The results demonstrate that a NF may be crossed, opened or slipped by an approaching hydraulic fracture (HF), depending on the tensile or shear stresses exerted on the NF. The combination of perforation parameter optimization and injection rate real-time control is able to utilize induced stresses to form a complex fracture network. A field application reveals that the modified well completion pattern performed better than conventional simultaneous fracturing due to increasing the near-wellbore and far-field fracture complexity. In addition, no additional equipment such as bridge plugs or coiled tubingis needed during operation, reducing potential issues.",2,3,3
Fracture,Natural Fracture,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Fracture,Natural Fracture,"Gul, Kiymet Gizem; Onur, Mustafa; Ozkan, Erdal","Linear superposition time for variable-rate, variable-pressure production from a fractured tight gas well",Perturbation method; Green's function; Superposition time; Pseudo-pressure; Tight gas well performance,FLOW,"Hydraulically fractured, tight gas wells produce under large pressure drawdowns, which may cause three-to ten-fold variations in the gas viscosity-compressibility product, particularly in the vicinity of the fracture, over the life of the production. Under such a large variation, the pseudo-pressure transformation cannot remove nonlinearity of the gas diffusion equation. The remaining nonlinearity makes the application of superposition principal questionable; specifically the linear superposition time based on linear flow, a dominant flow regime for hydraulically fractured tight gas reservoirs. Not accounting for the effect of large gas viscosity-compressibility product variations in pressure and rate transient analysis of fractured, tight gas well performances leads to misinterpretation of reservoir characteristics. In this paper, a perturbation-Green's function solution is developed for the nonlinear gas diffusion equation. Because each term in the perturbation solution represents the solution for a linearized problem, term-by-term application of the superposition principal is permitted. The semi-analytical nature of the solution also enables us to derive approximations for practical use. This paper explains the solution procedure, compares and verifies the solution with existing simulators presents variable-rate approximations in terms of new superposition time and discusses the results to provide guidelines for the analysis of fractured, tight gas well performances under large variations of viscosity and compressibility.",2,2,0
Fracture,Natural Fracture,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Fracture,Natural Fracture,"Li, Ben; Zhou, Fujian; Fan, Wentong; Ren, Dengfeng; Li, Hui; Li, Ming",Experimental investigation and theoretical modeling of stress-dependent permeability in naturally fractured tight gas reservoir,Stress-dependent permeability; Pressure pulse decay method; Modified power-law model; Naturally fractured sandstone; Regression analysis,SANDSTONE; PRESSURE; POROSITY,"Stress-dependent permeability (SDP) of naturally fractured tight gas reservoir (NFTGR) has drawn considerable attention in recent decades. The SDP of natural fracture (NF) is quite different from that of the rock matrix (RM) due to the variance NF width and NF filling degree. The SDP of naturally fractures can be obtained by conducting permeability measurement experiments on naturally fractured core plugs (NFCP). However, it is usually impossible to obtain downhole NFCPs due to economic and technical limitations. Our research group obtained various types of naturally fractured downhole core plugs from a NFTGR (Tarim filed, China) and make it possible to investigate the effect of NFs on SDP. The NF types of the downhole core plugs include RM core plug (RMCP), unpenetrated-ring fractured core plug (URFCP), penetrated-vertical fractured core plug (PVFCP), penetrated-incline fractured core plug (PIFCP), unpenetrated-U-type fractured core plug (UUFCP), and multiple fractured core plug (MFCP). We conducted SDP experiments through the application of pressure-pulse-decay (PPD) method. Results showed that the initial permeability of RMCP and MFCP were higher than that of others, and the permeability vanished stress of them were also highest, indicating that the flow resistance of RMCP and MFCP were lower than those of others. It is also shown that the degree of permeability stress-dependent (DPSD) varied from NF types. A modified exponential permeability model was derived to evaluate DPSD of natural fractured core plugs. Two parameters (gamma(sigma eff) and gamma(sigma eff)') were used to describe the DSDP in NFTGR, and the range of which were obtained from the experimental data by regression analysis. The reasonable gamma(sigma eff) and gamma(sigma eff)' range of NFCP were also proposed in this paper. Sensitivity analysis showed that the influence gamma(sigma eff)' on SDP was more significant than that of gamma(sigma eff). The proposed model can be integrated to reservoir simulators and help to improve of oil and gas production prediction accuracy in NFTGRs.",1,1,2
Fracture,Shale Gas,"Liu, Zhao; Sun, Youhong; Guo, Wei; Li, Qiang",Reservoir-scale study of oil shale hydration swelling and thermal expansion after hydraulic fracturing,Oil shale; Hydration swelling; Thermal expansion; Reservoir permeability; Permeability reduction,GAS; BEHAVIOR; PERMEABILITY; PYROLYSIS; WATER,"Volumetric expansion is a factor limiting oil shale exploitation via in situ pyrolysis because it affects the permeability of a reservoir. Most of the existing research on hydration swelling and thermal expansion involves core-scale experiments; however, it is also important to systematically study this topic at the reservoir scale. In this study, relevant field experiments between two wells were conducted to analyze the effects and mechanisms of hydration swelling and thermal expansion on reservoir permeability. The results showed that, after full hydration, the estimated permeability decreased by nearly 24% according to Darcy's law, depicting that hydration swelling had a weak effect on reservoir permeability. The microcracks induced by hydration were considered to weaken preexisting closed fractures. However, after heating the formation in a nitrogen atmosphere, the results showed that the estimated permeability decreased by nearly 52%. Even worse, after heating in an air atmosphere, the estimated permeability decreased by nearly 68%, and the high temperature produced by the combustion was considered to intensify the degree and range of thermal expansion in the oil shale. This study serves as a reference for follow-up oil shale exploitation via in situ pyrolysis.",3,3,11
Fracture,Shale Gas,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Fracture,Shale Gas,"Han, Songcai; Cheng, Yuanfang; Gao, Qi; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Analysis of instability mechanisms of natural fractures during the approach of a hydraulic fracture,Hydraulic fracture propagation; Numerical simulation; Induced stresses; Pore pressure; Natural fracture stability; Arrested/crossing criterion,SHALE GAS; FLUID-FLOW; PROPAGATION; BEHAVIOR; MODEL; INTERFACES; SIMULATION; CRITERION; LEAKOFF,"A fluid-driven fracture propagation model dominated by viscosity-leak-off regime was presented to investigate the mechanical stability of natural fracture (NF) when hydraulic fracture (HF) approaches. The induced stresses generated by the approaching HF were calculated by a fully coupled integro-differential equation. The pore pressure effect caused by fracturing fluid leak-off was simulated based on dual porosity medium theory. The critical failure conditions of NF were determined based on maximum tensile criterion and Barton-Bandis criterion. The sensitivity of the stability of NF to in-situ stress anisotropy, approaching angle and distance, injection rate, fracturing fluid viscosity, and NF properties was analyzed in detail. Simulation results reveal that the shearing-mode failure of NF is obviously easier than the opening-mode failure, and the shear slip zone is much larger than the tensile failure zone. As HF approaches NF non-orthogonally, the induced debonding process is unstable, and the debonding zone is asymmetric with respect to the center of NF. The tensile-induced expansion zone is primarily located in the portion of NF ahead of the HF tip, however the shear-induced slip zone can even occur on NF behind of the HF tip. Induced stresses alone have negligible effect on the stability of the NF that is unconnected to the HF. The change in pore pressure due to leak-off effect dominates the final stimulated reservoir volume during large-scale fracturing. The instability of the NF dominates the propagation trajectory of the subsequent HF. A more suitable arrested/crossing condition by extending Gu-Weng criterion was established to predict the path of HF propagation.",3,3,3
Fracture,Shale Gas,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Fracture,Shale Gas,"Cai, Can; Kang, Yong; Yang, Yingxin; Wang, Xiaochuan; Li, Yang; Huang, Man; Wu, Jiwei",The effect of shale bedding on supercritical CO2 jet fracturing: A experimental study,Shale bedding; Supercritical carbon dioxide jet fracturing; Fracture morphology; Perforation damage,CARBON-DIOXIDE; ACOUSTIC-EMISSION; GAS; SEQUESTRATION; PRESSURE; RECOVERY; STORAGE; PROPAGATION; SATURATION; ADSORPTION,"The bedding plane of shale is related to anisotropic mechanical property, which apparently affects the shale fracturing. To investigate the influence of shale bedding on the fracture morphology and perforation damage under Supercritical Carbon Dioxide (SC-CO2) jet fracturing, the experiments were comprehensively studied via the macro fracture analysis, strain monitoring, Scanning Electron Microscope (SEM) test and Energy Dispersive Spectroscopy (EDS) test. The results demonstrated that the average Young's Modulus (YM) and Uniaxial Compressive Strength (UCS) of shale specimen with the bedding plane angle of 0 degrees is 9.37 times and 2.89 times of the shale specimen with bedding plane angle of 90 degrees, respectively. During jet fracturing, both the jet pressure and existing bedding are beneficial for fracture initiating and propagating naturally along the weak bedding planes, and shear fracture can enhance the fracture complexity. When the perforation distributes in the direction perpendicular to the bedding plane, the less strain can be obtained, and the mass loss and CO2 absorption of shale specimen significantly increase by 350% and 300%, respectively, as the jet pressure increases from 25 MPa to 50 MPa, which is larger than the shale specimen with bedding plane angle of 0 degrees. The perforation damage is explored after jet fracturing via SEM and EDS, and it is found the direction of perforation perpendicular to the bedding plane is beneficial for micro-cracks generation, and leads to 10% decline of carbon (C) and oxygen (O) elements in the samples. These studies clearly show the influence of the bedding plane angle on the fracture morphology and perforation damage, which are crucial for SC-CO2 fracturing and CO2 storage in shale reservoir.",3,3,3
Fracture,Shale Gas,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Fracture,Shale Gas,"Dong, Yintao; Ju, Binshan; Zhang, Suian; Tian, Yapeng; Ma, Shuai; Liu, Nannan; Lu, Guangzhong",Microscopic mechanism of methane adsorption in shale: Experimental data analysis and interaction potential simulation,Shale; Methane; Adsorption; Interaction potential; Microscopic mechanism,MOLECULAR SIMULATION; MESOPOROUS CARBONS; PORE STRUCTURE; GAS; COAL; CAPACITY; BEHAVIOR; CO2,"The adsorbed methane in shale determines the geological reserves of shale gas and production of the well. Therefore, it is of great importance to clarify the microscopic mechanism of methane adsorption in shale for evaluating the geological condition and formulating exploitation plan. In this study, the experimental data and the simulation result were combined to research the microscopic mechanism of methane adsorption in shale. The experimental data for 99 groups of low-temperature nitrogen adsorption and methane isothermal adsorption were collected, to calculate the number of adsorption layers of methane in shale at the micro-level. The surface, microfracture and micropore structures of the organic matter in shale were constructed by graphite structure with the hydroxyl group. Thereafter, they were used to simulate the interaction potential of the organic matter on methane molecules and the adsorption layer's number by using the theory of intermolecular interaction potential field. Furthermore, the effects of different fracture widths and pore diameters on methane adsorption were analyzed and verified. The results show that the adsorption capacity of methane in shale is related to shale's structure, and the order of the adsorption capacity is surface < microfracture < micropore. Meanwhile, the multilayer adsorption can occur in microfractures with a width of 1.44-1.59 nm and micropores with a diameter of 1.49-1.83 nm, whereas the surface structure just can be the monolayer adsorption. These quantitatively results establish a foundation for the development of adsorption theory for methane in the shale.",2,3,4
Fracture,Shale Gas,"Wang, Y.; Liu, D. Q.; Zhao, Z. H.; Wang, H. J.",Investigation on the effect of confining pressure on the geomechanical and ultrasonic properties of black shale using ultrasonic transmission and post-test CT visualization,Velocity anisotropy; Confining pressure; CT imaging; Crack pattern,LONGMAXI FORMATION SHALE; ELASTIC-WAVE VELOCITIES; X-RAY CT; MECHANICAL-PROPERTIES; ANISOTROPY; DEFORMATION; BEHAVIOR; ROCKS,"Knowledge of the influence of confining pressure on the geomechanical and ultrasonic characteristics is essential to exploration and development of gas shale reservoirs. In contrast to the extensive studies on the physical and mechanical properties of shale, the velocities of P-wave and S-wave during continuous deformation are not thoroughly understood. In this study, a suite of triaxial compression tests were done on the shale samples collected from the Sichuan Basin and were cored with horizontal bedding structure under various confining pressure. In-situ ultrasonic transmission technique combined with post-test CT imaging analysis was used to reveal the velocity-pressure characteristics and crack patterns. The experimental results indicate that strength, elastic parameter, P- and S-wave velocities, and failure pattern are influenced by the applied confining pressure. At the pre-peak stage on the stress-strain curve, the P-wave velocity increases with elevated stress; however, the S-wave velocity first increases and then decreases, which is related to the crack damage evolution. The mesostructural changes during deformation are considered to be the main factor controlling the pressure sensitivity of the velocities. Under compression, the relatively soft pores, micro-cracks and minerals were compacted gradually, and it is the primary reason leading to the increment of velocities. Based on the CT scanning technique, the crack pattern was obtained after triaxial testing, the crack pattern analysis suggests that the fractal dimension of fracture distribution almost increases with confining pressure. What is more, the stimulated fracture density increases with increasing confining pressure. It suggests that, for the Longmaxi black shale, a high confining pressure condition is beneficial to form a complex fracture network.",2,2,4
Fracture,Shale Gas,"Zeng, Fanhui; Zhang, Yu; Guo, Jianchun; Zhang, Qiang; Chen, Zhangxin; Xiang, Jianhua; Zheng, Yunchuan",Optimized completion design for triggering a fracture network to enhance horizontal shale well production,Horizontal shale well; Completion design; Modified alternate fracturing; Fracture network; Field application,HYDRAULIC FRACTURES; PERFORATION CLUSTERS; INITIATION PRESSURE; NATURAL-FRACTURE; BARNETT SHALE; FLUID-FLOW; PROPAGATION; GROWTH; COMPLEXITY; INTERFACES,"Horizontal well drilling accompanied by multicluster fracturing is unlocking shale gas resources. It is essential to create a large-scale fracture network connecting the reservoir to the wellbore by activating the preexisting natural fractures (NFs) through well completion optimization. Coupling the geomechanical characteristics of a shale formation to achieve the maximum stimulated reservoir volume (SRV), we develop a new completion optimization pattern for a single horizontal wellbore called modified alternate fracturing. The new model is a combination of conventional simultaneous and alternate fracturing. Unlike the previous studies that mainly concentrated on predicting the quasistatic dilation of NF failure, the presented paper assesses the dynamic evolution progression of NF growth under different failure criteria. Additionally, an analysis of how the modified alternate fracturing influences the fracture network is performed. The results demonstrate that a NF may be crossed, opened or slipped by an approaching hydraulic fracture (HF), depending on the tensile or shear stresses exerted on the NF. The combination of perforation parameter optimization and injection rate real-time control is able to utilize induced stresses to form a complex fracture network. A field application reveals that the modified well completion pattern performed better than conventional simultaneous fracturing due to increasing the near-wellbore and far-field fracture complexity. In addition, no additional equipment such as bridge plugs or coiled tubingis needed during operation, reducing potential issues.",2,3,3
Fracture,Shale Gas,"Mohammed, Auwalu, I; Oyeneyin, Babs; Bartlett, Mark; Njuguna, James",Prediction of casing critical buckling during shale gas hydraulic fracturing,Casing buckling; Rock slippage; Fracturing; In-situ stresses; Shale gas wells,DEFORMATION; FIELD; SIMULATION; FAILURE; BRITTLE; STRESS; DAMAGE; WELL; SLIP,"Casing deformation during volume fracturing in shale gas horizontal wells is caused by both existing and induced stresses. These stresses jointly alter and compound the stress field around the casing leading to inefficient well stimulation as planned, lack of access into the well for recompletion, future workovers and present imminent danger of well integrity. Using two simulation scenarios, casing structural integrity was investigated in both radial and axial configurations under the mechanics of a combine system - casing, cement and formation rock. Results obtained show that time dependent rock slippage - creep during stimulation lead to an increase transverse displacement and corresponding stresses on the casing. In addition, the effect of combined loading results in significant increase in both displacements and stresses that can cause radial and axial permanent failure of the casing. This explains the lack of access into the casing during multi-stage hydraulic fracturing and future well intervention and recompletions and increased current understating of the downhole dynamics and casing structural integrity during volume fracturing. This new understanding is a major breakthrough in establishing casing health status during shale gas well stimulation.",2,2,2
Fracture,Shale Gas,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Fracture,Shale Gas,"Zhou, Qiumei; Wang, John Yilin; Xiao, Yitian",Identification and illustration of relationships between produced gas and water in marcellus under different spatial and temporal domains through data-driven analytics - Nonparametric model,Shale gas; Data driven; Fracture fluid flowback,FLOWBACK; CLEANUP; BLOCKS,"Understanding the relationship between produced gas and flowback/produced water is important for both shale gas well operation optimization and well performance enhancement; however, it is not fully understood due to complex flow mechanisms and interactions/feedback among various geoscience and engineering controls. Data-driven analysis, as an alternative way, could inversely provide valuable insights on the relationship between produced gas and water, to adjust future development plans for well/regional optimal economic production. An auto-updated nonlinear data analytics method was applied to evaluate the relationship between water and gas in different spatial and temporal domains, to inversely correlate the micro-scale flow mechanisms from macro-scale data. In this study, the cases were covered with both wet and dry shale gas regions, as well as short and long shale gas production periods. Fracture-fluid flowback is defined as water production within one month, following a fracture treatment (exclusive of well shut-in time), and the produced water is 1-3 years cumulative water production. 114 wells from the Marcellus Formation, in wet and dry gas regions of northwestern West Virginia, were selected to investigate the relationship between fracture-fluid flowback and corresponding one-month gas production. 67 Marcellus wells in Pennsylvania were selected to study the relationship between produced water and corresponding gas production across different time periods ranging from one to three years. The results indicate that the relationship between gas and fracture-fluid flowback in the wet gas region is positive while negative in the dry gas region. The discussion of water flow format was done by comparing the water gas ratio at reservoir conditions and at the surface condition. WGR (water gas ratio) is high ( > 9 bbl/mmcf) during the 1st-year and then leveled off at 3 bbl/mmcf after the 1st-year, indicating water initially be produced through displacement, and then be produced through evaporation.",2,2,1
Fracture,Shale Gas,"Cui, Shuai; Liu, Houbin; Meng, Yingfeng; Fan, Yu; Wang, Jiajun; Han, Zhengbo",Study on mechanical properties and wellbore stability of deep brittle shale,Deep brittle shale; Borehole stress field; Complex loading; Surge pressure; Tensile caving; Wellbore stability,,"As the drilling depth of shale's oil and gas wells increases worldwide, the problem of borehole collapse and instability becomes increasingly serious. Due to the high content of brittle minerals in deep shale, the complex situation of an underground collapse of a site is often manifested as borehole wall caving and falling. On the basis of the deep shale of China's Longmaxi formation, we developed a simulation experiment involving the complex loading mechanics of underground working conditions. The influence of loading and unloading confining pressure speeds and the sealing properties of drilling fluid on the mechanical properties of rock were analyzed. We established the dynamic changes in borehole formation, combining seepage and pore pressure, the effective stress field around the well, and a method of evaluating wellbore stability in deep shale gas horizontal wells. The results show that the deep shale of the Longmaxi formation has a high brittle mineral content and is prone to brittle fracturing along parallel bedding surfaces under downhole pressure. The effective liquid column pressure at the bottom of the wells change noticeably under different working conditions. Changes in bottom hole fluid column pressure are the cause of the complicated situation of well leakage and overflow in the horizontal sections of the Longmaxi formation. The effective support confining pressure of borehole wall rock differs with different tripping out speeds. The faster the tripping out is, the less the support confining pressure of the wellbore rock and the easier it is to induce the rock to break down along the bedding. The effective sealing property of drilling fluid also affects wellbore stability. A good sealing property of drilling fluid can improve the supporting effect of the fluid on borehole wall rock and improve its resistance strength. On the whole, the pressure of the bottom hole liquid column is effectively controlled during drilling in the Longmaxi formation; this can avoid complicated situations such as well leakage. The results of this study provide a theoretical basis for the study of wellbore stability in deep shale formations during the drilling process.",1,1,5
Fracture,Shale Gas,"Fang, Bo; Hu, Jinghong; Xu, Jinze; Zhang, Yuan",A semi-analytical model for horizontal-well productivity in shale gas reservoirs: Coupling of multi-scale seepage and matrix shrinkage,Shale gas; Multi-scale seepage; Apparent permeability; Semi-analytical model; Factor analysis,POROUS-MEDIA; APPARENT PERMEABILITY; SURFACE-DIFFUSION; FLOW; ADSORPTION; PERFORMANCE; TRANSPORT,"Matrix permeability is an important parameter in shale gas productivity prediction. However, the permeability affected by multi-scale seepage is difficult to calculate accurately. The object of this study is to develop an integrated apparent permeability model for multi-scale seepage mechanisms. The apparent permeability model considered shale gas flow from shrinkable matrix to fracture system with slip flow, Knudsen diffusion, and surface diffusion. The transport capacity change with different seepage mechanisms under different conditions was specifically analyzed. The importance of each parameter in the apparent permeability model was qualified using Grey correlation method. In addition, a semi-analytical model for horizontal-well productivity was developed to describe shale gas transport inreservoir. The semi-analytical model was solved using Laplace integral transformation and point source method. According to the results based on Grey correlation method, the effects of pore radius and Langmuir volume on dimensionless-type curves were discussed. Compared with the pore radius, the Langmuir volume had more influences on the shape of typical curve. The slip flow played the most important role in gas transport in mesopores and macropores when the pressure was more than 2 MPa and the surface diffusion was the primary transporting mechanism at any pressure in micropores but it can be negligible in macropores. The research result presented that the multi-scale seepage mechanisms would be considered in well tests and shale gas production.",1,1,3
Fracture,Numerical Simulation,"Wang, Shen; Li, Dongyin; Mitri, Hani; Li, Huamin",Numerical simulation of hydraulic fracture deflection influenced by slotted directional boreholes using XFEM with a modified rock fracture energy model,Directional hydraulic fracturing; XFEM; Slotted directional borehole; Hydraulic fracture morphology; Rock shear fracture energy,FINITE-ELEMENT-METHOD; PROPAGATION CONTROL; CRACK-GROWTH; PRESSURE; TECHNOLOGY; INITIATION; MECHANISM; MEDIA,"Directional hydraulic fracturing (DHF) has been used in conductivity improvement of oil, gas and geothermal energy reservoirs and hard rock roof breaking in coal mines. Although the new DHF method that integrates fracturing borehole and slotted directional borehole (SDB) has been recently introduced, the mechanism and effectiveness of SDB on hydraulic fracture guiding remain open issues. In this study, numerical simulation based on extended finite element method (XFEM) is performed to investigate the effect of SDB on hydraulic fracture deflection. A modified rock fracture energy model is proposed and performed by a user subroutine USDFLD with XFEM, which considers the hardening property of rock shear fracture energy as confining pressure increases. The effects of stress field and borehole line azimuth on hydraulic fracture deflection and bottomhole pressure are investigated. Hydraulic fracture morphologies of three kinds of multi-borehole fracturing technology are compared, the control mechanism of SDBs on hydraulic fracture is explained, and the bottomhole pressure relief effect, borehole spacing and potential application prospects are discussed. Result indicates that the modified model shows good accuracy and applicability in predicting hydraulic fracture propagation, and the hardening property of shear fracture energy should be considered when using XFEM and cohesive element method. The feature first drop and then rise ? of bottomhole pressure curve is an important sign that imply the hydraulic fracture propagates into the influence radius of SDB and can be used as an indicator to evaluate the effectiveness of DHF. Slot increases the influence radius of directional borehole and changes the local stress direction, thus allowing SDB-based DHF technique to be applied to the conditions where the stress difference ratio does not exceed one. When the stress difference ratio is greater than one, the pressurized SDB is more suitable.",3,3,15
Fracture,Numerical Simulation,"Jiang, Jiwei; Li, Jun; Liu, Gonghui; Lian, Wei; Xi, Yan; Yang, Hongwei; Li, Wai",Numerical simulation investigation on fracture debonding failure of cement plug/casing interface in abandoned wells,Abandoned wells; Cement plug/casing interface; Wellbore integrity; Fracture debonding height; Cohesive zone method,HYDRAULIC FRACTURE; FINITE-ELEMENT; COUPLED FLOW; WELLBORE; PLUG; PROPAGATION; INTEGRITY; PRESSURE; LEAKAGE; XFEM,"The fracture debonding failure of cement plug/casing interface caused by the migration of underground fluid with pressure accumulation imposed serious challenges to wellbore integrity of abandoned wells. This paper presents an investigation with a view of quantifying the relationships between the fracture debonding height and the migration time of underground fluid. A new 3D numerical model of cement plug/casing/cement sheath/formation system based on the cohesive zone method, which was validated by microannulus experiment, was developed to simulate the fracture debonding process. And then the relationships between fracture debonding height and propagation pressure was studied. Additionally, the influence of horizontal in-situ stress, cement plug mechanical parameters, and interface properties on the fracture debonding height and development geometry were also analyzed. The results of research indicated that the minimum horizontal in-situ stress played a decisive role in controlling the fracture propagation of cement/casing interface. Debonding fracture propagated along the whole circumference of the interface with the same height for the case that the horizontal in-situ stress was uniform, while propagated along a certain circumference angle of the interface with the maximum height in the direction of maximum horizontal principal stress for the case that the horizontal in-situ stress was non-uniform. The results of numerical analysis showed that lower elastic modulus and Poisson's ratio of cement plug, higher cement plug permeability, and larger critical normal strength and critical shear strength were beneficial to decrease the fracture debonding height and reduce the risk of debonding failure of the cement plug/casing interface. Finally, some effective measures to maintain the sealing integrity of abandoned wells were proposed.",3,3,5
Fracture,Numerical Simulation,"Han, Songcai; Cheng, Yuanfang; Gao, Qi; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Analysis of instability mechanisms of natural fractures during the approach of a hydraulic fracture,Hydraulic fracture propagation; Numerical simulation; Induced stresses; Pore pressure; Natural fracture stability; Arrested/crossing criterion,SHALE GAS; FLUID-FLOW; PROPAGATION; BEHAVIOR; MODEL; INTERFACES; SIMULATION; CRITERION; LEAKOFF,"A fluid-driven fracture propagation model dominated by viscosity-leak-off regime was presented to investigate the mechanical stability of natural fracture (NF) when hydraulic fracture (HF) approaches. The induced stresses generated by the approaching HF were calculated by a fully coupled integro-differential equation. The pore pressure effect caused by fracturing fluid leak-off was simulated based on dual porosity medium theory. The critical failure conditions of NF were determined based on maximum tensile criterion and Barton-Bandis criterion. The sensitivity of the stability of NF to in-situ stress anisotropy, approaching angle and distance, injection rate, fracturing fluid viscosity, and NF properties was analyzed in detail. Simulation results reveal that the shearing-mode failure of NF is obviously easier than the opening-mode failure, and the shear slip zone is much larger than the tensile failure zone. As HF approaches NF non-orthogonally, the induced debonding process is unstable, and the debonding zone is asymmetric with respect to the center of NF. The tensile-induced expansion zone is primarily located in the portion of NF ahead of the HF tip, however the shear-induced slip zone can even occur on NF behind of the HF tip. Induced stresses alone have negligible effect on the stability of the NF that is unconnected to the HF. The change in pore pressure due to leak-off effect dominates the final stimulated reservoir volume during large-scale fracturing. The instability of the NF dominates the propagation trajectory of the subsequent HF. A more suitable arrested/crossing condition by extending Gu-Weng criterion was established to predict the path of HF propagation.",3,3,3
Fracture,Numerical Simulation,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Fracture,Numerical Simulation,"Gudala, Manojkumar; Govindarajan, Suresh Kumar",Numerical modelling of coupled single-phase fluid flow and geomechanics in a fractured porous media,,MULTIPHASE FLOW; SHALE RESERVOIR; SIMULATION; EDFM,,3,3,0
Fracture,Numerical Simulation,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Fracture,Numerical Simulation,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Fracture,Numerical Simulation,"Lukin, Nikolas; Moura, Rafael Traldi; Alves, Marcilio; Bruenig, Michael; Driemeier, Larissa",Analysis of API S-135 steel drill pipe cutting process by blowout preventer,Offshore drilling; BlowOut preventer; Finite element method; Failure model; Experimental tests,DUCTILE FRACTURE; DAMAGE; PLASTICITY; CRITERION; BEHAVIOR; SHEARING; FAILURE; MODEL,"In offshore oil exploration, the use of a Dynamic Positioning System (DPS) to maintain the platform at a fixed point regardless of the influence of the environment has become common practice. In the event of failure, however, the drill string inside BOP (BlowOut Preventer) must be cut and safely disconnected from the platform. Therefore, it is evident the need for an accurate and realistic virtual model of this failure process. Numerical model analysis, in addition to avoiding expensive and complex experimental tests, allows, through post-processing tools, a detailed understanding of all phases of the failure process. The present work aims to characterize the API S-135 steel, as material commonly used to manufacturing drill strings. The material parameters for the Johnson-Cook model (J-C) are obtained from experimental tensile tests on dog bone and 3-point bending beams specimens with different notch radii, covering a wide range of stress triaxialities. Experimental tests and numerical simulations were compared by means of stress-strain curves, Digital Image Correlation (DIC) and Surface Electron Microscopy (SEM) to validate the model. The material model is applied to simulate the pipe cutting process and to predict the required force for the BOP to cut drill pipes with different geometries, which in comparison to experimental tests permitted to determine BOP internal frictions. Additionally, the numerical simulation also allowed a better understanding of the cutting process here presented as well, coherent to J-C model and SEM imaging of a similar cut tube in BOP.",2,3,1
Fracture,Numerical Simulation,"Liu, Qingling; Tian, Shouceng; Yu, Wei; Li, Gensheng; Sheng, Mao; Sepehrnoori, Kamy; Wang, Tianyu",A semi-analytical model for simulation of multiple vertical wells with well interference,Tight oil reservoir; Semi-analytical model; Well interference; Multiple well; Fracture hit,MULTIFRACTURED HORIZONTAL WELLS; SHALE-GAS-WELLS; FLOW; FRACTURES; RESERVOIR; PRESSURE; BEHAVIOR; ROCK,"Hydraulic fracturing is widely applied to develop tight oil reservoirs, and it is significant to diagnose fracture hit to determine optimal well spacing. Pressure test is an effective method to determine fracture hit in a multi-well system. In this study, we developed a semi-analytical model to quickly identify fracture hit in multiple vertical well system in tight oil reservoir. This semi-analytical model involves several steps, i.e., prior production step of parent wells, pressure build-up step, and interference test step. The model was verified by a numerical reservoir simulator for single well and multiple wells. Then, based on the model, the well interference by fracture hit in a three-well system (two parent wells and one child well) is discussed. Results show that the developed semianalytical model could efficiently simulate the entire production process of a multi-well system, quickly diagnose fracture hit by using pressure interference test data and determine the optimal shut-in time of parent well. The practicability of model lies in that the reservoir pressure depletion by prior production of parent wells is considered. Besides, it is found shutting down the parent well is very necessary to diagnose fracture hit when the child well is infilled. When the shut-in parent well is connected to producing child well, the pressure build-up process of parent well is terminated with the bottom hole pressure reducing continuously. What is more, the shut-in time of parent wells should be sufficient to better detect the fracture hit, especially under the condition that parent wells have produced for a long time or the connectivity among wells is weak. This work can provide critical insights into understanding the mechanism of well interference by fracture hit in a multi-well system.",1,1,5
Fracture,Numerical Simulation,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Fracture,Numerical Simulation,"Zhou, Dong; Liu, Zhixiang; Feng, Zengchao; Shen, Yongxing; Wu, YuCheng",The study of the local area density homogenization effect of meso-structures in coal during methane adsorption,Adsorption; Swelling deformation; Density homogenization; Local area; CT,FRACTAL CHARACTERISTICS; ANTHRACITE COAL; GAS-TRANSPORT; DESORPTION; DEFORMATION; PERMEABILITY; EVOLUTION,"The swelling deformations of coal structures during the methane adsorption cause the changes of the gas migration channels such as mesopores and fractures, which poses a great challenge to evaluate the methane migration efficiency in pore-fracture network structures of coal. Because of the complexity of the multi-scale inhomogeneity meso-structure in coal, the previous studies were failed to propose a unified equation to accurately describe and predict the complex deformation of coal structures during methane adsorption. Through lots of researches of meso structures deformation during methane adsorption in coal, the local area density homogenization effect of the meso structures in coal during methane adsorption was discovered. In view of this, the mechanism of the local area density homogenization effect was analyzed by establish a new model of coal structure, and the local area density homogenization equation of methane adsorption in coal was derived. It indicated that the deformation of meso target structure in coal during the methane adsorption is mainly determined by the density ratio of the target structure to the local area, and the swelling deformation of the local area that contains the target structure, as well as the density homogenization coefficient. Through multi-scale three-dimensional segmentation and statistics of the Computed Tomography (CT) scan data of anthracite sample adsorbed methane under different adsorption pressures, the rule of the local area density homogenization effect was verified. It was found that the deformations of the meso structures in coal during the methane adsorption was capable to fit to the local area density homogenization equation of methane adsorption in coal under different adsorption pressures and observation scales. The calculation accuracy of this equation was determined by the analysis of the 95% confidence intervals of the density homogenization coefficient.. The local area density homogenization equation provides a way to describe and predict deformation behavers of coal structures based on the their density information obtained by CT scanning, and has great significance for the numerical simulation of methane dynamic seepage characteristics in multi-scale structures of coal in the CBM exploitation process.",1,1,4
Fracture,Numerical Simulation,"Chen, Zhiming; Liao, Xinwei; Zeng, Lianbo",Pressure transient analysis in the child well with complex fracture geometries and fracture hits by a semi-analytical model,Unconventional reservoirs; Fracture hits; Fracture networks; Pressure transient analysis; Semi-analytical model,HORIZONTAL WELLS; SIMULATION; FLOW,"Recently, the model development of pressure transient analysis in wells with large-scale fracturing treatments has attracted more and more attention. However, a little work has involved the complex fracture networks with fracture hits. In this study, the transient pressure behaviors of a child well with complex fracture geometries and fracture hits are studied, using an efficient semi-analytical model. The semi-analytical model has the capability to simulate shale well performance by considering complex non-planar hydraulic fractures and fracture hits. The pressure transient solution of the semi-analytical model is obtained by the incorporation of nodal analysis and Laplace transforms. After the numerical verification of the proposed semi-analytical model, we apply it to analyze the pressure testing data of a child well and a parent well. Through conducting a series of history matching, the most likely fracture parameters of the child well is determined. Results show that the flow regimes of complex fracture geometries with fracture hits include wellbore storage, skin effect, fracture bilinear flow, ""fluid feed"", pseudo-boundary dominated flow, unconnected fracture (UF) impact, and pseudo radial flow. During the flow regime of UF impact, the pressure derivative curves exist a second ""V-shape"", as the UF improve the matrix permeability and the pressure depletion will be reduce once the flow reaches the UF. A case study in the Lucaogou shale oil reservoir from the Junggar Basin show that complex fracture geometries is developed along the child wellbore. After estimation, the fracture hits between the parent well and child well may via five hitting fractures. The length and conductivity of the hitting fractures are evaluated as 20 m and 120 mD.m, respectively. This work could be beneficial to performance forecast and well spacing optimization in unconventional reservoirs.",1,1,3
Fracture,Numerical Simulation,"Che, Jiaqi; Wang, Hanxiang; Zhang, Yanwen; Liu, Yanxin; Du, Mingchao; Ma, Shaohua",Experimental and numerical studies on chip formation mechanism and working performance of the milling tool with single abrasive grain,Single abrasive grain; Milling tool; Working mechanism; Experimental system; Weight on bit (WOB); Rotating speed; Unconventional oil and gas resources,FRACTURED HORIZONTAL WELL; TIGHT OIL; CUTTING FORCE; PDC CUTTER; GAS; ROCK; SIMULATION; BALL; PREDICTION; FRICTION,"It is a wildly accepted approach to study the working mechanism of the single abrasive grain by experiment and numerical simulation to improve the working performance of the milling tool in the development of unconventional oil and gas resources. In this study, a mechanical analysis model and a 2D numerical simulation model of single abrasive grain were established to analyze the working mechanism of the milling tool. Then a milling tool with single abrasive grain and an experimental system for milling tools were developed to verify the numerical results. Also, the working process was recorded by a high-speed camera to analyze the chip formation mechanism and the thermal field was obtained by the 2D numerical simulation model to improve service life. Besides, the influence of different working parameters including weight on bit (WOB) and rotating speed was conducted to improve efficiency and safety of the milling tool. Study results indicate that the error between simulation and experiment is within 7.43%, which verifies the accuracy of the 2D numerical simulation model. Both the chips of simulation and experiment are jagged chips without cooling and the error of the chip morphology is only 5.88%. The temperature on the cutting edge increased faster than other positions with some fluctuation while that on the rake face reached a peak at 658.5. degrees C with some fluctuation. These studies are significant for the design and application of the milling tool with high performance.",1,2,1
Fracture,Numerical Simulation,"Childers, D. P. E.; Wu, X.",Forecasting oil well performance in tight formation using the connected reservoir storage model,,,"Tight reservoir development requires complex fracture networks to economically produce hydrocarbons. The accurate prediction of a production well regarding this type of reservoir is not only critical for reservoir management but also challenging due to multiple and compound flow mechanisms. For wells producing from tight formations, curve fitting based forecasting models are destined to fail in the long term because they do not capture flow mechanisms or the physics governing fluid flow in the reservoir. Based on diffusivity theory, this paper presents the Connected Reservoir Storage Model (CRSM) employing only production rate and bottomhole flowing pressure (BHFP) to derive the reservoir behavior and can be used to predict production performance under variable operating conditions. This approach is easy to implement as the CRSM can be determined with no foreknowledge of reservoir geometry or reservoir parameters. The novelty of the CRSM is utilizing only production data to characterize extreme tight formations for performance forecasting under variable operational conditions. This paper will demonstrate the ability of the CRSM to predict production performance and compare the result to two classical empirical techniques currently used in unconventional reservoir predictions, and the validation is done via numerical simulation. Based on the CRSM, this paper also reveals the interrelated paradigms among well performance, increasing reservoir connected volume, and rate forecasts with uncertainties.",1,1,0
Fracture,Zone,"Jiang, Jiwei; Li, Jun; Liu, Gonghui; Lian, Wei; Xi, Yan; Yang, Hongwei; Li, Wai",Numerical simulation investigation on fracture debonding failure of cement plug/casing interface in abandoned wells,Abandoned wells; Cement plug/casing interface; Wellbore integrity; Fracture debonding height; Cohesive zone method,HYDRAULIC FRACTURE; FINITE-ELEMENT; COUPLED FLOW; WELLBORE; PLUG; PROPAGATION; INTEGRITY; PRESSURE; LEAKAGE; XFEM,"The fracture debonding failure of cement plug/casing interface caused by the migration of underground fluid with pressure accumulation imposed serious challenges to wellbore integrity of abandoned wells. This paper presents an investigation with a view of quantifying the relationships between the fracture debonding height and the migration time of underground fluid. A new 3D numerical model of cement plug/casing/cement sheath/formation system based on the cohesive zone method, which was validated by microannulus experiment, was developed to simulate the fracture debonding process. And then the relationships between fracture debonding height and propagation pressure was studied. Additionally, the influence of horizontal in-situ stress, cement plug mechanical parameters, and interface properties on the fracture debonding height and development geometry were also analyzed. The results of research indicated that the minimum horizontal in-situ stress played a decisive role in controlling the fracture propagation of cement/casing interface. Debonding fracture propagated along the whole circumference of the interface with the same height for the case that the horizontal in-situ stress was uniform, while propagated along a certain circumference angle of the interface with the maximum height in the direction of maximum horizontal principal stress for the case that the horizontal in-situ stress was non-uniform. The results of numerical analysis showed that lower elastic modulus and Poisson's ratio of cement plug, higher cement plug permeability, and larger critical normal strength and critical shear strength were beneficial to decrease the fracture debonding height and reduce the risk of debonding failure of the cement plug/casing interface. Finally, some effective measures to maintain the sealing integrity of abandoned wells were proposed.",3,3,5
Fracture,Zone,"She, Jiping; Zhang, Hao; Kang, Yili; Feng, Yin; Zhong, Ying; Yang, Bin",Cusp catastrophe model for plugging pressure prediction of lost circulation control in fractured reservoirs,Fractured reservoirs; Lost circulation; Cusp catastrophe; Maximum plugging pressure; Plugging zone,FRICTION COEFFICIENT,"Lost circulation is one of the most common and costly problems in drilling. The stability of the plugging zone is a key factor determining the lost circulation control. In this paper, an analytical model is derived based on the catastrophic theory, which considers key parameters affecting the stability of the plugging zone, such as formation parameters, contact parameters and plugging zone parameters. The maximum plugging pressure (MPP) can be calculated by this model to quantitatively evaluate the stability of the plugging zone. The validation case shows that the calculation result is in good agreement with the experimental measurement. In addition, the sensitivity analysis is performed and shows that the length of the plugging zone, the sliding friction coefficient of the fracture surface and the Young's modulus of plugging zone are positively correlated with MPP, but the shear height of plugging zone, sliding friction coefficient of lost circulation materials (LCMs) and Poisson's ratio of the plugging zone are negatively correlated with MPP. The model can be used to predict the MPP in lost circulation control and considered as a reference for the optimization of the LCMs and plugging program.",3,4,4
Fracture,Zone,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Fracture,Zone,"Han, Changcheng; Tian, Jijun; Hu, Chenlin; Liu, Hailei; Wang, Wenfeng; Huan, Zhipeng; Feng, Shuo","Lithofacies characteristics and their controlling effects on reservoirs in buried hills of metamorphic rocks: A case study of late Paleozoic units in the Aryskum depression, South Turgay Basin, Kazakhstan",Metamorphic rocks; Lithofacies characters; Reservoir properties; Aryskum depression,KARATAU FAULT; PETROGEOCHEMICAL CHARACTERISTICS; TECTONIC IMPLICATIONS; CARBONATE RESERVOIRS; VOLCANIC-ROCKS; LIAOHE BASIN; CORE COMPLEX; OIL-FIELD; EVOLUTION; BELT,"Metamorphic rock reservoirs are special reservoirs that are quite different from traditional sedimentary rock reservoirs and contain rich hydrocarbon reserves. However, their lithofacies characteristics and reservoir properties are relatively underexplored, and the key factor in reservoirs is lithofacies. Based on core samples, thin sections, whole-rock analysis and well-log and seismic data, we evaluated the lithologies, petrological characteristics and reservoir properties of metamorphic rocks and then explored the main factors controlling reservoir formation and metamorphic rock quality in the Aryskum depression, South Turgay Basin, Kazakhstan. In this area, four types of lithofacies are identified: granitic gneiss (high DEN and CN, low GR), leptite (high GR and CN), gabbro (low GR and CN) and granite (high GR and low CN); among these rocks, granitic gneiss is widely distributed. The reservoir spaces of metamorphic rocks are divided into fractures and pores produced via metamorphism and structural movements. Fractures can be subdivided into structural fractures (SFs), dissolution fractures (DFs), cleavage microfissures (CMfs) and microfissures (Mfs), and pores include dissolved intergranular pores (DInterPs), dissolved intragranular pores (DIntrPs) and vugs (Vgs). Numerous SFs and DFs provide the main reservoir spaces for hydrocarbons. The reservoir quality of metamorphic rocks is primarily controlled by faults, fractures, lithofacies, minerals, dissolution and paleogeomorphology. Lithofacies and minerals are the internal factors that control dissolution and fragmentation, while paleogeomorphology and faults are the external factors that control fracture development. Leptite and granitic gneiss are high-quality reservoir lithofacies, and high paleogeomorphology areas and fault zones are the optimal locations for fractures and pores. Reservoir spaces undergo a series of repeated changes from formation to development, filling and reformation, and a comprehensive reservoir evolution model is proposed to illustrate the distribution of high-quality reservoirs. This study has scientific significance for investigating the reservoir-forming mechanisms of metamorphic rocks and practical applications for exploring and developing oil and gas fields in areas with metamorphic rocks.",3,3,4
Fracture,Zone,"Han, Songcai; Cheng, Yuanfang; Gao, Qi; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Analysis of instability mechanisms of natural fractures during the approach of a hydraulic fracture,Hydraulic fracture propagation; Numerical simulation; Induced stresses; Pore pressure; Natural fracture stability; Arrested/crossing criterion,SHALE GAS; FLUID-FLOW; PROPAGATION; BEHAVIOR; MODEL; INTERFACES; SIMULATION; CRITERION; LEAKOFF,"A fluid-driven fracture propagation model dominated by viscosity-leak-off regime was presented to investigate the mechanical stability of natural fracture (NF) when hydraulic fracture (HF) approaches. The induced stresses generated by the approaching HF were calculated by a fully coupled integro-differential equation. The pore pressure effect caused by fracturing fluid leak-off was simulated based on dual porosity medium theory. The critical failure conditions of NF were determined based on maximum tensile criterion and Barton-Bandis criterion. The sensitivity of the stability of NF to in-situ stress anisotropy, approaching angle and distance, injection rate, fracturing fluid viscosity, and NF properties was analyzed in detail. Simulation results reveal that the shearing-mode failure of NF is obviously easier than the opening-mode failure, and the shear slip zone is much larger than the tensile failure zone. As HF approaches NF non-orthogonally, the induced debonding process is unstable, and the debonding zone is asymmetric with respect to the center of NF. The tensile-induced expansion zone is primarily located in the portion of NF ahead of the HF tip, however the shear-induced slip zone can even occur on NF behind of the HF tip. Induced stresses alone have negligible effect on the stability of the NF that is unconnected to the HF. The change in pore pressure due to leak-off effect dominates the final stimulated reservoir volume during large-scale fracturing. The instability of the NF dominates the propagation trajectory of the subsequent HF. A more suitable arrested/crossing condition by extending Gu-Weng criterion was established to predict the path of HF propagation.",3,3,3
Fracture,Zone,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Fracture,Zone,"Sie, Chao-Yu; Nguyen, Quoc P.",A pore-scale experimental study of non-aqueous foam for improving hydrocarbon miscible flooding,Non-aqueous foam; Hydrocarbon soluble foaming surfactants; Natural gas liquids flooding; Sweep efficiency; Conformance control; Microfluidics,VISCOUS OIL-RECOVERY; FRACTURED RESERVOIRS; SOLVENT INJECTION; FLOW; DISPLACEMENT; SOLUBILITY; GENERATION; DEPOSITION; MOBILITY,"Mobility control in hydrocarbon miscible flooding is crucial for commercial vitality where severe reservoir heterogeneity causes poor sweep efficiency. This study introduced a new concept of non-aqueous foam-assisted hydrocarbon miscible flooding in water-sensitive oil formations. This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and a raw mixture of NGLs (MNGLs) with a foaming additive to improve displacement and sweep efficiency. Foaming a light hydrocarbon liquid and the impact of non-aqueous foam on miscible displacement are the main focuses of this study. n-Pentane was used as a MNGLs (solvent) model for foam stability tests. Transient foam propagation and rheology were directly visualized and characterized based on the apparent gas (nitrogen) viscosity associated with foam texture and fluid saturations. Oil recovery factors were directly related to different degrees of in-situ foaming. For the injection of a solvent slug followed by a gas drive, the displacement of oil became unstable as nitrogen fingered through the solvent-oil mixing zone, resulting in a high residual liquid saturation. However, gas fingering was significantly hindered as the solvent was injected with a foaming agent. Dynamic fluid distribution indicate that the improved oil recovery could be attributed to the propagation of foam in the swept zone, which provided essential flow resistance for better displacement stability. To investigate the effect of initial gas saturation in the reservoir on flow behavior, a slug of gas was injected before solvent injection. Delayed solvent breakthrough and better sweep efficiency were observed in the presence of foam due to the reduced liquid phase mobility in preferential flow paths and the diversion of solvent into small pores by the trapped gas at the displacing front. Furthermore, it was possible to obtain stable foam flow with an apparent viscosity of 20 times greater than the solvent viscosity.",2,2,6
Fracture,Zone,"Li, Qing; You, Xuelian; Jiang, Zaixing; Wu, Shenghe; Zhang, Ruifeng","Lithofacies and reservoir characterization of a source-controlled carbonate succession in a lacustrine rift basin, the Shulu Sag of Bohai Bay Basin, East China",Eocene; Shahejing formation; Depositional process; Pore type; Gravity flow; Tight oil,MISSISSIPPIAN BARNETT SHALE; PETROLEUM; GEOCHEMISTRY; ACCUMULATION; DEPOSITS; SYSTEM,"The lower part of the third member of the Eocene Shahejie Formation (Es-3(L)) is one of the most important petroleum exploration targets in the Bohai Bay Basin. Source-controlled carbonate deposits are widely distributed in the Es-3(L) unit of the Shulu Sag and display strong vertical and horizontal variations in lithofacies, geochemical, and reservoir characteristics. Based on core data, thin-section petrography, stable delta C-13 isotope analyses, and organic geochemistry data, eight lithofacies with distinctly different characteristics and origins are identified. Clast-supported terrigenous carbonate rudstone and matrix-supported terrigenous carbonate rudstone were sourced from the surrounding Cambrian-Ordovician carbonate bedrocks and are widely distributed at the edge of the sag in fan delta environments. Some of the rudstones were transported from the littoral zone to profundal zone by slide and slump processes. Mixed-source rudstone was mainly deposited by sandy debris flow. Carbonate lithic sandstone and carbonate lithic siltstone were mainly formed by turbidity current deposition in a sublacustrine setting. Irregular-laminated marlstone was mainly formed by muddy turbidity currents, and massive marlstone was formed by turbid clouds in a relatively turbulent deep water environment. Regular-laminated marlstone is thought formed by seasonal laminae due to seasonal variations by suspension settling in the anoxic deep, quiet lake environment. Calcareous mudstone possibly formed by shallow lake gravity flow in a shallow lake environment. Various of pores have been identified in the Es-3(L) rocks: pores and cracks inside gravels, seams around gravels, intergranular pores, intercrystalline pores, intragranular pores, dissolution pores, organic matter pores, fractures and fracture-related pores. Different lithofacies have different space types, porosities and permeability. Clast-supported terrigenous carbonate rudstone has the best reservoir qualities, with the highest porosity and permeability. Laminated marlstone is the second best reservoir type. These two lithofacies can be the target for tight oil exploration in the study area.",2,2,4
Fracture,Zone,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Fracture,Zone,"Aghli, Ghasem; Moussavi-Harami, Reza; Tokhmechi, Behzad","Integration of sonic and resistivity conventional logs for identification of fracture parameters in the carbonate reservoirs (A case study, Carbonate Asmari Formation, Zagros Basin, SW Iran)",Fractures; Image logs; Sonic logs; Reservoir parameters; Resistivity logs,SITU STRESS DIRECTION; FOLD-THRUST BELT; IMAGE LOGS; OIL-FIELD; POROSITY; DENSITY; CORE,"Between all available methods for fractures evaluation, core and image logs are prime methods. However, both of these data are very expensive and practically available in less than 10% of drilled wells. Therefore, a less expensive and quick method would be very helpful for fracture analysis. The main aim of this study is to identify the fracture parameters in the carbonate reservoirs, i.e. fracture density and fracture aperture, using a combination of sonic, resistivity and other conventional logs which commonly available in all wells. For this aim, fractures and their parameters were precisely determined on the image logs in 6 wells from carbonate Asmari Formation as a typical fractured reservoir in the world. Then, the effect of fracture parameters on the sonic and resistivity logs were used to identify fracture parameters in the wells with no core and image logs. Results indicate that the zones with high fracture density and aperture are easily detectable by conventional logs. On the other hand, the behavior of these logs is a function of fracture parameters in the fractured intervals, especially in the zones with high fracture aperture. Separation between shallow (RLA2) and deep (RLA5) resistivity logs along with their cross plot are very reliable indicators for fractured intervals. Sonic transit time rapidly increases where fractures density or aperture increased as well. In this study, a combination of sonic and neutron porosity logs have also been used to determine the effect of fracture aperture, as the main effective factor on the reservoir properties. Furthermore, full waveforms in some studied wells combined with sonic transit time to improve the results of fractures evaluation. Using sonic and resistivity along with neutron porosity and gamma ray logs provides a reliable method for describing the fracture parameters which shows high correlation with image logs results. Due to the high impact of fracture aperture on both reservoir quality and conventional log responses, determination of this parameter is more crucial than other fracture parameters. This method is also applicable for OBM (Oil Base Mud) image tools which conventionally cannot detect fracture aperture.",2,2,3
Fracture,Zone,"Toth, Tivadar M.; Toth, Ilona Vargane","Lithologically controlled behaviour of the Dorozsma metamorphic hydrocarbon reservoir (Pannonian Basin, SE Hungary)",Fractured hydrocarbon reservoir; Metamorphic rocks; Shear zone; Dolomite marble; Pannonian basin,EVOLUTION; SYSTEM; EQUILIBRIUM; CONSTRAINTS; MIGRATION; GEOMETRY; NETWORK; QUARTZ; FLUID; ROCKS,"Numerous fractured hydrocarbon reservoirs occur in the metamorphic basement of the Pannonian Basin in Hungary, and among them, the Dorozsma field is one of the most productive. Here 66 boreholes penetrated the metamorphic massif, making detailed petrographic and microstructural evaluation possible. Well-log data (gamma-ray, density, neutron porosity and compressional slowness) are available for each well, which can be used to extend the petrographic information spatially. The data suggest three basic rock types in the study area, which align along a consequent rock column. In the deepest structural positions, amphibolite is typical, while the top of the basement is dominated by kyanite gneiss. Thermobarometric calculation results prove that the gneiss-rich realm was metamorphosed at a significantly higher temperature than the lowermost amphibolite, suggesting a post-metamorphic structural contact between them. The contact zone, observed in numerous boreholes, contains intensively deformed dolomite marble of a few tens of metres in thickness. The peak metamorphic temperature of this rock type is much lower than those typically seen in the two neighbouring blocks. Localising the position of the dolomite marble horizon in each well was accomplished using petrographic and well-log information, and through this investigation, a flat, low-angle shear zone became visible, cut by a set of younger normal faults. Hydrocarbon production data clearly shows that the best, most productive intervals in each well are strongly correlated to the shear zone between the gneiss- and amphibolite-dominated realms, namely the sheared dolomite marble zone.",2,2,2
Fracture,Zone,"Merey, Sukru",Geomechanical wellbore stability analysis for the wells drilled in the shallow sediments of the Mediterranean Sea,Wellbore stability; Hoop stress; Reservoir geomechanics; Gas hydrates; Mediterranean sea,NATURAL-GAS; HYDRATE; ORIENTATION; MAGNITUDE; FAILURE; ENERGY; BASIN; AREA; LOGS,"Gas hydrates are considered as near-future energy resources in the world. Due to high gas hydrate potential of the Mediterranean Sea, gas hydrate exploration wells are expected to be drilled. In this study, for the first time, the caliper logs of the wells drilled during ODP (Ocean Drilling Program) Leg 160 and ODP Leg 161 in the Eastern and Western Mediterranean Sea were evaluated together with the python codes predicting wellbore stresses, unconfined compressive strength (C-o) and lower-hemisphere projection. The required C-o in the Eastern Mediterranean Sea ranges from 60 psia to 2250 psia from seafloor to target depth. However, the estimated C-o of the sediments in the Eastern Mediterranean in this study by using the python codes developed in this study and the caliper logs of ODP Leg 160 ranges from 15 psia to 1250 psia with depth. Similarly, the required C-o to keep the wells in gauge and the estimated C-o of the sediments in ODP Leg 161 range between 100-12000 psi and 30-11000 psia, respectively. Mostly, C-o values of the sediments were less than the required C-o values for stable wellbore so extensive washouts were detected both in the wells of ODP Leg 160 and Leg 161. This is because the sediments within gas hydrate stability zone in the Mediterranean Sea are weak and almost unconsolidated. Moreover, in this study, it was shown that it is possible to reduce the degree of washouts by increasing the density of drilling fluid until fracture pressure. According to the estimations in this study, the wellbore enlargements for the wells in ODP Leg 160 and ODP Leg 161 were mostly reduced below 2 inches, below which better wellbore stability conditions, better well log data and better casing cement quality might be obtained.",2,2,2
Fracture,Zone,"Taheri, Reza; Kabuli, Muffazal; Vryzas, Zisis",Fracturing and permeability enhancement with laser technology employing fuzzy logic,Laser technology; Permeability; Porosity; Microfractures; Fuzzy logic,,"Increasing the rock permeability in low permeable zones of the hydrocarbon reservoirs by conventional methods will often cause formation damage and consequently will reduce the efficiency of recovery of the reservoirs in long term. The use of high energy laser technology as an alternative and innovative approach to mobilise heavy oil and improve permeability, as opposed to the conventional techniques, which have advert effects on the longterm reservoir productivity, was examined in this research. This paper will present study results of the employment of pulsed (Q-switched) Nd: YAG (Neodymium: Yttrium Aluminium Garnet) laser on impermeable heavy oil-bearing core samples which have been simulated in lab to be as close as possible to the real reservoir conditions. A unique technique was employed in this study where lasing experiment was conducted on samples followed by intervals of stopping lasing operation, known as relaxation intervals. The alternate lasing-relaxation intervals which were repeated for samples 3 times, yield positive and satisfactory results both for heavy oil mobilization as well as permeability improvement. Porosity increase was also observed due to fracture production. Specifications of applied laser pulses and their associated beam properties, samples characteristics and dimensions as well as the simulated experiment environment with that of the real reservoir conditions will be reported. Fuzzy logic was employed to normalize the varying and diverse parameters affecting the rock's thermal behaviour such as mineral content, fluid content and type and pressure. By employing the proposed technique on samples from heavy-oil-bearing low permeable zones of Burgan and Mauddud reservoirs of the Giant Burgan field in Kuwait, fractures were produced and permeability of the reservoir samples were improved to almost 3 times of their initial values in some of the samples. Upon the termination of the third lasing experiment, traces of oil could be observed on some of the core sample's surfaces, proving that the heavy oil was mobilised due to induced high temperatures generated in the samples during lasing.",2,2,0
Fracture,Carbonate Reservoirs,"Liu, Junrong; Shi, Weixin; Wu, Xingru",Experimental study on thermally enhanced permeability of rock with chemical agents,Rock; Thermal fracturing; Permeability enhancement; Chemical agent; Solution concentration; Reservoir thermal stimulation,HIGH-TEMPERATURE; DECOMPOSITION; STIMULATION; CARBONATE; PRESSURE; STRENGTH; CRACKING; DAMAGE,"Previous researches focused on dry sample thermal treatment to enhance rock permeability indicate that thermal treatment can be a novel stimulation technique for geothermal and hydrocarbon reservoirs development. The mechanicm of thermal permeability enhancement depends on the generation of microcracks by thermal cracking. In this study, chemical solutions were introduced on sandstone rock samples and observed that they can be used to control thermal permeability enhancement. Sandstone specimens with the same order of permeability were saturated with different salt solutions and heated to different temperatures. The results quantify permeabilities and porosities of specimens saturated with electrolyts over them without chemical treatment but heated to the same temperature. The KCl solution had the largest effect on permeability enhancement for the tested rock and showed a tenfold increase in permeability, and followed by NaCl and K2CO3 solutions. However, CaCl2 solution and distilled water had negative effects. Laboratory results also revealed a positive correlation between some chemical concentration with the permeability increment of rock. The effects of electrolyte type and concentration on thermally permeability enhancement of the tested rocks were determined and a statistical model was fitted. The results show that the permeability increment follows an exponential growth with temperature when the rock was heated over the threshold temperature of thermal cracking. Introducing specific chemical species into a low-permeability formation and heating the formation beyond the threshold temperature of rock thermal cracking will be a promising way to further enhance formation permeability.",3,3,11
Fracture,Carbonate Reservoirs,"Han, Changcheng; Tian, Jijun; Hu, Chenlin; Liu, Hailei; Wang, Wenfeng; Huan, Zhipeng; Feng, Shuo","Lithofacies characteristics and their controlling effects on reservoirs in buried hills of metamorphic rocks: A case study of late Paleozoic units in the Aryskum depression, South Turgay Basin, Kazakhstan",Metamorphic rocks; Lithofacies characters; Reservoir properties; Aryskum depression,KARATAU FAULT; PETROGEOCHEMICAL CHARACTERISTICS; TECTONIC IMPLICATIONS; CARBONATE RESERVOIRS; VOLCANIC-ROCKS; LIAOHE BASIN; CORE COMPLEX; OIL-FIELD; EVOLUTION; BELT,"Metamorphic rock reservoirs are special reservoirs that are quite different from traditional sedimentary rock reservoirs and contain rich hydrocarbon reserves. However, their lithofacies characteristics and reservoir properties are relatively underexplored, and the key factor in reservoirs is lithofacies. Based on core samples, thin sections, whole-rock analysis and well-log and seismic data, we evaluated the lithologies, petrological characteristics and reservoir properties of metamorphic rocks and then explored the main factors controlling reservoir formation and metamorphic rock quality in the Aryskum depression, South Turgay Basin, Kazakhstan. In this area, four types of lithofacies are identified: granitic gneiss (high DEN and CN, low GR), leptite (high GR and CN), gabbro (low GR and CN) and granite (high GR and low CN); among these rocks, granitic gneiss is widely distributed. The reservoir spaces of metamorphic rocks are divided into fractures and pores produced via metamorphism and structural movements. Fractures can be subdivided into structural fractures (SFs), dissolution fractures (DFs), cleavage microfissures (CMfs) and microfissures (Mfs), and pores include dissolved intergranular pores (DInterPs), dissolved intragranular pores (DIntrPs) and vugs (Vgs). Numerous SFs and DFs provide the main reservoir spaces for hydrocarbons. The reservoir quality of metamorphic rocks is primarily controlled by faults, fractures, lithofacies, minerals, dissolution and paleogeomorphology. Lithofacies and minerals are the internal factors that control dissolution and fragmentation, while paleogeomorphology and faults are the external factors that control fracture development. Leptite and granitic gneiss are high-quality reservoir lithofacies, and high paleogeomorphology areas and fault zones are the optimal locations for fractures and pores. Reservoir spaces undergo a series of repeated changes from formation to development, filling and reformation, and a comprehensive reservoir evolution model is proposed to illustrate the distribution of high-quality reservoirs. This study has scientific significance for investigating the reservoir-forming mechanisms of metamorphic rocks and practical applications for exploring and developing oil and gas fields in areas with metamorphic rocks.",3,3,4
Fracture,Carbonate Reservoirs,"Cai, Can; Kang, Yong; Yang, Yingxin; Wang, Xiaochuan; Li, Yang; Huang, Man; Wu, Jiwei",The effect of shale bedding on supercritical CO2 jet fracturing: A experimental study,Shale bedding; Supercritical carbon dioxide jet fracturing; Fracture morphology; Perforation damage,CARBON-DIOXIDE; ACOUSTIC-EMISSION; GAS; SEQUESTRATION; PRESSURE; RECOVERY; STORAGE; PROPAGATION; SATURATION; ADSORPTION,"The bedding plane of shale is related to anisotropic mechanical property, which apparently affects the shale fracturing. To investigate the influence of shale bedding on the fracture morphology and perforation damage under Supercritical Carbon Dioxide (SC-CO2) jet fracturing, the experiments were comprehensively studied via the macro fracture analysis, strain monitoring, Scanning Electron Microscope (SEM) test and Energy Dispersive Spectroscopy (EDS) test. The results demonstrated that the average Young's Modulus (YM) and Uniaxial Compressive Strength (UCS) of shale specimen with the bedding plane angle of 0 degrees is 9.37 times and 2.89 times of the shale specimen with bedding plane angle of 90 degrees, respectively. During jet fracturing, both the jet pressure and existing bedding are beneficial for fracture initiating and propagating naturally along the weak bedding planes, and shear fracture can enhance the fracture complexity. When the perforation distributes in the direction perpendicular to the bedding plane, the less strain can be obtained, and the mass loss and CO2 absorption of shale specimen significantly increase by 350% and 300%, respectively, as the jet pressure increases from 25 MPa to 50 MPa, which is larger than the shale specimen with bedding plane angle of 0 degrees. The perforation damage is explored after jet fracturing via SEM and EDS, and it is found the direction of perforation perpendicular to the bedding plane is beneficial for micro-cracks generation, and leads to 10% decline of carbon (C) and oxygen (O) elements in the samples. These studies clearly show the influence of the bedding plane angle on the fracture morphology and perforation damage, which are crucial for SC-CO2 fracturing and CO2 storage in shale reservoir.",3,3,3
Fracture,Carbonate Reservoirs,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Du, He","Design and construction of the knowledge base system for geological outfield cavities classifications: An example of the fracture-cavity reservoir outfield in Tarim basin, NW China",UAV scanning; 3D digital model; Multiple linear regression; Discriminant classification; Fracture-cavity reservoir,VUGGY CARBONATE RESERVOIRS; OIL-FIELD; NETWORK; SIMULATION; PREDICTION; CAVE; GAS,"Tahe oilfield, located in NW Tarim Basin, is one of the largest and most difficult fracture cavity reservoirs in the world. Different fracture cavities, different generated mechanisms, and different oil production capacities. In order to study the significant parameters that can characterize the categories of facture-cavity. This research adopted outfield manual measurement, 3D digital modeling technique to obtain characterization parameters. According to experienced geological survey, typical outcrops were selected, then scanned by UAV (Unmanned aerial vehicle). Consequently, 3D digital models, including real coordinates and parameter information, were established by Agisoft Photoscan. Through geological testing results, various combination characteristic patterns of relative categories were analyzed. By using digital measure tool, combined with manually measured data, the parameters were extracted from the 3D digital model (DM). Then an initial geological database was established. For furtherly analyzing the database, the mathematic statistics methods of multiple linear regression (MLR), neural network technique (NNT) and discriminative classification technique (DCT) were applied. Using software of SPSS statistics 17.0, more than 200 groups of geological data (various categories of fracture-cavity) were optimally processed. Consequently, the significant characteristic parameters were interpreted to determine diverse categories. The results showed that: (1) cavity width, height, fracture length and cavity aspect ratio were significant parameters to classify runoff cavity categories. (2) Fault-controlled cavities could be accurately classified by fracture length and fracture density. (3) The main cavity categories could be distinguished by cavity width, cavity height and fracture density. Performances of the approach have been examined with 10 percentages of the samples, and a good agreement performed in the simulated results, and anastomosis rate was more than 80%. The researched results have critical guiding significance to evaluate types of fracture-cavity, develop and explore of fracture-cavity reservoirs. The construction technique of knowledge base can be applied for diverse fracture-cavity reservoirs in the various formations in different areas in the world.",3,3,2
Fracture,Carbonate Reservoirs,"Bouquet, Sarah; Douarche, Frederic; Roggero, Frederic; Bourbiaux, Bernard",Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization,Enhanced oil recovery; Naturally fractured reservoir; Oil-wet; Foam; Multiphase flow; Capillary pressure; Interfacial tension; Reservoir simulation; Mobility reduction; Dual-medium; Viscous forces,SIMULATION,"In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction. Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale. This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals. This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ""low-IFT"" effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.",3,3,0
Fracture,Carbonate Reservoirs,"Li, Qing; You, Xuelian; Jiang, Zaixing; Wu, Shenghe; Zhang, Ruifeng","Lithofacies and reservoir characterization of a source-controlled carbonate succession in a lacustrine rift basin, the Shulu Sag of Bohai Bay Basin, East China",Eocene; Shahejing formation; Depositional process; Pore type; Gravity flow; Tight oil,MISSISSIPPIAN BARNETT SHALE; PETROLEUM; GEOCHEMISTRY; ACCUMULATION; DEPOSITS; SYSTEM,"The lower part of the third member of the Eocene Shahejie Formation (Es-3(L)) is one of the most important petroleum exploration targets in the Bohai Bay Basin. Source-controlled carbonate deposits are widely distributed in the Es-3(L) unit of the Shulu Sag and display strong vertical and horizontal variations in lithofacies, geochemical, and reservoir characteristics. Based on core data, thin-section petrography, stable delta C-13 isotope analyses, and organic geochemistry data, eight lithofacies with distinctly different characteristics and origins are identified. Clast-supported terrigenous carbonate rudstone and matrix-supported terrigenous carbonate rudstone were sourced from the surrounding Cambrian-Ordovician carbonate bedrocks and are widely distributed at the edge of the sag in fan delta environments. Some of the rudstones were transported from the littoral zone to profundal zone by slide and slump processes. Mixed-source rudstone was mainly deposited by sandy debris flow. Carbonate lithic sandstone and carbonate lithic siltstone were mainly formed by turbidity current deposition in a sublacustrine setting. Irregular-laminated marlstone was mainly formed by muddy turbidity currents, and massive marlstone was formed by turbid clouds in a relatively turbulent deep water environment. Regular-laminated marlstone is thought formed by seasonal laminae due to seasonal variations by suspension settling in the anoxic deep, quiet lake environment. Calcareous mudstone possibly formed by shallow lake gravity flow in a shallow lake environment. Various of pores have been identified in the Es-3(L) rocks: pores and cracks inside gravels, seams around gravels, intergranular pores, intercrystalline pores, intragranular pores, dissolution pores, organic matter pores, fractures and fracture-related pores. Different lithofacies have different space types, porosities and permeability. Clast-supported terrigenous carbonate rudstone has the best reservoir qualities, with the highest porosity and permeability. Laminated marlstone is the second best reservoir type. These two lithofacies can be the target for tight oil exploration in the study area.",2,2,4
Fracture,Carbonate Reservoirs,"Zhang, Kunpeng; Chen, Mian; Zhou, Changlin; Dai, Yifan; Liu, Fei; Li, Jiaxin",Study of alternating acid fracturing treatment in carbonate formation based on true tri-axial experiment,Carbonate; Unconventional reservoir; Hydraulic fracturing; Reservoir stimulation; Shale oil,LIMESTONE FORMATION; PROPAGATION,"Acid fracturing is a useful technique to stimulate carbonate reservoirs. Nowadays, acid leak-off becomes a vital problem during the operation of acid fracturing. In order to encounter this issue, alternating acid fracturing has been developed. However, the fracture propagation and the interaction between hydraulic fractures and natural fractures/caves during alternating acid fracturing are ambiguous. Hence, a series of alternating acid fracturing experiments covering coupling mechanics and chemical interaction were conducted for the first time. In this study, slick water, self-generating acid, cross-linked gel, and gelled acid were used as a fracturing fluid whereas the specimens for this experiment are carbonate outcrop which excavated from Dengsi Formation. The results show that: (1) acid fracturing can reduce fracturing pressure effectively as the acid will etch and weaken the natural fractures to let them easily connecting each other; (2) different pad fluid properties will have different impacts on the acid fracturing performance; (3) the interaction of hydraulic fractures and natural filled caves can be divided into five categories, and two of them had been observed in the experiments. Moreover, a new curvature-calculation algorithm has been developed based on the 3-D scanning technology. The results have a great significance for acid fracturing design and physical simulation experiments.",2,2,4
Fracture,Carbonate Reservoirs,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Fracture,Carbonate Reservoirs,"Aghli, Ghasem; Moussavi-Harami, Reza; Tokhmechi, Behzad","Integration of sonic and resistivity conventional logs for identification of fracture parameters in the carbonate reservoirs (A case study, Carbonate Asmari Formation, Zagros Basin, SW Iran)",Fractures; Image logs; Sonic logs; Reservoir parameters; Resistivity logs,SITU STRESS DIRECTION; FOLD-THRUST BELT; IMAGE LOGS; OIL-FIELD; POROSITY; DENSITY; CORE,"Between all available methods for fractures evaluation, core and image logs are prime methods. However, both of these data are very expensive and practically available in less than 10% of drilled wells. Therefore, a less expensive and quick method would be very helpful for fracture analysis. The main aim of this study is to identify the fracture parameters in the carbonate reservoirs, i.e. fracture density and fracture aperture, using a combination of sonic, resistivity and other conventional logs which commonly available in all wells. For this aim, fractures and their parameters were precisely determined on the image logs in 6 wells from carbonate Asmari Formation as a typical fractured reservoir in the world. Then, the effect of fracture parameters on the sonic and resistivity logs were used to identify fracture parameters in the wells with no core and image logs. Results indicate that the zones with high fracture density and aperture are easily detectable by conventional logs. On the other hand, the behavior of these logs is a function of fracture parameters in the fractured intervals, especially in the zones with high fracture aperture. Separation between shallow (RLA2) and deep (RLA5) resistivity logs along with their cross plot are very reliable indicators for fractured intervals. Sonic transit time rapidly increases where fractures density or aperture increased as well. In this study, a combination of sonic and neutron porosity logs have also been used to determine the effect of fracture aperture, as the main effective factor on the reservoir properties. Furthermore, full waveforms in some studied wells combined with sonic transit time to improve the results of fractures evaluation. Using sonic and resistivity along with neutron porosity and gamma ray logs provides a reliable method for describing the fracture parameters which shows high correlation with image logs results. Due to the high impact of fracture aperture on both reservoir quality and conventional log responses, determination of this parameter is more crucial than other fracture parameters. This method is also applicable for OBM (Oil Base Mud) image tools which conventionally cannot detect fracture aperture.",2,2,3
Fracture,Carbonate Reservoirs,"Pham, Chuyen; Chang, Chandong; Jang, Youngho; Kutty, Abdurahiman; Jeong, Jaehoon",Effect of faults and rock physical properties on in situ stress within highly heterogeneous carbonate reservoirs,Carbonate reservoir; In situ stress; Rock mechanical heterogeneity; Young's modulus; Fault,ORIENTATION; MAGNITUDE; FRACTURES; PERTURBATIONS; STABILITY; EVOLUTION; FAILURE; SYSTEM; TESTS; FIELD,"This study characterizes the reservoir-scale in situ stress state within a carbonate oil and gas field in the southeast United Arab Emirates (UAE) to further our understanding of the effects of faults and rock property heterogeneity on variations in stress. The in situ stress state was constrained using image-logged wellbore wall stress indicators (i.e., borehole breakouts and drilling-induced tensile fractures) observed within several vertical boreholes penetrating layered carbonate rock formations. The orientation and magnitude of the in situ stress state vary significantly with both location and depth. The azimuth of the maximum horizontal principal stress (S-Hmax) has diverse orientations that vary significantly with depth and span a similar to 60 degrees range from NW to NNE. The magnitudes of horizontal principal stresses also vary significantly, meaning that no unique stress-depth relations can be defined. Despite considerable fluctuation in stress magnitudes with depth, the stress state in the reservoir is generally in a strike-slip faulting regime, which is consistent with that prevailing throughout onshore UAE. These widespread variations in stress orientation and magnitude appear to be linked to a combination of geomechanical processes associated with the presence of a set of reservoir-scale faults and the highly heterogeneous mechanical properties of the carbonate reservoir. Our analysis indicates that the S-Hmax azimuth rotates proximal to faults from the prevailing far-field stress orientation toward the strike of the faults, but the angle of this azimuthal rotation is dependent on the Young's modulus characteristics of individual formations. The gradient of the horizontal principal stress tends to increase with increasing Young's modulus values, indicating that stiffer formations transfer higher magnitudes of stress. The observed stress variations also agree well with the results of three-dimensional finite element modelling. Our study demonstrates that the strong mechanical heterogeneity of carbonate reservoirs controls the in situ stress state in a complex but explainable way.",2,4,3
Fracture,Carbonate Reservoirs,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Fracture,Carbonate Reservoirs,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Fracture,Core,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Fracture,Core,"Han, Changcheng; Tian, Jijun; Hu, Chenlin; Liu, Hailei; Wang, Wenfeng; Huan, Zhipeng; Feng, Shuo","Lithofacies characteristics and their controlling effects on reservoirs in buried hills of metamorphic rocks: A case study of late Paleozoic units in the Aryskum depression, South Turgay Basin, Kazakhstan",Metamorphic rocks; Lithofacies characters; Reservoir properties; Aryskum depression,KARATAU FAULT; PETROGEOCHEMICAL CHARACTERISTICS; TECTONIC IMPLICATIONS; CARBONATE RESERVOIRS; VOLCANIC-ROCKS; LIAOHE BASIN; CORE COMPLEX; OIL-FIELD; EVOLUTION; BELT,"Metamorphic rock reservoirs are special reservoirs that are quite different from traditional sedimentary rock reservoirs and contain rich hydrocarbon reserves. However, their lithofacies characteristics and reservoir properties are relatively underexplored, and the key factor in reservoirs is lithofacies. Based on core samples, thin sections, whole-rock analysis and well-log and seismic data, we evaluated the lithologies, petrological characteristics and reservoir properties of metamorphic rocks and then explored the main factors controlling reservoir formation and metamorphic rock quality in the Aryskum depression, South Turgay Basin, Kazakhstan. In this area, four types of lithofacies are identified: granitic gneiss (high DEN and CN, low GR), leptite (high GR and CN), gabbro (low GR and CN) and granite (high GR and low CN); among these rocks, granitic gneiss is widely distributed. The reservoir spaces of metamorphic rocks are divided into fractures and pores produced via metamorphism and structural movements. Fractures can be subdivided into structural fractures (SFs), dissolution fractures (DFs), cleavage microfissures (CMfs) and microfissures (Mfs), and pores include dissolved intergranular pores (DInterPs), dissolved intragranular pores (DIntrPs) and vugs (Vgs). Numerous SFs and DFs provide the main reservoir spaces for hydrocarbons. The reservoir quality of metamorphic rocks is primarily controlled by faults, fractures, lithofacies, minerals, dissolution and paleogeomorphology. Lithofacies and minerals are the internal factors that control dissolution and fragmentation, while paleogeomorphology and faults are the external factors that control fracture development. Leptite and granitic gneiss are high-quality reservoir lithofacies, and high paleogeomorphology areas and fault zones are the optimal locations for fractures and pores. Reservoir spaces undergo a series of repeated changes from formation to development, filling and reformation, and a comprehensive reservoir evolution model is proposed to illustrate the distribution of high-quality reservoirs. This study has scientific significance for investigating the reservoir-forming mechanisms of metamorphic rocks and practical applications for exploring and developing oil and gas fields in areas with metamorphic rocks.",3,3,4
Fracture,Core,"Hussain, Maaruf; Amao, Abduljamiu Olalekan; Al-Ramadan, Khalid; Negara, Ardiansyah; Saleh, Tawfik A.",Non-destructive techniques for linking methodology of geochemical and mechanical properties of rock samples,Geochemical; Mechanical properties; Rock; Well,HYDRAULIC FRACTURE PROPAGATION; COMPRESSIVE STRENGTH; POROSITY; EQUOTIP; FIELD; RESERVOIR; BEHAVIOR; SHALE,"Inadequate conventional core data, increasing cost of native sampling techniques, economic downturn in the oil sector, sparse distribution of modern well log suites in horizontal wells, and data acquisition challenges are few among the reasons driving innovation in the use of drill cuttings for determining rock properties and adequate characterization of reservoir units. In this paper, we propose a rock strength proxy based on the correlation between rock strength and elemental geochemistry. The technique uses a combination of X-ray fluorescence and rebound impulse hammer measurements to establish links between the geochemical and mechanical properties of the sampled rocks. We identified five chemo-mechanical facies (CMF) that are formation specific. Furthermore, a cross-validation approach was used to build a predictive model based on acquired elemental and impulse hammer measurements. Consequently, the model was used to predict elastic property and results were encouraging with R-2 of 0.83, 0.87, and 0.89 for training, validation, and testing respectively. This proposed method was developed using core plugs retrieved from subsurface formations. It will be useful for examples in rapid assessment of drill cuttings for the determination of rock strength, especially where the only available data is elemental geochemical data.",3,3,0
Fracture,Core,"Luo, Xiao; Quoc Nguyen; DiCarlo, David",Experimental study on the formation damage caused by gas fracturing fluids,Formation damage; Permeability reduction; Fracturing gas; Compositional flow; Computed tomography; Flowback,LOW-PERMEABILITY; WATER; IMBIBITION; OIL,"Fracturing often results in a fluid invasion into the formation because the fracturing pressure is always greater than the reservoir pressure. The invaded fluid causes formation damage, oil permeability reduction, and potentially reduces production rates. We conduct experiments by invading gas into oil-saturated cores and vary the properties of the oil. We quantify the formation damage through pressure and saturation measurements. In addition, we model the experiment with a compositional fractional flow model, and the results show the formation damage caused by gas is cleared through dissolution transport. The results suggest that the time to clear depends on the fluid properties and the production rate.",3,3,0
Fracture,Core,"Li, Lei; Hao, Yongmao; Lv, Yuting; Wang, Chengwei; Yao, Chuanjin; Zhao, Qingmin; Xiao, Pufu",Experimental investigation on low-velocity seepage characteristics and influencing factors in a shale oil reservoir,,NON-DARCY FLOW; APPARENT PERMEABILITY; GAS-TRANSPORT; NANOPORES; MULTISCALE; MODEL; ADSORPTION; MULTICOMPONENT; PERFORMANCE; SIMULATION,"The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10(-4) ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, microfractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs.",2,2,11
Fracture,Core,"Li, Qing; You, Xuelian; Jiang, Zaixing; Wu, Shenghe; Zhang, Ruifeng","Lithofacies and reservoir characterization of a source-controlled carbonate succession in a lacustrine rift basin, the Shulu Sag of Bohai Bay Basin, East China",Eocene; Shahejing formation; Depositional process; Pore type; Gravity flow; Tight oil,MISSISSIPPIAN BARNETT SHALE; PETROLEUM; GEOCHEMISTRY; ACCUMULATION; DEPOSITS; SYSTEM,"The lower part of the third member of the Eocene Shahejie Formation (Es-3(L)) is one of the most important petroleum exploration targets in the Bohai Bay Basin. Source-controlled carbonate deposits are widely distributed in the Es-3(L) unit of the Shulu Sag and display strong vertical and horizontal variations in lithofacies, geochemical, and reservoir characteristics. Based on core data, thin-section petrography, stable delta C-13 isotope analyses, and organic geochemistry data, eight lithofacies with distinctly different characteristics and origins are identified. Clast-supported terrigenous carbonate rudstone and matrix-supported terrigenous carbonate rudstone were sourced from the surrounding Cambrian-Ordovician carbonate bedrocks and are widely distributed at the edge of the sag in fan delta environments. Some of the rudstones were transported from the littoral zone to profundal zone by slide and slump processes. Mixed-source rudstone was mainly deposited by sandy debris flow. Carbonate lithic sandstone and carbonate lithic siltstone were mainly formed by turbidity current deposition in a sublacustrine setting. Irregular-laminated marlstone was mainly formed by muddy turbidity currents, and massive marlstone was formed by turbid clouds in a relatively turbulent deep water environment. Regular-laminated marlstone is thought formed by seasonal laminae due to seasonal variations by suspension settling in the anoxic deep, quiet lake environment. Calcareous mudstone possibly formed by shallow lake gravity flow in a shallow lake environment. Various of pores have been identified in the Es-3(L) rocks: pores and cracks inside gravels, seams around gravels, intergranular pores, intercrystalline pores, intragranular pores, dissolution pores, organic matter pores, fractures and fracture-related pores. Different lithofacies have different space types, porosities and permeability. Clast-supported terrigenous carbonate rudstone has the best reservoir qualities, with the highest porosity and permeability. Laminated marlstone is the second best reservoir type. These two lithofacies can be the target for tight oil exploration in the study area.",2,2,4
Fracture,Core,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Fracture,Core,"Aghli, Ghasem; Moussavi-Harami, Reza; Tokhmechi, Behzad","Integration of sonic and resistivity conventional logs for identification of fracture parameters in the carbonate reservoirs (A case study, Carbonate Asmari Formation, Zagros Basin, SW Iran)",Fractures; Image logs; Sonic logs; Reservoir parameters; Resistivity logs,SITU STRESS DIRECTION; FOLD-THRUST BELT; IMAGE LOGS; OIL-FIELD; POROSITY; DENSITY; CORE,"Between all available methods for fractures evaluation, core and image logs are prime methods. However, both of these data are very expensive and practically available in less than 10% of drilled wells. Therefore, a less expensive and quick method would be very helpful for fracture analysis. The main aim of this study is to identify the fracture parameters in the carbonate reservoirs, i.e. fracture density and fracture aperture, using a combination of sonic, resistivity and other conventional logs which commonly available in all wells. For this aim, fractures and their parameters were precisely determined on the image logs in 6 wells from carbonate Asmari Formation as a typical fractured reservoir in the world. Then, the effect of fracture parameters on the sonic and resistivity logs were used to identify fracture parameters in the wells with no core and image logs. Results indicate that the zones with high fracture density and aperture are easily detectable by conventional logs. On the other hand, the behavior of these logs is a function of fracture parameters in the fractured intervals, especially in the zones with high fracture aperture. Separation between shallow (RLA2) and deep (RLA5) resistivity logs along with their cross plot are very reliable indicators for fractured intervals. Sonic transit time rapidly increases where fractures density or aperture increased as well. In this study, a combination of sonic and neutron porosity logs have also been used to determine the effect of fracture aperture, as the main effective factor on the reservoir properties. Furthermore, full waveforms in some studied wells combined with sonic transit time to improve the results of fractures evaluation. Using sonic and resistivity along with neutron porosity and gamma ray logs provides a reliable method for describing the fracture parameters which shows high correlation with image logs results. Due to the high impact of fracture aperture on both reservoir quality and conventional log responses, determination of this parameter is more crucial than other fracture parameters. This method is also applicable for OBM (Oil Base Mud) image tools which conventionally cannot detect fracture aperture.",2,2,3
Fracture,Core,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Fracture,Core,"Taheri, Reza; Kabuli, Muffazal; Vryzas, Zisis",Fracturing and permeability enhancement with laser technology employing fuzzy logic,Laser technology; Permeability; Porosity; Microfractures; Fuzzy logic,,"Increasing the rock permeability in low permeable zones of the hydrocarbon reservoirs by conventional methods will often cause formation damage and consequently will reduce the efficiency of recovery of the reservoirs in long term. The use of high energy laser technology as an alternative and innovative approach to mobilise heavy oil and improve permeability, as opposed to the conventional techniques, which have advert effects on the longterm reservoir productivity, was examined in this research. This paper will present study results of the employment of pulsed (Q-switched) Nd: YAG (Neodymium: Yttrium Aluminium Garnet) laser on impermeable heavy oil-bearing core samples which have been simulated in lab to be as close as possible to the real reservoir conditions. A unique technique was employed in this study where lasing experiment was conducted on samples followed by intervals of stopping lasing operation, known as relaxation intervals. The alternate lasing-relaxation intervals which were repeated for samples 3 times, yield positive and satisfactory results both for heavy oil mobilization as well as permeability improvement. Porosity increase was also observed due to fracture production. Specifications of applied laser pulses and their associated beam properties, samples characteristics and dimensions as well as the simulated experiment environment with that of the real reservoir conditions will be reported. Fuzzy logic was employed to normalize the varying and diverse parameters affecting the rock's thermal behaviour such as mineral content, fluid content and type and pressure. By employing the proposed technique on samples from heavy-oil-bearing low permeable zones of Burgan and Mauddud reservoirs of the Giant Burgan field in Kuwait, fractures were produced and permeability of the reservoir samples were improved to almost 3 times of their initial values in some of the samples. Upon the termination of the third lasing experiment, traces of oil could be observed on some of the core sample's surfaces, proving that the heavy oil was mobilised due to induced high temperatures generated in the samples during lasing.",2,2,0
Fracture,Core,"Li, Ben; Zhou, Fujian; Fan, Wentong; Ren, Dengfeng; Li, Hui; Li, Ming",Experimental investigation and theoretical modeling of stress-dependent permeability in naturally fractured tight gas reservoir,Stress-dependent permeability; Pressure pulse decay method; Modified power-law model; Naturally fractured sandstone; Regression analysis,SANDSTONE; PRESSURE; POROSITY,"Stress-dependent permeability (SDP) of naturally fractured tight gas reservoir (NFTGR) has drawn considerable attention in recent decades. The SDP of natural fracture (NF) is quite different from that of the rock matrix (RM) due to the variance NF width and NF filling degree. The SDP of naturally fractures can be obtained by conducting permeability measurement experiments on naturally fractured core plugs (NFCP). However, it is usually impossible to obtain downhole NFCPs due to economic and technical limitations. Our research group obtained various types of naturally fractured downhole core plugs from a NFTGR (Tarim filed, China) and make it possible to investigate the effect of NFs on SDP. The NF types of the downhole core plugs include RM core plug (RMCP), unpenetrated-ring fractured core plug (URFCP), penetrated-vertical fractured core plug (PVFCP), penetrated-incline fractured core plug (PIFCP), unpenetrated-U-type fractured core plug (UUFCP), and multiple fractured core plug (MFCP). We conducted SDP experiments through the application of pressure-pulse-decay (PPD) method. Results showed that the initial permeability of RMCP and MFCP were higher than that of others, and the permeability vanished stress of them were also highest, indicating that the flow resistance of RMCP and MFCP were lower than those of others. It is also shown that the degree of permeability stress-dependent (DPSD) varied from NF types. A modified exponential permeability model was derived to evaluate DPSD of natural fractured core plugs. Two parameters (gamma(sigma eff) and gamma(sigma eff)') were used to describe the DSDP in NFTGR, and the range of which were obtained from the experimental data by regression analysis. The reasonable gamma(sigma eff) and gamma(sigma eff)' range of NFCP were also proposed in this paper. Sensitivity analysis showed that the influence gamma(sigma eff)' on SDP was more significant than that of gamma(sigma eff). The proposed model can be integrated to reservoir simulators and help to improve of oil and gas production prediction accuracy in NFTGRs.",1,1,2
Fracture,Fault,"Wang, Sheng; Zhao, Wanchun; Fu, Xiaofei; Zhang, Ziming; Wang, Tingting; Ge, Jing",A universal method for quantitatively evaluating rock brittle-ductile transition behaviors,Brittleness; Ductility; Brittle-ductile index; Rock deformation,POROUS SANDSTONES; GRAIN-SIZE; FAILURE; DEFORMATION; STRENGTH; FRICTION; CRITERIA; LEAKAGE; FAULTS; FLOW,"In this paper, by investigating the coupling law of crack formation and energy release, establish a universal method for evaluating the brittle-ductile transition stages of rocks. This method can continuously describe the dynamic evolution process of rock from brittle to ductile deformation and the deformation stages are divided quantitatively through the brittle-ductile index (BDI):.brittle deformation phase (BDI >0.5), brittle-ductile transition stage (0 <BDI <0.5) and ductile deformation phase (BDI <0). The triaxial loading test results from various rocks show that when BDI> 0.5, the failure modes are mainly split fractures or low-angle shear fractures; When 0 <BDI <0.5, the conjugate fractures and local fragmentation appear in the rock failure modes; When BDI <0, the rock deformation exhibits no macroscopic damage characteristics, or distributed fine cracks, or distributed fragmentation effect. Therefore, this method can well evaluate the brittle-ductile transition behaviors for various rocks, which has certain universality.",3,3,8
Fracture,Fault,"Jiang, Bingyou; Zhao, Yang; Lin, Baiquan; Liu, Ting",Effect of faults on the pore structure of coal and its resultant change on gas emission,Pore structure; Desorption hysteresis; Fault; Multifractal; Coal and gas outburst,MULTIFRACTAL ANALYSIS; FRACTAL CHARACTERISTICS; ADSORPTION-PORES; DEFORMED COALS; METHANE; EVOLUTION; NITROGEN; OUTBURSTS; SEEPAGE,"Faults are one of the important factors influencing coal and gas outburst in outburst coal seams. In this paper, 3# and 8# coal seams in Xinjing Coal Mine were taken as the research objects in the hope of revealing the mechanism of how faults affect coal seam. The pore structure and its resultant change on gas emission of coal samples at different distances from the faults were studied by means of scanning electron microscope, nuclear magnetic resonance and adsorption/desorption experiments. The results show that the fault significantly influences the pore structure. The coal sample closer to the fault has a greater number of well-developed macropores and fractures as well as better connectivity between pores and fractures. Besides, compared with 8# coal seam, 3# coal seam which is more notably impacted by the fault possesses a more developed pore structure at the micron scale. As the distance from the fault increases, the gas adsorption volume declines while the desorption hysteresis coefficient grows on the whole. The coal sample closer to the fault adsorbs a larger volume of gas and meanwhile desorbs gas more easily, so it is more prone to coal and gas outburst. The initial velocity of gas emission falls gradually as the distance from the fault increases. The desorption hysteresis coefficient generally drops with the rise of the initial velocity of gas emission. Judged by the influence scope of the fault, 3# coal seam possesses a much higher outburst risk than 8# coal seam. The research results reveal the mechanism of how faults affect coal pore structure and gas sorption characteristics, which can provide a basis for the prevention and control of gas dynamic disasters in fault-containing coal seams.",3,3,7
Fracture,Fault,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Fracture,Fault,"Han, Changcheng; Tian, Jijun; Hu, Chenlin; Liu, Hailei; Wang, Wenfeng; Huan, Zhipeng; Feng, Shuo","Lithofacies characteristics and their controlling effects on reservoirs in buried hills of metamorphic rocks: A case study of late Paleozoic units in the Aryskum depression, South Turgay Basin, Kazakhstan",Metamorphic rocks; Lithofacies characters; Reservoir properties; Aryskum depression,KARATAU FAULT; PETROGEOCHEMICAL CHARACTERISTICS; TECTONIC IMPLICATIONS; CARBONATE RESERVOIRS; VOLCANIC-ROCKS; LIAOHE BASIN; CORE COMPLEX; OIL-FIELD; EVOLUTION; BELT,"Metamorphic rock reservoirs are special reservoirs that are quite different from traditional sedimentary rock reservoirs and contain rich hydrocarbon reserves. However, their lithofacies characteristics and reservoir properties are relatively underexplored, and the key factor in reservoirs is lithofacies. Based on core samples, thin sections, whole-rock analysis and well-log and seismic data, we evaluated the lithologies, petrological characteristics and reservoir properties of metamorphic rocks and then explored the main factors controlling reservoir formation and metamorphic rock quality in the Aryskum depression, South Turgay Basin, Kazakhstan. In this area, four types of lithofacies are identified: granitic gneiss (high DEN and CN, low GR), leptite (high GR and CN), gabbro (low GR and CN) and granite (high GR and low CN); among these rocks, granitic gneiss is widely distributed. The reservoir spaces of metamorphic rocks are divided into fractures and pores produced via metamorphism and structural movements. Fractures can be subdivided into structural fractures (SFs), dissolution fractures (DFs), cleavage microfissures (CMfs) and microfissures (Mfs), and pores include dissolved intergranular pores (DInterPs), dissolved intragranular pores (DIntrPs) and vugs (Vgs). Numerous SFs and DFs provide the main reservoir spaces for hydrocarbons. The reservoir quality of metamorphic rocks is primarily controlled by faults, fractures, lithofacies, minerals, dissolution and paleogeomorphology. Lithofacies and minerals are the internal factors that control dissolution and fragmentation, while paleogeomorphology and faults are the external factors that control fracture development. Leptite and granitic gneiss are high-quality reservoir lithofacies, and high paleogeomorphology areas and fault zones are the optimal locations for fractures and pores. Reservoir spaces undergo a series of repeated changes from formation to development, filling and reformation, and a comprehensive reservoir evolution model is proposed to illustrate the distribution of high-quality reservoirs. This study has scientific significance for investigating the reservoir-forming mechanisms of metamorphic rocks and practical applications for exploring and developing oil and gas fields in areas with metamorphic rocks.",3,3,4
Fracture,Fault,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Fracture,Fault,"Pham, Chuyen; Chang, Chandong; Jang, Youngho; Kutty, Abdurahiman; Jeong, Jaehoon",Effect of faults and rock physical properties on in situ stress within highly heterogeneous carbonate reservoirs,Carbonate reservoir; In situ stress; Rock mechanical heterogeneity; Young's modulus; Fault,ORIENTATION; MAGNITUDE; FRACTURES; PERTURBATIONS; STABILITY; EVOLUTION; FAILURE; SYSTEM; TESTS; FIELD,"This study characterizes the reservoir-scale in situ stress state within a carbonate oil and gas field in the southeast United Arab Emirates (UAE) to further our understanding of the effects of faults and rock property heterogeneity on variations in stress. The in situ stress state was constrained using image-logged wellbore wall stress indicators (i.e., borehole breakouts and drilling-induced tensile fractures) observed within several vertical boreholes penetrating layered carbonate rock formations. The orientation and magnitude of the in situ stress state vary significantly with both location and depth. The azimuth of the maximum horizontal principal stress (S-Hmax) has diverse orientations that vary significantly with depth and span a similar to 60 degrees range from NW to NNE. The magnitudes of horizontal principal stresses also vary significantly, meaning that no unique stress-depth relations can be defined. Despite considerable fluctuation in stress magnitudes with depth, the stress state in the reservoir is generally in a strike-slip faulting regime, which is consistent with that prevailing throughout onshore UAE. These widespread variations in stress orientation and magnitude appear to be linked to a combination of geomechanical processes associated with the presence of a set of reservoir-scale faults and the highly heterogeneous mechanical properties of the carbonate reservoir. Our analysis indicates that the S-Hmax azimuth rotates proximal to faults from the prevailing far-field stress orientation toward the strike of the faults, but the angle of this azimuthal rotation is dependent on the Young's modulus characteristics of individual formations. The gradient of the horizontal principal stress tends to increase with increasing Young's modulus values, indicating that stiffer formations transfer higher magnitudes of stress. The observed stress variations also agree well with the results of three-dimensional finite element modelling. Our study demonstrates that the strong mechanical heterogeneity of carbonate reservoirs controls the in situ stress state in a complex but explainable way.",2,4,3
Fracture,Fault,"Toth, Tivadar M.; Toth, Ilona Vargane","Lithologically controlled behaviour of the Dorozsma metamorphic hydrocarbon reservoir (Pannonian Basin, SE Hungary)",Fractured hydrocarbon reservoir; Metamorphic rocks; Shear zone; Dolomite marble; Pannonian basin,EVOLUTION; SYSTEM; EQUILIBRIUM; CONSTRAINTS; MIGRATION; GEOMETRY; NETWORK; QUARTZ; FLUID; ROCKS,"Numerous fractured hydrocarbon reservoirs occur in the metamorphic basement of the Pannonian Basin in Hungary, and among them, the Dorozsma field is one of the most productive. Here 66 boreholes penetrated the metamorphic massif, making detailed petrographic and microstructural evaluation possible. Well-log data (gamma-ray, density, neutron porosity and compressional slowness) are available for each well, which can be used to extend the petrographic information spatially. The data suggest three basic rock types in the study area, which align along a consequent rock column. In the deepest structural positions, amphibolite is typical, while the top of the basement is dominated by kyanite gneiss. Thermobarometric calculation results prove that the gneiss-rich realm was metamorphosed at a significantly higher temperature than the lowermost amphibolite, suggesting a post-metamorphic structural contact between them. The contact zone, observed in numerous boreholes, contains intensively deformed dolomite marble of a few tens of metres in thickness. The peak metamorphic temperature of this rock type is much lower than those typically seen in the two neighbouring blocks. Localising the position of the dolomite marble horizon in each well was accomplished using petrographic and well-log information, and through this investigation, a flat, low-angle shear zone became visible, cut by a set of younger normal faults. Hydrocarbon production data clearly shows that the best, most productive intervals in each well are strongly correlated to the shear zone between the gneiss- and amphibolite-dominated realms, namely the sheared dolomite marble zone.",2,2,2
Fracture,Fault,"Gao, Jiajia; Li, Qian; Deng, Jingen; Tang, Hongming; Yin, Hu; Yan, Xinjiang",Initiation of hydraulically or drilling-induced tensile wall-fractures from arbitrarily inclined boreholes: Implications for constraints in the magnitudes of in-situ stresses,Fracture initiation pressure; Fracture initiation position; Fracture trace angle; Transverse hydraulically induced tensile wall-fractures; Critical borehole inclination or azimuth angles,WELL BORE BREAKOUTS; BASIN; ORIENTATION; STATE; INVERSION; FIELD; PROPAGATION; EXPLORATION; STABILITY; PRESSURE,"An accurate estimation of the magnitudes of three in-situ stresses can usefully improve the production performance of hydraulic fracturing and reduce the risk of wellbore instability. Considering two types of linear elastic stress around the non-perforated arbitrarily inclined borehole (plane strain and plane stress conditions), the theory of hydraulic fracturing, and the maximum tensile criterion, the generalized governing formulas are derived to explain the mechanism of hydraulically or drilling-induced longitudinal, oblique, and transverse tensile wall-fractures in arbitrarily inclined boreholes. These formulas provide useful implications for constraints on the magnitudes of in-situ stresses, which determine the initiation of different types of tensile wall-fractures under different faulting stress regimes. The present paper extends the initiating conditions of the common transverse tensile wall-fractures related to the works of Hossain et al. (2000) and Nelson et al. (2005). The prerequisite for the special transverse tensile wall-fractures that tensile fractures simultaneously initiated around a whole borehole wall (Huang et al., 2012) is generalized by introducing the concept of the turning locations. The formulas corresponding to the turning locations are provided under different faulting stress regimes, revealing that the work proposed by Huang et al. (2012) is only a particular case. It is found that the turning locations are related to the critical borehole inclination or azimuth angles. Overall, all the formulas in this study for longitudinal, oblique, and transverse tensile wall-fractures can be used to design hydraulic fracturing experiments and to determine the in-situ stress by using the information of drilling-induced tensile wall-fractures. Moreover, the governing formulas of the turning locations can also be used to optimize the borehole trajectory.",2,2,2
Fracture,Fault,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Fracture,Borehole,"Wang, Shen; Li, Dongyin; Mitri, Hani; Li, Huamin",Numerical simulation of hydraulic fracture deflection influenced by slotted directional boreholes using XFEM with a modified rock fracture energy model,Directional hydraulic fracturing; XFEM; Slotted directional borehole; Hydraulic fracture morphology; Rock shear fracture energy,FINITE-ELEMENT-METHOD; PROPAGATION CONTROL; CRACK-GROWTH; PRESSURE; TECHNOLOGY; INITIATION; MECHANISM; MEDIA,"Directional hydraulic fracturing (DHF) has been used in conductivity improvement of oil, gas and geothermal energy reservoirs and hard rock roof breaking in coal mines. Although the new DHF method that integrates fracturing borehole and slotted directional borehole (SDB) has been recently introduced, the mechanism and effectiveness of SDB on hydraulic fracture guiding remain open issues. In this study, numerical simulation based on extended finite element method (XFEM) is performed to investigate the effect of SDB on hydraulic fracture deflection. A modified rock fracture energy model is proposed and performed by a user subroutine USDFLD with XFEM, which considers the hardening property of rock shear fracture energy as confining pressure increases. The effects of stress field and borehole line azimuth on hydraulic fracture deflection and bottomhole pressure are investigated. Hydraulic fracture morphologies of three kinds of multi-borehole fracturing technology are compared, the control mechanism of SDBs on hydraulic fracture is explained, and the bottomhole pressure relief effect, borehole spacing and potential application prospects are discussed. Result indicates that the modified model shows good accuracy and applicability in predicting hydraulic fracture propagation, and the hardening property of shear fracture energy should be considered when using XFEM and cohesive element method. The feature first drop and then rise ? of bottomhole pressure curve is an important sign that imply the hydraulic fracture propagates into the influence radius of SDB and can be used as an indicator to evaluate the effectiveness of DHF. Slot increases the influence radius of directional borehole and changes the local stress direction, thus allowing SDB-based DHF technique to be applied to the conditions where the stress difference ratio does not exceed one. When the stress difference ratio is greater than one, the pressurized SDB is more suitable.",3,3,15
Fracture,Borehole,"Xiao, Caiyun; Ni, Hongjian; Shi, Xian; Wang, Ruihe",A fracture initiation model for carbon dioxide fracturing considering the bottom hole pressure and temperature condition,CO2 fracturing; Fracture initiation; Wellbore flow model; Pressure transmission; Parameter optimization,CO2 INJECTION; HEAT-TRANSFER; PROPAGATION; STATE; SEQUESTRATION; MECHANISM; EQUATION; STORAGE; WELLS; FLOW,"The properties of CO2 under different conditions significantly affect the breakdown pressure during CO2 fracturing. In this study, the fracture initiation model is combined with real bottom-hole temperature-pressure condition by considering CO2 borehole pressurization rate. The results show that the breakdown pressure can be reduced by 26.2%-35.5%. With a constant pump rate of 0.5 m(3)/min, bottom-hole pressure exceeds the breakdown pressure at approximately 408s, meanwhile, bottom-hole temperature decreases by 4.38% and borehole pressurization rate expands by 2.4 times. As the pump rate increases, the pressurization rate reaches its peak at a pump rate of 6.0 m(3)/min, and the downtrend is delayed with inlet pressure increasing. Case study shows that the breakdown pressure predicted by the new model agrees well with in-situ data, and the range of optimal inlet pump rate is 1.9-2.5 m(3)/min under the in-situ inlet condition (T-0 = 258 K and p(0) = 6 MPa). Furthermore, the range of optimal inlet pump rate expands with inlet pressure increasing and shrinks with inlet temperature increasing. This new initiation pressure model can provide more insights for CO2 fracturing mechanisms and design.",3,3,2
Fracture,Borehole,"Garolera, Daniel; Carol, Ignacio; Papanastasiou, Panos",Application of zero-thickness interface elements to sanding prediction analysis,Sand production prediction; Sanding; Zero-thickness interfaces; Micromechanics; Localization; Cracking,MICROMECHANICAL ANALYSIS; BOREHOLE; FRACTURE; MODEL; LOCALIZATION; CRACKING,"A computational micromechanical analysis based on zero thickness interface elements for modelling solid prediction in hydrocarbon reservoir sandstones is presented. The model is capable of modelling localization of deformation, disintegration and cracking of cemented rock formation that leads to initiation and continuous sand production during hydrocarbon production and reservoir depletion. Using only few physical parameters, the model is calibrated at the macroscale by reproducing the typical behaviour of geomaterials in compression element tests that is characterized by transition from brittle dilatant to ductile compactant behaviour with increasing confining stress. In the presented application presented, the model was calibrated first using the results of two triaxial tests performed on samples that were recovered from a deep well and then a sand production analysis was carried out. The model predictions are compared well with the experimental results of thick wall cylinder tests. The proposed methodology is very promising as it can predict not only the initiation of sanding, but also the continuous produced sand volumes under geometry changing conditions which is still a challenging research problem.",3,3,1
Fracture,Borehole,"Li, Yanliang; Peng, Jianming; Zhang, Guang; Yang, Zhenglong; Li, Keke",Study on perforation performance of abrasive water jet enhanced by percussive drilling,AWJ Perforation; Percussive drilling; Perforation performance; Impact cracks,HYDRAULIC FRACTURE INITIATION; GEOTHERMAL-ENERGY; PRESSURE; TECHNOLOGY; STIMULATION; MECHANISM; IMPACT; SHALE,"Geothermal energy is abundant and has a high economic development value. Perforation would need to be utilized to establish fluid channels between the borehole and geothermal reservoirs. In the present paper, it is proposed to use percussive drilling to create impact cracks near the borehole to improve abrasive water jet (AWJ) perforation performance. Two groups of the specimen were used for experiments. One was the specimen near the borehole after conventional rotary drilling (G1), the other was the specimen near the borehole after percussive drilling (G2). The optimal parameters of AWJ perforation assisted by percussive drilling were obtained. Through evaluation of AWJ perforation performance, it was found that the perforation depth, diameter and volume of G2 were 1.5 times, 1.3 times and 2 times of the G1, respectively. Besides, there were many internal cracks in G2, which interweave with each other and form a crack network. The results indicated that the impact cracks could change the mechanical properties of the granite near the borehole, then reduce the difficulty of AWJ perforation and improve the perforation performance. All the above merits can provide important technical support for reducing the fracturing pressure, increasing fluid flow and enhancing heat exchange efficiency between geothermal reservoir and borehole.",2,2,6
Fracture,Borehole,"Pham, Chuyen; Chang, Chandong; Jang, Youngho; Kutty, Abdurahiman; Jeong, Jaehoon",Effect of faults and rock physical properties on in situ stress within highly heterogeneous carbonate reservoirs,Carbonate reservoir; In situ stress; Rock mechanical heterogeneity; Young's modulus; Fault,ORIENTATION; MAGNITUDE; FRACTURES; PERTURBATIONS; STABILITY; EVOLUTION; FAILURE; SYSTEM; TESTS; FIELD,"This study characterizes the reservoir-scale in situ stress state within a carbonate oil and gas field in the southeast United Arab Emirates (UAE) to further our understanding of the effects of faults and rock property heterogeneity on variations in stress. The in situ stress state was constrained using image-logged wellbore wall stress indicators (i.e., borehole breakouts and drilling-induced tensile fractures) observed within several vertical boreholes penetrating layered carbonate rock formations. The orientation and magnitude of the in situ stress state vary significantly with both location and depth. The azimuth of the maximum horizontal principal stress (S-Hmax) has diverse orientations that vary significantly with depth and span a similar to 60 degrees range from NW to NNE. The magnitudes of horizontal principal stresses also vary significantly, meaning that no unique stress-depth relations can be defined. Despite considerable fluctuation in stress magnitudes with depth, the stress state in the reservoir is generally in a strike-slip faulting regime, which is consistent with that prevailing throughout onshore UAE. These widespread variations in stress orientation and magnitude appear to be linked to a combination of geomechanical processes associated with the presence of a set of reservoir-scale faults and the highly heterogeneous mechanical properties of the carbonate reservoir. Our analysis indicates that the S-Hmax azimuth rotates proximal to faults from the prevailing far-field stress orientation toward the strike of the faults, but the angle of this azimuthal rotation is dependent on the Young's modulus characteristics of individual formations. The gradient of the horizontal principal stress tends to increase with increasing Young's modulus values, indicating that stiffer formations transfer higher magnitudes of stress. The observed stress variations also agree well with the results of three-dimensional finite element modelling. Our study demonstrates that the strong mechanical heterogeneity of carbonate reservoirs controls the in situ stress state in a complex but explainable way.",2,4,3
Fracture,Borehole,"Toth, Tivadar M.; Toth, Ilona Vargane","Lithologically controlled behaviour of the Dorozsma metamorphic hydrocarbon reservoir (Pannonian Basin, SE Hungary)",Fractured hydrocarbon reservoir; Metamorphic rocks; Shear zone; Dolomite marble; Pannonian basin,EVOLUTION; SYSTEM; EQUILIBRIUM; CONSTRAINTS; MIGRATION; GEOMETRY; NETWORK; QUARTZ; FLUID; ROCKS,"Numerous fractured hydrocarbon reservoirs occur in the metamorphic basement of the Pannonian Basin in Hungary, and among them, the Dorozsma field is one of the most productive. Here 66 boreholes penetrated the metamorphic massif, making detailed petrographic and microstructural evaluation possible. Well-log data (gamma-ray, density, neutron porosity and compressional slowness) are available for each well, which can be used to extend the petrographic information spatially. The data suggest three basic rock types in the study area, which align along a consequent rock column. In the deepest structural positions, amphibolite is typical, while the top of the basement is dominated by kyanite gneiss. Thermobarometric calculation results prove that the gneiss-rich realm was metamorphosed at a significantly higher temperature than the lowermost amphibolite, suggesting a post-metamorphic structural contact between them. The contact zone, observed in numerous boreholes, contains intensively deformed dolomite marble of a few tens of metres in thickness. The peak metamorphic temperature of this rock type is much lower than those typically seen in the two neighbouring blocks. Localising the position of the dolomite marble horizon in each well was accomplished using petrographic and well-log information, and through this investigation, a flat, low-angle shear zone became visible, cut by a set of younger normal faults. Hydrocarbon production data clearly shows that the best, most productive intervals in each well are strongly correlated to the shear zone between the gneiss- and amphibolite-dominated realms, namely the sheared dolomite marble zone.",2,2,2
Fracture,Borehole,"Gao, Jiajia; Li, Qian; Deng, Jingen; Tang, Hongming; Yin, Hu; Yan, Xinjiang",Initiation of hydraulically or drilling-induced tensile wall-fractures from arbitrarily inclined boreholes: Implications for constraints in the magnitudes of in-situ stresses,Fracture initiation pressure; Fracture initiation position; Fracture trace angle; Transverse hydraulically induced tensile wall-fractures; Critical borehole inclination or azimuth angles,WELL BORE BREAKOUTS; BASIN; ORIENTATION; STATE; INVERSION; FIELD; PROPAGATION; EXPLORATION; STABILITY; PRESSURE,"An accurate estimation of the magnitudes of three in-situ stresses can usefully improve the production performance of hydraulic fracturing and reduce the risk of wellbore instability. Considering two types of linear elastic stress around the non-perforated arbitrarily inclined borehole (plane strain and plane stress conditions), the theory of hydraulic fracturing, and the maximum tensile criterion, the generalized governing formulas are derived to explain the mechanism of hydraulically or drilling-induced longitudinal, oblique, and transverse tensile wall-fractures in arbitrarily inclined boreholes. These formulas provide useful implications for constraints on the magnitudes of in-situ stresses, which determine the initiation of different types of tensile wall-fractures under different faulting stress regimes. The present paper extends the initiating conditions of the common transverse tensile wall-fractures related to the works of Hossain et al. (2000) and Nelson et al. (2005). The prerequisite for the special transverse tensile wall-fractures that tensile fractures simultaneously initiated around a whole borehole wall (Huang et al., 2012) is generalized by introducing the concept of the turning locations. The formulas corresponding to the turning locations are provided under different faulting stress regimes, revealing that the work proposed by Huang et al. (2012) is only a particular case. It is found that the turning locations are related to the critical borehole inclination or azimuth angles. Overall, all the formulas in this study for longitudinal, oblique, and transverse tensile wall-fractures can be used to design hydraulic fracturing experiments and to determine the in-situ stress by using the information of drilling-induced tensile wall-fractures. Moreover, the governing formulas of the turning locations can also be used to optimize the borehole trajectory.",2,2,2
Fracture,Borehole,"Cui, Shuai; Liu, Houbin; Meng, Yingfeng; Fan, Yu; Wang, Jiajun; Han, Zhengbo",Study on mechanical properties and wellbore stability of deep brittle shale,Deep brittle shale; Borehole stress field; Complex loading; Surge pressure; Tensile caving; Wellbore stability,,"As the drilling depth of shale's oil and gas wells increases worldwide, the problem of borehole collapse and instability becomes increasingly serious. Due to the high content of brittle minerals in deep shale, the complex situation of an underground collapse of a site is often manifested as borehole wall caving and falling. On the basis of the deep shale of China's Longmaxi formation, we developed a simulation experiment involving the complex loading mechanics of underground working conditions. The influence of loading and unloading confining pressure speeds and the sealing properties of drilling fluid on the mechanical properties of rock were analyzed. We established the dynamic changes in borehole formation, combining seepage and pore pressure, the effective stress field around the well, and a method of evaluating wellbore stability in deep shale gas horizontal wells. The results show that the deep shale of the Longmaxi formation has a high brittle mineral content and is prone to brittle fracturing along parallel bedding surfaces under downhole pressure. The effective liquid column pressure at the bottom of the wells change noticeably under different working conditions. Changes in bottom hole fluid column pressure are the cause of the complicated situation of well leakage and overflow in the horizontal sections of the Longmaxi formation. The effective support confining pressure of borehole wall rock differs with different tripping out speeds. The faster the tripping out is, the less the support confining pressure of the wellbore rock and the easier it is to induce the rock to break down along the bedding. The effective sealing property of drilling fluid also affects wellbore stability. A good sealing property of drilling fluid can improve the supporting effect of the fluid on borehole wall rock and improve its resistance strength. On the whole, the pressure of the bottom hole liquid column is effectively controlled during drilling in the Longmaxi formation; this can avoid complicated situations such as well leakage. The results of this study provide a theoretical basis for the study of wellbore stability in deep shale formations during the drilling process.",1,1,5
Fracture,Low Permeability,"Liu, Junrong; Shi, Weixin; Wu, Xingru",Experimental study on thermally enhanced permeability of rock with chemical agents,Rock; Thermal fracturing; Permeability enhancement; Chemical agent; Solution concentration; Reservoir thermal stimulation,HIGH-TEMPERATURE; DECOMPOSITION; STIMULATION; CARBONATE; PRESSURE; STRENGTH; CRACKING; DAMAGE,"Previous researches focused on dry sample thermal treatment to enhance rock permeability indicate that thermal treatment can be a novel stimulation technique for geothermal and hydrocarbon reservoirs development. The mechanicm of thermal permeability enhancement depends on the generation of microcracks by thermal cracking. In this study, chemical solutions were introduced on sandstone rock samples and observed that they can be used to control thermal permeability enhancement. Sandstone specimens with the same order of permeability were saturated with different salt solutions and heated to different temperatures. The results quantify permeabilities and porosities of specimens saturated with electrolyts over them without chemical treatment but heated to the same temperature. The KCl solution had the largest effect on permeability enhancement for the tested rock and showed a tenfold increase in permeability, and followed by NaCl and K2CO3 solutions. However, CaCl2 solution and distilled water had negative effects. Laboratory results also revealed a positive correlation between some chemical concentration with the permeability increment of rock. The effects of electrolyte type and concentration on thermally permeability enhancement of the tested rocks were determined and a statistical model was fitted. The results show that the permeability increment follows an exponential growth with temperature when the rock was heated over the threshold temperature of thermal cracking. Introducing specific chemical species into a low-permeability formation and heating the formation beyond the threshold temperature of rock thermal cracking will be a promising way to further enhance formation permeability.",3,3,11
Fracture,Low Permeability,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Fracture,Low Permeability,"Wang, HanYi; Sharma, Mukul M.",A rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure,In-situ stress; Pore pressure; Hydraulic fracturing; RIFT; DFIT; Effective fracture volume,ELASTIC COMPLIANCES; FRACTURE-COMPLIANCE; CAPROCK INTEGRITY; CONDUCTIVITY; STIMULATION; FIELD,"Extended leak-off test (XLOT) and pump-in and flow-back test (PIFB) are commonly used during drilling operations to estimate minimum stress. These estimates are adversely affected by hoop stress and drilling mud. Diagnostic Fracture Injection Tests (DFIT) can estimate both in-situ stress and pore pressure, but it takes days or weeks to conduct the test in low permeability formations. In this study, we present a novel rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure. Our new approach not only provides an unambiguous way to estimate in-situ stress (even in naturally fractured formations where DFIT fails to do so), but also allows us to estimate pore pressure with data from a test that lasts only a few hours, in addition, the effective fracture volume can also be estimated. Both simulations and field cases are presented to demonstrate the advantages of RIFT, along with a discussion of cautions and the potential pitfalls when designing and executing RIFT.",3,3,0
Fracture,Low Permeability,"Luo, Xiao; Quoc Nguyen; DiCarlo, David",Experimental study on the formation damage caused by gas fracturing fluids,Formation damage; Permeability reduction; Fracturing gas; Compositional flow; Computed tomography; Flowback,LOW-PERMEABILITY; WATER; IMBIBITION; OIL,"Fracturing often results in a fluid invasion into the formation because the fracturing pressure is always greater than the reservoir pressure. The invaded fluid causes formation damage, oil permeability reduction, and potentially reduces production rates. We conduct experiments by invading gas into oil-saturated cores and vary the properties of the oil. We quantify the formation damage through pressure and saturation measurements. In addition, we model the experiment with a compositional fractional flow model, and the results show the formation damage caused by gas is cleared through dissolution transport. The results suggest that the time to clear depends on the fluid properties and the production rate.",3,3,0
Fracture,Low Permeability,"Li, Lei; Hao, Yongmao; Lv, Yuting; Wang, Chengwei; Yao, Chuanjin; Zhao, Qingmin; Xiao, Pufu",Experimental investigation on low-velocity seepage characteristics and influencing factors in a shale oil reservoir,,NON-DARCY FLOW; APPARENT PERMEABILITY; GAS-TRANSPORT; NANOPORES; MULTISCALE; MODEL; ADSORPTION; MULTICOMPONENT; PERFORMANCE; SIMULATION,"The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10(-4) ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, microfractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs.",2,2,11
Fracture,Low Permeability,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Fracture,Low Permeability,"Taheri, Reza; Kabuli, Muffazal; Vryzas, Zisis",Fracturing and permeability enhancement with laser technology employing fuzzy logic,Laser technology; Permeability; Porosity; Microfractures; Fuzzy logic,,"Increasing the rock permeability in low permeable zones of the hydrocarbon reservoirs by conventional methods will often cause formation damage and consequently will reduce the efficiency of recovery of the reservoirs in long term. The use of high energy laser technology as an alternative and innovative approach to mobilise heavy oil and improve permeability, as opposed to the conventional techniques, which have advert effects on the longterm reservoir productivity, was examined in this research. This paper will present study results of the employment of pulsed (Q-switched) Nd: YAG (Neodymium: Yttrium Aluminium Garnet) laser on impermeable heavy oil-bearing core samples which have been simulated in lab to be as close as possible to the real reservoir conditions. A unique technique was employed in this study where lasing experiment was conducted on samples followed by intervals of stopping lasing operation, known as relaxation intervals. The alternate lasing-relaxation intervals which were repeated for samples 3 times, yield positive and satisfactory results both for heavy oil mobilization as well as permeability improvement. Porosity increase was also observed due to fracture production. Specifications of applied laser pulses and their associated beam properties, samples characteristics and dimensions as well as the simulated experiment environment with that of the real reservoir conditions will be reported. Fuzzy logic was employed to normalize the varying and diverse parameters affecting the rock's thermal behaviour such as mineral content, fluid content and type and pressure. By employing the proposed technique on samples from heavy-oil-bearing low permeable zones of Burgan and Mauddud reservoirs of the Giant Burgan field in Kuwait, fractures were produced and permeability of the reservoir samples were improved to almost 3 times of their initial values in some of the samples. Upon the termination of the third lasing experiment, traces of oil could be observed on some of the core sample's surfaces, proving that the heavy oil was mobilised due to induced high temperatures generated in the samples during lasing.",2,2,0
Fracture,Low Permeability,"Artun, E.",Performance assessment and forecasting of cyclic gas injection into a hydraulically fractured well using data analytics and machine learning,Cyclic gas injection; Data analytics; Enhanced oil recovery; Hydraulically fractured wells; Machine learning; Performance forecasting,NITROGEN,"Single-well application of cyclic gas injection is a promising enhanced oil recovery method especially in fractured and depleted reservoirs. It was previously shown that presence of hydraulic/natural fractures would increase the effectiveness of this method because of the surface area of fractures that supports gas diffusion into the rock matrix. Increased pressure and changes in the physical properties of oil after injection both contribute to improved oil recovery. In this study, a comprehensive analysis of the performance-related design aspects of kcyclic injection of a mixture of N-2, CO2 and CH4 in a hydraulically-fractured well is presented. These three types of gases can contribute to different mechanisms for enhanced recovery because of their unique phase behavior. On the other hand, their costs and availability may be different which may lead to different economic benefits. For the proposed analysis, a large number of injection scenarios were run using a compositional reservoir model that represents the drainage area of a hydraulically fractured well in a low-permeability reservoir. Design parameters such as the injection rate, duration (and volume), soaking duration, economic rate limit, and injected gas composition are varied with uniformly distributed values of each parameter within pre-defined ranges. Both volumetric and economic utilization efficiency factors are analyzed as the performance indicators. Discounted values of incremental oil produced, volume of injected gas, oil price and costs of injected gas for varying project periods of 5, 10, 15 and 20 years are considered for the efficiency calculations. It is observed that the presented method can be a cost-effective enhanced recovery method for hydraulically-fractured wells depending on the proper selection of operational conditions. Injection volume should be kept below 10,000 MCF per cycle. Economic rate limit and soaking period should be optimized. While N-2 is more cost effective than other gases, it mostly provides short-term benefits. The data set is used to train a neural network that can be used to forecast the economic efficiency indicator. Results show that machine learning is an effective approach to develop accurate forecasting models. R-2 values greater than 0.90 are observed for the correlation between real and predicted values for both training and testing, regardless of design considerations of the neural network.",1,1,1
Fracture,Lost Circulation,"She, Jiping; Zhang, Hao; Kang, Yili; Feng, Yin; Zhong, Ying; Yang, Bin",Cusp catastrophe model for plugging pressure prediction of lost circulation control in fractured reservoirs,Fractured reservoirs; Lost circulation; Cusp catastrophe; Maximum plugging pressure; Plugging zone,FRICTION COEFFICIENT,"Lost circulation is one of the most common and costly problems in drilling. The stability of the plugging zone is a key factor determining the lost circulation control. In this paper, an analytical model is derived based on the catastrophic theory, which considers key parameters affecting the stability of the plugging zone, such as formation parameters, contact parameters and plugging zone parameters. The maximum plugging pressure (MPP) can be calculated by this model to quantitatively evaluate the stability of the plugging zone. The validation case shows that the calculation result is in good agreement with the experimental measurement. In addition, the sensitivity analysis is performed and shows that the length of the plugging zone, the sliding friction coefficient of the fracture surface and the Young's modulus of plugging zone are positively correlated with MPP, but the shear height of plugging zone, sliding friction coefficient of lost circulation materials (LCMs) and Poisson's ratio of the plugging zone are negatively correlated with MPP. The model can be used to predict the MPP in lost circulation control and considered as a reference for the optimization of the LCMs and plugging program.",3,4,4
Fracture,Lost Circulation,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Fracture,Lost Circulation,"Li, Jia; Qiu, Zhengsong; Zhao, Xin; Zhong, Hanyi; Yang, Yifan; Huang, Weian",Effect of different parameters on sealing performance of lost circulation process with dynamic fracture aperture testing apparatus,,LOSSES; DESIGN,,2,2,5
Fracture,Lost Circulation,"Wang, Peng; Ni, Hongjian; Liu, Haoge; Zhao, Bo",A novel wellbore strengthening method by using rotary jet while drilling,Lost circulation; Wellbore strengthening; Mechanism; Rotary jet; Field test,LOST-CIRCULATION; STRESS,Lost circulation is one of the most common and costly problems in drilling operations. Improving the wellbore strengthening by plugging drilling induced fractures using rotary jet method is a novel and effective method to mitigate lost circulation. A stress analysis model based on elastic-plastic mechanics was established to reveal the wellbore strengthening mechanism of rotary jet plugging while drilling. The structure of rotary jet tool was proposed and mixture multiphase flow model was adopted to optimize the structure of the modulation unit of rotary jet. The field tests of engineering prototype were carried out in 81/2 '' interval of three wells. Satisfactory plugging results verify the effectiveness of rotary jet plugging and wellbore strengthening technology.,2,2,1
Fracture,Pressure Gradient,"Li, Lei; Hao, Yongmao; Lv, Yuting; Wang, Chengwei; Yao, Chuanjin; Zhao, Qingmin; Xiao, Pufu",Experimental investigation on low-velocity seepage characteristics and influencing factors in a shale oil reservoir,,NON-DARCY FLOW; APPARENT PERMEABILITY; GAS-TRANSPORT; NANOPORES; MULTISCALE; MODEL; ADSORPTION; MULTICOMPONENT; PERFORMANCE; SIMULATION,"The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10(-4) ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, microfractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs.",2,2,11
Fracture,Pressure Gradient,"Zhu, Jianting",Impact of yield stress and fractal characteristics on the flow of Bingham fluid through fracture network,Bingham fluid; Newtonian fluid; Yield stress; Fractured reservoir; Fractal dimension; Flowrate ratio,STARTING PRESSURE-GRADIENT; EFFECTIVE PERMEABILITY; GAS-RESERVOIRS; MODEL; MECHANICS; WELL,"Flow process of a fluid with yield stress in fractured reservoirs is important in petroleum recovery. In this study, a new approach is proposed to study the combined effect of Bingham fluid properties and fractal characteristics on the flow of a Bingham fluid through a fractal fracture network. Both the aperture and trace length of fractures are distributed according to the power-law fractal distribution with distinct fractal dimensions. The relative effect on the flowrate of Bingham fluid in the network by the Bingham fluid properties and fractal characteristics compared to the Newtonian counterpart is examined. The results demonstrate that the flowrate of Bingham fluid through the network increases quickly with the pressure head gradient since large fractures are first activated which are responsible to quickly increase the Bingham fluid flowrate. The flowrate ratio of the Bingham fluid over Newtonian fluid decreases with the fractal dimension of aperture since the Bingham fluid flowrate decreases with increasing fractal dimension at a faster rate than the Newtonian fluid. A larger ratio of minimum over maximum apertures in the fractal network results in a larger flowrate ratio of the Bingham fluid over Newtonian fluid. The trace length fractal parameters do not affect the flowrate ratio of the Bingham fluid over the Newtonian fluid due to the fact that these parameters affect the actual flowrate for both types of fluid to the same extent.",2,2,0
Fracture,Pressure Gradient,"Merey, Sukru",Estimation of fracture pressure gradients in the shallow sediments of the Mediterranean Sea by using ODP Leg 160 and Leg 161 data,Fracture pressure; Pore pressure; Gas hydrates; Shallow sediments; Drilling; Well log,NATURAL-GAS; HYDRATE; BASIN; ORIENTATION; PREDICTION; PARAMETERS; RESERVOIRS; MAGNITUDE,"Pore pressure gradient and fracture gradient are two of the most important parameters while making well drilling design. Hence, in this study, these gradients were estimated for the Mediterranean Sea shallow sediments where gas hydrate might exist by using ODP Leg 160 and ODP Leg 161 data (mainly density logs). The density logs obtained during these drilling programs were used to estimate fracture pressure gradients. In this study, pore pressure gradient intervals in the Eastern Mediterranean Sea and the Western Mediterranean Sea were estimated as 0.433-0.484 psi/ft and 0.459-0.460 psi/ft, respectively. It was found that geothermal gradients of the holes drilled in the Western Mediterranean Sea sediments are quite high (up to 128 degrees C/km) but the maximum geothermal gradient observed in the Eastern Mediterranean Sea is 12.85 degrees C/km. The estimated fracture pressure gradient ranges in the Eastern Mediterranean Sea and the Western Mediterranean Sea shallow sediments are 0.604-0.659 psi/ft and 0.675 psi/ft-0.766 psi/ft. For the first time, the fracture gradients in the shallow sediments (where gas hydrate might exist) of the Mediterranean Sea were predicted in this study. These fracture gradients are suggested for the drilling and well completion designs of gas hydrate wells in the conditions of the Mediterranean Sea.",1,1,1
Fracture,Pressure Gradient,"Mohajeri, Sina; Eslahi, Reza; Bakhtiari, Maryam; Alizadeh, Ali; Madani, Mohammad; Zeinali, Mostafa; Rajabi, Hamed; Sharifi, Ebrahim; Mortezazadeh, Emad; Mahdavifar, Yasser",A novel linear solver for simulating highly heterogeneous black oil reservoirs,CPR-AAMG; Linear solver; Reservoir simulation; Heterogeneous reservoirs; Black oil model; SPE 10,,"A great deal of computational power and time is necessary for the simulation of highly heterogeneous fractured reservoirs with complicated geometry. Simulating such largescale complex reservoirs with both minimum time and maximum accuracy has consistently remained a topic of concern to reservoir simulation engineers worldwide. The currently used linear solvers in well-known commercial simulators that utilize classical methods such as Nested Factorization (NF) and Incomplete LU Factorization (ILU) as their preconditioners, all suffer from severe convergence problems in models with high heterogeneity and/or large number of non-neighbor connections. To overcome such problems, a novel Adaptive Algebraic Multi-grid algorithm (AAMG) is proposed to be used in a constrained pressure residual (CPR) preconditioner, abbreviated as CPR-AAMG, in order to solve the governing discretized three-dimensional partial differential equations. The implemented CPR preconditioner which uses AAMG as the preconditioner for the elliptic pressure equation, and the Blocked ILU for the hyperbolic saturation equations, is a robust way for damping both smooth pressure field and high frequency saturation field errors in giant reservoir models. The findings of the current study illustrate that the developed Biconjugate Gradient Stabilized (BiCG-Stab) solver preconditioned by CPR-AAMG is capable of achieving acceptable results of high efficiency and robustness in the SPE10 project which is renowned as an enormous challenge for linear solvers due to the highly heterogeneous porosity and permeability values. The novelty of the proposed CPR-AAMG preconditioner is its ability to solve three-dimensional black oil models of giant, complex and heterogeneous fractured reservoirs without any convergence problems with reduction in time and required computational power.",1,1,0
Fracture,Mediterranean Sea,"Merey, Sukru",Geomechanical wellbore stability analysis for the wells drilled in the shallow sediments of the Mediterranean Sea,Wellbore stability; Hoop stress; Reservoir geomechanics; Gas hydrates; Mediterranean sea,NATURAL-GAS; HYDRATE; ORIENTATION; MAGNITUDE; FAILURE; ENERGY; BASIN; AREA; LOGS,"Gas hydrates are considered as near-future energy resources in the world. Due to high gas hydrate potential of the Mediterranean Sea, gas hydrate exploration wells are expected to be drilled. In this study, for the first time, the caliper logs of the wells drilled during ODP (Ocean Drilling Program) Leg 160 and ODP Leg 161 in the Eastern and Western Mediterranean Sea were evaluated together with the python codes predicting wellbore stresses, unconfined compressive strength (C-o) and lower-hemisphere projection. The required C-o in the Eastern Mediterranean Sea ranges from 60 psia to 2250 psia from seafloor to target depth. However, the estimated C-o of the sediments in the Eastern Mediterranean in this study by using the python codes developed in this study and the caliper logs of ODP Leg 160 ranges from 15 psia to 1250 psia with depth. Similarly, the required C-o to keep the wells in gauge and the estimated C-o of the sediments in ODP Leg 161 range between 100-12000 psi and 30-11000 psia, respectively. Mostly, C-o values of the sediments were less than the required C-o values for stable wellbore so extensive washouts were detected both in the wells of ODP Leg 160 and Leg 161. This is because the sediments within gas hydrate stability zone in the Mediterranean Sea are weak and almost unconsolidated. Moreover, in this study, it was shown that it is possible to reduce the degree of washouts by increasing the density of drilling fluid until fracture pressure. According to the estimations in this study, the wellbore enlargements for the wells in ODP Leg 160 and ODP Leg 161 were mostly reduced below 2 inches, below which better wellbore stability conditions, better well log data and better casing cement quality might be obtained.",2,2,2
Fracture,Mediterranean Sea,"Merey, Sukru",Estimation of fracture pressure gradients in the shallow sediments of the Mediterranean Sea by using ODP Leg 160 and Leg 161 data,Fracture pressure; Pore pressure; Gas hydrates; Shallow sediments; Drilling; Well log,NATURAL-GAS; HYDRATE; BASIN; ORIENTATION; PREDICTION; PARAMETERS; RESERVOIRS; MAGNITUDE,"Pore pressure gradient and fracture gradient are two of the most important parameters while making well drilling design. Hence, in this study, these gradients were estimated for the Mediterranean Sea shallow sediments where gas hydrate might exist by using ODP Leg 160 and ODP Leg 161 data (mainly density logs). The density logs obtained during these drilling programs were used to estimate fracture pressure gradients. In this study, pore pressure gradient intervals in the Eastern Mediterranean Sea and the Western Mediterranean Sea were estimated as 0.433-0.484 psi/ft and 0.459-0.460 psi/ft, respectively. It was found that geothermal gradients of the holes drilled in the Western Mediterranean Sea sediments are quite high (up to 128 degrees C/km) but the maximum geothermal gradient observed in the Eastern Mediterranean Sea is 12.85 degrees C/km. The estimated fracture pressure gradient ranges in the Eastern Mediterranean Sea and the Western Mediterranean Sea shallow sediments are 0.604-0.659 psi/ft and 0.675 psi/ft-0.766 psi/ft. For the first time, the fracture gradients in the shallow sediments (where gas hydrate might exist) of the Mediterranean Sea were predicted in this study. These fracture gradients are suggested for the drilling and well completion designs of gas hydrate wells in the conditions of the Mediterranean Sea.",1,1,1
Fracture,Contact Angle,"Khodadadi, Behayeen; Siddiqui, Mohammed Abdul Qadeer; Pirzada, Muhammad Asad; Le-Hussain, Furqan; Iglauer, Stefan; Roshan, Hamid",Direct observation of two-phase flow in deformable fractures of shales: A Utica shale example,Shale; Fracture; Microfluidic; Two-phase flow; Wettability; Utica; Deformation,DYNAMIC CONTACT-ANGLE; SURFACE WETTABILITY; CAPILLARY RISE; ROUGHNESS; ROCK; IMBIBITION; DEPENDENCE; INSIGHTS; WATER,"Despite the success of hydrocarbon production from unconventional shale reservoirs, the physical processes controlling the production are not yet fully understood. The wettability controlling the two-phase flow in deformable natural fractures of shale is among the processes that still need special attention. With the advances of optical technologies, microfluidics can now be used to observe, measure, and analyse the dynamic changes of flow in fractured systems. However, mimicking the natural wall roughness of the fractures with high precision and having flexibility to allow fracture deformation has remained challenging. We have therefore developed a new microfluidic technique to create tensile fractures in shale with subsurface representative random geometries and roughness, and then observed two-phase flow in these deformable fractures at a high resolution for Utica shale. During the two-phase flow, dynamic contact angles of water-oil in the fractures with varying apertures of 60-100 mu m were measured and analysed. Significant contact angle hysteresis was observed when oil displaced water out of the fracture and vice versa. Interestingly, water completely displaced the oil out of the fracture through spontaneous imbibition, although its contact angle in the fracture varied from 20 degrees to 90 degrees. The water velocity in the fracture was found to be correlated to the observed contact angles during the spontaneous imbibition test. The large change in the contact angle was further investigated using fluorescence tracking where patches of oil were observed to remain on the fracture wall despite its water wetness. It was then shown through further investigations that the formation of these oil patches was primarily controlled by mineral heterogeneity than wall roughness.",3,3,4
Fracture,Contact Angle,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Oil Recovery,Permeability,"Xiong, Chunming; Ding, Bin; Geng, Xiangfei; Guan, Baoshan; Pan, Jingjun; Dong, Jingfeng; Huang, Bo; Yan, Youguo",Quantitative analysis on distribution of microcosmic residual oil in reservoirs by frozen phase and nuclear magnetic resonance (NMR) technology,Microcosmic residual oil; Phase change; Frozen section; Low field NMR; Laser confocal,PORE STRUCTURE; RECOVERY; PERMEABILITY; SEM; SURFACTANT; INJECTION; MECHANISM; EXPLORATION; SATURATION; IMBIBITION,"Understanding and characterizing the distribution and occurrence state of microcosmic residual oil is helpful to optimize judicious strategy for enhancing oil recovery (EOR). In this paper, frozen phase technology was developed to realize accurately characterize the oil and water saturation and their occurrence state. First, the core was placed in liquid nitrogen to frozen the oil and water inside it, and the solidified oil and water guarantees no destroying of their original distribution of oil and water, and 0.05 mm slice could be obtained. Second, taking advantage of different freezing point of oil and water, the low-field NMR is employed to achieve high-resolution single oil signal under freezing point of water and both oil and water signal at room temperature, thus, the oil and water saturation could be accessed, and their distribution in different-sized pore could be achieved based on conversion calculation of transverse relaxation time of NMR. Third, the displacing performance of water flooding and CO2 flooding was investigated. The results characterized by laser confocal indicates that the water flooding has strong scouring capability for free-state oil and CO2 flooding has strong stripping capability for bound-state oil, suggesting CO2 water-alternating-gas injection has unique advantage for EOR. Our work develops a frozen phase technique to realize accurate characterization the residual oil and water saturation and give their original distribution, which could provide basic foundation for EOR design.",3,4,4
Oil Recovery,Permeability,"Huang, Shijun; Zhu, Yuanrui; Ding, Junwu; Li, Xingmin; Xue, Yongchao",A semi-analytical model for predicting inflow profile of long horizontal wells in super-heavy foamy oil reservoir,Super-heavy foamy oil; Horizontal well; Semi-analytical model; Formation heterogeneity; Inflow profile; Productivity prediction,RECOVERY STRATEGIES; BEHAVIOR; FLOW,"In most super-heavy oil reservoirs, depletion recovery is one of the important cold recovery methods accompanied by foamy oil production. However, the inflow profiles of horizontal wells in super-heavy foamy oil reservoirs cannot be obtained by conventional methods at present. In this study, a semi-analytical model which couples the wellbore and reservoir was established to predict the inflow profile of horizontal wells in super-heavy foamy oil reservoirs with cold production method. The coupled wellbore/reservoir model is based on the prediction of the dynamic physical property parameters of foamy oil, and employs reservoir engineering methods, such as the microelement, mirror reflection, and potential function methods. The numerical solution was obtained by applying iteration method in MATLAB. Meanwhile, the model accounts for formation heterogeneity along the horizontal well that has never been considered before and pressure drop loss along the horizontal wellbore. The model was applied to a field case, and the calculation results were compared with those predicted by using the Joshi and Furui productivity formulas. It showed that the developed model led to the smallest errors from field production data, which further verifies the accuracy of the model. Moreover, sensitivity analysis is conducted by changing the permeability distribution along the horizontal well and the length of the horizontal section based on the established model. And the results are instructive for horizontal well optimization design. In short, this model is of great significance for productivity calculations, horizontal well design optimization, and production predictions of cold production with horizontal wells in super-heavy oil reservoirs.",3,3,3
Oil Recovery,Permeability,"Mogensen, Kristian; Xu, Siqing","Comparison of three miscible injectants for a high-temperature, volatile oil reservoir - With particular emphasis on nitrogen injection",Miscible flooding; Nitrogen injection; Low-permeability; Carbonate reservoir; High temperature,,"Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. Miscible nitrogen injection into oil reservoirs is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. In this paper, we investigate the potential for applying miscible nitrogen injection for a high-temperature, low-permeability carbonate reservoir, which contains a volatile oil with some H2S and CO2. The field is still in its early development phase but suffers from relatively low throughput rate because of low permeability. At the prevailing reservoir pressures, extensive phase behavior studies confirm that the reservoir fluids develop miscibility with nitrogen, carbon dioxide, and hydrocarbon gas. Nitrogen behaves differently from hydrocarbon gas, despite the fact that the two gases lead to similar minimum miscibility pressures. At the prevailing reservoir pressure, the swelling factor with hydrocarbon gas is four times higher than for nitrogen. Furthermore, the reservoir fluid density increases during swelling with nitrogen, whereas it decreases as a result of hydrocarbon gas swelling. The same trend is observed for viscosity. Injection gas blends with various proportions of nitrogen and carbon dioxide shows that the MMP is constant when more than 35-40% nitrogen is present in the blend. The simulation studies involve a number of sensitivity runs performed on sector models, which are sufficiently fine-gridded to capture the compositional transition zone propagating between injector and producer pairs. Miscible nitrogen injection comes out as a viable option with the potential to increase recovery by 10-20% above the current water flood development scheme. The significantly improved sweep and displacement efficiency are due to N-2 miscibility with reservoir oil under reservoir conditions, possibility of increased PV injected in a N-2 WAG scheme, and the ability to maintain the initial reservoir pressure.",3,3,3
Oil Recovery,Permeability,"Shabani, Ali; Sisakhti, Hossein; Sheikhi, Sobhan; Barzegar, Farzad",A reactive transport approach for modeling scale formation and deposition in water injection wells,Scale precipitation and deposition; Thermodynamic condition; Wellbore; PHREEQC,PERMEABILITY REDUCTION; GEOTHERMAL WELLS; FINES MIGRATION; CALCIUM-SULFATE; TEMPERATURE; SEAWATER; WELLBORE; DECLINE; PHREEQC; IMPACT,"Petroleum industry is moving toward enhancing oil recovery methods, especially water-based methods, including low salinity and smart water flooding which water with an optimized composition is injected into the reservoir for improving oil recovery. Injection of water into the target formation is also a common operation in geothermal energy production. As the water is being injected into the reservoir, pressure and temperature change along the well column and cause scale formation. Mineral scale precipitation and deposition is a common problem for water injection wells which reduces the effective radius of the wellbore and affects the injection efficiency. In this paper, modeling scale precipitation and deposition in a pipe flow system by coupling of species transport model and a geochemical software package (PHREEQC) is investigated. The results of the proposed method were matched with experimental data. The model has been used for prediction of scale precipitation and deposition profile along with water injection wells during low salinity waterflooding. The results show deposition of calcium carbonate scale in the bottom section of the water injection wells. Higher temperature, higher salinity and more rate fluctuation cause an increase in scale precipitation and deposition in the wellbore condition.",3,3,2
Oil Recovery,Permeability,"Almetwally, Ahmed G.; Jabbari, Hadi",Finite-difference simulation of coreflooding based on a reconstructed CT scan; modeling transient oscillating and pulse decay permeability experiment,Coreflooding; Static Model; Dynamic Simulation; Transient; Permeability; Image processing,ROCK SAMPLES; FLOW; PRESSURE; OIL,"Numerical simulation and experimental research of fluid flow in porous media enhance the practices of petroleum reservoirs' management. Experiments on acquired reservoir-rock samples are conducted for accurate characterization and realization of the insitu hydrocarbon reserves. Implementing precise numerical simulation of those experiments is crucial to acquire accurate conclusions from the obtained experimental results. Coreflooding experiments quantify reservoir rock's storage capacity, measure its transport connectivity, and evaluate recovery methods' effectiveness for that rock. In this paper, a reconstruction image-processing workflow of cores' CT scan is developed to build a finite difference numerical model for simulating coreflooding experiments. In a transient coreflooding experiment, a controlled pressure pulse with a known frequency and amplitude is transmitted to the rock sample. Rock permeability can be quantified by analytically solving the diffusivity flow equation for that experiment. Simulating the transient permeability experiment is very sensitive to the level of details of the pores' structure described in the numerical model. A transient permeability experiment with two different transient modes, sinusoidal oscillation, and pulse decay, was conducted on a standard Berea core sample. The Berea CT scan was image-processed to reconstruct the static porosity and permeability model in Petrel software using a 3D variogram geostatistical population. Injection and production sources were assigned to the finite gridblock, which correspond to flow nozzles of injection and production coreflooding setup's heads. Scheduled flow and controlled-pressure boundary-conditions were imposed on the dynamic model. Eclipse simulator was used to solve the dynamic model and calculate the pressure in each gridblock. The outlet pressure was calculated at each time step by three different realization approaches for porosity and permeability, i.e., from experiments, from statistical analysis for the CT scan, and by the proposed image processing workflow. The simulated outlet pressure from the prosed workflow matched ideally, with a Pearson correlation coefficient of 0.98 and 0.99, the recorded one in the two experiments compared to underestimated or overestimated outlet pressure from the other two traditional realization approaches, i.e., statistical or experimental.",3,3,2
Oil Recovery,Permeability,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Oil Recovery,Permeability,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model for gravity segregation in WAG displacement recovery of inclined stratified reservoirs,Gravity segregation; WAG; Analytical model; Inclined stratified reservoir; Numerical simulation,OIL-RECOVERY; PERFORMANCE; FLUID; FLOW,"The present study deals with the extension of Stone's model to develop the analytical model of gravity segregated length (distance travelled by injected water and gas together before the complete segregation) and gravity segregated water zone height in water-alternative-gas (WAG) displacement for inclined stratified heterogeneous reservoirs. However, as per our knowledge, until now, all available analytical models of gravity segregation in the WAG displacement process consider the assumption that the reservoir is homogeneous i.e. one-layer system with constant porosity and permeability. In reality, most of the reservoirs are heterogeneous with random variation in permeability due to the variation in the depositional environments, which have a major impact on a vertical sweep in WAG displacement. The analytical models of gravity segregation for dipping stratified heterogeneous reservoir are developed by solving the fractional flow equations of displacement of fluids through MOC (method of characteristics). Then the results of these analytical models are compared with 3D finite-difference compositional reservoir simulation. The developed analytical models give appropriately similar results as 3D finite-difference compositional model. Also, analytical model results show that the complete gravity segregated length (vertical sweep efficiency) increases with an increase in reservoir dip angle and mobility ratio, and a decrease in gravity number, vertical permeability, and horizontal permeability heterogeneity. On the other hand, the gravity segregated water zone height decreases with an increase in reservoir dip angle and gravity number.",3,3,1
Oil Recovery,Permeability,"Kim, Min; Shin, Hyundon",Numerical simulation of undulating shale breaking with steam-assisted gravity drainage (UB-SAGD) for the oil sands reservoir with a shale barrier,Shale barrier; Undulating shale breaking with steam-assisted; gravity drainage (UB-SAGD); Undulating drilling; Rotary-steerable system (RSS); Maximum NPV (M_NPV),OVER-SOLVENT INJECTION; HEAVY-OIL; RECOVERY; PERFORMANCE; PARAMETERS; WATER; INTEGRATION; BITUMEN; VAPEX; WELL,"A thick oil sands reservoir separated into two thin oil sands reservoirs by a shale barrier, particularly when the separated reservoir thickness is less than 10 m, is inefficient for economic steam-assisted gravity drainage (SAGD) applications. This paper proposes undulating shale breaking with SAGD (UB-SAGD) to develop this type of reservoir, and the trajectory of undulating drilling to break the shale was designed. In addition, sensitivity analysis was performed to evaluate the effects of the area and permeability of a breaking zone and steam injection pressure. The UB-SAGD is a novel in-situ recovery method that applies undulating drilling to break the shale in the parallel direction and the above SAGD well pairs. In addition, it adds an extra injector to facilitate thermal communication between the upper and lower parts of the shale barrier, and the steam chamber can be expanded into the upper the oil sands layer along a flow path. As the area and permeability of the breaking zone were increased, the recovery factor (RF) and maximum NPV (M_NPV) increased, and the cumulative steam-oil ratio (CSOR) decreased. A comparison of the low and high steam injection pressures revealed the M_NPV of high steam injection pressure to be higher than that of low steam injection pressure because a high injection pressure facilitates flow in a smaller area of the breaking zone. The RF and CSOR of best result were improved by 24.65% and 10.21%, respectively, compared to two well-pairs of SAGD without undulating drilling. In addition, the M_NPV of this result was $3.05 MM higher than that of two well-pairs. The UB-SAGD will be very useful for the economic development of shale interbedded oil sands reservoirs using conventional SAGD.",3,3,1
Oil Recovery,Permeability,"Su, Xin; Yue, Xiang-an",Mechanism study of the relation between the performance of CO2 immiscible flooding and rock permeability,CO2 immiscible flooding; Permeability; Mechanism; Oil recovery; Gas chromatography,ENHANCED OIL-RECOVERY; TIGHT OIL; CARBON-DIOXIDE; GAS INJECTION; RESERVOIR; PRESSURE; HETEROGENEITY; WETTABILITY; MISCIBILITY; SURFACTANT,"The CO2 immiscible flooding experiments mostly conducted on a rock with a given permeability. However, there is a need for understanding the performance of CO2 immiscible flooding and its mechanisms over a range of rock permeability for some tight or low-permeability reservoirs. In these reservoirs, permeability can significantly vary due to presence and distribution of microfractures. We examine the performance and different mechanisms of CO2 immiscible flooding over a permeability range between 0.4 and 324mD by core flood experiments and oil-gas interaction tests. The results show that owing to the high MMP of Changqing oil field (20 MPa), the CO2 flooding were all conducted at immiscible condition. The CO2 immiscible flooding efficiency inversely varies with permeability, but the trend of it is significantly different before and after a threshold permeability K-c. When the rock permeability is higher than K-c, owing to the small difference between all mechanisms, the CO2 immiscible flooding efficiency smoothly varies with permeability and their overall oil recoveries are all near 50%. However, When the rock permeability is lower than K-c, the overall oil recovery significantly increases to more than 70%, and different mechanisms also show significantly diversity. The contribution of these mechanism is: ""oil viscosity and CO2-oil IFT reduction > CO2 extraction > solution gas drive and gas expansion > the effect of pore structure > oil swelling"". Among these mechanisms, CO2-oil IFT reduction and CO2 extraction play the most important role in CO2 immiscible flooding, especially in tight or low-permeability cores.",2,2,7
Oil Recovery,Permeability,"Wei, Jianguang; Zhou, Xiaofeng; Zhou, Jiumu; Li, Jiangtao; Wang, Anlun",Recovery efficiency of tight oil reservoirs with different injection fluids: An experimental investigation of oil-water distribution feature,Tight oil reservoirs; Recovery efficiency; Experimental study; Well-spacing optimization,THRESHOLD PRESSURE-GRADIENT; GAS-RESERVOIRS; LOW-PERMEABILITY; FLOW MODEL; SHALE-GAS; WELLS; PERFORMANCE; DISSOLUTION,"After depletion development stage, the well-utilized approach to enhance recovery of tight oil reservoirs is fluid-injection, involving nitrogen, water, and CO2. Although a great deal of research efforts has been devoted to relevant scope, it is still challenging to identify the appropriate fluid type which can achieve favorable recovery efficiency. Also, the oil-water distribution feature in tight oil reservoirs from the microscopic view is rarely investigated, especially for that after fluid-injection. Moreover, inherent TPG (threshold pressure gradient) will make a great difference on the assignment of well-spacing, which have not well investigated. Given the current situation, this work expects to bridge up the knowledge gap. First, the original oil-water distribution feature and that after fluid-injection are revealed through laboratory experiments, in which different kinds of fluid are measured. Then, the relationship between TPG and fluid type is quantified based on another set of experiments. After that, considering the pressure distribution characteristics in whole tight oil reservoirs, the optimization plate for well-placing under different fluid types is concluded. Results show that (1) Gas-flooding shares advantages compared with water-flooding, displacement efficiency for gas-flooding is over 40% and that for waterflooding is 36% on average; (2) the main pore types initially occupied by oil consists of pore-throat, cluster, corner and intergranular, which account for 9.51%, 26.42%, 15.51%, and 13.82% respectively. And the major contributor to oil recovery comes from cluster pore-type; (3) gas-flooding approach is recommended as for the low-permeability case, and the water-flooding approach becomes favorable as for the high-permeability case.",2,2,4
Oil Recovery,Permeability,"Zhang, Jihong; Tan, Xinjian; Zhao, Xinrui; He, Qingbin; Wang, Yanan",Experimental study of small-sized polymeric microgel (SPM) in low- or median-permeability reservoirs,Polymer microgel; Gel treatment; Conformance control; Water management; Low-permeability reservoir,PREFORMED PARTICLE GEL; CONFORMANCE CONTROL; MICROSPHERES; WATER; NANOPARTICLES; PERFORMANCE; TRANSPORT; MODEL,"Polymeric Microgel has been applied to reservoirs with varied permeability ranging from 10 to 1000 mD for mobility-control and/or conformance control. For a successful microgel treatment, the microgel particle size must be compatible with the reservoir pore-throat size to ensure effective in-depth transportation. Given such a situation, Small-sized Polymer Microgel (SPM) was developed for microgel treatment in low- and medium-permeability reservoirs. This paper presents an experimental study regarding the applicability of SPM in the low- (<100 mD) or median-permeability (100-300 mD) conditions. The experimental study involved pore-throat size determination, initial particle size distribution, swelling ratio measurements, resistance factor and residual resistance factor measurements, oil displacement experiments, and a pilot test conducted in ZT-21 producing zone located in Pubei Block 7. The result shows SPM has a good compatibility with the reservoir pore-throat size. SPM swells in water, ending up a ultimate swelling ratio of 4.8. During resistance factor and residual resistance factor measurements, SPM solution is effective at reservoir permeability of above 130 mD. That was saying, SPM is recommended to be applied in low- but not median-permeability reservoirs. In the oil displacement test, SPM improved the oil recovery through both SPM injection and post water injection at the core permeability of 95 mD, revealing SPM is available for conformance control purposes. In the pilot test, oil production improved in SPM injection and post water injection stages are 2.1 and 5.2%, respectively. The development of SPM can be contributive to oil and gas industry as it provide a guaranteed material for low-permeability reservoir microgel treatment.",2,2,4
Oil Recovery,Permeability,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Oil Recovery,Permeability,"Hosseini-Kaldozakh, Seyed Arman; Khamehchi, Ehsan; Dabir, Bahram; Alizadeh, Ali; Mansouri, Zohreh",Rock wettability effect on Colloidal Gas Aphron invasion near wellbore region,Colloidal Gas Aphron drilling fluid; Formation damage; Wettability; Pore blocking,ENHANCED OIL-RECOVERY; DRILLING-FLUID; FORMATION DAMAGE; LIQUID DRAINAGE; POROUS-MEDIUM; STABILITY; TEMPERATURE,"Colloidal Gas Aphron drilling fluid is colloidal dispersions of gas microbubbles, which are designed to reduce the loss of circulation in depleted reservoirs. This fluid creates a robust and elastic micro-bubble network, to block the pores of the formation and minimize filtration loss. In this study, Xanthan Gum (XG) polymer and Sodium Dodecyl Benzene Sulphonate (SDBS) surfactant were the primary materials utilized to generate a water-based Colloidal Gas Aphron drilling fluid. A dynamic and static invasion of prepared Aphron drilling fluid in carbonate rock with different wettabilities was investigated. Moreover, the formation damage induced by the invasion of Aphron fluid to porous media was also studied. Results demonstrated that wettability alteration of a water-wet porous media to oil-wet lead to an increment of differential pressure throughout porous media during Aphron drilling fluid invasion. A significant influence of wettability was also observed on return permeability of carbonate rock. A reduction of 73.53% of carbonate rock permeability was observed in oil-wet core invaded by water-based Aphron drilling fluid.",2,2,2
Oil Recovery,Permeability,"Salimi, Hamidreza; Bruining, Johannes; Joekar-Niasar, Vahid",Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities,Percolation theory; Effective-medium approximation; Relative permeability; Pore-network theory; Primary and secondary drainage; Noncircular pore throats,2-PHASE FLOW; POROUS-MEDIA; PERCOLATION THEORY; WETTING LIQUID; LAMINAR-FLOW; IMBIBITION; CORNERS,"Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation-at which there is no infinite cluster of completely filled water pores-but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 x 301 x 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).",2,2,2
Oil Recovery,Permeability,"Liu, Huiqing; Wang, Yanwei; Zheng, Aiping; Sun, Xinge; Dong, Xiaohu; Li, Dandan; Zhang, Qichen",Experimental investigation on improving steam sweep efficiency by novel particles in heavy oil reservoirs,,DEPTH PROFILE CONTROL; HIGH-TEMPERATURE; EXPANDABLE GRAPHITE; FLAME-RETARDANT; FOAM STABILITY; WATER-SHUTOFF; RECOVERY; SOLVENT; PERMEABILITY; MODEL,,2,2,2
Oil Recovery,Permeability,"Wu, Yuqi; Tahmasebi, Pejman; Lin, Chengyan; Ren, Lihua; Zhang, Yimin",Quantitative characterization of non-wetting phase in water-wet porous media based on multiphase flow experiment and numerical simulation,Multiphase fluid flow; Residual oil; Fluid physics; Pore-scale modeling; Pore occupancy,PORE-SCALE; RESIDUAL OIL; RELATIVE-PERMEABILITY; 2-PHASE FLOW; RECOVERY; SHALE; TECHNOLOGIES; MULTISCALE; SALINITY; SIZE,"It is of great significance to analyze the distribution characteristics of the non-wetting phase during the multiphase flow and identify the positions of the oil ganglia since it can guide us to design the schemes for improving oil recovery. In this paper, the two-phase (brine and oil) flow experiment and simulation are performed on a water-wet sandstone. A comprehensive analysis of the distribution of the non-wetting (oil) phase in 3D pore space and individual pores are presented. To calculate the pore occupancy of the non-wetting ganglia in every single pore from 3D CT experimental data, we proposed a technique, called the Axis-aligned Bounding Box (AABB) algorithm, to determine which oil blobs exist in a unique pore. The pore-by-pore distribution characteristics of the residual phase are then analyzed based on the experimental and numerical data. The results reveal the large oil clusters are separated into small blobs during the imbibition process, which results in increasing the number of non-wetting ganglia, dropping its connectivity, and increasing the smoothness. Moreover, the larger the volume of one pore, the larger the volume and saturation of residual oil ganglia in the pore are. Furthermore, our analysis based on the experimental and numerical results indicates that most of the non-wetting ganglia reside in the median-size pores. Hence, the finding provides us a piece of significant evidence to better target the pore-spaces for the purpose of increasing the recovery.",2,2,2
Oil Recovery,Permeability,"Wu, Dejun; Zhou, Kang; Hou, Jian; An, Zhibin; Zhai, Mingkun; Liu, Wenbin",Experimental study on combining heterogeneous phase composite flooding and streamline adjustment to improve oil recovery in heterogeneous reservoirs,Heterogeneous reservoirs; Heterogeneous phase composite flooding; Streamline adjustment; Synergy mechanism; Affected regions,PREFORMED PARTICLE GEL; HYDROLYZED POLYACRYLAMIDE; ELASTIC MICROSPHERES; CONFORMANCE CONTROL; POLYMER; MECHANISM; PERMEABILITY; SYSTEM; SIZE,"The heterogeneity of reservoirs is the key factor restricting the development performance of oilfields. Heterogeneous phase composite flooding (HPCF) and streamline adjustment (SA) are both viable strategies for improving oil recovery of heterogeneous reservoirs. However, both strategies have their own deficiencies, which limits further development. In recent years, a hybrid strategy combining HPCF and SA has attracted considerable interest from oil industry. In this paper, two-dimensional (2D) large-scale physical model experiments were performed to verify whether the hybrid strategy could offer better development performance than the single strategy, and the mechanism of hybrid strategy for improving oil recovery was elucidated. On this basis, the influence of SA angle on improved development performance was investigated. Finally, the affected regions of remaining oil in different strategies were proposed. The experimental results indicate that HPCF can effectively improve sweep efficiency and oil displacement efficiency in the main streamline regions; furthermore, it prolongs the time of incremental oil production. Streamline adjustment can forcibly utilize the remaining oil in the low-permeability regions at non-main streamline where water flooding and HPCF are poorly affected. The hybrid strategy can give full play to the respective strengths of each single strategy. Meanwhile, SA provides a good induction effect on HPCF, which creates an excellent opportunity for the latter to effectively displace the remaining oil in the low-permeability regions at non-main streamline over extended periods. When the SA angle is 90 degrees, the best development performance can be achieved. The affected regions of remaining oil in different strategies were proposed in this paper, which affords significant guidance for effective development of heterogeneous reservoirs.",2,2,1
Oil Recovery,Permeability,"Marquez, Sharoh G.; Ghafoori, Samira; Omar, Mohamed; Almarshed, Abdullah",Delineation of most efficient recovery technique for typical heavy oil reservoir in the Middle East region through compositional simulation of temperature-dependent relative permeabilities,Heavy oil; Temperature-dependence; Relative permeabilities; Compositional simulation; Thermal simulation,,"In modelling and design of heavy oil recovery, the complex interactions between the reservoir fluid and the injected fluid fosters a need for its behavior to be captured precisely and accurately. However, determining the most influential parameters in the recovery process is of great importance. In this study, the temperature-dependence of relative permeabilities has been identified as the most potent factor in aiding the improved simulated recovery of heavy oils and is being modelled in both compositional and thermal simulation environments for comparison of their recovery effectivity. Several techniques for recovering heavy oil, such as cold production, waterflooding, solvent injection, cyclic steam injection and even hot solvent injection is modelled and ranked according to their resulting recovery factors considering that the relative permeabilities alongside its temperature-dependence are the most significant factors in moving the fluid during simulation. Pressure-Volume-Temperature (PVT) relations to describe and characterize typical heavy oil from Middle East region is utilized for the application of this study and the results showed that hot solvent injection is the most effective technique in maximizing the recovery for the model oil description.",2,2,1
Oil Recovery,Permeability,"Zaberi, Husain A.; Lee, Jason J.; Enick, Robert M.; Beckman, Eric J.; Cummings, Stephen D.; Dailey, Chris; Vasilache, Mihai",An experimental feasibility study on the use of CO2-soluble polyfluoroacrylates for CO2 mobility and conformance control applications,CO2 enhanced oil recovery; Polyfluoroacrylate; Mobility control; Conformance control; Polymer adsorption,,"High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.",2,2,1
Oil Recovery,Permeability,"Taheri, Reza; Kabuli, Muffazal; Vryzas, Zisis",Fracturing and permeability enhancement with laser technology employing fuzzy logic,Laser technology; Permeability; Porosity; Microfractures; Fuzzy logic,,"Increasing the rock permeability in low permeable zones of the hydrocarbon reservoirs by conventional methods will often cause formation damage and consequently will reduce the efficiency of recovery of the reservoirs in long term. The use of high energy laser technology as an alternative and innovative approach to mobilise heavy oil and improve permeability, as opposed to the conventional techniques, which have advert effects on the longterm reservoir productivity, was examined in this research. This paper will present study results of the employment of pulsed (Q-switched) Nd: YAG (Neodymium: Yttrium Aluminium Garnet) laser on impermeable heavy oil-bearing core samples which have been simulated in lab to be as close as possible to the real reservoir conditions. A unique technique was employed in this study where lasing experiment was conducted on samples followed by intervals of stopping lasing operation, known as relaxation intervals. The alternate lasing-relaxation intervals which were repeated for samples 3 times, yield positive and satisfactory results both for heavy oil mobilization as well as permeability improvement. Porosity increase was also observed due to fracture production. Specifications of applied laser pulses and their associated beam properties, samples characteristics and dimensions as well as the simulated experiment environment with that of the real reservoir conditions will be reported. Fuzzy logic was employed to normalize the varying and diverse parameters affecting the rock's thermal behaviour such as mineral content, fluid content and type and pressure. By employing the proposed technique on samples from heavy-oil-bearing low permeable zones of Burgan and Mauddud reservoirs of the Giant Burgan field in Kuwait, fractures were produced and permeability of the reservoir samples were improved to almost 3 times of their initial values in some of the samples. Upon the termination of the third lasing experiment, traces of oil could be observed on some of the core sample's surfaces, proving that the heavy oil was mobilised due to induced high temperatures generated in the samples during lasing.",2,2,0
Oil Recovery,Permeability,"Lopez, Daniel; Zabala, Richard D.; Cardenas, Jose C.; Lopera, Sergio H.; Riazi, Masoud; Franco, Camilo A.; Cortes, Farid B.",A novel design of silica-based completion nanofluids for heavy oil reservoirs,Adsorption; Completion nanofluid; Interfacial tension; Silica nanoparticles; Surfactant; Wettability,WETTABILITY ALTERATION; INTERFACIAL-TENSION; SURFACE-ROUGHNESS; NANOPARTICLES; GAS; RECOVERY; WATER; ADSORPTION; PRODUCTIVITY; MODEL,"The main objective of this manuscript is the design of completion nanofluids (NanoCF) using silica nanoparticles based on the impact on the capillary number for being applied in heavy crude oil reservoirs. Six types of silica nanoparticles with different chemical nature were characterized by dynamic light scattering (DLS), point of zero charge (pHpzc), Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), surface area (S-BET), X-ray diffraction (XRD) and total surface acidity through temperature-programmed desorption of NH3 (TPD-NH3). Adsorption isotherms were constructed for understanding the non-ionic surfactant interaction with nanoparticles and rock surfaces, showing that a high adsorption affinity of the surfactant onto the rock surface, leaving less than 24% of free surfactant molecules able to migrate to the water/oil interface. Nevertheless, nanoparticle addition onto completion fluids (CF) could reduce the adsorbed surfactant onto the rock surface by 75%, which means more molecules of surfactant at the interface due to the nature of the obtained nanoparticles (NPS). The nanoparticles were selected based on the capillary number, showing that the best material reduced the interfacial tension between heavy crude oil and CF more than 76% and have the capacity to modify an initial oil-wet state to a water-wet rock surface. Finally, a coreflooding test was carried out at reservoir conditions (158 degrees F and 6.89 MPa) for evaluating the best completion nanofluid design based on the static tests, showing an increase of the oil effective permeability of 37% and incremental oil recovery of 3% in comparison to the completion fluid without nanoparticles. For the first time, novel completion nanofluids could allow stimulating the well from the beginning of the productive life.",2,2,0
Oil Recovery,Permeability,"Wang, Y.; Kabir, C. S.; Reza, Z.",Deciphering well connectivity with diagnostic signal processing techniques,Signal processing; Interwell connectivity; Production/injection data; Life-long processing tools,INFERRING INTERWELL CONNECTIVITY; WATERFLOOD PERFORMANCE; RESERVOIR; OIL; FLUCTUATIONS; TRACER; MODELS,"Data mining has become increasingly crucial in deciphering reservoir dynamics, given that operators currently acquire an enormous amount of data. These data contain valuable information about subsurface processes. Interwell connectivity is one of the most significant aspects of subsurface characterization that can impact a project's success. In this study, we present novel techniques to quantify and monitor interwell communication by applying signal processing methods to observe and derive well-based measurements. A large dataset from the Permian Basin constituted the primary content of this investigation. We constructed a suite of realistic reservoir models under varying conditions involving multiple producing and water injection wells. More than 40 static and dynamic parameters including permeability, porosity, water saturation, fluid properties, and rock-fluid interaction terms are varied using experimental designs to capture realistic uncertainty. Waterflood scenarios are modeled using streamline simulation to infer injector-producer pair connectivity, pattern allocations, drainage efficiency, and their evolution period. These injector-producer variables are analyzed using numerous signal processing methods, including cross-correlation, time-lag correlation coefficient, coherence, and periodogram, among others. Well variables examined involve pressure, rate, and their derivative functions. The objectives of this study include: (1) Examining and devising several signal-processing techniques; (2) Identifying informative well data to provide information of communication between injectors and producers over time; (3) Deducing connectivity measures and systematically evaluate their efficacy in characterizing subsurface connectivity picture. The approaches reveal new insights into determining reservoir communication metrics. The proposed methods have the potential for implementation in the automated virtual flow-metering system. These methods also helped identifying the predominant injector-producer pairs and making operational decisions at any stage of any waterflood and enhanced recovery projects.",2,2,0
Oil Recovery,Permeability,"Li, Qiuyan; Yue, Xiang'an; Zhang, Lijuan; Husein, Maen",Production performance by polymer conformance control in ultra -low permeability heterogeneous sandstone reservoirs produced under their natural energy,,ENHANCED OIL-RECOVERY; CO2 INJECTION; MECHANISMS; PRESSURE; FLOODS; TIGHT; MODEL,,2,2,0
Oil Recovery,Permeability,"Artun, E.",Performance assessment and forecasting of cyclic gas injection into a hydraulically fractured well using data analytics and machine learning,Cyclic gas injection; Data analytics; Enhanced oil recovery; Hydraulically fractured wells; Machine learning; Performance forecasting,NITROGEN,"Single-well application of cyclic gas injection is a promising enhanced oil recovery method especially in fractured and depleted reservoirs. It was previously shown that presence of hydraulic/natural fractures would increase the effectiveness of this method because of the surface area of fractures that supports gas diffusion into the rock matrix. Increased pressure and changes in the physical properties of oil after injection both contribute to improved oil recovery. In this study, a comprehensive analysis of the performance-related design aspects of kcyclic injection of a mixture of N-2, CO2 and CH4 in a hydraulically-fractured well is presented. These three types of gases can contribute to different mechanisms for enhanced recovery because of their unique phase behavior. On the other hand, their costs and availability may be different which may lead to different economic benefits. For the proposed analysis, a large number of injection scenarios were run using a compositional reservoir model that represents the drainage area of a hydraulically fractured well in a low-permeability reservoir. Design parameters such as the injection rate, duration (and volume), soaking duration, economic rate limit, and injected gas composition are varied with uniformly distributed values of each parameter within pre-defined ranges. Both volumetric and economic utilization efficiency factors are analyzed as the performance indicators. Discounted values of incremental oil produced, volume of injected gas, oil price and costs of injected gas for varying project periods of 5, 10, 15 and 20 years are considered for the efficiency calculations. It is observed that the presented method can be a cost-effective enhanced recovery method for hydraulically-fractured wells depending on the proper selection of operational conditions. Injection volume should be kept below 10,000 MCF per cycle. Economic rate limit and soaking period should be optimized. While N-2 is more cost effective than other gases, it mostly provides short-term benefits. The data set is used to train a neural network that can be used to forecast the economic efficiency indicator. Results show that machine learning is an effective approach to develop accurate forecasting models. R-2 values greater than 0.90 are observed for the correlation between real and predicted values for both training and testing, regardless of design considerations of the neural network.",1,1,1
Oil Recovery,Water Injection,"Xiong, Chunming; Ding, Bin; Geng, Xiangfei; Guan, Baoshan; Pan, Jingjun; Dong, Jingfeng; Huang, Bo; Yan, Youguo",Quantitative analysis on distribution of microcosmic residual oil in reservoirs by frozen phase and nuclear magnetic resonance (NMR) technology,Microcosmic residual oil; Phase change; Frozen section; Low field NMR; Laser confocal,PORE STRUCTURE; RECOVERY; PERMEABILITY; SEM; SURFACTANT; INJECTION; MECHANISM; EXPLORATION; SATURATION; IMBIBITION,"Understanding and characterizing the distribution and occurrence state of microcosmic residual oil is helpful to optimize judicious strategy for enhancing oil recovery (EOR). In this paper, frozen phase technology was developed to realize accurately characterize the oil and water saturation and their occurrence state. First, the core was placed in liquid nitrogen to frozen the oil and water inside it, and the solidified oil and water guarantees no destroying of their original distribution of oil and water, and 0.05 mm slice could be obtained. Second, taking advantage of different freezing point of oil and water, the low-field NMR is employed to achieve high-resolution single oil signal under freezing point of water and both oil and water signal at room temperature, thus, the oil and water saturation could be accessed, and their distribution in different-sized pore could be achieved based on conversion calculation of transverse relaxation time of NMR. Third, the displacing performance of water flooding and CO2 flooding was investigated. The results characterized by laser confocal indicates that the water flooding has strong scouring capability for free-state oil and CO2 flooding has strong stripping capability for bound-state oil, suggesting CO2 water-alternating-gas injection has unique advantage for EOR. Our work develops a frozen phase technique to realize accurate characterization the residual oil and water saturation and give their original distribution, which could provide basic foundation for EOR design.",3,4,4
Oil Recovery,Water Injection,"Lu, Meng; Connell, Luke Daulton; Pan, Zhejun","Wetting fluid behaviour with phase transition in geological nanopores: Liquid film, capillary condensation and evaporative flow",Nanopores; Tight rocks; Thermodynamics; Phase transition; Unconventional reservoirs,HOMOGENEOUS NUCLEATION; THERMODYNAMIC ANALYSIS; POROUS-MEDIA; SHALE; STABILITY; WALL; NANOFLUIDICS; ADSORPTION; TRANSPORT; INJECTION,"Fluid behaviour in nanoscale pores may significantly deviate from that in its bulk state, because pore-wall effects may have critical influences on fluid properties such that its behaviour becomes surface-controlled. Geologically, study of fluid flow with phase transition (condensation/evaporation) in nanoscale pores is of considerable significance in practice, as understandings of the relevant mechanisms may greatly help optimise operation conditions in field applications. Typical examples include geological disposal of contaminated wastes and recovery of resources from unconventional gas and oil reservoirs. In this text, we present a study to systematically investigate how the fluid behaviour, such as the liquid film formed on a pore-wall, the condensation/evaporation of the fluid and the evaporative flow profile in the pore, depends on the molecular/electrical surface forces and the pore-wall-curvature. Towards this we first formulated a set of extended phase equilibrium relationships following a rigorous thermodynamic procedure in which the relevant pore-wall effects are included. Then, a set of new evaporative flow equations was developed, which improves the original Mahadevan model by taking into account the pore-wall effects engaged. Several laboratory tests published in literature were employed to compare the present model with the Mahadevan model. With the results obtained we discussed the pertinent pore-wall effects on the evaporation behaviour of the water, and it was shown that for the evaporative flow process concerned, these effects are significantly important and considerable deviations would be generated without consideration of them.",3,3,4
Oil Recovery,Water Injection,"Salehpour, Mohammad; Riazi, Masoud; Malayeri, M. Reza; Seyyedi, Mojtaba",CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage,"Carbon capture, and storage (CCS); Carbon capture, utilization, and storage (CCUS); Carbonated water injection; Heavy asphaltic crude oil; Water-in-oil emulsion; Enhanced oil recovery",PORE-SCALE MECHANISMS; WATER INJECTION; INTERFACIAL-TENSION; WETTABILITY ALTERATION; CO2 INJECTION; PERFORMANCE; SECONDARY; SCENARIOS; EMULSIONS; DIOXIDE,"Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsioninduced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.",3,3,4
Oil Recovery,Water Injection,"Mogensen, Kristian; Xu, Siqing","Comparison of three miscible injectants for a high-temperature, volatile oil reservoir - With particular emphasis on nitrogen injection",Miscible flooding; Nitrogen injection; Low-permeability; Carbonate reservoir; High temperature,,"Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. Miscible nitrogen injection into oil reservoirs is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. In this paper, we investigate the potential for applying miscible nitrogen injection for a high-temperature, low-permeability carbonate reservoir, which contains a volatile oil with some H2S and CO2. The field is still in its early development phase but suffers from relatively low throughput rate because of low permeability. At the prevailing reservoir pressures, extensive phase behavior studies confirm that the reservoir fluids develop miscibility with nitrogen, carbon dioxide, and hydrocarbon gas. Nitrogen behaves differently from hydrocarbon gas, despite the fact that the two gases lead to similar minimum miscibility pressures. At the prevailing reservoir pressure, the swelling factor with hydrocarbon gas is four times higher than for nitrogen. Furthermore, the reservoir fluid density increases during swelling with nitrogen, whereas it decreases as a result of hydrocarbon gas swelling. The same trend is observed for viscosity. Injection gas blends with various proportions of nitrogen and carbon dioxide shows that the MMP is constant when more than 35-40% nitrogen is present in the blend. The simulation studies involve a number of sensitivity runs performed on sector models, which are sufficiently fine-gridded to capture the compositional transition zone propagating between injector and producer pairs. Miscible nitrogen injection comes out as a viable option with the potential to increase recovery by 10-20% above the current water flood development scheme. The significantly improved sweep and displacement efficiency are due to N-2 miscibility with reservoir oil under reservoir conditions, possibility of increased PV injected in a N-2 WAG scheme, and the ability to maintain the initial reservoir pressure.",3,3,3
Oil Recovery,Water Injection,"Shabani, Ali; Sisakhti, Hossein; Sheikhi, Sobhan; Barzegar, Farzad",A reactive transport approach for modeling scale formation and deposition in water injection wells,Scale precipitation and deposition; Thermodynamic condition; Wellbore; PHREEQC,PERMEABILITY REDUCTION; GEOTHERMAL WELLS; FINES MIGRATION; CALCIUM-SULFATE; TEMPERATURE; SEAWATER; WELLBORE; DECLINE; PHREEQC; IMPACT,"Petroleum industry is moving toward enhancing oil recovery methods, especially water-based methods, including low salinity and smart water flooding which water with an optimized composition is injected into the reservoir for improving oil recovery. Injection of water into the target formation is also a common operation in geothermal energy production. As the water is being injected into the reservoir, pressure and temperature change along the well column and cause scale formation. Mineral scale precipitation and deposition is a common problem for water injection wells which reduces the effective radius of the wellbore and affects the injection efficiency. In this paper, modeling scale precipitation and deposition in a pipe flow system by coupling of species transport model and a geochemical software package (PHREEQC) is investigated. The results of the proposed method were matched with experimental data. The model has been used for prediction of scale precipitation and deposition profile along with water injection wells during low salinity waterflooding. The results show deposition of calcium carbonate scale in the bottom section of the water injection wells. Higher temperature, higher salinity and more rate fluctuation cause an increase in scale precipitation and deposition in the wellbore condition.",3,3,2
Oil Recovery,Water Injection,"Zhang, Chi; Tian, Ye; Shen, Yizi; Yao, Bowen; Wu, Yu-Shu",Simulation study of water cut surge after CO 2 injection in tight oil reservoirs,,HUFF-N-PUFF; COMPOSITIONAL SIMULATION; RECOVERY; PERFORMANCE; PRESSURE,,3,3,2
Oil Recovery,Water Injection,"Mehraban, Mohammad Fattahi; Rostami, Peyman; Afzali, Shokufe; Ahmadi, Zahra; Sharifi, Mohammad; Ayatollahi, Shahab",Brine composition effect on the oil recovery in carbonate oil reservoirs: A comprehensive experimental and CFD simulation study,Interfacial tension; Wettability; Enhanced oil recovery; Computational fluid dynamic; Spontaneous imbibition,WETTABILITY ALTERATION; NAPHTHENIC ACIDS; MASS-TRANSFER; SALINITY; WATER; PORE; IMPACT; HEAT; EMULSIFICATION; INTERFACE,"In order to understand the potential role of divalent ions involved in smart water, fluid-fluid and rock-fluid interactions are studied through contact angle and interfacial tension (IFT) measurements. Then, the suitable brines in changing contact angle and IFT are brought into measurement with spontaneous imbibition experiments to evaluate the co-impact of fluid-fluid and rock-fluid interactions. The results show the importance of SO42- ions during smart water injection as removing them from the injection water leads to a sharp drop in ultimate oil recovery. Accordingly, when the concentration of SO42- within the injection water increases four times, 10% ultimate oil recovery is recovered. Furthermore, the spontaneous imbibition measurements exhibit the higher ultimate oil recovery from the neutrally-wet core plugs more rather than the strong water-wet plugs. Further elaborating about the effect of wettability on the pore-scale displacement of oil by injection water is conducted through Computational Fluid Dynamics (CFD) modelling. The results confirm that the lowest residual oil saturation is achieved in the model with neutral wettability state as well as the highest oil recovery which is in line with the piston-like displacement in the neutral wet rock medium.",3,4,1
Oil Recovery,Water Injection,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model for gravity segregation in WAG displacement recovery of inclined stratified reservoirs,Gravity segregation; WAG; Analytical model; Inclined stratified reservoir; Numerical simulation,OIL-RECOVERY; PERFORMANCE; FLUID; FLOW,"The present study deals with the extension of Stone's model to develop the analytical model of gravity segregated length (distance travelled by injected water and gas together before the complete segregation) and gravity segregated water zone height in water-alternative-gas (WAG) displacement for inclined stratified heterogeneous reservoirs. However, as per our knowledge, until now, all available analytical models of gravity segregation in the WAG displacement process consider the assumption that the reservoir is homogeneous i.e. one-layer system with constant porosity and permeability. In reality, most of the reservoirs are heterogeneous with random variation in permeability due to the variation in the depositional environments, which have a major impact on a vertical sweep in WAG displacement. The analytical models of gravity segregation for dipping stratified heterogeneous reservoir are developed by solving the fractional flow equations of displacement of fluids through MOC (method of characteristics). Then the results of these analytical models are compared with 3D finite-difference compositional reservoir simulation. The developed analytical models give appropriately similar results as 3D finite-difference compositional model. Also, analytical model results show that the complete gravity segregated length (vertical sweep efficiency) increases with an increase in reservoir dip angle and mobility ratio, and a decrease in gravity number, vertical permeability, and horizontal permeability heterogeneity. On the other hand, the gravity segregated water zone height decreases with an increase in reservoir dip angle and gravity number.",3,3,1
Oil Recovery,Water Injection,"Kim, Min; Shin, Hyundon",Numerical simulation of undulating shale breaking with steam-assisted gravity drainage (UB-SAGD) for the oil sands reservoir with a shale barrier,Shale barrier; Undulating shale breaking with steam-assisted; gravity drainage (UB-SAGD); Undulating drilling; Rotary-steerable system (RSS); Maximum NPV (M_NPV),OVER-SOLVENT INJECTION; HEAVY-OIL; RECOVERY; PERFORMANCE; PARAMETERS; WATER; INTEGRATION; BITUMEN; VAPEX; WELL,"A thick oil sands reservoir separated into two thin oil sands reservoirs by a shale barrier, particularly when the separated reservoir thickness is less than 10 m, is inefficient for economic steam-assisted gravity drainage (SAGD) applications. This paper proposes undulating shale breaking with SAGD (UB-SAGD) to develop this type of reservoir, and the trajectory of undulating drilling to break the shale was designed. In addition, sensitivity analysis was performed to evaluate the effects of the area and permeability of a breaking zone and steam injection pressure. The UB-SAGD is a novel in-situ recovery method that applies undulating drilling to break the shale in the parallel direction and the above SAGD well pairs. In addition, it adds an extra injector to facilitate thermal communication between the upper and lower parts of the shale barrier, and the steam chamber can be expanded into the upper the oil sands layer along a flow path. As the area and permeability of the breaking zone were increased, the recovery factor (RF) and maximum NPV (M_NPV) increased, and the cumulative steam-oil ratio (CSOR) decreased. A comparison of the low and high steam injection pressures revealed the M_NPV of high steam injection pressure to be higher than that of low steam injection pressure because a high injection pressure facilitates flow in a smaller area of the breaking zone. The RF and CSOR of best result were improved by 24.65% and 10.21%, respectively, compared to two well-pairs of SAGD without undulating drilling. In addition, the M_NPV of this result was $3.05 MM higher than that of two well-pairs. The UB-SAGD will be very useful for the economic development of shale interbedded oil sands reservoirs using conventional SAGD.",3,3,1
Oil Recovery,Water Injection,"Naeem, Mohammad Hossein Towfighi; Dehaghani, Amir Hossein Saeedi",Evaluation of the performance of oil as a membrane during low-salinity water injection; focusing on type and concentration of salts,Smart water; Low-salinity water; Semi-permeable membrane; Osmotic pressure gradient,WETTABILITY; EOR; SANDSTONE,"Injection of low-salinity or smart water into the reservoir is one of the most common EOR techniques. This technique leads to more oil recovery in comparison to reservoir water and seawater injection. Several mechanisms explain the reasons for this increased recovery level, the most important of which is the wettability alteration towards water-wet conditions. However, in recent years, further mechanisms have been added to the previous ones as the main or complementary mechanism. One of these newly added mechanisms is the performance of oil as a semi-permeable membrane between connate and low-salinity waters. According to this mechanism, water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure (difference in chemical potential), which works as the driving force, until the system moves toward equilibrium in concentration. Introducing water molecules into connate water causes the swelling of connate water, and eventually moves the oil towards the pore throats. In this study, experiments have been performed on capillary tubes, while ignoring the effect of fluid-rock interactions to investigate the proposed theory. Experimental results confirmed the role of osmotic theory. Furthermore, a decrease in the salinity of the low-salinity water causes the oil-droplets' displacement to increase, whereas further reductions in the salinity of the injected water cause lower displacements. Therefore, there is an optimum value of low-salinity water concentration to obtain the highest possible oil drop displacement. The optimum values for the tested samples in this study were about 5000-10000 ppm. Additionally, it was found that among all of the essential seawater salts, potassium chloride leads to the highest oil drop displacement; and among oil samples, heptane showed better membrane-like performance in comparison to toluene and crude oil.",3,3,0
Oil Recovery,Water Injection,"Bouquet, Sarah; Douarche, Frederic; Roggero, Frederic; Bourbiaux, Bernard",Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization,Enhanced oil recovery; Naturally fractured reservoir; Oil-wet; Foam; Multiphase flow; Capillary pressure; Interfacial tension; Reservoir simulation; Mobility reduction; Dual-medium; Viscous forces,SIMULATION,"In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction. Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale. This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals. This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ""low-IFT"" effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.",3,3,0
Oil Recovery,Water Injection,"Wei, Jianguang; Zhou, Xiaofeng; Zhou, Jiumu; Li, Jiangtao; Wang, Anlun",Recovery efficiency of tight oil reservoirs with different injection fluids: An experimental investigation of oil-water distribution feature,Tight oil reservoirs; Recovery efficiency; Experimental study; Well-spacing optimization,THRESHOLD PRESSURE-GRADIENT; GAS-RESERVOIRS; LOW-PERMEABILITY; FLOW MODEL; SHALE-GAS; WELLS; PERFORMANCE; DISSOLUTION,"After depletion development stage, the well-utilized approach to enhance recovery of tight oil reservoirs is fluid-injection, involving nitrogen, water, and CO2. Although a great deal of research efforts has been devoted to relevant scope, it is still challenging to identify the appropriate fluid type which can achieve favorable recovery efficiency. Also, the oil-water distribution feature in tight oil reservoirs from the microscopic view is rarely investigated, especially for that after fluid-injection. Moreover, inherent TPG (threshold pressure gradient) will make a great difference on the assignment of well-spacing, which have not well investigated. Given the current situation, this work expects to bridge up the knowledge gap. First, the original oil-water distribution feature and that after fluid-injection are revealed through laboratory experiments, in which different kinds of fluid are measured. Then, the relationship between TPG and fluid type is quantified based on another set of experiments. After that, considering the pressure distribution characteristics in whole tight oil reservoirs, the optimization plate for well-placing under different fluid types is concluded. Results show that (1) Gas-flooding shares advantages compared with water-flooding, displacement efficiency for gas-flooding is over 40% and that for waterflooding is 36% on average; (2) the main pore types initially occupied by oil consists of pore-throat, cluster, corner and intergranular, which account for 9.51%, 26.42%, 15.51%, and 13.82% respectively. And the major contributor to oil recovery comes from cluster pore-type; (3) gas-flooding approach is recommended as for the low-permeability case, and the water-flooding approach becomes favorable as for the high-permeability case.",2,2,4
Oil Recovery,Water Injection,"Zhang, Jihong; Tan, Xinjian; Zhao, Xinrui; He, Qingbin; Wang, Yanan",Experimental study of small-sized polymeric microgel (SPM) in low- or median-permeability reservoirs,Polymer microgel; Gel treatment; Conformance control; Water management; Low-permeability reservoir,PREFORMED PARTICLE GEL; CONFORMANCE CONTROL; MICROSPHERES; WATER; NANOPARTICLES; PERFORMANCE; TRANSPORT; MODEL,"Polymeric Microgel has been applied to reservoirs with varied permeability ranging from 10 to 1000 mD for mobility-control and/or conformance control. For a successful microgel treatment, the microgel particle size must be compatible with the reservoir pore-throat size to ensure effective in-depth transportation. Given such a situation, Small-sized Polymer Microgel (SPM) was developed for microgel treatment in low- and medium-permeability reservoirs. This paper presents an experimental study regarding the applicability of SPM in the low- (<100 mD) or median-permeability (100-300 mD) conditions. The experimental study involved pore-throat size determination, initial particle size distribution, swelling ratio measurements, resistance factor and residual resistance factor measurements, oil displacement experiments, and a pilot test conducted in ZT-21 producing zone located in Pubei Block 7. The result shows SPM has a good compatibility with the reservoir pore-throat size. SPM swells in water, ending up a ultimate swelling ratio of 4.8. During resistance factor and residual resistance factor measurements, SPM solution is effective at reservoir permeability of above 130 mD. That was saying, SPM is recommended to be applied in low- but not median-permeability reservoirs. In the oil displacement test, SPM improved the oil recovery through both SPM injection and post water injection at the core permeability of 95 mD, revealing SPM is available for conformance control purposes. In the pilot test, oil production improved in SPM injection and post water injection stages are 2.1 and 5.2%, respectively. The development of SPM can be contributive to oil and gas industry as it provide a guaranteed material for low-permeability reservoir microgel treatment.",2,2,4
Oil Recovery,Water Injection,"Qu, Ming; Hou, Jirui; Liang, Tuo; Raj, Infant; Yang, Yulong; Qi, Pengpeng","Synthesis of alpha-starch based nanogel particles and its application for long-term stabilizing foam in high-salinity, high-temperature and crude oil environment",Nanogel particle; Foam stability; Viscoelasticity; High temperature tolerance; High salinity tolerance; Crude oil tolerance,RECOVERY; MIXTURES; FLUID; WATER; CO2,"Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using a-starch, acrylamide, N,N'-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T-90 as indicators at temperature of 30-120 degrees C, salinity of 0-240 g/L and oil percentage of 0-50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery.",2,2,3
Oil Recovery,Water Injection,"Ladipo, Lekan; Blunt, Martin J.; King, Peter R.",A salinity cut-off method to control numerical dispersion in low-salinity waterflooding simulation,Low-salinity waterflooding; Numerical dispersion; Effective salinity thresholds; Physical mixing,OIL-RECOVERY; DIFFUSION; WATER; FLOW; AQUIFER; SCHEME; CHALK,"Low-salinity or controlled salinity waterflooding (LSWF) is a promising enhanced oil recovery (EOR) technique. In simulations of this process, numerical dispersion smears saturation fronts, causing errors in the results. The objective of this work is to control these effects in LSWF simulation. We examine the impact of numerical dispersion on simulated LSWF performance. The low-salinity (LS) front is smeared even at unfeasibly fine grids. The velocities of the water fronts are altered. A numerical mixed zone forms around the interface between the injected and resident brines. This mimics a typical physical mixing effect. In reservoir simulation, threshold salinities are defined where the low salinity effect (LSE) is first encountered. It has been suggested that numerical dispersion effects can be corrected by imposing effective thresholds. We demonstrate that existing methods to evaluate these effective salinities do not accurately predict the salt front movement especially when dispersion is significant. We propose a simple simulation-based approach to evaluate the effective salinities based on the conservation of volumes of the resident and injected brines in the reference and upscaled solutions. After comparing analytical and corrected coarse-grid solutions in one-dimension, the effectiveness of the approach is demonstrated in multidimensional systems. A method is proposed to control the numerical mixed zone to replicate a physical longitudinal mixing effect. This method is demonstrated in one-dimension and does not require a fine-grid numerical solution as a benchmark. We investigate the effects of effective thresholds on the modeled transverse mixing or dispersion. A method to model transverse dispersion in simulations with an effective longitudinal component is suggested. This method is extended to the explicit modeling of physical dispersion in systems with transverse flows. We can now simply evaluate the effective salinities for a simulation grid; and control its numerical dispersion effects to representative physical mixing or dispersion.",2,2,1
Oil Recovery,Water Injection,"Petitfrere, Martin; Nichita, Dan Vladimir; Voskov, Denis; Zaydullin, Rustem; Bogdanov, Igor",Full-EoS based thermal multiphase compositional simulation of CO2 and steam injection processes,Phase equilibrium calculations; Multiphase flash; Phase stability; Reduction; Trust-region; Convergence; Thermodynamics; SAGD; Compositional; Thermal; Simulation; Heavy oil; Steam; Injection; Steam flooding,ISOTHERMAL FLASH PROBLEM; EQUATION-OF-STATE; STABILITY ANALYSIS; PARAMETERIZATION; WATER; MIXTURES; STRATEGY; RECOVERY; FLOW,"Several compositional reservoir simulators based on equations of state (EoS) have been designed. Yet, few of them can deal with thermal processes such as steam injection and no fully compositional thermal simulation of the steam injection process has been proposed with extra-heavy oils yet. Those simulations appear essential and will offer better tools to decide whether to carry out the exploitation of a heavy oil field or not. In those processes, the accurate modelling of the water/steam phase plays an important role and accurate multiphase equilibrium calculations are necessary. Thermodynamics generate highly nonlinear problems. Besides, in reservoir simulation a huge amount of phase equilibrium calculations is required, and a single failure may cause significant error propagations leading to false solutions. This study presents several improvements leading to a more robust and efficient phase equilibrium calculation (stability and flash) program. A general multiphase flash implementing all the developed algorithms is presented and tested against experimental and literature data. It can handle any number of phases; a numerical example consists in a four-phase simulation of CO2 injection. Simulations of steam flooding are performed with highly heterogeneous reservoirs. Besides, a fully compositional simulation of the SAGD process for an extra heavy bitumen is performed, which appears to be the one of the first simulation of the kind in the literature.",2,2,0
Oil Recovery,Water Injection,"Wang, Y.; Kabir, C. S.; Reza, Z.",Deciphering well connectivity with diagnostic signal processing techniques,Signal processing; Interwell connectivity; Production/injection data; Life-long processing tools,INFERRING INTERWELL CONNECTIVITY; WATERFLOOD PERFORMANCE; RESERVOIR; OIL; FLUCTUATIONS; TRACER; MODELS,"Data mining has become increasingly crucial in deciphering reservoir dynamics, given that operators currently acquire an enormous amount of data. These data contain valuable information about subsurface processes. Interwell connectivity is one of the most significant aspects of subsurface characterization that can impact a project's success. In this study, we present novel techniques to quantify and monitor interwell communication by applying signal processing methods to observe and derive well-based measurements. A large dataset from the Permian Basin constituted the primary content of this investigation. We constructed a suite of realistic reservoir models under varying conditions involving multiple producing and water injection wells. More than 40 static and dynamic parameters including permeability, porosity, water saturation, fluid properties, and rock-fluid interaction terms are varied using experimental designs to capture realistic uncertainty. Waterflood scenarios are modeled using streamline simulation to infer injector-producer pair connectivity, pattern allocations, drainage efficiency, and their evolution period. These injector-producer variables are analyzed using numerous signal processing methods, including cross-correlation, time-lag correlation coefficient, coherence, and periodogram, among others. Well variables examined involve pressure, rate, and their derivative functions. The objectives of this study include: (1) Examining and devising several signal-processing techniques; (2) Identifying informative well data to provide information of communication between injectors and producers over time; (3) Deducing connectivity measures and systematically evaluate their efficacy in characterizing subsurface connectivity picture. The approaches reveal new insights into determining reservoir communication metrics. The proposed methods have the potential for implementation in the automated virtual flow-metering system. These methods also helped identifying the predominant injector-producer pairs and making operational decisions at any stage of any waterflood and enhanced recovery projects.",2,2,0
Oil Recovery,Water Injection,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Oil Recovery,Water Injection,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Oil Recovery,Water Injection,"Khoshkalam, Yegane; Khosravi, Maryam; Rostami, Behzad",Role of viscous cross-flow and emulsification in recovery of bypassed oil during foam injection in a microfluidic matrix-fracture system,Enhanced oil recovery; Viscous cross-flow; Emulsion; Foam injection; Foam generation mechanisms; Fractured reservoirs,POROUS-MEDIA; SNAP-OFF; MOBILITY CONTROL; GENERATION; DISPLACEMENT; GLASS,"Role of viscous cross-flow and emulsification on foam displacement process, has been experimentally studied in a microfluidic device (consists of homogeneous matrix pattern and a fracture in one side) by changing the injectant type (gas/foam/aqueous solution of surfactant/water) and foam quality and presence of connate water. Two distinct regions have been identified during foam displacement: 1) A dynamic region where gas and foam saturation is low and it mostly consists of aqueous phase. Emulsions of oil phase is generated at the front of dynamic region. 2) A static region where foam saturation is high and fluids' mobility is low. The discussion has been also supported by analysis of calculated oil recovery variation versus foam quality with a bell-shaped trend, matched with foam rheology reported in standard quality scan tests. Foam injection tests and gas injection ones as the case of no viscous cross-flow have been contrasted and the results confirmed the proposed role of viscous drives. Proper condition of emulsification has been discussed in foam injection tests and it has been shown that lack of such conditions in surfactant injection leads to weak emulsification. Moreover, foam generation mechanisms which have been observed during the experiments are snap-off and pinch-off.",1,1,1
Oil Recovery,Numerical Simulation,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Oil Recovery,Numerical Simulation,"Almetwally, Ahmed G.; Jabbari, Hadi",Finite-difference simulation of coreflooding based on a reconstructed CT scan; modeling transient oscillating and pulse decay permeability experiment,Coreflooding; Static Model; Dynamic Simulation; Transient; Permeability; Image processing,ROCK SAMPLES; FLOW; PRESSURE; OIL,"Numerical simulation and experimental research of fluid flow in porous media enhance the practices of petroleum reservoirs' management. Experiments on acquired reservoir-rock samples are conducted for accurate characterization and realization of the insitu hydrocarbon reserves. Implementing precise numerical simulation of those experiments is crucial to acquire accurate conclusions from the obtained experimental results. Coreflooding experiments quantify reservoir rock's storage capacity, measure its transport connectivity, and evaluate recovery methods' effectiveness for that rock. In this paper, a reconstruction image-processing workflow of cores' CT scan is developed to build a finite difference numerical model for simulating coreflooding experiments. In a transient coreflooding experiment, a controlled pressure pulse with a known frequency and amplitude is transmitted to the rock sample. Rock permeability can be quantified by analytically solving the diffusivity flow equation for that experiment. Simulating the transient permeability experiment is very sensitive to the level of details of the pores' structure described in the numerical model. A transient permeability experiment with two different transient modes, sinusoidal oscillation, and pulse decay, was conducted on a standard Berea core sample. The Berea CT scan was image-processed to reconstruct the static porosity and permeability model in Petrel software using a 3D variogram geostatistical population. Injection and production sources were assigned to the finite gridblock, which correspond to flow nozzles of injection and production coreflooding setup's heads. Scheduled flow and controlled-pressure boundary-conditions were imposed on the dynamic model. Eclipse simulator was used to solve the dynamic model and calculate the pressure in each gridblock. The outlet pressure was calculated at each time step by three different realization approaches for porosity and permeability, i.e., from experiments, from statistical analysis for the CT scan, and by the proposed image processing workflow. The simulated outlet pressure from the prosed workflow matched ideally, with a Pearson correlation coefficient of 0.98 and 0.99, the recorded one in the two experiments compared to underestimated or overestimated outlet pressure from the other two traditional realization approaches, i.e., statistical or experimental.",3,3,2
Oil Recovery,Numerical Simulation,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model for gravity segregation in WAG displacement recovery of inclined stratified reservoirs,Gravity segregation; WAG; Analytical model; Inclined stratified reservoir; Numerical simulation,OIL-RECOVERY; PERFORMANCE; FLUID; FLOW,"The present study deals with the extension of Stone's model to develop the analytical model of gravity segregated length (distance travelled by injected water and gas together before the complete segregation) and gravity segregated water zone height in water-alternative-gas (WAG) displacement for inclined stratified heterogeneous reservoirs. However, as per our knowledge, until now, all available analytical models of gravity segregation in the WAG displacement process consider the assumption that the reservoir is homogeneous i.e. one-layer system with constant porosity and permeability. In reality, most of the reservoirs are heterogeneous with random variation in permeability due to the variation in the depositional environments, which have a major impact on a vertical sweep in WAG displacement. The analytical models of gravity segregation for dipping stratified heterogeneous reservoir are developed by solving the fractional flow equations of displacement of fluids through MOC (method of characteristics). Then the results of these analytical models are compared with 3D finite-difference compositional reservoir simulation. The developed analytical models give appropriately similar results as 3D finite-difference compositional model. Also, analytical model results show that the complete gravity segregated length (vertical sweep efficiency) increases with an increase in reservoir dip angle and mobility ratio, and a decrease in gravity number, vertical permeability, and horizontal permeability heterogeneity. On the other hand, the gravity segregated water zone height decreases with an increase in reservoir dip angle and gravity number.",3,3,1
Oil Recovery,Numerical Simulation,"Kim, Min; Shin, Hyundon",Numerical simulation of undulating shale breaking with steam-assisted gravity drainage (UB-SAGD) for the oil sands reservoir with a shale barrier,Shale barrier; Undulating shale breaking with steam-assisted; gravity drainage (UB-SAGD); Undulating drilling; Rotary-steerable system (RSS); Maximum NPV (M_NPV),OVER-SOLVENT INJECTION; HEAVY-OIL; RECOVERY; PERFORMANCE; PARAMETERS; WATER; INTEGRATION; BITUMEN; VAPEX; WELL,"A thick oil sands reservoir separated into two thin oil sands reservoirs by a shale barrier, particularly when the separated reservoir thickness is less than 10 m, is inefficient for economic steam-assisted gravity drainage (SAGD) applications. This paper proposes undulating shale breaking with SAGD (UB-SAGD) to develop this type of reservoir, and the trajectory of undulating drilling to break the shale was designed. In addition, sensitivity analysis was performed to evaluate the effects of the area and permeability of a breaking zone and steam injection pressure. The UB-SAGD is a novel in-situ recovery method that applies undulating drilling to break the shale in the parallel direction and the above SAGD well pairs. In addition, it adds an extra injector to facilitate thermal communication between the upper and lower parts of the shale barrier, and the steam chamber can be expanded into the upper the oil sands layer along a flow path. As the area and permeability of the breaking zone were increased, the recovery factor (RF) and maximum NPV (M_NPV) increased, and the cumulative steam-oil ratio (CSOR) decreased. A comparison of the low and high steam injection pressures revealed the M_NPV of high steam injection pressure to be higher than that of low steam injection pressure because a high injection pressure facilitates flow in a smaller area of the breaking zone. The RF and CSOR of best result were improved by 24.65% and 10.21%, respectively, compared to two well-pairs of SAGD without undulating drilling. In addition, the M_NPV of this result was $3.05 MM higher than that of two well-pairs. The UB-SAGD will be very useful for the economic development of shale interbedded oil sands reservoirs using conventional SAGD.",3,3,1
Oil Recovery,Numerical Simulation,"Loaiza, Cristian S.; Patino, Juan F.; Mejia, Juan M.",Numerical evaluation of a combined chemical enhanced oil recovery process with polymer and nanoparticles based on experimental observations,Polymer; Nanoparticles; Chemical enhanced oil recovery (CEOR); Reservoir simulation,MECHANICAL DEGRADATION; SIO2 NANOPARTICLES; THERMAL-STABILITY; POLYACRYLAMIDE; BEHAVIOR,"Polymer flooding is the most widely implemented chemical enhanced oil recovery (CEOR) process. However, polymer degradation, caused by chemical, thermal, and mechanical stresses, is still the most notable limitation on the implementation of the technology at the field scale. Recent studies have shown that the addition of nanoparticles in a traditional polymer flooding can improve operating conditions and hydrocarbon production. Thus, a comprehensive numerical simulation study is presented to model the performance of the co-injection of polymers with nanoparticles in oil reservoirs. An articulated process was followed to take into account most of the physical and chemical mechanisms of the technique. Initially, a conceptual model was developed by identifying relevant mass transport and surface mechanisms, and their dynamics. The following phases are accounted in the model: oleic, volatile, and aqueous. Then, local mass balance equations were written for the following components: oil, gas, water, solid nanoparticles and polymers. An extended black-oil model for the hydrocarbon and aqueous phases was used. Constitutive equations were specified for polymer adsorption, rheology, degradation, and nanoparticles retention and remobilization, as well. The numerical strategy was described for numerically solving the Jacobian matrix. The model was subsequently validated in two steps: initially, the simulation results of a polymer flooding are compared to the ones obtained using a commercial software. Then, the nanoparticles transport and retention on the solid matrix was validated with experimental core-flooding tests reported in specialized literature. A set of numerical experiments of the co-injection of polymer-nanoparticles were done, showing that the synergy between both chemical species allowed to retain the viscoelastic network, which considerably improves operational and production parameters. This investigation provides a powerful tool for Oil & Gas industry and can be used to design novel CEOR deployment strategies in sandstone reservoirs.",3,3,0
Oil Recovery,Numerical Simulation,"Feng, Guoqing; Li, Ying; Yang, Zhidong",Performance evaluation of nitrogen-assisted steam flooding process in heavy oil reservoir via numerical simulation,Steam flooding; Nitrogen; Orthogonal design; Numerical simulation; Optimization of injection parameters,INJECTION; RECOVERY; STIMULATION; EFFICIENCY,"In this study, numerical simulation studies have been conducted to enhance oil production in X1 heavy oil reservoir using nitrogen-assisted steam injection processes. Five types of nitrogen-assisted steam flooding methods-steam flooding, steam flooding coupled with continuous nitrogen injection, coupled with intermittent nitrogen injection, coupled with nitrogen slug injection, and nitrogen flooding-have been carried out to investigate the effect of nitrogen-assisted steam flooding method on production performance. In numerical simulation study, the STARS module is applied to implement history-matching of production data, and good agreement has been achieved. Next, the orthogonal design principle is adopted to optimize the scheme of nitrogen-assisted steam flooding. The results show that steam flooding assisted by intermittent nitrogen injection is the most suitable method. In the end, the plan of nitrogen-assisted steam flooding of X1 reservoir has been designed and the oil production rate in the next 5 years has been predicted.",2,3,6
Oil Recovery,Numerical Simulation,"Wang, Kai; Wang, Zi Ming; Song, Guang-Ling",Batch transportation of oil and water for reducing pipeline corrosion,Oil production; Multiphase flow; Corrosion; Water wetting,CARBON-DIOXIDE CORROSION; 2-PHASE FLOW; CRUDE-OIL; NUMERICAL-SIMULATION; INTERNAL CORROSION; STEEL; MECHANISM; EMULSIONS; GREEN,"Different from the conventional transportation of oil-water mixtures, we proposed a method to reduce pipeline corrosion based on a concept of flow management, where the mixed fluids were firstly separated into oil and water and then a batch transportation of oil and water was introduced to tune the water wetting state at pipeline bottom. In this way, the corrosion risk of pipe bottom can be properly reduced with a minor modification of the transportation procedure. In this paper, the idea was theoretically and experimentally verified, and the modified procedure was effective in corrosion mitigation compared with the conventional oil gathering system in a CO2-enhanced oil recovery (EOR) production system. It was found that the corrosion mitigation efficiency held a positive relationship with the dimensionless length of the oil phase, which was determined by the input length of oil and water batch and the evolution of flow pattern at the oil/water interface. This is of special benefits for the case where a large amount of free water is unable to be entrained into oil phase. Such a concept of corrosion mitigation can be applied in the transportation of corrosive oil-water mixtures in petroleum industry, such as in CO2-EOR and offshore oil production.",2,2,6
Oil Recovery,Numerical Simulation,"Zheng, Yang; Lei, Guanglun; Yao, Chuanjin; Fu, Jingang; Wang, Long; Zhang, Xin; Jia, Xiaofei",A calculation model about reservoir thermal efficiency of in-situ upgrading for oil shale via steam injection,In-situ upgrading; Oil shale; Reservoir thermal efficiency; Steam injection; Kerogen pyrolysis,RANITIDINE HCL MICROSPHERES; OPTIMIZATION; DESIGN,"The reasonable determination of the reservoir thermal efficiency is essential for the successful application of thermal recovery technology in oilfield. However, in terms of the in-situ upgrading for oil shale via steam injection, there is currently no calculation model to evaluate the reservoir thermal efficiency. In this work, a calculation model was established based on the theory of steam flooding front prediction in thermal recovery, and it was validated mainly through comparing with numerical simulation results. One-quarter of a five-spot well group was applied for this simulation, the response surface analysis and sensitivity studies were performed to study the effect of various parameters on reservoir thermal efficiency. Injection rate, reservoir thickness, kerogen concentration and steam temperature all have significant effect on reservoir thermal efficiency, and there is a strong interaction between injection rate and reservoir thickness. High thermal efficiency mainly depends on increasing heat reserved in reservoir and reducing heat loss to upper and lower formations. Meanwhile, the existence of gravity override has an adverse effect on thermal efficiency. Therefore, the sensitivity studies are to explore the comprehensive influence of different parameters on above three aspects. The results show that appropriately increasing the injection rate of steam in a certain range can effective improve and stabilize the efficiency. Under the premise of well thermal insulation of the upper and lower formations, the reservoir thickness is supposed to large enough, and the reservoir with high kerogen concentration can be selected. Increasing steam temperature and reducing initial pyrolysis temperature not only can ensure the high conversion ratio of kerogen pyrolysis, but also has beneficial effect on maintaining the higher reservoir thermal efficiency. Reducing the mobility ratio of steam flooding can avoid the correction shape factor being too small, thus improving the thermal efficiency.",2,2,2
Oil Recovery,Numerical Simulation,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Oil Recovery,Numerical Simulation,"Wu, Yuqi; Tahmasebi, Pejman; Lin, Chengyan; Ren, Lihua; Zhang, Yimin",Quantitative characterization of non-wetting phase in water-wet porous media based on multiphase flow experiment and numerical simulation,Multiphase fluid flow; Residual oil; Fluid physics; Pore-scale modeling; Pore occupancy,PORE-SCALE; RESIDUAL OIL; RELATIVE-PERMEABILITY; 2-PHASE FLOW; RECOVERY; SHALE; TECHNOLOGIES; MULTISCALE; SALINITY; SIZE,"It is of great significance to analyze the distribution characteristics of the non-wetting phase during the multiphase flow and identify the positions of the oil ganglia since it can guide us to design the schemes for improving oil recovery. In this paper, the two-phase (brine and oil) flow experiment and simulation are performed on a water-wet sandstone. A comprehensive analysis of the distribution of the non-wetting (oil) phase in 3D pore space and individual pores are presented. To calculate the pore occupancy of the non-wetting ganglia in every single pore from 3D CT experimental data, we proposed a technique, called the Axis-aligned Bounding Box (AABB) algorithm, to determine which oil blobs exist in a unique pore. The pore-by-pore distribution characteristics of the residual phase are then analyzed based on the experimental and numerical data. The results reveal the large oil clusters are separated into small blobs during the imbibition process, which results in increasing the number of non-wetting ganglia, dropping its connectivity, and increasing the smoothness. Moreover, the larger the volume of one pore, the larger the volume and saturation of residual oil ganglia in the pore are. Furthermore, our analysis based on the experimental and numerical results indicates that most of the non-wetting ganglia reside in the median-size pores. Hence, the finding provides us a piece of significant evidence to better target the pore-spaces for the purpose of increasing the recovery.",2,2,2
Oil Recovery,Numerical Simulation,"Ladipo, Lekan; Blunt, Martin J.; King, Peter R.",A salinity cut-off method to control numerical dispersion in low-salinity waterflooding simulation,Low-salinity waterflooding; Numerical dispersion; Effective salinity thresholds; Physical mixing,OIL-RECOVERY; DIFFUSION; WATER; FLOW; AQUIFER; SCHEME; CHALK,"Low-salinity or controlled salinity waterflooding (LSWF) is a promising enhanced oil recovery (EOR) technique. In simulations of this process, numerical dispersion smears saturation fronts, causing errors in the results. The objective of this work is to control these effects in LSWF simulation. We examine the impact of numerical dispersion on simulated LSWF performance. The low-salinity (LS) front is smeared even at unfeasibly fine grids. The velocities of the water fronts are altered. A numerical mixed zone forms around the interface between the injected and resident brines. This mimics a typical physical mixing effect. In reservoir simulation, threshold salinities are defined where the low salinity effect (LSE) is first encountered. It has been suggested that numerical dispersion effects can be corrected by imposing effective thresholds. We demonstrate that existing methods to evaluate these effective salinities do not accurately predict the salt front movement especially when dispersion is significant. We propose a simple simulation-based approach to evaluate the effective salinities based on the conservation of volumes of the resident and injected brines in the reference and upscaled solutions. After comparing analytical and corrected coarse-grid solutions in one-dimension, the effectiveness of the approach is demonstrated in multidimensional systems. A method is proposed to control the numerical mixed zone to replicate a physical longitudinal mixing effect. This method is demonstrated in one-dimension and does not require a fine-grid numerical solution as a benchmark. We investigate the effects of effective thresholds on the modeled transverse mixing or dispersion. A method to model transverse dispersion in simulations with an effective longitudinal component is suggested. This method is extended to the explicit modeling of physical dispersion in systems with transverse flows. We can now simply evaluate the effective salinities for a simulation grid; and control its numerical dispersion effects to representative physical mixing or dispersion.",2,2,1
Oil Recovery,Numerical Simulation,"Petitfrere, Martin; Nichita, Dan Vladimir; Voskov, Denis; Zaydullin, Rustem; Bogdanov, Igor",Full-EoS based thermal multiphase compositional simulation of CO2 and steam injection processes,Phase equilibrium calculations; Multiphase flash; Phase stability; Reduction; Trust-region; Convergence; Thermodynamics; SAGD; Compositional; Thermal; Simulation; Heavy oil; Steam; Injection; Steam flooding,ISOTHERMAL FLASH PROBLEM; EQUATION-OF-STATE; STABILITY ANALYSIS; PARAMETERIZATION; WATER; MIXTURES; STRATEGY; RECOVERY; FLOW,"Several compositional reservoir simulators based on equations of state (EoS) have been designed. Yet, few of them can deal with thermal processes such as steam injection and no fully compositional thermal simulation of the steam injection process has been proposed with extra-heavy oils yet. Those simulations appear essential and will offer better tools to decide whether to carry out the exploitation of a heavy oil field or not. In those processes, the accurate modelling of the water/steam phase plays an important role and accurate multiphase equilibrium calculations are necessary. Thermodynamics generate highly nonlinear problems. Besides, in reservoir simulation a huge amount of phase equilibrium calculations is required, and a single failure may cause significant error propagations leading to false solutions. This study presents several improvements leading to a more robust and efficient phase equilibrium calculation (stability and flash) program. A general multiphase flash implementing all the developed algorithms is presented and tested against experimental and literature data. It can handle any number of phases; a numerical example consists in a four-phase simulation of CO2 injection. Simulations of steam flooding are performed with highly heterogeneous reservoirs. Besides, a fully compositional simulation of the SAGD process for an extra heavy bitumen is performed, which appears to be the one of the first simulation of the kind in the literature.",2,2,0
Oil Recovery,Numerical Simulation,"Eghbali, Sara; Dehghanpour, Hassan",A Simulation Study on Solvent-Aided Process using C-3 and C-4 in Clearwater Oil-Sand Formation,Solvent-steam co-injection; Numerical simulation; SAGD; Production performance; Steam oil ratio,NUMERICAL-SIMULATION; SAGD; PERFORMANCE; VISCOSITY; BEHAVIOR; BITUMEN,"Solvent-aided processes (SAP) have been considered to enhance the energy efficiency of Steam Assisted Gravity Drainage (SAGD) process for hydrocarbon recovery from oil-sand formations. We performed numerical simulations to investigate how solvent type and concentration affect the performance of SAP. First, we created simulation models in which light solvents are co-injected with steam into a developed steam chamber in Clearwater oil-sand Formation. Second, we investigated the phase behaviour of steam-solvent-bitumen and its effects on bitumen viscosity at steam-bitumen interface. Third, we investigated the effects of solvent concentration on production performance of SAP. The results show three main stages in bitumen production profile during SAP. Oil rate reaches two peaks (one during the first stage, and one during the second stage), then drops and stabilizes during the third stage. During the first stage, C-4 condensation near the chamber edge leads to dilution and drainage of the heated bitumen. During the second stage, the steam chamber grows more laterally. During the third stage, as water accumulates at the bottom of the chamber, steam chamber volume decreases. In addition, contact area between the condensed solvent and bitumen reduces. Therefore, oil rate stabilizes even though solvent is co-injected with steam during this stage due to the adverse effect of water accumulation near the production well. Compared with C-4 steam co-injection process, C-3-steam co-injection leads to higher bitumen viscosity near the chamber edge due to 1) less C-3 solubility than C-4 in the oil phase and 2) lower chamber temperature in the C-3-steam co-injection. Maximum-performance scenarios for C-3-, and C-4-steam co-injections are co-injecting C-3 with steam at 2% mol C-3 and co-injecting C-4 with steam at 3% mol C-4. These scenarios of C-3- and C-4-steam co-injections lead to 1.5% and 5% increase in SAGD ultimate bitumen recovery factor, respectively. C-3- and C-4-steam co-injections with maximum-performance scenarios reduce SAGD cummulative steam oil ratio (CSOR) by 31.5% and 29%, respectively.",2,2,0
Oil Recovery,Numerical Simulation,"Wang, Y.; Kabir, C. S.; Reza, Z.",Deciphering well connectivity with diagnostic signal processing techniques,Signal processing; Interwell connectivity; Production/injection data; Life-long processing tools,INFERRING INTERWELL CONNECTIVITY; WATERFLOOD PERFORMANCE; RESERVOIR; OIL; FLUCTUATIONS; TRACER; MODELS,"Data mining has become increasingly crucial in deciphering reservoir dynamics, given that operators currently acquire an enormous amount of data. These data contain valuable information about subsurface processes. Interwell connectivity is one of the most significant aspects of subsurface characterization that can impact a project's success. In this study, we present novel techniques to quantify and monitor interwell communication by applying signal processing methods to observe and derive well-based measurements. A large dataset from the Permian Basin constituted the primary content of this investigation. We constructed a suite of realistic reservoir models under varying conditions involving multiple producing and water injection wells. More than 40 static and dynamic parameters including permeability, porosity, water saturation, fluid properties, and rock-fluid interaction terms are varied using experimental designs to capture realistic uncertainty. Waterflood scenarios are modeled using streamline simulation to infer injector-producer pair connectivity, pattern allocations, drainage efficiency, and their evolution period. These injector-producer variables are analyzed using numerous signal processing methods, including cross-correlation, time-lag correlation coefficient, coherence, and periodogram, among others. Well variables examined involve pressure, rate, and their derivative functions. The objectives of this study include: (1) Examining and devising several signal-processing techniques; (2) Identifying informative well data to provide information of communication between injectors and producers over time; (3) Deducing connectivity measures and systematically evaluate their efficacy in characterizing subsurface connectivity picture. The approaches reveal new insights into determining reservoir communication metrics. The proposed methods have the potential for implementation in the automated virtual flow-metering system. These methods also helped identifying the predominant injector-producer pairs and making operational decisions at any stage of any waterflood and enhanced recovery projects.",2,2,0
Oil Recovery,Numerical Simulation,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Oil Recovery,Numerical Simulation,"Niu, Jun; Liu, Shuo; Xu, Jing-yu",Investigation into atomization spray blending property in heavy crude oil extraction under laboratory conditions,Heavy crude oil extraction; Atomization spray; Blending; Viscosity reduction; Droplet behavior,VISCOSITY; BREAKUP; RECOVERY; SIZE,"In this study, the atomization blending property for heavy crude oil extraction was systematically investigated both numerically and experimentally. In the experiment conducted, the blending behavior was simulated using hydraulic oil and spray with 1:10 light phase-gas atomize volume flow rate ratio in an equipment sharing the same scale as the on-site production. A Malvern Insitec droplet size analyzer was applied for the droplet size measurement, and a quick closing valve method was applied for the phase fraction measurement. A numerical simulation combined with a population balance model and the RNG k-epsilon model was performed under both the corresponding operating conditions and a high-pressure drop environment to further investigate the blending procedure. The results show that the atomization spray blending performs better than the equivalent pure gas lifting method with more crude oil carried at the exit. Under 0.6 m(3)/h light phase inlet conditions, spray blending brings 8% more heavy crude than gas lifting, and the improvement rises as inlet flow rate increases. Both a droplet and liquid film are present in the casing space before blending for the spray liquid phase. In addition, the light phase droplet diameter decreases with an increase in the inlet flow rates in the lifting pipe after blending. Moreover, the blending behavior differs under various light phase inlet flow rates, while the mixture viscosity is reduced by 50% for the atomization spray method. Each of these factors was shown to be beneficial for refining the blending used in a heavy crude oil extraction technique.",1,2,2
Oil Recovery,Numerical Simulation,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Oil Recovery,Heavy Oil,"Hou, Qingfeng; Wang, Yuanyuan; Wang, Zhe; Wu, Qi; Wang, Fan; Ni, Chen; Zheng, Xiaobo; Xu, Yan; Zhao, Yujun",Temperature sensitivity of CO2-triggered switchable surfactants with acetamidine group,CO2-triggered; Switchable; Surfactants; Acetamidine; Conductivity; Emulsification,EMULSION BREAKING; TERTIARY AMINE; HEAVY OIL; FOAMS; FUEL,"In this study, a series of CO2-switchable acetamidines surfactants with different hydrophobic tail groups were synthesized using N, N-dimethylacetamide dimethyl acetal and different aliphatic amines. The conductivity assessment demonstrated the exceptional CO2-switchable performance of these surfactants. It was believed this switchability mainly resulted from the activity of acetamidine groups which could react with CO2 to form the amphiphilic acetamidine carbonate. For this reason, the protonation during CO2 bubbling of acetamidine surfactants with longer hydrophobic tail was more likely to occur at higher temperature due to the improved solubility. It was also found that acetamidines containing shorter hydrophobic tail tend to be more temperature-insensitive in the protonation process. However, as for the deprotonation process (N-2 bubbling), the asformed acetamidines bicarbonates with short hydrophobic tails displayed evident temperature sensitivity, and thus higher temperature favored the regeneration of acetamidines. Additionally, the acetamidine bicarbonates with longer hydrophobic tails showed remarkable surface activity in the hexadecane/water emulsion than those with shorter hydrophobic tails. Furthermore, higher temperature and longer standing time accelerated the N-2-triggered demulsification and the recovery of oil phase. The temperature sensitivity could allow these acetamidines to be deployed in CO2-triggered enhanced oil recovery (EOR).",3,3,4
Oil Recovery,Heavy Oil,"Salehpour, Mohammad; Riazi, Masoud; Malayeri, M. Reza; Seyyedi, Mojtaba",CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage,"Carbon capture, and storage (CCS); Carbon capture, utilization, and storage (CCUS); Carbonated water injection; Heavy asphaltic crude oil; Water-in-oil emulsion; Enhanced oil recovery",PORE-SCALE MECHANISMS; WATER INJECTION; INTERFACIAL-TENSION; WETTABILITY ALTERATION; CO2 INJECTION; PERFORMANCE; SECONDARY; SCENARIOS; EMULSIONS; DIOXIDE,"Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsioninduced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.",3,3,4
Oil Recovery,Heavy Oil,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Oil Recovery,Heavy Oil,"Afra, Mohammad; Peyghambarzadeh, S. M.; Shahbazi, Khalil; Tahmassebi, Narges",Experimental study of implementing nano thermal insulation coating on the steam injection tubes in enhanced oil recovery operation for reducing heat loss,Heat transfer; Steam injection; Nano thermal insulation coating; Thermal recovery; Enhanced oil recovery,,"Thermal recovery in oil fields is an effective conventional method for extracting heavy oil. Steam injection is one of the main techniques in thermal recovery. Temperature reduction of the injected steam due to heat transfer from tubes to the reservoir environment is one of the essential problems in this method. Increasing the steam temperature or injection rate to overcome this energy loss and to provide the required temperature at the tube outlet considerably enhances the steam generation costs. Furthermore, increasing the injection temperature enhances the thermal stress to injection tubes that in turn brings irreparable damages to production units like casing breakage. In this study, an experimental setup used to simulate steam injection operation in order to decrease the heat transfer coefficient and reduce heat loss to conserve the injected steam temperature. This aim ascertained by using nano coatings as thermal insulator. Two types of thermal insulators including nano silica-based and nano ceramic-based insulators used in this study. Temperature, pressure, and injection rate of steam, and type and thickness of nano thermal insulators were the operating variables. Results show that increasing the injection temperature from 119 degrees C to 145 degrees C improves the heat transfer coefficient about twofold that in turn, causes rapid reduction of temperature in injection process. It was also shown that increasing the injection rate from 2.1 g/l to 6.3 g/l inside the bare tube improves the heat transfer coefficient up to 2.5-folds. Therefore, increasing the temperature or injection rate of steam could not be the suitable solution for compensating steam heat loss. The experimental results showed that using ceramic-based and silica-based nano insulation with 5 mm thickness reduces the heat loss up to 45% and 33% for injected steam at 145 degrees C, respectively.",3,4,0
Oil Recovery,Heavy Oil,"Feng, Guoqing; Li, Ying; Yang, Zhidong",Performance evaluation of nitrogen-assisted steam flooding process in heavy oil reservoir via numerical simulation,Steam flooding; Nitrogen; Orthogonal design; Numerical simulation; Optimization of injection parameters,INJECTION; RECOVERY; STIMULATION; EFFICIENCY,"In this study, numerical simulation studies have been conducted to enhance oil production in X1 heavy oil reservoir using nitrogen-assisted steam injection processes. Five types of nitrogen-assisted steam flooding methods-steam flooding, steam flooding coupled with continuous nitrogen injection, coupled with intermittent nitrogen injection, coupled with nitrogen slug injection, and nitrogen flooding-have been carried out to investigate the effect of nitrogen-assisted steam flooding method on production performance. In numerical simulation study, the STARS module is applied to implement history-matching of production data, and good agreement has been achieved. Next, the orthogonal design principle is adopted to optimize the scheme of nitrogen-assisted steam flooding. The results show that steam flooding assisted by intermittent nitrogen injection is the most suitable method. In the end, the plan of nitrogen-assisted steam flooding of X1 reservoir has been designed and the oil production rate in the next 5 years has been predicted.",2,3,6
Oil Recovery,Heavy Oil,"Liu, Huiqing; Wang, Yanwei; Zheng, Aiping; Sun, Xinge; Dong, Xiaohu; Li, Dandan; Zhang, Qichen",Experimental investigation on improving steam sweep efficiency by novel particles in heavy oil reservoirs,,DEPTH PROFILE CONTROL; HIGH-TEMPERATURE; EXPANDABLE GRAPHITE; FLAME-RETARDANT; FOAM STABILITY; WATER-SHUTOFF; RECOVERY; SOLVENT; PERMEABILITY; MODEL,,2,2,2
Oil Recovery,Heavy Oil,"Marquez, Sharoh G.; Ghafoori, Samira; Omar, Mohamed; Almarshed, Abdullah",Delineation of most efficient recovery technique for typical heavy oil reservoir in the Middle East region through compositional simulation of temperature-dependent relative permeabilities,Heavy oil; Temperature-dependence; Relative permeabilities; Compositional simulation; Thermal simulation,,"In modelling and design of heavy oil recovery, the complex interactions between the reservoir fluid and the injected fluid fosters a need for its behavior to be captured precisely and accurately. However, determining the most influential parameters in the recovery process is of great importance. In this study, the temperature-dependence of relative permeabilities has been identified as the most potent factor in aiding the improved simulated recovery of heavy oils and is being modelled in both compositional and thermal simulation environments for comparison of their recovery effectivity. Several techniques for recovering heavy oil, such as cold production, waterflooding, solvent injection, cyclic steam injection and even hot solvent injection is modelled and ranked according to their resulting recovery factors considering that the relative permeabilities alongside its temperature-dependence are the most significant factors in moving the fluid during simulation. Pressure-Volume-Temperature (PVT) relations to describe and characterize typical heavy oil from Middle East region is utilized for the application of this study and the results showed that hot solvent injection is the most effective technique in maximizing the recovery for the model oil description.",2,2,1
Oil Recovery,Heavy Oil,"Petitfrere, Martin; Nichita, Dan Vladimir; Voskov, Denis; Zaydullin, Rustem; Bogdanov, Igor",Full-EoS based thermal multiphase compositional simulation of CO2 and steam injection processes,Phase equilibrium calculations; Multiphase flash; Phase stability; Reduction; Trust-region; Convergence; Thermodynamics; SAGD; Compositional; Thermal; Simulation; Heavy oil; Steam; Injection; Steam flooding,ISOTHERMAL FLASH PROBLEM; EQUATION-OF-STATE; STABILITY ANALYSIS; PARAMETERIZATION; WATER; MIXTURES; STRATEGY; RECOVERY; FLOW,"Several compositional reservoir simulators based on equations of state (EoS) have been designed. Yet, few of them can deal with thermal processes such as steam injection and no fully compositional thermal simulation of the steam injection process has been proposed with extra-heavy oils yet. Those simulations appear essential and will offer better tools to decide whether to carry out the exploitation of a heavy oil field or not. In those processes, the accurate modelling of the water/steam phase plays an important role and accurate multiphase equilibrium calculations are necessary. Thermodynamics generate highly nonlinear problems. Besides, in reservoir simulation a huge amount of phase equilibrium calculations is required, and a single failure may cause significant error propagations leading to false solutions. This study presents several improvements leading to a more robust and efficient phase equilibrium calculation (stability and flash) program. A general multiphase flash implementing all the developed algorithms is presented and tested against experimental and literature data. It can handle any number of phases; a numerical example consists in a four-phase simulation of CO2 injection. Simulations of steam flooding are performed with highly heterogeneous reservoirs. Besides, a fully compositional simulation of the SAGD process for an extra heavy bitumen is performed, which appears to be the one of the first simulation of the kind in the literature.",2,2,0
Oil Recovery,Heavy Oil,"Taheri, Reza; Kabuli, Muffazal; Vryzas, Zisis",Fracturing and permeability enhancement with laser technology employing fuzzy logic,Laser technology; Permeability; Porosity; Microfractures; Fuzzy logic,,"Increasing the rock permeability in low permeable zones of the hydrocarbon reservoirs by conventional methods will often cause formation damage and consequently will reduce the efficiency of recovery of the reservoirs in long term. The use of high energy laser technology as an alternative and innovative approach to mobilise heavy oil and improve permeability, as opposed to the conventional techniques, which have advert effects on the longterm reservoir productivity, was examined in this research. This paper will present study results of the employment of pulsed (Q-switched) Nd: YAG (Neodymium: Yttrium Aluminium Garnet) laser on impermeable heavy oil-bearing core samples which have been simulated in lab to be as close as possible to the real reservoir conditions. A unique technique was employed in this study where lasing experiment was conducted on samples followed by intervals of stopping lasing operation, known as relaxation intervals. The alternate lasing-relaxation intervals which were repeated for samples 3 times, yield positive and satisfactory results both for heavy oil mobilization as well as permeability improvement. Porosity increase was also observed due to fracture production. Specifications of applied laser pulses and their associated beam properties, samples characteristics and dimensions as well as the simulated experiment environment with that of the real reservoir conditions will be reported. Fuzzy logic was employed to normalize the varying and diverse parameters affecting the rock's thermal behaviour such as mineral content, fluid content and type and pressure. By employing the proposed technique on samples from heavy-oil-bearing low permeable zones of Burgan and Mauddud reservoirs of the Giant Burgan field in Kuwait, fractures were produced and permeability of the reservoir samples were improved to almost 3 times of their initial values in some of the samples. Upon the termination of the third lasing experiment, traces of oil could be observed on some of the core sample's surfaces, proving that the heavy oil was mobilised due to induced high temperatures generated in the samples during lasing.",2,2,0
Oil Recovery,Heavy Oil,"Lopez, Daniel; Zabala, Richard D.; Cardenas, Jose C.; Lopera, Sergio H.; Riazi, Masoud; Franco, Camilo A.; Cortes, Farid B.",A novel design of silica-based completion nanofluids for heavy oil reservoirs,Adsorption; Completion nanofluid; Interfacial tension; Silica nanoparticles; Surfactant; Wettability,WETTABILITY ALTERATION; INTERFACIAL-TENSION; SURFACE-ROUGHNESS; NANOPARTICLES; GAS; RECOVERY; WATER; ADSORPTION; PRODUCTIVITY; MODEL,"The main objective of this manuscript is the design of completion nanofluids (NanoCF) using silica nanoparticles based on the impact on the capillary number for being applied in heavy crude oil reservoirs. Six types of silica nanoparticles with different chemical nature were characterized by dynamic light scattering (DLS), point of zero charge (pHpzc), Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), surface area (S-BET), X-ray diffraction (XRD) and total surface acidity through temperature-programmed desorption of NH3 (TPD-NH3). Adsorption isotherms were constructed for understanding the non-ionic surfactant interaction with nanoparticles and rock surfaces, showing that a high adsorption affinity of the surfactant onto the rock surface, leaving less than 24% of free surfactant molecules able to migrate to the water/oil interface. Nevertheless, nanoparticle addition onto completion fluids (CF) could reduce the adsorbed surfactant onto the rock surface by 75%, which means more molecules of surfactant at the interface due to the nature of the obtained nanoparticles (NPS). The nanoparticles were selected based on the capillary number, showing that the best material reduced the interfacial tension between heavy crude oil and CF more than 76% and have the capacity to modify an initial oil-wet state to a water-wet rock surface. Finally, a coreflooding test was carried out at reservoir conditions (158 degrees F and 6.89 MPa) for evaluating the best completion nanofluid design based on the static tests, showing an increase of the oil effective permeability of 37% and incremental oil recovery of 3% in comparison to the completion fluid without nanoparticles. For the first time, novel completion nanofluids could allow stimulating the well from the beginning of the productive life.",2,2,0
Oil Recovery,Heavy Oil,"Canbolat, Serhat",Assessment of SAGD heat transfer mechanism via noncondensable gas CO-INJECTION,SAGD; Noncondensable gas; Heat transfer; Conductive heat flux; Convective heat flux; SAGP,MULTIPHASE FLOW; STEAM; EDGE; CONVECTION,"The favored process for extracting heavy oil from reservoirs using twin horizontal wells is called steam-assisted gravity drainage (SAGD). During this application, steam is injected into the reservoir from above well and when heated, heavy oil is mobilized under gravity to the producer lying below. Steam build-up inside the pay zone is called the steam chamber. The main problems facing SAGD are the thermal efficiency and the thermal conductivity of the heat flux at the uppermost part of the steam chamber. Moreover, the role of solution gas and injection of gas in SAGD steam chambers remains unclear, particularly issues involving heat transfer. The objective of the study is to analyze the variation of heat transfer behavior by conduction and convection on heavy oil production using heat fluxes via the co-injection of noncondensable gas (NCG) during SAGD. To evaluate this phenomenon, the field verified SAGD analytical model was modified and used to analyze the experimental results of steam with/without NCG addition at comparable volumetric injection ratios. The outcomes of the modified heat transfer study conducted during SAGD on co-injection of NCG showed that an adequately large concentration at the uppermost part of the chamber decreased the heat flow at the edge. Besides, conduction was the primary heat transfer method for steam injection only. In the modified model, there was no obvious convective heat transfer below 125 degrees C for steam alone and below 150 degrees C for cases with NCG addition. However, the convective heat flux was more dominant after 230 degrees C and 240 degrees C for the NCG addition to steam at 1:1.29 and 1:4.41 volumetric ratio cases respectively. For the conductive and convective heat fluxes, the modified model fit with the steam only case. However, the results of the addition of NCG to steam at both runs showed a tendency to decrease at higher temperatures. On the contrary, the interaction between NCG and steam at the edge of the chamber influences the flow of heat resulting in both a decreased transfer of heat to the overburden as well as to the sides of the depletion chamber and a low recovery mechanism that produces the steam and gas push (SAGP) mechanism.",1,1,4
Oil Recovery,Heavy Oil,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Oil Recovery,Heavy Oil,"Niu, Jun; Liu, Shuo; Xu, Jing-yu",Investigation into atomization spray blending property in heavy crude oil extraction under laboratory conditions,Heavy crude oil extraction; Atomization spray; Blending; Viscosity reduction; Droplet behavior,VISCOSITY; BREAKUP; RECOVERY; SIZE,"In this study, the atomization blending property for heavy crude oil extraction was systematically investigated both numerically and experimentally. In the experiment conducted, the blending behavior was simulated using hydraulic oil and spray with 1:10 light phase-gas atomize volume flow rate ratio in an equipment sharing the same scale as the on-site production. A Malvern Insitec droplet size analyzer was applied for the droplet size measurement, and a quick closing valve method was applied for the phase fraction measurement. A numerical simulation combined with a population balance model and the RNG k-epsilon model was performed under both the corresponding operating conditions and a high-pressure drop environment to further investigate the blending procedure. The results show that the atomization spray blending performs better than the equivalent pure gas lifting method with more crude oil carried at the exit. Under 0.6 m(3)/h light phase inlet conditions, spray blending brings 8% more heavy crude than gas lifting, and the improvement rises as inlet flow rate increases. Both a droplet and liquid film are present in the casing space before blending for the spray liquid phase. In addition, the light phase droplet diameter decreases with an increase in the inlet flow rates in the lifting pipe after blending. Moreover, the blending behavior differs under various light phase inlet flow rates, while the mixture viscosity is reduced by 50% for the atomization spray method. Each of these factors was shown to be beneficial for refining the blending used in a heavy crude oil extraction technique.",1,2,2
Oil Recovery,Heavy Oil,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Oil Recovery,Remaining Oil,"Zhang, Yang; Lu, Fengming; Cai, Mingjun; Yang, Yongqiang; Li, Ji; Guo, Zhiqiao; Wang, Rui; Zheng, Rongji",Physical simulation experiments of remaining oil distribution and production in alluvial fans controlled by dynamic and static factors,Alluvial fan; Dynamic and static factors; Physical simulation experiment for water flooding; Remaining oil distribution and production; Cangdong sag,DEBRIS-FLOW; BASIN; FIELD; INTERCALATION; SEDIMENTATION; PERFORATION; RESERVOIRS; SATURATION; EVOLUTION; VALLEY,"In order to study the remaining oil distribution and production in alluvial fans controlled by both static geologic factors and dynamic development factors, 2D and 3D macroscopic physical models have been constructed for the alluvial fan reservoirs in the eastern part of Cangdong sag, Bohai Bay Basin, China. Through considering static reservoir architecture and dynamic displacement rate, perforation position, well type, and well pattern, 7 water flooding physical simulation experiments have been finished, and the remaining oil distribution and production in oilfields with ultra-high water cut controlled by both dynamic and static factors were revealed. The study shows that without considering the economic benefits, drilling horizontal well, drilling infilled vertical well, increasing displacement rate, and plugging off water flooded layers at the initial stage of ultra-high water cut exhibited decreased performance in remaining oil production. After the dynamic factors adjustment, the remaining oil distribution and production is mainly controlled by the interlayer position, reservoir rhythm and the combination relationship between dynamic and static factors. When more injector-producer groups are located in the same single sand body, and the oil wells are uniformly drilled in single sand of different types, the oil recovery efficiency will be higher, and the distribution of the remaining oil will be more uniform. According to the experimental results, the remaining oil controlled by braided sand island and braided river channel could be divided into three types, and the corresponding measures to tap the potential were proposed.",3,3,2
Oil Recovery,Remaining Oil,"Soulat, A.; Douarche, F.; Flauraud, E.",A modified well index to account for shear-thinning behaviour in foam EOR simulation,Multiphase flow; Porous media; Foam; Shear-thinning; Injectivity; Well index; Enhanced oil recovery; Upscaling,STEADY-STATE; INJECTIVITY; MODEL; GAS,"An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shear-thinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements. We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on coarser grids when compared to a sufficiently refined reference grid. In order to correct these errors we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address. This modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. Our proposed solution, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour. Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.",3,3,2
Oil Recovery,Remaining Oil,"Li, Shunming; He, Hui; Hao, Ruilin; Chen, Huanqing; Bie, Hanyu; Liu, Pengcheng","Depositional regimes and reservoir architecture characterization of alluvial fans of Karamay oilfield in Junggar basin, Western China",Junggar basin; Alluvial fan; Cohesive debris flows; Sandy debris flows; Conglomeratic reservoir architectures,PERMIAN LUCAOGOU FORMATION; GRAINED DEBRIS FLOWS; SEDIMENTARY PROCESSES; NATURAL DISTINCTION; HYDRAULIC PROCESSES; SOURCE ROCKS; FACIES; MORPHOLOGY; GEOCHEMISTRY; DELTA,"We analyzed the lithology and sedimentary structures of the lower Karamay formation alluvial fan of Karamay oilfield in Junggar basin and subdivided its lithofacies into six types. The depositional regimes of the lower Karamay formation regressive alluvial fans contain (1) cohesive debris flows, (2) sandy debris flows, (3) grain flows, (4) turbidity currents, and (5) traction currents in the light of sedimentary fabrics and lithofacies association. In terms of lithofacies association, depositional succession, boundary surface hierarchy and wireline logs, fourth-order reservoir architectures for this alluvial fan are composed of nine types: (1) trench channel conglomerates, (2) trench sandy conglomerates, (3) trench proximal sandbody, (4) trench sheetflood lithosome, (5) trench distal sandbody, (6) braided channel, (7) channel gravel bar, (8) overflow sandbody, and (9) runoff channel. On the basis of the reservoir architecture identification of all wells, we established a three-dimensional (3D) architectural element model of the lower Karamay formation with a method of sequential indicator simulation to reveal the reservoir architecture spatial distribution. Integrated three-dimensional reservoir architecture models with contemporary depositional characteristics of alluvial fans, we concluded the depositional patterns of reservoir architectures for different alluvial fan subfacies, which shows the geometric features and aspects of the reservoir architectures. This information provided a technical foundation for the remaining oil prediction, development strategy optimization, and oil recovery enhancement of the conglomeratic oil reservoirs at the high water-cut stage.",3,4,1
Oil Recovery,Remaining Oil,"Salimi, Hamidreza; Bruining, Johannes; Joekar-Niasar, Vahid",Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities,Percolation theory; Effective-medium approximation; Relative permeability; Pore-network theory; Primary and secondary drainage; Noncircular pore throats,2-PHASE FLOW; POROUS-MEDIA; PERCOLATION THEORY; WETTING LIQUID; LAMINAR-FLOW; IMBIBITION; CORNERS,"Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation-at which there is no infinite cluster of completely filled water pores-but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 x 301 x 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).",2,2,2
Oil Recovery,Remaining Oil,"Wu, Dejun; Zhou, Kang; Hou, Jian; An, Zhibin; Zhai, Mingkun; Liu, Wenbin",Experimental study on combining heterogeneous phase composite flooding and streamline adjustment to improve oil recovery in heterogeneous reservoirs,Heterogeneous reservoirs; Heterogeneous phase composite flooding; Streamline adjustment; Synergy mechanism; Affected regions,PREFORMED PARTICLE GEL; HYDROLYZED POLYACRYLAMIDE; ELASTIC MICROSPHERES; CONFORMANCE CONTROL; POLYMER; MECHANISM; PERMEABILITY; SYSTEM; SIZE,"The heterogeneity of reservoirs is the key factor restricting the development performance of oilfields. Heterogeneous phase composite flooding (HPCF) and streamline adjustment (SA) are both viable strategies for improving oil recovery of heterogeneous reservoirs. However, both strategies have their own deficiencies, which limits further development. In recent years, a hybrid strategy combining HPCF and SA has attracted considerable interest from oil industry. In this paper, two-dimensional (2D) large-scale physical model experiments were performed to verify whether the hybrid strategy could offer better development performance than the single strategy, and the mechanism of hybrid strategy for improving oil recovery was elucidated. On this basis, the influence of SA angle on improved development performance was investigated. Finally, the affected regions of remaining oil in different strategies were proposed. The experimental results indicate that HPCF can effectively improve sweep efficiency and oil displacement efficiency in the main streamline regions; furthermore, it prolongs the time of incremental oil production. Streamline adjustment can forcibly utilize the remaining oil in the low-permeability regions at non-main streamline where water flooding and HPCF are poorly affected. The hybrid strategy can give full play to the respective strengths of each single strategy. Meanwhile, SA provides a good induction effect on HPCF, which creates an excellent opportunity for the latter to effectively displace the remaining oil in the low-permeability regions at non-main streamline over extended periods. When the SA angle is 90 degrees, the best development performance can be achieved. The affected regions of remaining oil in different strategies were proposed in this paper, which affords significant guidance for effective development of heterogeneous reservoirs.",2,2,1
Oil Recovery,Remaining Oil,Sun Zhifeng; Lin Chengyan; Du Dongxing; Bi Haisheng; Ren Huaiqiang,Application of seismic architecture interpretation in enhancing oil recovery in late development Stage-Taking meandering river reservoir in Dongying depression as an example,Meander belt; Sand body geometry; Coaxial morphology; Seismic architecture; Remaining oil distribution,BASIN; BELT; EVOLUTION; FAN,"Taking typical meandering river deposits of Ng(52+3) in the west 7th block of Gudong Oilfield as an example, the influence of point-bar-sandstone superposition structure on flooding law and remaining oil distribution is studied by means of seismic architecture interpretation under the guidance of point-bar geometry. Meanwhile, the influence of morphological parameters and lithology of lateral accretionary surfaces on remaining oil and development characteristics is discussed. The seismic waveform and amplitude of point-bar boundary sandstones are obvious when they overlap with each other. The connectivity of superimposed zones between boundary sand-bodies of point-bars is poor. The remaining oil near the superimposed zones is enriched when base-of-channel sandstone that infills abandonment (PI) and the earliest sandstone at the beginning of migration of the point bars (PI) superimposed with each other. Remaining oil is relatively not enriched when PI sandstones of point-bars are superimposed in superimposed zone. Remaining oil is relatively enriched in the upper point-bar sandstone at the superimposed zone. The effective shielding area effective distance to obstruct fluid flow of mudstone section of lateral accretionary surfaces is 50-80 m along the lateral direction of lateral-accretion surfaces, and the remaining oil is not enriched in the same point bar within the range of 50-80 m around oil and water wells. The physical property section of lateral-accretion surfaces in the middle and lower part of the surfaces has a certain blocking effect on flow and can obviously reduce the recovery degree. Seismic architectural interpretation plays an important role in predicting remaining oil enriched areas and prolonging oil field life in order to improve oil recovery.",1,1,4
Oil Recovery,Remaining Oil,"Canbolat, Serhat",Assessment of SAGD heat transfer mechanism via noncondensable gas CO-INJECTION,SAGD; Noncondensable gas; Heat transfer; Conductive heat flux; Convective heat flux; SAGP,MULTIPHASE FLOW; STEAM; EDGE; CONVECTION,"The favored process for extracting heavy oil from reservoirs using twin horizontal wells is called steam-assisted gravity drainage (SAGD). During this application, steam is injected into the reservoir from above well and when heated, heavy oil is mobilized under gravity to the producer lying below. Steam build-up inside the pay zone is called the steam chamber. The main problems facing SAGD are the thermal efficiency and the thermal conductivity of the heat flux at the uppermost part of the steam chamber. Moreover, the role of solution gas and injection of gas in SAGD steam chambers remains unclear, particularly issues involving heat transfer. The objective of the study is to analyze the variation of heat transfer behavior by conduction and convection on heavy oil production using heat fluxes via the co-injection of noncondensable gas (NCG) during SAGD. To evaluate this phenomenon, the field verified SAGD analytical model was modified and used to analyze the experimental results of steam with/without NCG addition at comparable volumetric injection ratios. The outcomes of the modified heat transfer study conducted during SAGD on co-injection of NCG showed that an adequately large concentration at the uppermost part of the chamber decreased the heat flow at the edge. Besides, conduction was the primary heat transfer method for steam injection only. In the modified model, there was no obvious convective heat transfer below 125 degrees C for steam alone and below 150 degrees C for cases with NCG addition. However, the convective heat flux was more dominant after 230 degrees C and 240 degrees C for the NCG addition to steam at 1:1.29 and 1:4.41 volumetric ratio cases respectively. For the conductive and convective heat fluxes, the modified model fit with the steam only case. However, the results of the addition of NCG to steam at both runs showed a tendency to decrease at higher temperatures. On the contrary, the interaction between NCG and steam at the edge of the chamber influences the flow of heat resulting in both a decreased transfer of heat to the overburden as well as to the sides of the depletion chamber and a low recovery mechanism that produces the steam and gas push (SAGP) mechanism.",1,1,4
Oil Recovery,Remaining Oil,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Oil Recovery,Remaining Oil,"Moussa, Tamer; Dehghanpour, Hassan; Fu, Yingkun; Ezulike, Obinna",The use of flowback data for estimating dynamic fracture volume and its correlation with completion-design parameters: Eagle Ford cases,Initial effective fracture volume; Characteristic fracture-closure rate; Multivariate analysis; Multiple linear regression analysis; Completion design parameters; Flowback data analysis,,"Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (V-ef), and 2) investigate the existence of correlations between CDPs and V-ef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume (V-efi) using harmonic-decline (HD)model. Second, we estimate the loss in V-ef (V-loss) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast V-ef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with V-efi and FCR. The developed correlation between V-efi and CDPs shows that the gross perforated interval (GPI) has the most significant effect on V-efi. The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.",1,1,1
Oil Recovery,Steam Injection,"Kim, Min; Shin, Hyundon",Numerical simulation of undulating shale breaking with steam-assisted gravity drainage (UB-SAGD) for the oil sands reservoir with a shale barrier,Shale barrier; Undulating shale breaking with steam-assisted; gravity drainage (UB-SAGD); Undulating drilling; Rotary-steerable system (RSS); Maximum NPV (M_NPV),OVER-SOLVENT INJECTION; HEAVY-OIL; RECOVERY; PERFORMANCE; PARAMETERS; WATER; INTEGRATION; BITUMEN; VAPEX; WELL,"A thick oil sands reservoir separated into two thin oil sands reservoirs by a shale barrier, particularly when the separated reservoir thickness is less than 10 m, is inefficient for economic steam-assisted gravity drainage (SAGD) applications. This paper proposes undulating shale breaking with SAGD (UB-SAGD) to develop this type of reservoir, and the trajectory of undulating drilling to break the shale was designed. In addition, sensitivity analysis was performed to evaluate the effects of the area and permeability of a breaking zone and steam injection pressure. The UB-SAGD is a novel in-situ recovery method that applies undulating drilling to break the shale in the parallel direction and the above SAGD well pairs. In addition, it adds an extra injector to facilitate thermal communication between the upper and lower parts of the shale barrier, and the steam chamber can be expanded into the upper the oil sands layer along a flow path. As the area and permeability of the breaking zone were increased, the recovery factor (RF) and maximum NPV (M_NPV) increased, and the cumulative steam-oil ratio (CSOR) decreased. A comparison of the low and high steam injection pressures revealed the M_NPV of high steam injection pressure to be higher than that of low steam injection pressure because a high injection pressure facilitates flow in a smaller area of the breaking zone. The RF and CSOR of best result were improved by 24.65% and 10.21%, respectively, compared to two well-pairs of SAGD without undulating drilling. In addition, the M_NPV of this result was $3.05 MM higher than that of two well-pairs. The UB-SAGD will be very useful for the economic development of shale interbedded oil sands reservoirs using conventional SAGD.",3,3,1
Oil Recovery,Steam Injection,"Afra, Mohammad; Peyghambarzadeh, S. M.; Shahbazi, Khalil; Tahmassebi, Narges",Experimental study of implementing nano thermal insulation coating on the steam injection tubes in enhanced oil recovery operation for reducing heat loss,Heat transfer; Steam injection; Nano thermal insulation coating; Thermal recovery; Enhanced oil recovery,,"Thermal recovery in oil fields is an effective conventional method for extracting heavy oil. Steam injection is one of the main techniques in thermal recovery. Temperature reduction of the injected steam due to heat transfer from tubes to the reservoir environment is one of the essential problems in this method. Increasing the steam temperature or injection rate to overcome this energy loss and to provide the required temperature at the tube outlet considerably enhances the steam generation costs. Furthermore, increasing the injection temperature enhances the thermal stress to injection tubes that in turn brings irreparable damages to production units like casing breakage. In this study, an experimental setup used to simulate steam injection operation in order to decrease the heat transfer coefficient and reduce heat loss to conserve the injected steam temperature. This aim ascertained by using nano coatings as thermal insulator. Two types of thermal insulators including nano silica-based and nano ceramic-based insulators used in this study. Temperature, pressure, and injection rate of steam, and type and thickness of nano thermal insulators were the operating variables. Results show that increasing the injection temperature from 119 degrees C to 145 degrees C improves the heat transfer coefficient about twofold that in turn, causes rapid reduction of temperature in injection process. It was also shown that increasing the injection rate from 2.1 g/l to 6.3 g/l inside the bare tube improves the heat transfer coefficient up to 2.5-folds. Therefore, increasing the temperature or injection rate of steam could not be the suitable solution for compensating steam heat loss. The experimental results showed that using ceramic-based and silica-based nano insulation with 5 mm thickness reduces the heat loss up to 45% and 33% for injected steam at 145 degrees C, respectively.",3,4,0
Oil Recovery,Steam Injection,"Feng, Guoqing; Li, Ying; Yang, Zhidong",Performance evaluation of nitrogen-assisted steam flooding process in heavy oil reservoir via numerical simulation,Steam flooding; Nitrogen; Orthogonal design; Numerical simulation; Optimization of injection parameters,INJECTION; RECOVERY; STIMULATION; EFFICIENCY,"In this study, numerical simulation studies have been conducted to enhance oil production in X1 heavy oil reservoir using nitrogen-assisted steam injection processes. Five types of nitrogen-assisted steam flooding methods-steam flooding, steam flooding coupled with continuous nitrogen injection, coupled with intermittent nitrogen injection, coupled with nitrogen slug injection, and nitrogen flooding-have been carried out to investigate the effect of nitrogen-assisted steam flooding method on production performance. In numerical simulation study, the STARS module is applied to implement history-matching of production data, and good agreement has been achieved. Next, the orthogonal design principle is adopted to optimize the scheme of nitrogen-assisted steam flooding. The results show that steam flooding assisted by intermittent nitrogen injection is the most suitable method. In the end, the plan of nitrogen-assisted steam flooding of X1 reservoir has been designed and the oil production rate in the next 5 years has been predicted.",2,3,6
Oil Recovery,Steam Injection,"Zheng, Yang; Lei, Guanglun; Yao, Chuanjin; Fu, Jingang; Wang, Long; Zhang, Xin; Jia, Xiaofei",A calculation model about reservoir thermal efficiency of in-situ upgrading for oil shale via steam injection,In-situ upgrading; Oil shale; Reservoir thermal efficiency; Steam injection; Kerogen pyrolysis,RANITIDINE HCL MICROSPHERES; OPTIMIZATION; DESIGN,"The reasonable determination of the reservoir thermal efficiency is essential for the successful application of thermal recovery technology in oilfield. However, in terms of the in-situ upgrading for oil shale via steam injection, there is currently no calculation model to evaluate the reservoir thermal efficiency. In this work, a calculation model was established based on the theory of steam flooding front prediction in thermal recovery, and it was validated mainly through comparing with numerical simulation results. One-quarter of a five-spot well group was applied for this simulation, the response surface analysis and sensitivity studies were performed to study the effect of various parameters on reservoir thermal efficiency. Injection rate, reservoir thickness, kerogen concentration and steam temperature all have significant effect on reservoir thermal efficiency, and there is a strong interaction between injection rate and reservoir thickness. High thermal efficiency mainly depends on increasing heat reserved in reservoir and reducing heat loss to upper and lower formations. Meanwhile, the existence of gravity override has an adverse effect on thermal efficiency. Therefore, the sensitivity studies are to explore the comprehensive influence of different parameters on above three aspects. The results show that appropriately increasing the injection rate of steam in a certain range can effective improve and stabilize the efficiency. Under the premise of well thermal insulation of the upper and lower formations, the reservoir thickness is supposed to large enough, and the reservoir with high kerogen concentration can be selected. Increasing steam temperature and reducing initial pyrolysis temperature not only can ensure the high conversion ratio of kerogen pyrolysis, but also has beneficial effect on maintaining the higher reservoir thermal efficiency. Reducing the mobility ratio of steam flooding can avoid the correction shape factor being too small, thus improving the thermal efficiency.",2,2,2
Oil Recovery,Steam Injection,"Marquez, Sharoh G.; Ghafoori, Samira; Omar, Mohamed; Almarshed, Abdullah",Delineation of most efficient recovery technique for typical heavy oil reservoir in the Middle East region through compositional simulation of temperature-dependent relative permeabilities,Heavy oil; Temperature-dependence; Relative permeabilities; Compositional simulation; Thermal simulation,,"In modelling and design of heavy oil recovery, the complex interactions between the reservoir fluid and the injected fluid fosters a need for its behavior to be captured precisely and accurately. However, determining the most influential parameters in the recovery process is of great importance. In this study, the temperature-dependence of relative permeabilities has been identified as the most potent factor in aiding the improved simulated recovery of heavy oils and is being modelled in both compositional and thermal simulation environments for comparison of their recovery effectivity. Several techniques for recovering heavy oil, such as cold production, waterflooding, solvent injection, cyclic steam injection and even hot solvent injection is modelled and ranked according to their resulting recovery factors considering that the relative permeabilities alongside its temperature-dependence are the most significant factors in moving the fluid during simulation. Pressure-Volume-Temperature (PVT) relations to describe and characterize typical heavy oil from Middle East region is utilized for the application of this study and the results showed that hot solvent injection is the most effective technique in maximizing the recovery for the model oil description.",2,2,1
Oil Recovery,Steam Injection,"Petitfrere, Martin; Nichita, Dan Vladimir; Voskov, Denis; Zaydullin, Rustem; Bogdanov, Igor",Full-EoS based thermal multiphase compositional simulation of CO2 and steam injection processes,Phase equilibrium calculations; Multiphase flash; Phase stability; Reduction; Trust-region; Convergence; Thermodynamics; SAGD; Compositional; Thermal; Simulation; Heavy oil; Steam; Injection; Steam flooding,ISOTHERMAL FLASH PROBLEM; EQUATION-OF-STATE; STABILITY ANALYSIS; PARAMETERIZATION; WATER; MIXTURES; STRATEGY; RECOVERY; FLOW,"Several compositional reservoir simulators based on equations of state (EoS) have been designed. Yet, few of them can deal with thermal processes such as steam injection and no fully compositional thermal simulation of the steam injection process has been proposed with extra-heavy oils yet. Those simulations appear essential and will offer better tools to decide whether to carry out the exploitation of a heavy oil field or not. In those processes, the accurate modelling of the water/steam phase plays an important role and accurate multiphase equilibrium calculations are necessary. Thermodynamics generate highly nonlinear problems. Besides, in reservoir simulation a huge amount of phase equilibrium calculations is required, and a single failure may cause significant error propagations leading to false solutions. This study presents several improvements leading to a more robust and efficient phase equilibrium calculation (stability and flash) program. A general multiphase flash implementing all the developed algorithms is presented and tested against experimental and literature data. It can handle any number of phases; a numerical example consists in a four-phase simulation of CO2 injection. Simulations of steam flooding are performed with highly heterogeneous reservoirs. Besides, a fully compositional simulation of the SAGD process for an extra heavy bitumen is performed, which appears to be the one of the first simulation of the kind in the literature.",2,2,0
Oil Recovery,Steam Injection,"Canbolat, Serhat",Assessment of SAGD heat transfer mechanism via noncondensable gas CO-INJECTION,SAGD; Noncondensable gas; Heat transfer; Conductive heat flux; Convective heat flux; SAGP,MULTIPHASE FLOW; STEAM; EDGE; CONVECTION,"The favored process for extracting heavy oil from reservoirs using twin horizontal wells is called steam-assisted gravity drainage (SAGD). During this application, steam is injected into the reservoir from above well and when heated, heavy oil is mobilized under gravity to the producer lying below. Steam build-up inside the pay zone is called the steam chamber. The main problems facing SAGD are the thermal efficiency and the thermal conductivity of the heat flux at the uppermost part of the steam chamber. Moreover, the role of solution gas and injection of gas in SAGD steam chambers remains unclear, particularly issues involving heat transfer. The objective of the study is to analyze the variation of heat transfer behavior by conduction and convection on heavy oil production using heat fluxes via the co-injection of noncondensable gas (NCG) during SAGD. To evaluate this phenomenon, the field verified SAGD analytical model was modified and used to analyze the experimental results of steam with/without NCG addition at comparable volumetric injection ratios. The outcomes of the modified heat transfer study conducted during SAGD on co-injection of NCG showed that an adequately large concentration at the uppermost part of the chamber decreased the heat flow at the edge. Besides, conduction was the primary heat transfer method for steam injection only. In the modified model, there was no obvious convective heat transfer below 125 degrees C for steam alone and below 150 degrees C for cases with NCG addition. However, the convective heat flux was more dominant after 230 degrees C and 240 degrees C for the NCG addition to steam at 1:1.29 and 1:4.41 volumetric ratio cases respectively. For the conductive and convective heat fluxes, the modified model fit with the steam only case. However, the results of the addition of NCG to steam at both runs showed a tendency to decrease at higher temperatures. On the contrary, the interaction between NCG and steam at the edge of the chamber influences the flow of heat resulting in both a decreased transfer of heat to the overburden as well as to the sides of the depletion chamber and a low recovery mechanism that produces the steam and gas push (SAGP) mechanism.",1,1,4
Oil Recovery,Steam Injection,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Oil Recovery,Tight Oil,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Oil Recovery,Tight Oil,"Lu, Meng; Connell, Luke Daulton; Pan, Zhejun","Wetting fluid behaviour with phase transition in geological nanopores: Liquid film, capillary condensation and evaporative flow",Nanopores; Tight rocks; Thermodynamics; Phase transition; Unconventional reservoirs,HOMOGENEOUS NUCLEATION; THERMODYNAMIC ANALYSIS; POROUS-MEDIA; SHALE; STABILITY; WALL; NANOFLUIDICS; ADSORPTION; TRANSPORT; INJECTION,"Fluid behaviour in nanoscale pores may significantly deviate from that in its bulk state, because pore-wall effects may have critical influences on fluid properties such that its behaviour becomes surface-controlled. Geologically, study of fluid flow with phase transition (condensation/evaporation) in nanoscale pores is of considerable significance in practice, as understandings of the relevant mechanisms may greatly help optimise operation conditions in field applications. Typical examples include geological disposal of contaminated wastes and recovery of resources from unconventional gas and oil reservoirs. In this text, we present a study to systematically investigate how the fluid behaviour, such as the liquid film formed on a pore-wall, the condensation/evaporation of the fluid and the evaporative flow profile in the pore, depends on the molecular/electrical surface forces and the pore-wall-curvature. Towards this we first formulated a set of extended phase equilibrium relationships following a rigorous thermodynamic procedure in which the relevant pore-wall effects are included. Then, a set of new evaporative flow equations was developed, which improves the original Mahadevan model by taking into account the pore-wall effects engaged. Several laboratory tests published in literature were employed to compare the present model with the Mahadevan model. With the results obtained we discussed the pertinent pore-wall effects on the evaporation behaviour of the water, and it was shown that for the evaporative flow process concerned, these effects are significantly important and considerable deviations would be generated without consideration of them.",3,3,4
Oil Recovery,Tight Oil,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Oil Recovery,Tight Oil,"Zhang, Chi; Tian, Ye; Shen, Yizi; Yao, Bowen; Wu, Yu-Shu",Simulation study of water cut surge after CO 2 injection in tight oil reservoirs,,HUFF-N-PUFF; COMPOSITIONAL SIMULATION; RECOVERY; PERFORMANCE; PRESSURE,,3,3,2
Oil Recovery,Tight Oil,"Su, Xin; Yue, Xiang-an",Mechanism study of the relation between the performance of CO2 immiscible flooding and rock permeability,CO2 immiscible flooding; Permeability; Mechanism; Oil recovery; Gas chromatography,ENHANCED OIL-RECOVERY; TIGHT OIL; CARBON-DIOXIDE; GAS INJECTION; RESERVOIR; PRESSURE; HETEROGENEITY; WETTABILITY; MISCIBILITY; SURFACTANT,"The CO2 immiscible flooding experiments mostly conducted on a rock with a given permeability. However, there is a need for understanding the performance of CO2 immiscible flooding and its mechanisms over a range of rock permeability for some tight or low-permeability reservoirs. In these reservoirs, permeability can significantly vary due to presence and distribution of microfractures. We examine the performance and different mechanisms of CO2 immiscible flooding over a permeability range between 0.4 and 324mD by core flood experiments and oil-gas interaction tests. The results show that owing to the high MMP of Changqing oil field (20 MPa), the CO2 flooding were all conducted at immiscible condition. The CO2 immiscible flooding efficiency inversely varies with permeability, but the trend of it is significantly different before and after a threshold permeability K-c. When the rock permeability is higher than K-c, owing to the small difference between all mechanisms, the CO2 immiscible flooding efficiency smoothly varies with permeability and their overall oil recoveries are all near 50%. However, When the rock permeability is lower than K-c, the overall oil recovery significantly increases to more than 70%, and different mechanisms also show significantly diversity. The contribution of these mechanism is: ""oil viscosity and CO2-oil IFT reduction > CO2 extraction > solution gas drive and gas expansion > the effect of pore structure > oil swelling"". Among these mechanisms, CO2-oil IFT reduction and CO2 extraction play the most important role in CO2 immiscible flooding, especially in tight or low-permeability cores.",2,2,7
Oil Recovery,Tight Oil,"Wei, Jianguang; Zhou, Xiaofeng; Zhou, Jiumu; Li, Jiangtao; Wang, Anlun",Recovery efficiency of tight oil reservoirs with different injection fluids: An experimental investigation of oil-water distribution feature,Tight oil reservoirs; Recovery efficiency; Experimental study; Well-spacing optimization,THRESHOLD PRESSURE-GRADIENT; GAS-RESERVOIRS; LOW-PERMEABILITY; FLOW MODEL; SHALE-GAS; WELLS; PERFORMANCE; DISSOLUTION,"After depletion development stage, the well-utilized approach to enhance recovery of tight oil reservoirs is fluid-injection, involving nitrogen, water, and CO2. Although a great deal of research efforts has been devoted to relevant scope, it is still challenging to identify the appropriate fluid type which can achieve favorable recovery efficiency. Also, the oil-water distribution feature in tight oil reservoirs from the microscopic view is rarely investigated, especially for that after fluid-injection. Moreover, inherent TPG (threshold pressure gradient) will make a great difference on the assignment of well-spacing, which have not well investigated. Given the current situation, this work expects to bridge up the knowledge gap. First, the original oil-water distribution feature and that after fluid-injection are revealed through laboratory experiments, in which different kinds of fluid are measured. Then, the relationship between TPG and fluid type is quantified based on another set of experiments. After that, considering the pressure distribution characteristics in whole tight oil reservoirs, the optimization plate for well-placing under different fluid types is concluded. Results show that (1) Gas-flooding shares advantages compared with water-flooding, displacement efficiency for gas-flooding is over 40% and that for waterflooding is 36% on average; (2) the main pore types initially occupied by oil consists of pore-throat, cluster, corner and intergranular, which account for 9.51%, 26.42%, 15.51%, and 13.82% respectively. And the major contributor to oil recovery comes from cluster pore-type; (3) gas-flooding approach is recommended as for the low-permeability case, and the water-flooding approach becomes favorable as for the high-permeability case.",2,2,4
Oil Recovery,Tight Oil,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Oil Recovery,Tight Oil,"Sundberg, Jonas; Feilberg, Karen L.",Characterization of heteroatom distributions in the polar fraction of North Sea oils using high-resolution mass spectrometry,Crude oil; Mass spectrometry; North sea; Geochemistry; Resins; EOR,PETROLEUM; ASPHALTENES; SEPARATION; RESINS; ADSORPTION; COMPONENTS; HPLC,"Resins are a sub-fraction of crude oil consisting of heteroatom-containing polar compounds. These species are of key importance in oil recovery, oil fluid thermodynamic properties, refining processes and for the environmental impact of petroleum production. Due to the inherent complexity of crude oil, little is known of the absolute molecular structure of these compounds. Here we show how a combination of separation science and mass spectrometry reveal the compositional space of resins isolated from Danish North Sea crudes. By employing spectral stitching mass spectrometry, we resolve over 15,000 unique peaks, an increase of 50% compared to broadband acquisition. The results indicate that the dominant component of North Sea resins are basic nitrogencontaining compounds with small to medium sized aromatic cores. Using chemometric data treatment it becomes evident that each field displays unique profiles, and that these fractions can be used for oil-oil and oil-source correlations. Further, a more detailed knowledge of their composition will allow us to gain a better understanding of the interactions between resins, hydrocarbons and reservoir rock material. Improved understanding of rock-fluid and fluid-fluid interactions is key for development and understanding of improved recovery mechanisms for tight chalk reservoirs.",2,2,2
Oil Recovery,Foam,"Soulat, A.; Douarche, F.; Flauraud, E.",A modified well index to account for shear-thinning behaviour in foam EOR simulation,Multiphase flow; Porous media; Foam; Shear-thinning; Injectivity; Well index; Enhanced oil recovery; Upscaling,STEADY-STATE; INJECTIVITY; MODEL; GAS,"An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shear-thinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements. We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on coarser grids when compared to a sufficiently refined reference grid. In order to correct these errors we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address. This modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. Our proposed solution, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour. Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.",3,3,2
Oil Recovery,Foam,"Barrabino, Albert; Holt, Torleif; Lindeberg, Erik",Partitioning of non-ionic surfactants between CO2 and brine,Mobility control of CO2; Foam; Enhanced oil recovery; Aquifer storage; Surfactant partitioning,,"The partitioning of non-ionic surfactants in a CO2/synthetic brine system was studied for a selection of surfactants at reservoir conditions for CO2 enhanced oil recovery and aquifer storage. Alkyl and alkylphenol ethoxylates with different degrees of branching in their hydrophobic moiety were chosen. Generally, higher temperature and pressure promoted increased solubility in CO2. Branching of the hydrophobic moiety tends to favour CO2 solubility (higher partition coefficient). Highly branched moieties were found to hinder solubility probably due to a decrease of their conformational entropy. The addition of an aromatic ring connecting the ethoxylate moiety and the hydrophobic moiety seemed to have an adverse effect at lower temperatures. For two surfactants, the effect of concentration on partitioning was also studied. The partition coefficient decreased for increasing concentrations until a plateau was reached above the corresponding surfactant critical micelle concentration (CMC). This may indicate micelle formation both in the CO2 and in the aqueous phase.",3,4,1
Oil Recovery,Foam,"Bouquet, Sarah; Douarche, Frederic; Roggero, Frederic; Bourbiaux, Bernard",Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization,Enhanced oil recovery; Naturally fractured reservoir; Oil-wet; Foam; Multiphase flow; Capillary pressure; Interfacial tension; Reservoir simulation; Mobility reduction; Dual-medium; Viscous forces,SIMULATION,"In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction. Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale. This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals. This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ""low-IFT"" effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.",3,3,0
Oil Recovery,Foam,"Sie, Chao-Yu; Nguyen, Quoc P.",A pore-scale experimental study of non-aqueous foam for improving hydrocarbon miscible flooding,Non-aqueous foam; Hydrocarbon soluble foaming surfactants; Natural gas liquids flooding; Sweep efficiency; Conformance control; Microfluidics,VISCOUS OIL-RECOVERY; FRACTURED RESERVOIRS; SOLVENT INJECTION; FLOW; DISPLACEMENT; SOLUBILITY; GENERATION; DEPOSITION; MOBILITY,"Mobility control in hydrocarbon miscible flooding is crucial for commercial vitality where severe reservoir heterogeneity causes poor sweep efficiency. This study introduced a new concept of non-aqueous foam-assisted hydrocarbon miscible flooding in water-sensitive oil formations. This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and a raw mixture of NGLs (MNGLs) with a foaming additive to improve displacement and sweep efficiency. Foaming a light hydrocarbon liquid and the impact of non-aqueous foam on miscible displacement are the main focuses of this study. n-Pentane was used as a MNGLs (solvent) model for foam stability tests. Transient foam propagation and rheology were directly visualized and characterized based on the apparent gas (nitrogen) viscosity associated with foam texture and fluid saturations. Oil recovery factors were directly related to different degrees of in-situ foaming. For the injection of a solvent slug followed by a gas drive, the displacement of oil became unstable as nitrogen fingered through the solvent-oil mixing zone, resulting in a high residual liquid saturation. However, gas fingering was significantly hindered as the solvent was injected with a foaming agent. Dynamic fluid distribution indicate that the improved oil recovery could be attributed to the propagation of foam in the swept zone, which provided essential flow resistance for better displacement stability. To investigate the effect of initial gas saturation in the reservoir on flow behavior, a slug of gas was injected before solvent injection. Delayed solvent breakthrough and better sweep efficiency were observed in the presence of foam due to the reduced liquid phase mobility in preferential flow paths and the diversion of solvent into small pores by the trapped gas at the displacing front. Furthermore, it was possible to obtain stable foam flow with an apparent viscosity of 20 times greater than the solvent viscosity.",2,2,6
Oil Recovery,Foam,"Qu, Ming; Hou, Jirui; Liang, Tuo; Raj, Infant; Yang, Yulong; Qi, Pengpeng","Synthesis of alpha-starch based nanogel particles and its application for long-term stabilizing foam in high-salinity, high-temperature and crude oil environment",Nanogel particle; Foam stability; Viscoelasticity; High temperature tolerance; High salinity tolerance; Crude oil tolerance,RECOVERY; MIXTURES; FLUID; WATER; CO2,"Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using a-starch, acrylamide, N,N'-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T-90 as indicators at temperature of 30-120 degrees C, salinity of 0-240 g/L and oil percentage of 0-50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery.",2,2,3
Oil Recovery,Foam,"Liu, Huiqing; Wang, Yanwei; Zheng, Aiping; Sun, Xinge; Dong, Xiaohu; Li, Dandan; Zhang, Qichen",Experimental investigation on improving steam sweep efficiency by novel particles in heavy oil reservoirs,,DEPTH PROFILE CONTROL; HIGH-TEMPERATURE; EXPANDABLE GRAPHITE; FLAME-RETARDANT; FOAM STABILITY; WATER-SHUTOFF; RECOVERY; SOLVENT; PERMEABILITY; MODEL,,2,2,2
Oil Recovery,Foam,"Khoshkalam, Yegane; Khosravi, Maryam; Rostami, Behzad",Role of viscous cross-flow and emulsification in recovery of bypassed oil during foam injection in a microfluidic matrix-fracture system,Enhanced oil recovery; Viscous cross-flow; Emulsion; Foam injection; Foam generation mechanisms; Fractured reservoirs,POROUS-MEDIA; SNAP-OFF; MOBILITY CONTROL; GENERATION; DISPLACEMENT; GLASS,"Role of viscous cross-flow and emulsification on foam displacement process, has been experimentally studied in a microfluidic device (consists of homogeneous matrix pattern and a fracture in one side) by changing the injectant type (gas/foam/aqueous solution of surfactant/water) and foam quality and presence of connate water. Two distinct regions have been identified during foam displacement: 1) A dynamic region where gas and foam saturation is low and it mostly consists of aqueous phase. Emulsions of oil phase is generated at the front of dynamic region. 2) A static region where foam saturation is high and fluids' mobility is low. The discussion has been also supported by analysis of calculated oil recovery variation versus foam quality with a bell-shaped trend, matched with foam rheology reported in standard quality scan tests. Foam injection tests and gas injection ones as the case of no viscous cross-flow have been contrasted and the results confirmed the proposed role of viscous drives. Proper condition of emulsification has been discussed in foam injection tests and it has been shown that lack of such conditions in surfactant injection leads to weak emulsification. Moreover, foam generation mechanisms which have been observed during the experiments are snap-off and pinch-off.",1,1,1
Oil Recovery,Degrees C.,"Afra, Mohammad; Peyghambarzadeh, S. M.; Shahbazi, Khalil; Tahmassebi, Narges",Experimental study of implementing nano thermal insulation coating on the steam injection tubes in enhanced oil recovery operation for reducing heat loss,Heat transfer; Steam injection; Nano thermal insulation coating; Thermal recovery; Enhanced oil recovery,,"Thermal recovery in oil fields is an effective conventional method for extracting heavy oil. Steam injection is one of the main techniques in thermal recovery. Temperature reduction of the injected steam due to heat transfer from tubes to the reservoir environment is one of the essential problems in this method. Increasing the steam temperature or injection rate to overcome this energy loss and to provide the required temperature at the tube outlet considerably enhances the steam generation costs. Furthermore, increasing the injection temperature enhances the thermal stress to injection tubes that in turn brings irreparable damages to production units like casing breakage. In this study, an experimental setup used to simulate steam injection operation in order to decrease the heat transfer coefficient and reduce heat loss to conserve the injected steam temperature. This aim ascertained by using nano coatings as thermal insulator. Two types of thermal insulators including nano silica-based and nano ceramic-based insulators used in this study. Temperature, pressure, and injection rate of steam, and type and thickness of nano thermal insulators were the operating variables. Results show that increasing the injection temperature from 119 degrees C to 145 degrees C improves the heat transfer coefficient about twofold that in turn, causes rapid reduction of temperature in injection process. It was also shown that increasing the injection rate from 2.1 g/l to 6.3 g/l inside the bare tube improves the heat transfer coefficient up to 2.5-folds. Therefore, increasing the temperature or injection rate of steam could not be the suitable solution for compensating steam heat loss. The experimental results showed that using ceramic-based and silica-based nano insulation with 5 mm thickness reduces the heat loss up to 45% and 33% for injected steam at 145 degrees C, respectively.",3,4,0
Oil Recovery,Degrees C.,"Qu, Ming; Hou, Jirui; Liang, Tuo; Raj, Infant; Yang, Yulong; Qi, Pengpeng","Synthesis of alpha-starch based nanogel particles and its application for long-term stabilizing foam in high-salinity, high-temperature and crude oil environment",Nanogel particle; Foam stability; Viscoelasticity; High temperature tolerance; High salinity tolerance; Crude oil tolerance,RECOVERY; MIXTURES; FLUID; WATER; CO2,"Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using a-starch, acrylamide, N,N'-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T-90 as indicators at temperature of 30-120 degrees C, salinity of 0-240 g/L and oil percentage of 0-50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery.",2,2,3
Oil Recovery,Degrees C.,"Khalid, Mozamil; Sultan, Abdullah; Noui-Mehidi, Mohamed Nabil; Al-Sarkhi, Abdelsalam; Salim, Omer",Effect of Nano-Clay Cloisite 20A on water-in-oil stable emulsion flow at different temperatures,Water-in-oil; Emulsion; Nano-Clay; Pressure drop reduction; Stable-emulsion,CRUDE-OIL; SALINITY; BEHAVIOR,"In Enhanced Oil Recovery (EOR) operations, water-in-oil emulsions are often used to ensure good sweep of the crude in the flooding process. Dispersions of 70% water in 30% oil (diesel) were extensively used to move the crude in the porous medium with good results. The present paper is concerned with a study on the influence of Cloisite 20A Nano-Clay particles particularly on the hydrodynamic performance and the stability of water-in-oil emulsions at different temperatures between 25 degrees C and 45 degrees C. The experimental results showed that the presence of Cloisite 20A stabilized the water-in-oil emulsions compared to the dispersion without Nano-Clay. It was found that the Nano-Clay concentration affects the emulsion viscosity depending on mainly the water volume fractions. In general, small quantities of the Nano-Clay reduce emulsion viscosity, while higher concentrations of the Nano-Clay resulted in a clear increase of the emulsion viscosity. The results also revealed the percentage of pressure drop reduction at different temperatures as a function of the concentration of Nano-clays, oil/water ratios and emulsion flowrates. The influence of fluid temperature on pressure drop reduction is higher than the influence of Nano-Clay concentration especially at low flowrate.",2,2,2
Oil Recovery,Degrees C.,"Canbolat, Serhat",Assessment of SAGD heat transfer mechanism via noncondensable gas CO-INJECTION,SAGD; Noncondensable gas; Heat transfer; Conductive heat flux; Convective heat flux; SAGP,MULTIPHASE FLOW; STEAM; EDGE; CONVECTION,"The favored process for extracting heavy oil from reservoirs using twin horizontal wells is called steam-assisted gravity drainage (SAGD). During this application, steam is injected into the reservoir from above well and when heated, heavy oil is mobilized under gravity to the producer lying below. Steam build-up inside the pay zone is called the steam chamber. The main problems facing SAGD are the thermal efficiency and the thermal conductivity of the heat flux at the uppermost part of the steam chamber. Moreover, the role of solution gas and injection of gas in SAGD steam chambers remains unclear, particularly issues involving heat transfer. The objective of the study is to analyze the variation of heat transfer behavior by conduction and convection on heavy oil production using heat fluxes via the co-injection of noncondensable gas (NCG) during SAGD. To evaluate this phenomenon, the field verified SAGD analytical model was modified and used to analyze the experimental results of steam with/without NCG addition at comparable volumetric injection ratios. The outcomes of the modified heat transfer study conducted during SAGD on co-injection of NCG showed that an adequately large concentration at the uppermost part of the chamber decreased the heat flow at the edge. Besides, conduction was the primary heat transfer method for steam injection only. In the modified model, there was no obvious convective heat transfer below 125 degrees C for steam alone and below 150 degrees C for cases with NCG addition. However, the convective heat flux was more dominant after 230 degrees C and 240 degrees C for the NCG addition to steam at 1:1.29 and 1:4.41 volumetric ratio cases respectively. For the conductive and convective heat fluxes, the modified model fit with the steam only case. However, the results of the addition of NCG to steam at both runs showed a tendency to decrease at higher temperatures. On the contrary, the interaction between NCG and steam at the edge of the chamber influences the flow of heat resulting in both a decreased transfer of heat to the overburden as well as to the sides of the depletion chamber and a low recovery mechanism that produces the steam and gas push (SAGP) mechanism.",1,1,4
Oil Recovery,Degrees C.,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Oil Recovery,Degrees C.,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Oil Recovery,Degrees C.,"Facanha, J. M. F.; Maqueira, L.; Souza, A. V. O.; Moura, P. G.; Perez-Gramatges, A.",Conservative tracer tests in sandstones and carbonates using a cost-effective fluorescence method,Conservative tracer tests; Swept pore volume; Lithium detection; Fluorescence; Breakthrough curve,SPECTROPHOTOMETRIC DETERMINATION; ION-EXCHANGE; OIL-RECOVERY; LITHIUM; QUINIZARIN; EXTRACTION; TEMPERATURE; SALINITY; FLUIDS,"The use of inorganic ions as conservative tracers in porous media is limited by the need of complex and expensive analytical techniques, such as inductively coupled plasma (ICP), for tracer quantification. In this work, a cost-effective and straightforward in-house method was developed using fluorescence spectroscopy to quantify lithium in a high salinity brine, based on the formation of a complex with quinizarin (Li-Q). The method was adjusted to minimize interferences from Ca2+ and Mg2+ ions in the effluent, and to avoid extensive dilution steps in the quantification procedure. This approach yielded a sub-millimolar detection limit (8.2 x 10(-5) mol L-1) in the conservative tracer tests performed using four different rock samples, namely two sandstone and two carbonate cores, at 13.8 MPa and 20 degrees C. The breakthrough/elution curves obtained for Berea sandstones showed distinct characteristics of homogeneous rocks, such as the sharp increase in lithium concentration, in contrast with the sluggish profile observed for more heterogeneous Indiana limestones. Moreover, the sensitivity of the method allowed to calculate the swept volumes for both cores, which resembled the rock pore volumes measured with nitrogen gas. These results compared well with those obtained using ICP-OES as a reference method (>95% agreement), which demonstrated that the proposed Li-Q fluorescence method can be used as an efficient alternative method to quantify lithium in conservative tracer tests for coreflood studies, significantly reducing time and cost of analysis, with potential to be used for field applications.",1,1,1
Oil Recovery,Conformance Control,"Aguiar, Kelly L. N. P.; Pereira, Kaique A. B.; Mendes, Matheus S. L.; Pedroni, Lucas G.; Oliveira, Priscila F.; Mansur, Claudia R. E.",Study of the modification of bentonite for the formation of nanocomposite hydrogels with potential applicability in conformance control,Bentonite; Chemical modification; Organophilic clay; Hydrogel nanocomposite; Conformance control,PREFORMED PARTICLE GELS; ENHANCED OIL-RECOVERY; SWELLING BEHAVIOR; MONTMORILLONITE; SURFACTANT; ORGANOCLAYS; ADSORPTION; POLYMERIZATION,"In this work, the structure of bentonite clay was modified by ion exchange mechanism using 30%, 60% and 100% of its cation exchange capacity (CEC) with the surfactants hexadecyltrimethylammonium bromide, tetramethylammonium bromide, and trimethylphenylammonium bromide. The organically modified clay samples were characterized by Fourier-transform infrared spectrometry (FTIR), thermogravimetric analysis (TGA), X-ray diffraction (XRD), scanning electron microscopy (SEM) and energy-dispersive X-ray spectroscopy (EDX). The clays modified with hexadecyltrimethylammonium bromide presented the best results and were used for the formation of nanocomposite hydrogels and the systems were characterized by FTIR, TGA, SEM and rheological analysis. Thus, it was observed that the systems produced with 100% hexadecyltrimethylammonium bromide modified clay presented better properties and nanofiller showed better reinforcement capacity due to the greater interaction between the organophilic clay and the polymeric matrix.",3,3,1
Oil Recovery,Conformance Control,"Sie, Chao-Yu; Nguyen, Quoc P.",A pore-scale experimental study of non-aqueous foam for improving hydrocarbon miscible flooding,Non-aqueous foam; Hydrocarbon soluble foaming surfactants; Natural gas liquids flooding; Sweep efficiency; Conformance control; Microfluidics,VISCOUS OIL-RECOVERY; FRACTURED RESERVOIRS; SOLVENT INJECTION; FLOW; DISPLACEMENT; SOLUBILITY; GENERATION; DEPOSITION; MOBILITY,"Mobility control in hydrocarbon miscible flooding is crucial for commercial vitality where severe reservoir heterogeneity causes poor sweep efficiency. This study introduced a new concept of non-aqueous foam-assisted hydrocarbon miscible flooding in water-sensitive oil formations. This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and a raw mixture of NGLs (MNGLs) with a foaming additive to improve displacement and sweep efficiency. Foaming a light hydrocarbon liquid and the impact of non-aqueous foam on miscible displacement are the main focuses of this study. n-Pentane was used as a MNGLs (solvent) model for foam stability tests. Transient foam propagation and rheology were directly visualized and characterized based on the apparent gas (nitrogen) viscosity associated with foam texture and fluid saturations. Oil recovery factors were directly related to different degrees of in-situ foaming. For the injection of a solvent slug followed by a gas drive, the displacement of oil became unstable as nitrogen fingered through the solvent-oil mixing zone, resulting in a high residual liquid saturation. However, gas fingering was significantly hindered as the solvent was injected with a foaming agent. Dynamic fluid distribution indicate that the improved oil recovery could be attributed to the propagation of foam in the swept zone, which provided essential flow resistance for better displacement stability. To investigate the effect of initial gas saturation in the reservoir on flow behavior, a slug of gas was injected before solvent injection. Delayed solvent breakthrough and better sweep efficiency were observed in the presence of foam due to the reduced liquid phase mobility in preferential flow paths and the diversion of solvent into small pores by the trapped gas at the displacing front. Furthermore, it was possible to obtain stable foam flow with an apparent viscosity of 20 times greater than the solvent viscosity.",2,2,6
Oil Recovery,Conformance Control,"Zhang, Jihong; Tan, Xinjian; Zhao, Xinrui; He, Qingbin; Wang, Yanan",Experimental study of small-sized polymeric microgel (SPM) in low- or median-permeability reservoirs,Polymer microgel; Gel treatment; Conformance control; Water management; Low-permeability reservoir,PREFORMED PARTICLE GEL; CONFORMANCE CONTROL; MICROSPHERES; WATER; NANOPARTICLES; PERFORMANCE; TRANSPORT; MODEL,"Polymeric Microgel has been applied to reservoirs with varied permeability ranging from 10 to 1000 mD for mobility-control and/or conformance control. For a successful microgel treatment, the microgel particle size must be compatible with the reservoir pore-throat size to ensure effective in-depth transportation. Given such a situation, Small-sized Polymer Microgel (SPM) was developed for microgel treatment in low- and medium-permeability reservoirs. This paper presents an experimental study regarding the applicability of SPM in the low- (<100 mD) or median-permeability (100-300 mD) conditions. The experimental study involved pore-throat size determination, initial particle size distribution, swelling ratio measurements, resistance factor and residual resistance factor measurements, oil displacement experiments, and a pilot test conducted in ZT-21 producing zone located in Pubei Block 7. The result shows SPM has a good compatibility with the reservoir pore-throat size. SPM swells in water, ending up a ultimate swelling ratio of 4.8. During resistance factor and residual resistance factor measurements, SPM solution is effective at reservoir permeability of above 130 mD. That was saying, SPM is recommended to be applied in low- but not median-permeability reservoirs. In the oil displacement test, SPM improved the oil recovery through both SPM injection and post water injection at the core permeability of 95 mD, revealing SPM is available for conformance control purposes. In the pilot test, oil production improved in SPM injection and post water injection stages are 2.1 and 5.2%, respectively. The development of SPM can be contributive to oil and gas industry as it provide a guaranteed material for low-permeability reservoir microgel treatment.",2,2,4
Oil Recovery,Conformance Control,"Wu, Dejun; Zhou, Kang; Hou, Jian; An, Zhibin; Zhai, Mingkun; Liu, Wenbin",Experimental study on combining heterogeneous phase composite flooding and streamline adjustment to improve oil recovery in heterogeneous reservoirs,Heterogeneous reservoirs; Heterogeneous phase composite flooding; Streamline adjustment; Synergy mechanism; Affected regions,PREFORMED PARTICLE GEL; HYDROLYZED POLYACRYLAMIDE; ELASTIC MICROSPHERES; CONFORMANCE CONTROL; POLYMER; MECHANISM; PERMEABILITY; SYSTEM; SIZE,"The heterogeneity of reservoirs is the key factor restricting the development performance of oilfields. Heterogeneous phase composite flooding (HPCF) and streamline adjustment (SA) are both viable strategies for improving oil recovery of heterogeneous reservoirs. However, both strategies have their own deficiencies, which limits further development. In recent years, a hybrid strategy combining HPCF and SA has attracted considerable interest from oil industry. In this paper, two-dimensional (2D) large-scale physical model experiments were performed to verify whether the hybrid strategy could offer better development performance than the single strategy, and the mechanism of hybrid strategy for improving oil recovery was elucidated. On this basis, the influence of SA angle on improved development performance was investigated. Finally, the affected regions of remaining oil in different strategies were proposed. The experimental results indicate that HPCF can effectively improve sweep efficiency and oil displacement efficiency in the main streamline regions; furthermore, it prolongs the time of incremental oil production. Streamline adjustment can forcibly utilize the remaining oil in the low-permeability regions at non-main streamline where water flooding and HPCF are poorly affected. The hybrid strategy can give full play to the respective strengths of each single strategy. Meanwhile, SA provides a good induction effect on HPCF, which creates an excellent opportunity for the latter to effectively displace the remaining oil in the low-permeability regions at non-main streamline over extended periods. When the SA angle is 90 degrees, the best development performance can be achieved. The affected regions of remaining oil in different strategies were proposed in this paper, which affords significant guidance for effective development of heterogeneous reservoirs.",2,2,1
Oil Recovery,Conformance Control,"Zaberi, Husain A.; Lee, Jason J.; Enick, Robert M.; Beckman, Eric J.; Cummings, Stephen D.; Dailey, Chris; Vasilache, Mihai",An experimental feasibility study on the use of CO2-soluble polyfluoroacrylates for CO2 mobility and conformance control applications,CO2 enhanced oil recovery; Polyfluoroacrylate; Mobility control; Conformance control; Polymer adsorption,,"High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.",2,2,1
Oil Recovery,Conformance Control,"Li, Qiuyan; Yue, Xiang'an; Zhang, Lijuan; Husein, Maen",Production performance by polymer conformance control in ultra -low permeability heterogeneous sandstone reservoirs produced under their natural energy,,ENHANCED OIL-RECOVERY; CO2 INJECTION; MECHANISMS; PRESSURE; FLOODS; TIGHT; MODEL,,2,2,0
Oil Recovery,Analytical Model,"Almetwally, Ahmed G.; Jabbari, Hadi",Finite-difference simulation of coreflooding based on a reconstructed CT scan; modeling transient oscillating and pulse decay permeability experiment,Coreflooding; Static Model; Dynamic Simulation; Transient; Permeability; Image processing,ROCK SAMPLES; FLOW; PRESSURE; OIL,"Numerical simulation and experimental research of fluid flow in porous media enhance the practices of petroleum reservoirs' management. Experiments on acquired reservoir-rock samples are conducted for accurate characterization and realization of the insitu hydrocarbon reserves. Implementing precise numerical simulation of those experiments is crucial to acquire accurate conclusions from the obtained experimental results. Coreflooding experiments quantify reservoir rock's storage capacity, measure its transport connectivity, and evaluate recovery methods' effectiveness for that rock. In this paper, a reconstruction image-processing workflow of cores' CT scan is developed to build a finite difference numerical model for simulating coreflooding experiments. In a transient coreflooding experiment, a controlled pressure pulse with a known frequency and amplitude is transmitted to the rock sample. Rock permeability can be quantified by analytically solving the diffusivity flow equation for that experiment. Simulating the transient permeability experiment is very sensitive to the level of details of the pores' structure described in the numerical model. A transient permeability experiment with two different transient modes, sinusoidal oscillation, and pulse decay, was conducted on a standard Berea core sample. The Berea CT scan was image-processed to reconstruct the static porosity and permeability model in Petrel software using a 3D variogram geostatistical population. Injection and production sources were assigned to the finite gridblock, which correspond to flow nozzles of injection and production coreflooding setup's heads. Scheduled flow and controlled-pressure boundary-conditions were imposed on the dynamic model. Eclipse simulator was used to solve the dynamic model and calculate the pressure in each gridblock. The outlet pressure was calculated at each time step by three different realization approaches for porosity and permeability, i.e., from experiments, from statistical analysis for the CT scan, and by the proposed image processing workflow. The simulated outlet pressure from the prosed workflow matched ideally, with a Pearson correlation coefficient of 0.98 and 0.99, the recorded one in the two experiments compared to underestimated or overestimated outlet pressure from the other two traditional realization approaches, i.e., statistical or experimental.",3,3,2
Oil Recovery,Analytical Model,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model for gravity segregation in WAG displacement recovery of inclined stratified reservoirs,Gravity segregation; WAG; Analytical model; Inclined stratified reservoir; Numerical simulation,OIL-RECOVERY; PERFORMANCE; FLUID; FLOW,"The present study deals with the extension of Stone's model to develop the analytical model of gravity segregated length (distance travelled by injected water and gas together before the complete segregation) and gravity segregated water zone height in water-alternative-gas (WAG) displacement for inclined stratified heterogeneous reservoirs. However, as per our knowledge, until now, all available analytical models of gravity segregation in the WAG displacement process consider the assumption that the reservoir is homogeneous i.e. one-layer system with constant porosity and permeability. In reality, most of the reservoirs are heterogeneous with random variation in permeability due to the variation in the depositional environments, which have a major impact on a vertical sweep in WAG displacement. The analytical models of gravity segregation for dipping stratified heterogeneous reservoir are developed by solving the fractional flow equations of displacement of fluids through MOC (method of characteristics). Then the results of these analytical models are compared with 3D finite-difference compositional reservoir simulation. The developed analytical models give appropriately similar results as 3D finite-difference compositional model. Also, analytical model results show that the complete gravity segregated length (vertical sweep efficiency) increases with an increase in reservoir dip angle and mobility ratio, and a decrease in gravity number, vertical permeability, and horizontal permeability heterogeneity. On the other hand, the gravity segregated water zone height decreases with an increase in reservoir dip angle and gravity number.",3,3,1
Oil Recovery,Analytical Model,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Oil Recovery,Analytical Model,"Ladipo, Lekan; Blunt, Martin J.; King, Peter R.",A salinity cut-off method to control numerical dispersion in low-salinity waterflooding simulation,Low-salinity waterflooding; Numerical dispersion; Effective salinity thresholds; Physical mixing,OIL-RECOVERY; DIFFUSION; WATER; FLOW; AQUIFER; SCHEME; CHALK,"Low-salinity or controlled salinity waterflooding (LSWF) is a promising enhanced oil recovery (EOR) technique. In simulations of this process, numerical dispersion smears saturation fronts, causing errors in the results. The objective of this work is to control these effects in LSWF simulation. We examine the impact of numerical dispersion on simulated LSWF performance. The low-salinity (LS) front is smeared even at unfeasibly fine grids. The velocities of the water fronts are altered. A numerical mixed zone forms around the interface between the injected and resident brines. This mimics a typical physical mixing effect. In reservoir simulation, threshold salinities are defined where the low salinity effect (LSE) is first encountered. It has been suggested that numerical dispersion effects can be corrected by imposing effective thresholds. We demonstrate that existing methods to evaluate these effective salinities do not accurately predict the salt front movement especially when dispersion is significant. We propose a simple simulation-based approach to evaluate the effective salinities based on the conservation of volumes of the resident and injected brines in the reference and upscaled solutions. After comparing analytical and corrected coarse-grid solutions in one-dimension, the effectiveness of the approach is demonstrated in multidimensional systems. A method is proposed to control the numerical mixed zone to replicate a physical longitudinal mixing effect. This method is demonstrated in one-dimension and does not require a fine-grid numerical solution as a benchmark. We investigate the effects of effective thresholds on the modeled transverse mixing or dispersion. A method to model transverse dispersion in simulations with an effective longitudinal component is suggested. This method is extended to the explicit modeling of physical dispersion in systems with transverse flows. We can now simply evaluate the effective salinities for a simulation grid; and control its numerical dispersion effects to representative physical mixing or dispersion.",2,2,1
Oil Recovery,Analytical Model,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Oil Recovery,Analytical Model,"Canbolat, Serhat",Assessment of SAGD heat transfer mechanism via noncondensable gas CO-INJECTION,SAGD; Noncondensable gas; Heat transfer; Conductive heat flux; Convective heat flux; SAGP,MULTIPHASE FLOW; STEAM; EDGE; CONVECTION,"The favored process for extracting heavy oil from reservoirs using twin horizontal wells is called steam-assisted gravity drainage (SAGD). During this application, steam is injected into the reservoir from above well and when heated, heavy oil is mobilized under gravity to the producer lying below. Steam build-up inside the pay zone is called the steam chamber. The main problems facing SAGD are the thermal efficiency and the thermal conductivity of the heat flux at the uppermost part of the steam chamber. Moreover, the role of solution gas and injection of gas in SAGD steam chambers remains unclear, particularly issues involving heat transfer. The objective of the study is to analyze the variation of heat transfer behavior by conduction and convection on heavy oil production using heat fluxes via the co-injection of noncondensable gas (NCG) during SAGD. To evaluate this phenomenon, the field verified SAGD analytical model was modified and used to analyze the experimental results of steam with/without NCG addition at comparable volumetric injection ratios. The outcomes of the modified heat transfer study conducted during SAGD on co-injection of NCG showed that an adequately large concentration at the uppermost part of the chamber decreased the heat flow at the edge. Besides, conduction was the primary heat transfer method for steam injection only. In the modified model, there was no obvious convective heat transfer below 125 degrees C for steam alone and below 150 degrees C for cases with NCG addition. However, the convective heat flux was more dominant after 230 degrees C and 240 degrees C for the NCG addition to steam at 1:1.29 and 1:4.41 volumetric ratio cases respectively. For the conductive and convective heat fluxes, the modified model fit with the steam only case. However, the results of the addition of NCG to steam at both runs showed a tendency to decrease at higher temperatures. On the contrary, the interaction between NCG and steam at the edge of the chamber influences the flow of heat resulting in both a decreased transfer of heat to the overburden as well as to the sides of the depletion chamber and a low recovery mechanism that produces the steam and gas push (SAGP) mechanism.",1,1,4
Oil Recovery,Contact Angle,"Klimenko, Alexandra; Molinier, Valerie; Bourrel, Maurice",Mechanisms underlying the adhesion of crude oil to mineral surfaces: Relevance of oil-brine interactions,Wettability; Low salinity; Contact angle; Washburn capillary rise method; Flotation test,ORGANIC-ACIDS; CONTACT-ANGLE; WETTABILITY; WATER; RECOVERY; ADSORPTION; SANDSTONE; SALINITY; CALCITE,"The wettability state of mineral surface relative to water and oil is a key factor for crude oil recovery from reservoirs. It appears particularly relevant to EOR by low salinity brine, where change towards water wettability is often presented as a crucial factor. The purpose of this paper is to demonstrate the importance of the adsorption onto the mineral surface of species extracted from crude oils by the aqueous phase. The transfer of endogenous oil species during oil-water contact is evidenced by Total Organic Carbon, pH, interfacial tension and surface tension measurements for three different crude oils. The impact of the presence of these species on the wettability state of solid surfaces (silica and carbonate) is studied by using n-octane as a probe liquid. Contact angle measurements, Washburn capillary rise and flotation tests were carried out to evidence the hydrophobation of the surface. Interfacial tension is systematically taken into account to interpret contact angle and capillary rise results by calculating the adhesion tension, a quantity of thermodynamic significance. The effect of changes of water composition (salinity, pH) on oil adhesion is carefully investigated, and the efficiency of low salinity brine to decrease the adhesion of oil to the substrate, i.e. to remove the organic species adsorbed onto the surface, is evaluated. The importance of running wettability measurements with synthetic brine previously equilibrated with the crude oil is demonstrated.",3,3,4
Oil Recovery,Contact Angle,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Oil Recovery,Contact Angle,"Mehraban, Mohammad Fattahi; Rostami, Peyman; Afzali, Shokufe; Ahmadi, Zahra; Sharifi, Mohammad; Ayatollahi, Shahab",Brine composition effect on the oil recovery in carbonate oil reservoirs: A comprehensive experimental and CFD simulation study,Interfacial tension; Wettability; Enhanced oil recovery; Computational fluid dynamic; Spontaneous imbibition,WETTABILITY ALTERATION; NAPHTHENIC ACIDS; MASS-TRANSFER; SALINITY; WATER; PORE; IMPACT; HEAT; EMULSIFICATION; INTERFACE,"In order to understand the potential role of divalent ions involved in smart water, fluid-fluid and rock-fluid interactions are studied through contact angle and interfacial tension (IFT) measurements. Then, the suitable brines in changing contact angle and IFT are brought into measurement with spontaneous imbibition experiments to evaluate the co-impact of fluid-fluid and rock-fluid interactions. The results show the importance of SO42- ions during smart water injection as removing them from the injection water leads to a sharp drop in ultimate oil recovery. Accordingly, when the concentration of SO42- within the injection water increases four times, 10% ultimate oil recovery is recovered. Furthermore, the spontaneous imbibition measurements exhibit the higher ultimate oil recovery from the neutrally-wet core plugs more rather than the strong water-wet plugs. Further elaborating about the effect of wettability on the pore-scale displacement of oil by injection water is conducted through Computational Fluid Dynamics (CFD) modelling. The results confirm that the lowest residual oil saturation is achieved in the model with neutral wettability state as well as the highest oil recovery which is in line with the piston-like displacement in the neutral wet rock medium.",3,4,1
Oil Recovery,Contact Angle,"Yekshaveh, Jamal Salehzadeh; Jafari, Arezou; Tohidi, Zahra; Salehi, Reza Pour",Nano-scale simulation of oil-water-nanosilica-rock system: Wettability and rheological properties alteration using charged nanoparticles,Molecular dynamics simulation; Charged silica nanoparticle; Contact angle; Enhanced oil recovery,FORCE-FIELD; DETACHMENT; SURFACE,"The real mechanisms beyond the effect of nanoparticles on oil phase displacement by water are still not completely understood. So, in this research, the simultaneous effects of charge and concentration of silica nanoparticles on the oil droplet detachment from calcite surface has been investigated for the first time. For this aim, the parameters of oil droplet contact angle, oil Center Of Mass, Mean Square Displacement and viscosity of water phase have been studied by using molecular dynamics simulation. The thickness of 15 degrees A is selected for all simulations after checking the thickness effect on contact angle results. It was declared that initial shape of oil droplet affected on final contact angle slightly with the relative error of 0.7%. According to the results, silica nanoparticles can lift the oil droplet from the edges because of their interactions with rock surface and water viscosity enhancement which leads to intensify viscous forces and wettability alteration toward more water wet state. In addition, and there is an optimum concentration which decreases with nanoparticle charge rising. In neutral system, the most contact angle alteration occurs in presence of 14 nanoparticles. While the amount of optimum concentration decreased with the growth of nanoparticle's charge and reached to 4 nanoparticles at charge of 0.4 electrons. In addition, there is an optimum charge and it is 0.4e for nanoparticles. The state of rock wettability depends on nanoparticle properties such as charge, size and concentration and this lets us to design a nanoparticle with best performance and least cost.",1,1,6
Oil Recovery,Contact Angle,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Drilling,Drilling Fluid,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Drilling,Drilling Fluid,"Xu, Bingwei; Zhou, Shouwei; He, Faqi; Wang, Fubin; Guo, Jianchu",Using particle image velocimetry to evaluate the displacement efficiency of drilling mud in horizontal well cementing,Cementing; Particle image velocimetry; Eccentricity; Displacement efficiency; Horizontal wells,ANNULAR DISPLACEMENTS; COMPLETION FLUIDS; OIL-WELL; MODEL; FLOW,"For a horizontal well cementing, successful displacement of the drilling mud from the annulus using the cement slurry were paramount for achieving zonal isolation. This study evaluated the displacement efficiency of drilling mud from the annulus by applying particle image velocimetry incorporating the development of a large-scale displacement efficiency device. Displacement efficiency measurements revealed that increasing the injection displacement and reducing the eccentricity cleans up residual drilling mud and significantly improves displacement efficiency. Slurry density significantly affected displacement efficiency, because high- and lightdensity slurries were shown to lead to low velocities and to increase the boundary layer thickness of the drilling mud. High injection displacement swirling flows were found to be more effective for reducing drilling mud adhesion to the casing and wellbore walls. The eccentric annuli tended to result in a narrow channel, which results significantly reducing the displacement efficiency owed to the laminar fluid flow.",3,3,3
Drilling,Drilling Fluid,"Lichinga, Kevin Nsolloh; Maagi, Mtaki Thomas; Ntawanga, Athanas Christopher; Hao, Haiyang; Gu, Jun",A novel preflush to improve shear bond strength at cement-formation interface and zonal isolation,Cement-formation interface; Water-based mud; Filtercake; Preflush; Shear bond strength; Zonal isolation,OIL,"The effective removal of filtercake during the oil-well cementing job is of utmost importance for the reduction of well integrity problems during well drilling and production activities. Poor removal of filtercake will lead to a failure in the ability of the cement to provide zonal isolation at the cement-formation interface (CFI), during completion and for the well's lifetime. Several chemical mechanisms (chelating agents, acids, enzymes, and oxidizers) have been widely employed to remove filtercake. Nonetheless, at certain circumstances, these strategies have drawbacks that can adversely impact oil-well productivity. This research introduces a novel preflush (KV-IIA as well as KV-IIB) developed in the laboratory to transform the water-based filtercake at CFI into cement-based materials to enhance shear bonding. KV-IIA solution contained 16% CaCl2, and 1% Alkyl Polyglucoside (APG-1214), while KV-IIB fluid comprised 1% Alkyl Polyglucoside (APG-0810), 12% NaOH, 15% Na2SiO3 and water. Simulated wellbores (SWB) with porosity and permeability of 18% and 150'10(-3) mu m(2) respectively, were also used. The results showed the Reynold numbers for the preflushes KV-IIA and KV-IIB were 46,509 and 29,660 respectively. Since Reynold numbers are greater than 4000 value, the flow regime in the annulus is turbulent. The reactions among H3AlO42 and H3SiO4 from alkali-dissolved reaction, Ca2+, Na+ and H3SiO4 in the KV-II solution, and Ca2+ and OH from cement slurry form the natrolite and calcium silicate hydrate (CSH) with different silicate-calcium ratio. Based on that, the wellbore shear bond strength (SBS) and the cementing quality were improved. Analysis of the FTIR demonstrated that the CFI of the specimens tested produced additional cement binder material which resulted in increased bonding strength. The results of this work are anticipated to provide insights into the bond strengthening mechanisms in water-based mud that could help cementing specialists customize the preflushes to enhance the rock-cement bonding for better annular sealing to ensure a long-term zonal isolation.",3,3,3
Drilling,Drilling Fluid,"Wan, Yizhao; Liu, Yuewu; Wu, Nengyou",Numerical pressure transient analysis for unfilled-caved carbonate reservoirs based on Stokes-Darcy coupled theory,Carbonate reservoir; Pressure transient behavior; Stokes-Darcy coupled; Flow in porous media; Numerical simulation,TARIM BASIN; BOUNDARY-CONDITION; MODEL; FLOW; VUGGY; WELL; CAVITY,"Caved carbonate reservoirs are very special because of the strong heterogeneity. The pressure transient behavior of the caved carbonate reservoirs is quite different from the conventional homogeneous or dual medium reservoirs because of the presence of large-scale cavities. There are two types of cavities: filled and unfilled, which dominated the production of the reservoirs. Fluid flow in the unfilled cavity should be described by Stokes' equation rather than Darcy's law. It is needed to better understand the role of the unfilled cavities plays in the pressure transient analysis. The objective of this work is to analyze the pressure transient behavior of the unfilled cavities. A coupled Stokes-Darcy pressure transient model is developed and the finite element method is applied in the solutions of the mathematical models. Then, the numerical pressure transient model is used in the analysis of two typical cases: a well drilled into the unfilled cavity (WIC) and a well not drilled into the unfilled cavity (WOC). The type curves of the WIC model indicate that flow in the unfilled cavity is an oscillated pressure-drop rather than a radial flow. The unfilled cavity that the well drilled into would be considered as an enlarged wellbore which is equivalent to a negative skin factor, as a consequence the wellbore storage coefficient will increase. Main characteristics of type curves for WOC model are the valley on the pressure derivative. A cavity with a larger size and smaller distance from the wellbore would give rise to a deeper valley. Comparative results indicate that unfilled cavities described by the Stokes' equation are not the limit of the filled cavities with extremely large mobility, which was predicted by previous work.",3,3,3
Drilling,Drilling Fluid,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Drilling,Drilling Fluid,"Galvao, Mauricio S. C.; Carvalho, Marcio S.; Barreto Jr, Abelardo B.",Thermal impacts on pressure transient tests using a coupled wellbore/reservoir analytical model,Pressure transient analysis; Transient temperature data; Well testing; Wellbore thermal model,WATER GEOTHERMAL-RESERVOIRS; TEMPERATURE BEHAVIOR; DRAWDOWN,"This work investigates the impact of temperature effect on pressure-transient measurements made at any gauge location along a slanted wellbore completed with a production tubing. The analysis is based on a coupled transient-wellbore/reservoir thermal analytical model, which considers flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system. The analytical model provides temperature- and pressure-transient data for drawdown and buildup tests, accounting for Joule-Thomson, adiabatic fluid-expansion, conduction and convection effects. Regarding pressure transient analysis (PTA), thermal distorted pressure data might lead to the interpretation of false geological heterogeneities, because the transient heat loss during the buildup period provides an increase in the pressure exerted by the wellbore-fluid column and a change in the gauge location due to pipe contraction. Though some of the derived expressions are lengthy, they encompass an intrinsic simplicity in that one can compute pressure- and temperature-transient data on a spreadsheet. Analytical results are compared with those of a commercial thermal wellbore/reservoir simulator showing a good agreement. Thermal impacts on PTA interpretations are demonstrated by showing that a homogenous reservoir can be wrongly interpreted as a double-porosity system. A field case is presented, consisting of a drill stem test conducted in a multi-layered heterogeneous reservoir.",3,3,1
Drilling,Drilling Fluid,"Rocha, Robson R.; Oechsler, Bruno F.; Meleiro, Luiz A. C.; Fagundes, Flavia M.; Arouca, Fabio O.; Damasceno, Joao J. R.; Scheid, Claudia M.; Calcada, Luis A.","Settling of weighting agents in non-Newtonian fluids to off-shore drilling wells: Modeling, parameter estimation and analysis of constitutive equations",Drilling fluids; Modeling; Parameter estimation; Permeability; Effective solid pressure,BATCH SEDIMENTATION; MATHEMATICAL-MODEL; SUSPENSIONS; SIMULATION; STABILITY; BEHAVIOR; DESIGN,"High-density solids such as barite and hematite are generally added to drilling fluids to increase their density, allowing the control of subsurface pressures. However, a variety of problems in drilling wells has been related to the gravitational settling of particulate materials. In this work, the dynamic behavior of barite settling in a synthetic paraffin-based drilling fluid was evaluated experimentally by monitoring the solid concentration as a function of time and height. The tests were conducted in a gravitational settling bench-scale rig using a gamma-ray attenuation technique. Following the standard approach of continuum mechanics, a mathematical model was developed to yield a single set of partial differential equations capable of describing all settling zones inherent in a batch sedimentation process. Further, by means of the predicted solid concentration profiles, it was possible to obtain the height of bottom piled up solids. The mathematical model takes particles compressibility under their own weight and permeability of the sediment into consideration. The parameters of the proposed constitutive equations for the effective pressure on solids and porous matrix permeability were estimated and statistically analyzed from the experimental profiles of solid concentration. In particular, the results obtained in this work indicated a good agreement between the model predictions and the experimental data.",3,4,0
Drilling,Drilling Fluid,"Ge, Dong; Peng, Jianming; Li, Keke; Huang, Chaoyang; Lian, Moke; Yang, Zhenglong",Influence of water-based drilling fluids on the performance of the fluidic down-the-hole hammer,Fluidic DTH hammer; Percussion drilling; Output power; Motion characteristic; Pressure drop; Water-based drilling fluids,,"Fluidic down-the-hole (DTH) hammer is a recently explored percussion drilling tool for the production of boreholes in hard rock. It has been proven efficient for exploration core drilling, geothermal drilling, and oil and gas drilling. Previous studies of this hammer have concentrated on its performance operating with clear water rather than water-based drilling fluids with additives. As the first step to filling the gap of knowledge in this area, this study was designed to explore only the performance of an SC86-H fluidic DTH hammer driven by water-based drilling fluids with various temperatures and different contents of bentonite and barite. Such performance was characterized in terms of output power, motion characteristic and operating pressure drop, and compared with that driven by water. The results showed that the output power of the SC86-H type hammer driven by drilling fluids with bentonite content <3% was better than that driven by water thanks to the lubrication effect in the fit clearance, whereas with bentonite content >= 3%, its output power was in the range or below that driven by water due to the elevation of the hydraulic losses and the frictional drag. Its operating pressure drop is only insignificantly influenced by the bentonite content. As the weighting agents in the drilling fluids, the barite particles impeded the smooth motion of the piston. However, the increased impact energy and output power can entirely offset the disadvantage mentioned above. Temperature affects the performance of the SC86-H type hammer by influencing the viscosity and density of the drilling fluids. Some optimal schemes are suggested for the rational design and application of the fluidic DTH hammer in practice. In summary, the SC86-H type hammer operated well in the drilling fluids with realistic fluid power levels. It means that the fluidic DTH hammer has good adaptation and robustness, which is favorable to practical application.",2,2,9
Drilling,Drilling Fluid,"Li, Yanliang; Peng, Jianming; Zhang, Guang; Yang, Zhenglong; Li, Keke",Study on perforation performance of abrasive water jet enhanced by percussive drilling,AWJ Perforation; Percussive drilling; Perforation performance; Impact cracks,HYDRAULIC FRACTURE INITIATION; GEOTHERMAL-ENERGY; PRESSURE; TECHNOLOGY; STIMULATION; MECHANISM; IMPACT; SHALE,"Geothermal energy is abundant and has a high economic development value. Perforation would need to be utilized to establish fluid channels between the borehole and geothermal reservoirs. In the present paper, it is proposed to use percussive drilling to create impact cracks near the borehole to improve abrasive water jet (AWJ) perforation performance. Two groups of the specimen were used for experiments. One was the specimen near the borehole after conventional rotary drilling (G1), the other was the specimen near the borehole after percussive drilling (G2). The optimal parameters of AWJ perforation assisted by percussive drilling were obtained. Through evaluation of AWJ perforation performance, it was found that the perforation depth, diameter and volume of G2 were 1.5 times, 1.3 times and 2 times of the G1, respectively. Besides, there were many internal cracks in G2, which interweave with each other and form a crack network. The results indicated that the impact cracks could change the mechanical properties of the granite near the borehole, then reduce the difficulty of AWJ perforation and improve the perforation performance. All the above merits can provide important technical support for reducing the fracturing pressure, increasing fluid flow and enhancing heat exchange efficiency between geothermal reservoir and borehole.",2,2,6
Drilling,Drilling Fluid,"Liu, Keman",Model and control method of a downhole electromagnetic transmitter for EM-MWD system,Electromagnetic measurement while drilling; Single-phase inverter; Downhole electromagnetic transmitter; Model; PI regulator,CONTROL STRATEGY; SINGLE; BOREHOLE; FIELD,"Downhole electromagnetic transmitter is an important part of EM-MWD system, which can send low-frequency EM waves data from a downhole tool to surface in real time for oil and gas exploration. In order to reduce the volume and weight of the downhole electromagnetic transmitter and improve the depth and accuracy of petroleum exploration, a novel downhole electromagnetic transmitter topology for electromagnetic MWD system is designed. Aiming at the complex and changeable characteristics of load impedance of transmitter, an equivalent load model for downhole electromagnetic transmitter is established with drill string, casing, drill-bit, drilling fluid and formation being taken into account. Because the attenuation characteristic of electromagnetic signal in the wellbore is similar to that of capacitor discharge, the characteristic of electromagnetic channel can be equivalent to the combination of capacitance and resistance. Then, in order to ensure that the downhole electromagnetic transmitter will produce the nominal load voltage, irrespective of disturbances such as variations in the lithium batteries voltage, perturbations in the switching times, and the load, a dual-loop real-time feedback control scheme with an outer voltage loop and an inner current loop is proposed. Simulation and experimental results with laboratory prototype demonstrate the effectiveness of the control method for downhole electromagnetic transmitter. It also ensures the downhole electromagnetic transmitter's excellent stability and the accuracy of the established equivalent load model as well as its ability to meet the requirements of practical field deep exploration. The findings of our work can help for better understanding of approximate load model of downhole electromagnetic transmitter. Furthermore, it will be of great significance for designing control algorithm of downhole electromagnetic transmitter for different areas or boreholes, achieving the purpose of increasing transmission depth. The research results can be used to improve the design and optimization of electromagnetic MWD measurement system in the aspects of improving the control accuracy of the transmitter, saving energy and increasing the transmission depth.",2,3,5
Drilling,Drilling Fluid,"Chen, Pengju; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, Evren",Poroelastic modeling of cutting bottom-hole rock - Part I: Stress state of bottom-hole rock,Far field in-situ stresses; Cutting rock; Poroelasticity; Directional drilling; Bottom-hole rock; MSE,,"This is the first part of a series of two papers modeling cutting bottom-hole rock during drilling. This paper studies the stress state of a bottom-hole rock that a downhole bit is drilling. A bottom-hole rock underground is subjected to far field in-situ stresses. During drilling process, the rock materials above the bottom-hole rock are gradually removed and replaced with drilling fluid, thus altering the stress state of the bottom-hole rock. In this paper, a model is developed based on the theory of Linear Poroelasticity to calculate the evolution of stresses and pore pressure in a bottom-hole rock during drilling process. The bottom-hole rock under consideration can be selected at any depth underground. To solve the model, superposition principle and finite difference method are employed. The model is also extended for inclined wellbores in arbitrary directions. A series of case studies with various drilling parameters in different formations are presented. The results show that during drilling bottom-hole rock will expand, leading to the pore pressure decrease if formation has a low permeability. The pore pressure decrease in a bottom-hole rock will increase differential pressure, eventually increasing difficulties in drilling. The results show that low permeability formation drilled with a greater rate of penetration will lead to a lower pore pressure in a bottom-hole rock. Moreover, during air drilling in hard formation, the pore pressure decreases significantly in bottom-hole rock.",2,2,2
Drilling,Drilling Fluid,"Merey, Sukru",Geomechanical wellbore stability analysis for the wells drilled in the shallow sediments of the Mediterranean Sea,Wellbore stability; Hoop stress; Reservoir geomechanics; Gas hydrates; Mediterranean sea,NATURAL-GAS; HYDRATE; ORIENTATION; MAGNITUDE; FAILURE; ENERGY; BASIN; AREA; LOGS,"Gas hydrates are considered as near-future energy resources in the world. Due to high gas hydrate potential of the Mediterranean Sea, gas hydrate exploration wells are expected to be drilled. In this study, for the first time, the caliper logs of the wells drilled during ODP (Ocean Drilling Program) Leg 160 and ODP Leg 161 in the Eastern and Western Mediterranean Sea were evaluated together with the python codes predicting wellbore stresses, unconfined compressive strength (C-o) and lower-hemisphere projection. The required C-o in the Eastern Mediterranean Sea ranges from 60 psia to 2250 psia from seafloor to target depth. However, the estimated C-o of the sediments in the Eastern Mediterranean in this study by using the python codes developed in this study and the caliper logs of ODP Leg 160 ranges from 15 psia to 1250 psia with depth. Similarly, the required C-o to keep the wells in gauge and the estimated C-o of the sediments in ODP Leg 161 range between 100-12000 psi and 30-11000 psia, respectively. Mostly, C-o values of the sediments were less than the required C-o values for stable wellbore so extensive washouts were detected both in the wells of ODP Leg 160 and Leg 161. This is because the sediments within gas hydrate stability zone in the Mediterranean Sea are weak and almost unconsolidated. Moreover, in this study, it was shown that it is possible to reduce the degree of washouts by increasing the density of drilling fluid until fracture pressure. According to the estimations in this study, the wellbore enlargements for the wells in ODP Leg 160 and ODP Leg 161 were mostly reduced below 2 inches, below which better wellbore stability conditions, better well log data and better casing cement quality might be obtained.",2,2,2
Drilling,Drilling Fluid,"Hosseini-Kaldozakh, Seyed Arman; Khamehchi, Ehsan; Dabir, Bahram; Alizadeh, Ali; Mansouri, Zohreh",Rock wettability effect on Colloidal Gas Aphron invasion near wellbore region,Colloidal Gas Aphron drilling fluid; Formation damage; Wettability; Pore blocking,ENHANCED OIL-RECOVERY; DRILLING-FLUID; FORMATION DAMAGE; LIQUID DRAINAGE; POROUS-MEDIUM; STABILITY; TEMPERATURE,"Colloidal Gas Aphron drilling fluid is colloidal dispersions of gas microbubbles, which are designed to reduce the loss of circulation in depleted reservoirs. This fluid creates a robust and elastic micro-bubble network, to block the pores of the formation and minimize filtration loss. In this study, Xanthan Gum (XG) polymer and Sodium Dodecyl Benzene Sulphonate (SDBS) surfactant were the primary materials utilized to generate a water-based Colloidal Gas Aphron drilling fluid. A dynamic and static invasion of prepared Aphron drilling fluid in carbonate rock with different wettabilities was investigated. Moreover, the formation damage induced by the invasion of Aphron fluid to porous media was also studied. Results demonstrated that wettability alteration of a water-wet porous media to oil-wet lead to an increment of differential pressure throughout porous media during Aphron drilling fluid invasion. A significant influence of wettability was also observed on return permeability of carbonate rock. A reduction of 73.53% of carbonate rock permeability was observed in oil-wet core invaded by water-based Aphron drilling fluid.",2,2,2
Drilling,Drilling Fluid,"Okesanya, Temi; Abdukarimov, Aibek; Kuru, Ergun",Generalized models for predicting the drag coefficient and settling velocity of rigid spheres in viscoelastic and viscoinelastic power-law fluids,Settling velocity; Elasticity; Non-Newtonian fluids; Particle Transport; Modeling,SPHERICAL-PARTICLES; DRILLING-FLUIDS; BED EXPANSION; ELASTICITY; CUTTINGS; FALL; FLOW,"The design and optimization of several fluid-particle transport systems often require the determination of particle settling velocity in non-Newtonian fluids. These fluid-particle transport systems are encountered in a wide variety of industrial processes including drill cuttings transport in oil and gas well drilling operations and proppant transport in hydraulic fracturing operations. Current conventional approaches to estimate settling velocity in these non-Newtonian fluids often exclude the effect of elasticity on particle settling which can lead to erroneous estimation. It is therefore imperative to devise an accurate means to mathematically account for the fluid elasticity in particle settling in viscoelastic fluids. An experimental study was conducted to measure the settling velocity of spherical particles in viscoelastic and viscoinelastic power-law type fluids. Using a semi-mechanistic approach, explicit mathematical models were developed for estimating drag coefficient and particle settling velocity in viscoelastic fluids and viscoinelastic fluids. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoelastic and viscoinelastic power-law type fluids intended at augmenting the present corpus of experimental data in literature. ii.) To develop new drag coefficient and particle Reynolds number correlations that are applicable to viscoelastic and viscoinelastic power-law type fluids and, iii.) To present a general explicit approach for predicting settling velocities of particles in viscoelastic and viscoinelastic fluids. Particle Image Shadowgraphy (PIS) was used to measure the settling velocities of the spherical particles (Specific gravity 2.5-7.7; Diameters: 0.71-4.00 mm) in Hydrolyzed Polyacrylamide and Tylose solutions of varying elastic properties. Rheological characterization of the fluids was carried out using the C-VOR Bohlin Rheometer. Experimental results from this study were combined with various data published in the literature to create an extensive database and widen the scope for empirical analysis. The database had a consistency index (k) range of 0.012-6.773 Pa.s(n) and a fluid behavior index (n) range of 0.370-0.940. New drag coefficient and Reynold number correlations for particles settling in viscoelastic and viscoinelastic power-law fluids were developed by using a semi-mechanistic approach, which also included the fluid elasticity effect quantified in terms of the longest relaxation time. The newly developed correlations and an advanced statistical modeling program (OriginPro 9.0) were used to mathematically create explicit models that can be used for predicting particle settling velocity in viscoelastic and viscoinelastic fluids. Comparative analysis showed that an increase in the fluid elasticity gave a corresponding decrease in the particle Reynolds number and dampened the particle settling velocity in viscoelastic fluids. This dampening effect can be attributed to the unique ability of elastic fluids to partially or fully regain their original structure after deformation. Furthermore, statistical analysis showed that the presented new models predict settling velocity accurately with a very low with a Percentage Mean Absolute Error of about 7.5% and 30% for viscoinelastic and viscoelastic fluids respectively. The proposed models also exhibited Root Mean Square Error (RMSE) values of 0.04 m/s and 0.009 m/s for viscoinelastic and viscoinelastic fluids respectively.",2,2,1
Drilling,Drilling Fluid,"Chen, Jingkai; Zhang, Yanting; Zheng, Zhibin; Liu, Zhendong; Huang, Lumeng",Dynamic analysis of top-excited vibration assisted stuck release in vertical borehole with fatigue-like model,Stuck pipe; Axial vibration; Shear stress distribution; Fatigue-like release model,STICK-SLIP VIBRATIONS; TORSIONAL VIBRATION; ROCK JOINTS; STABILITY ANALYSIS; SHEAR MECHANISM; ROOT CAUSE; DRILL; FRICTION; PERFORMANCE; BEHAVIORS,"Stuck release operation is one of the largest contributions for the increase of non-productive time and consequently the increase of the well cost. Traditional stuck release operations including the jarring operations, changing flow rate, varying mud density are expensive and time-consuming. Recently, a surface vibration apparatus is introduced to the drilling industry and the stuck release time is highly reduced with this new apparatus. In this paper, a fatigue-like stuck release model is introduced to analyze the release mechanism of the stuck pipe excited by the vibration agitator. First, the drill string vibration behavior subjected to surface vibration agitator is analyzed. The natural frequencies and mode shapes are calculated analytically. The damping effect of drill mud is intensively investigated by assuming the laminar flow and Newtonian fluid. Second, the shear stress distribution on the stuck section is proposed analytically and verified with numerical examples. The influence of the shear parameter on the shear stress distribution is discussed and calibrated for certain configuration. Third, the stuck release behavior subjected to cyclic load is modeled with fatigue-like model, which is characterized by the formation release strength and stress factor. The stuck release process is progressive and three stuck release stages are identified. Finally, the top-excited drill string vibration is coupled with the release process on the stuck section. The top-excited vibration assisted stuck release system is modeled numerically. The stuck release processes operated at different resonant excitations are discussed. This paper casts light on the theoretical explanation of the vibration assisted stuck release mechanism and is important in optimizing the stuck release operations.",2,3,1
Drilling,Drilling Fluid,"Wang, Xianglei; Liu, Xiuquan; Zhang, Shenyan; Chen, Guoming; Chang, Yuanjiang",Study on mud discharge after emergency disconnection of deepwater drilling risers,Riser; Emergency disconnection; Mud discharge; CFD,FLOW; CFD; PREDICTION,"Mud is often discharged into seawater after emergency disconnection of risers in offshore oil and gas drilling engineering. The discharged mud needs to be simulated accurately since it can produce a huge load on risers. Several mud discharge models have been proposed, such as Young's slug model, SFM model, WFC model and one-dimensional finite volume model. However, the mud is taken as a one-dimensional rigid body in existing mud discharge models. As a consequence, the radial velocity of mud, the mixing interface between mud and seawater, and mud discharge in complicated riser flow channels cannot be simulated. In this paper, a more accurate and applicable three-dimensional (3D) computational fluid dynamics (CFD) model is established to simulate the mud discharge process. The proposed method is demonstrated by its application to a case. It turns out that the actual mud discharge process can be simulated based on the 3D CFD model. Characteristics of the mud discharge including the radial velocity, axial velocity and the interface between two fluids are calculated based on the 3D CFD model, which improves the understanding of the mud discharge. Besides, the applicability of each mud discharge model is determined through model comparison. The influence of key factors including drill pipes with pipe joints, riser inner diameter, mud density and mud dynamic viscosity on the mud discharge is also analyzed based on the 3D CFD model.",2,2,1
Drilling,Drilling Fluid,"Skalle, Pal; Aamodt, Agnar",Petrol 18 946: Downhole failures revealed through ontology engineering,Oil well drilling; big data; process failure and error; ontology engineering,,"Frequency of failures occurring during offshore oil-well drilling do not diminish over time, probably due to increased operational complexity. The volume and frequency of information generated during the drilling process are high. Every few seconds around 30 drilling parameters are recorded and stored. There will always be a need for new, smart solutions to drilling challenges. Present approaches to drilling challenges apply various types of knowledge generated by the operation; wellbore geometry, fluid info, lithology of the sediments, time-based drilling parameters, drilling equipment data, etc. In our research said knowledge is generalized into general concepts, and structured to form a knowledge model of the drilling process. This model is referred to as a drilling ontology, and we report how methods of knowledge modeling and ontology engineering have been used in developing the model, and subsequently how the model has been applied to predict downhole failures during drilling. The knowledge model and the drilling data are combined in the following manner: Data agents are surveilling drilling data. Deviatoric behavior of the drilling parameters are being detected and formed into symptoms. Symptoms trigger other concepts embedded in the ontology by means of linked cause-effect relationships. The end concept of the relationship path will always be one or several failure states. Tests show that reasoning within the ontology produces the highest probability of the failure identical with the real failure. The causes behind the failure can be retrieved from the ontology and applied in a useful manner in combatting the failure. The testing process also shows that this program is a potential supplement to warning against threatening failures before they occur.",2,2,0
Drilling,Drilling Fluid,"Zhang, Sen; Diao, Binbin; Gao, Deli",Numerical simulation and sensitivity analysis of accurate ranging of adjacent wells while drilling,Adjacent well; Accurate measurement; Double-layer radial medium; Magnetic field distribution; Relative positional relationship,,"Cluster well drilling technology is the key to large-scale development of unconventional oil and gas, but it is difficult to measure the distance of adjacent wells accurately by using off-the-shelf tilting tools and algorithms. Therefore, this paper proposes a novel algorithm for accurate ranging of adjacent wells while drilling. Firstly, a double-layer radial medium model, a magnetic field distribution law model and a relative position relationship model were established. Then, by solving the above model, the accumulation discipline of low-frequency current on the casing and the distribution law of the magnetic field around the casing are revealed. The calculation method of the relative position relationship is also obtained. The model is also compared with the experimental data of previous scholars to verify its effectiveness. Finally, the sensitivity analysis of the electric field strength in the radial direction, the current distribution on the casing and the magnetic field strength of the measuring point were carried out. The analysis results show that the electric field strength in the radial direction has obvious jump at the interface between the drilling fluid and the formation; the current on the casing and the distribution of the surrounding magnetic field are affected by the current intensity, the conductivity of the drilling fluid, the distance between the wells, the size of the wellbore, and the relative inclination angle of the well; in addition, in the short-distance measurement process, as the distance from electrode to probe is greater than 60 m, the relative well angle of construction well and production well should be controlled within 3 degrees to avoid collision. The research shows that the algorithm can provide theoretical basis for the high-precision measurement of clusters and infill wells.",2,3,0
Drilling,Drilling Fluid,"Nwaka, Nnamdi; Wei, Chen; Ambrus, Adrian; Chen, Yuanhang",Gas in riser: On modeling gas influxes in non-aqueous drilling fluids with time-dependent desorption considerations,Gas in riser; Time-dependent mass transfer; Non-aqueous fluids; Drift-flux model; AUSMV Scheme,DRIFT-FLUX MODEL; MASS-TRANSFER COEFFICIENTS; 2-PHASE FLOW; KICK SIMULATION; CO2 ABSORPTION; TEMPERATURE; MIGRATION,"The presence of formation gas in a marine riser above the subsea blowout preventer (SSBOP) can pose great risks to personnel, equipment, and the structural stability of the drilling rig. The offshore drilling industry has been seeking to better understand and simulate gas-in-riser events, to optimize mitigation methods and justify the adoption of new flow control equipment and techniques. This paper presents a modified multiphase model to more realistically describe gas-in-riser events by incorporating time-dependent mass transfer processes occurring in non-aqueous muds (NAMs). A hybrid advection upstream splitting scheme (AUSMV) was used as the numerical scheme. Verification of the model and the numerical scheme were performed using field data from well control events with both NAMs and water-based muds (WBMs). The role of time-dependent mass transfer played during the process, and the proper range of desorption coefficient was evaluated in the case study with NAMs. Furthermore, a comprehensive parametric study was conducted, and results show that the severity of unloading will be significantly underestimated without considering mass transfer in NAMs. Meanwhile, unloading severity can be overestimated if the desorption process is considered as instantaneous instead of time-dependent.",2,2,0
Drilling,Drilling Fluid,"He, Haikang; Sun, Baojiang; Wang, Zhiyuan; Liu, Yueliang; Sun, Xiaohui",A constitutive model for predicting the solubility of gases in water at high temperature and pressure,Solubility; Equation of state (EOS); Mixed gas; Accuracy; Single gas,VAPOR-LIQUID-EQUILIBRIA; EQUATION-OF-STATE; PHASE-EQUILIBRIA; CARBON-DIOXIDE; HYDROGEN-SULFIDE; PURE WATER; THERMODYNAMIC MODEL; LIGHT-HYDROCARBONS; MUTUAL SOLUBILITY; CO2 SOLUBILITY,"In the drilling and development of gas fields, gas exhibits good solubility in drilling fluids and in the formation water under high temperatures and pressures. Therefore, the prediction of the amount of dissolved gas in water plays a vital role in the development of natural gas. In this work, the principle of equal fugacity in a gas-liquid equilibrium, a non-iterative gas solubility prediction model was established. The gas-phase fugacity coefficient was calculated by the Peng-Robinson equation of state combined with the non-random mixing rule, and the liquid phase was calculated by Henry's law. The model can predict the solubility of CO2, CH4 and C2H6 in pure water at temperatures of 273-448 K and pressures of 0-100 MPa, with an error of less than 5.5%; however, the calculation accuracy for H2S was low. It is found that the effect of moisture in the gas phase of gas-liquid equilibrium cannot be ignored. Compared with the existing mixed gas solubility experimental data, this model could accurately calculate the solubility of non-polar mixed gases, such as CO2 + CH4, and CH4 + C2H6 mixture. For the mixtures containing a polar gas, the lower the polar gas content, the smaller was the prediction error of the model for the non-polar gas in the mixture. On the contrary, the higher the content of polar gas, the larger was the deviation in the prediction of non-polar gas in the mixture, but lower was the deviation in the prediction of polar gas. Finally, the ability of Krichevsky-Kasarnovsky equation to predict the solubility of pure gas was evaluated.",1,1,9
Drilling,Drilling Fluid,"Cui, Shuai; Liu, Houbin; Meng, Yingfeng; Fan, Yu; Wang, Jiajun; Han, Zhengbo",Study on mechanical properties and wellbore stability of deep brittle shale,Deep brittle shale; Borehole stress field; Complex loading; Surge pressure; Tensile caving; Wellbore stability,,"As the drilling depth of shale's oil and gas wells increases worldwide, the problem of borehole collapse and instability becomes increasingly serious. Due to the high content of brittle minerals in deep shale, the complex situation of an underground collapse of a site is often manifested as borehole wall caving and falling. On the basis of the deep shale of China's Longmaxi formation, we developed a simulation experiment involving the complex loading mechanics of underground working conditions. The influence of loading and unloading confining pressure speeds and the sealing properties of drilling fluid on the mechanical properties of rock were analyzed. We established the dynamic changes in borehole formation, combining seepage and pore pressure, the effective stress field around the well, and a method of evaluating wellbore stability in deep shale gas horizontal wells. The results show that the deep shale of the Longmaxi formation has a high brittle mineral content and is prone to brittle fracturing along parallel bedding surfaces under downhole pressure. The effective liquid column pressure at the bottom of the wells change noticeably under different working conditions. Changes in bottom hole fluid column pressure are the cause of the complicated situation of well leakage and overflow in the horizontal sections of the Longmaxi formation. The effective support confining pressure of borehole wall rock differs with different tripping out speeds. The faster the tripping out is, the less the support confining pressure of the wellbore rock and the easier it is to induce the rock to break down along the bedding. The effective sealing property of drilling fluid also affects wellbore stability. A good sealing property of drilling fluid can improve the supporting effect of the fluid on borehole wall rock and improve its resistance strength. On the whole, the pressure of the bottom hole liquid column is effectively controlled during drilling in the Longmaxi formation; this can avoid complicated situations such as well leakage. The results of this study provide a theoretical basis for the study of wellbore stability in deep shale formations during the drilling process.",1,1,5
Drilling,Drilling Fluid,"Krishna, Shwetank; Ridha, Syahrir; Vasant, Pandian; Ilyas, Suhaib Umer; Irawan, Sonny; Gholami, Raoof",Explicit flow velocity modelling of yield power-law fluid in concentric annulus to predict surge and swab pressure gradient for petroleum drilling applications,Couette-Poiseuille flow; Drilling; Flow velocity modelling; Yield power-law fluid; Surge/ Swab pressure,COUETTE-POISEUILLE FLOW; HERSCHEL-BULKLEY FLUIDS; LAMINAR; DISPLACEMENT; EQUATIONS; WELLS,"Exact prediction and controlling of surge/swab pressure are required during drilling of hydrocarbon reservoirs and other geological formations that often leads to well control challenges. The existing methods to predict the surge/swab pressure gradient in the wellbore are much implicitly developed, which further reduces the model accuracy. Therefore, the present research aims to develop a novel analytical model by incorporating the explicit flow velocity equations to further improve the efficiency in predicting the surge pressure gradient. The governing flow velocity equations are developed for a concentric annulus exhibiting Couette-Poiseuille flow phenomenon that subsequently used in designing a new analytical model for yield power-law fluids to predict surge pressure gradient. Detailed analysis for the validation of a newly developed model is performed using existing predictive models and experimental data of surge pressure. The statistical analysis exhibits satisfactory outcomes with a maximum error of 5.61% and R-2 of 0.988. A detailed analysis on the effect of relevant parameters on surge/swab pressure is also presented. The impact of fluid behaviour index and diameter ratio is found to be highly dependent on surge pressure under varying tripping speeds compared to other drilling parameters such as fluid yield point and consistency index.",1,1,4
Drilling,Rock,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Drilling,Rock,"Wang, Kai; Hu, Yinan; Yang, Kui; Qin, Min; Li, Yichen; Liu, Gang; Wang, Gang",Experimental evaluation of rock disintegration detection in drilling by a new acoustic sensor method,Acoustic analysis; Broken rocks; Lithological identification; Drilling,FAULT-DETECTION; VIBRATION; IDENTIFICATION; SIGNAL,"A simple and reliable method for monitoring the rock properties in drilling is recognized as a global challenge, especially for cluster and infill development well drilling in oil and gas production. To improve the existing limitations in the detection of formation lithology in drilling systems, an acoustic sensor approach for rock disintegration in the drilling using a polycrystalline diamond compact (PDC) drill bit is developed and evaluated. In this paper, we report the application of a special acoustic sensor device to qualitatively survey rock disintegration by rotary drilling. In this work, an acoustic focusing component is designed to assist a condenser microphone in detecting signals emerging in the process of drilling as an integrating information resource. A time-frequency with zoom fast-Fourier-transform analysis method is presented to recognize the acoustic signal features in breaking different rocks. Additionally, principal component analysis and Support Vector Machine method are used to check the qualitative analysis results for the monitored rock information. An experimental investigation considered four types of rock broken by a PDC drill bit with drilling weights ranging from 5 to 12.5 kN and drilling rates ranging from 64 to 128 r/min. To verify the reliability and accuracy of our acoustic rock detection method, two sensors installed in the orthogonal direction are examined. Furthermore, the coherent analysis was used to reveal the correlation of the output auto-correlation spectrum for each measurement. The results show that there is a good average percentage of lithology calculated by the time-frequency analysis results between the acoustic signal features and different types of rock. Accordingly, the acoustic sensor approach can help enhance the detection of rock properties in drilling systems, laying the foundation for quantitative lithology identification in more complex drilling.",3,3,4
Drilling,Rock,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Drilling,Rock,"Al Reda, Stephane M.; Yu, Catherine; Berthe, Guillaume; Matray, Jean-Michel",Study of the permeability in the Opalinus clay series (Mont Terri - Switzerland) using the steady state method in Hassler cell,Mont Terri; Opalinus clay; BDB-1 borehole; Gas permeability; Water permeability; Steady state method; Hassler cell; Slippage effect,DIFFUSION-COEFFICIENTS; POROUS-MEDIA; GAS-FLOW; WATER; PARAMETERS; PRESSURE; ROCKS; FAULT,"Mont Terri rock laboratory located in the Northwestern Switzerland is an international platform for applied research in the field of radioactive waste disposal in clayrock formations. A borehole named BDB1 has been drilled in the Opalinus claystone in 2013 to assess its containment properties. Characterization of petrophysical and hydrogeological parameters in the Jurassic shale known as Opalinus Clay were performed by in situ experiments conducted in the rock laboratory of Jura Mountains and on borehole samples. This paper presents the results of laboratory measurements of permeability in a permeameter called Hassler cell by using the steady state method. The study is applied to core samples drilled perpendicular and parallel to the bedding, and involves gas and water permeability measurements. The Hassler cell is an experimental device that allows to put samples under a confining pressure reproducing the in situ one. In all, results were obtained for nine samples over sixteen for gas permeability measurements with values ranging between 6.9 x 10(-21) and 2.3 x 10(-19) m(2) and one sample for water permeability measurements with a value of 1.38 x 10(-20) m(2). Most of the results are in good agreement with previous studies obtained by in situ experiments and using the Poiseuille type law method. The usage of several methods to determine the permeability of the Opalinus clay unit helps to conclude about the accuracy, trueness and precision of the measurements.",3,3,0
Drilling,Rock,"Hussain, Maaruf; Amao, Abduljamiu Olalekan; Al-Ramadan, Khalid; Negara, Ardiansyah; Saleh, Tawfik A.",Non-destructive techniques for linking methodology of geochemical and mechanical properties of rock samples,Geochemical; Mechanical properties; Rock; Well,HYDRAULIC FRACTURE PROPAGATION; COMPRESSIVE STRENGTH; POROSITY; EQUOTIP; FIELD; RESERVOIR; BEHAVIOR; SHALE,"Inadequate conventional core data, increasing cost of native sampling techniques, economic downturn in the oil sector, sparse distribution of modern well log suites in horizontal wells, and data acquisition challenges are few among the reasons driving innovation in the use of drill cuttings for determining rock properties and adequate characterization of reservoir units. In this paper, we propose a rock strength proxy based on the correlation between rock strength and elemental geochemistry. The technique uses a combination of X-ray fluorescence and rebound impulse hammer measurements to establish links between the geochemical and mechanical properties of the sampled rocks. We identified five chemo-mechanical facies (CMF) that are formation specific. Furthermore, a cross-validation approach was used to build a predictive model based on acquired elemental and impulse hammer measurements. Consequently, the model was used to predict elastic property and results were encouraging with R-2 of 0.83, 0.87, and 0.89 for training, validation, and testing respectively. This proposed method was developed using core plugs retrieved from subsurface formations. It will be useful for examples in rapid assessment of drill cuttings for the determination of rock strength, especially where the only available data is elemental geochemical data.",3,3,0
Drilling,Rock,"Ge, Dong; Peng, Jianming; Li, Keke; Huang, Chaoyang; Lian, Moke; Yang, Zhenglong",Influence of water-based drilling fluids on the performance of the fluidic down-the-hole hammer,Fluidic DTH hammer; Percussion drilling; Output power; Motion characteristic; Pressure drop; Water-based drilling fluids,,"Fluidic down-the-hole (DTH) hammer is a recently explored percussion drilling tool for the production of boreholes in hard rock. It has been proven efficient for exploration core drilling, geothermal drilling, and oil and gas drilling. Previous studies of this hammer have concentrated on its performance operating with clear water rather than water-based drilling fluids with additives. As the first step to filling the gap of knowledge in this area, this study was designed to explore only the performance of an SC86-H fluidic DTH hammer driven by water-based drilling fluids with various temperatures and different contents of bentonite and barite. Such performance was characterized in terms of output power, motion characteristic and operating pressure drop, and compared with that driven by water. The results showed that the output power of the SC86-H type hammer driven by drilling fluids with bentonite content <3% was better than that driven by water thanks to the lubrication effect in the fit clearance, whereas with bentonite content >= 3%, its output power was in the range or below that driven by water due to the elevation of the hydraulic losses and the frictional drag. Its operating pressure drop is only insignificantly influenced by the bentonite content. As the weighting agents in the drilling fluids, the barite particles impeded the smooth motion of the piston. However, the increased impact energy and output power can entirely offset the disadvantage mentioned above. Temperature affects the performance of the SC86-H type hammer by influencing the viscosity and density of the drilling fluids. Some optimal schemes are suggested for the rational design and application of the fluidic DTH hammer in practice. In summary, the SC86-H type hammer operated well in the drilling fluids with realistic fluid power levels. It means that the fluidic DTH hammer has good adaptation and robustness, which is favorable to practical application.",2,2,9
Drilling,Rock,"Chen, Pengju; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, Evren",Poroelastic modeling of cutting bottom-hole rock - Part I: Stress state of bottom-hole rock,Far field in-situ stresses; Cutting rock; Poroelasticity; Directional drilling; Bottom-hole rock; MSE,,"This is the first part of a series of two papers modeling cutting bottom-hole rock during drilling. This paper studies the stress state of a bottom-hole rock that a downhole bit is drilling. A bottom-hole rock underground is subjected to far field in-situ stresses. During drilling process, the rock materials above the bottom-hole rock are gradually removed and replaced with drilling fluid, thus altering the stress state of the bottom-hole rock. In this paper, a model is developed based on the theory of Linear Poroelasticity to calculate the evolution of stresses and pore pressure in a bottom-hole rock during drilling process. The bottom-hole rock under consideration can be selected at any depth underground. To solve the model, superposition principle and finite difference method are employed. The model is also extended for inclined wellbores in arbitrary directions. A series of case studies with various drilling parameters in different formations are presented. The results show that during drilling bottom-hole rock will expand, leading to the pore pressure decrease if formation has a low permeability. The pore pressure decrease in a bottom-hole rock will increase differential pressure, eventually increasing difficulties in drilling. The results show that low permeability formation drilled with a greater rate of penetration will lead to a lower pore pressure in a bottom-hole rock. Moreover, during air drilling in hard formation, the pore pressure decreases significantly in bottom-hole rock.",2,2,2
Drilling,Rock,"Hosseini-Kaldozakh, Seyed Arman; Khamehchi, Ehsan; Dabir, Bahram; Alizadeh, Ali; Mansouri, Zohreh",Rock wettability effect on Colloidal Gas Aphron invasion near wellbore region,Colloidal Gas Aphron drilling fluid; Formation damage; Wettability; Pore blocking,ENHANCED OIL-RECOVERY; DRILLING-FLUID; FORMATION DAMAGE; LIQUID DRAINAGE; POROUS-MEDIUM; STABILITY; TEMPERATURE,"Colloidal Gas Aphron drilling fluid is colloidal dispersions of gas microbubbles, which are designed to reduce the loss of circulation in depleted reservoirs. This fluid creates a robust and elastic micro-bubble network, to block the pores of the formation and minimize filtration loss. In this study, Xanthan Gum (XG) polymer and Sodium Dodecyl Benzene Sulphonate (SDBS) surfactant were the primary materials utilized to generate a water-based Colloidal Gas Aphron drilling fluid. A dynamic and static invasion of prepared Aphron drilling fluid in carbonate rock with different wettabilities was investigated. Moreover, the formation damage induced by the invasion of Aphron fluid to porous media was also studied. Results demonstrated that wettability alteration of a water-wet porous media to oil-wet lead to an increment of differential pressure throughout porous media during Aphron drilling fluid invasion. A significant influence of wettability was also observed on return permeability of carbonate rock. A reduction of 73.53% of carbonate rock permeability was observed in oil-wet core invaded by water-based Aphron drilling fluid.",2,2,2
Drilling,Rock,"Zhang, Lisong; Jiang, Menggang; Li, Wenjie; Bian, Yinghui",A new analytical model of wellbore collapse pressure based on stability theory,Wellbore stability; Stability theory; Equilibrium path; Limit point instability; Analytical model,ROCK STRENGTH CRITERIA; FAILURE CRITERIA; COULOMB; STRESS; LIMIT; MOGI,"In theory, the wellbore collapse for the petroleum drilling belongs to the limit point instability, and should be treated as the stability problem, but instead of the strength problem. For this purpose, a new analytical model was established to determine the collapse pressure based on the stability theory. Using the elastoplastic mechanics, the stress and displacement around the wellbore were solved, and the equilibrium path (i.e., the relation between the inner pressure and the radial displacement) was proposed. According to the equilibrium path, it can be found that the wellbore collapse occurs at the end of the plastic softening stage and the beginning of the residual stage. Additionally, a comprehensive numerical validation was performed based on the numerical methods, to examine the proposed analytical model. The stress and displacement around the wellbore by the proposed method agree well with those from the numerical method, with a deviation of less than 8.9%. Finally, the parametric analysis was performed to investigate the effects of the plastic hardening modulus, the plastic softening modulus, the yielding stress, the strength limit and the residual strength on the equilibrium path. The results show that the collapse pressure decreases as the plastic hardening modulus, the plastic softening modulus, the yield limit and the residual strength increasing. On the contrary, an increasing of the strength limit can increase the wellbore collapse pressure, which is different to the common understanding.",2,2,2
Drilling,Rock,"Chen, Jingkai; Zhang, Yanting; Zheng, Zhibin; Liu, Zhendong; Huang, Lumeng",Dynamic analysis of top-excited vibration assisted stuck release in vertical borehole with fatigue-like model,Stuck pipe; Axial vibration; Shear stress distribution; Fatigue-like release model,STICK-SLIP VIBRATIONS; TORSIONAL VIBRATION; ROCK JOINTS; STABILITY ANALYSIS; SHEAR MECHANISM; ROOT CAUSE; DRILL; FRICTION; PERFORMANCE; BEHAVIORS,"Stuck release operation is one of the largest contributions for the increase of non-productive time and consequently the increase of the well cost. Traditional stuck release operations including the jarring operations, changing flow rate, varying mud density are expensive and time-consuming. Recently, a surface vibration apparatus is introduced to the drilling industry and the stuck release time is highly reduced with this new apparatus. In this paper, a fatigue-like stuck release model is introduced to analyze the release mechanism of the stuck pipe excited by the vibration agitator. First, the drill string vibration behavior subjected to surface vibration agitator is analyzed. The natural frequencies and mode shapes are calculated analytically. The damping effect of drill mud is intensively investigated by assuming the laminar flow and Newtonian fluid. Second, the shear stress distribution on the stuck section is proposed analytically and verified with numerical examples. The influence of the shear parameter on the shear stress distribution is discussed and calibrated for certain configuration. Third, the stuck release behavior subjected to cyclic load is modeled with fatigue-like model, which is characterized by the formation release strength and stress factor. The stuck release process is progressive and three stuck release stages are identified. Finally, the top-excited drill string vibration is coupled with the release process on the stuck section. The top-excited vibration assisted stuck release system is modeled numerically. The stuck release processes operated at different resonant excitations are discussed. This paper casts light on the theoretical explanation of the vibration assisted stuck release mechanism and is important in optimizing the stuck release operations.",2,3,1
Drilling,Rock,"Buckman, Jim; Chudi, Obinna; Lewis, Helen; Couples, Gary; Huang, Tianshen; Jiang, Zeyun","Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",Pore occlusion; Pore network model; Digital rock model; Quartz cementation; Permeability,,"Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36-51%, and the earlier Miocene samples have a porosity of around 18-35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234-1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",2,2,1
Drilling,Rock,"Cui, Shuai; Liu, Houbin; Meng, Yingfeng; Fan, Yu; Wang, Jiajun; Han, Zhengbo",Study on mechanical properties and wellbore stability of deep brittle shale,Deep brittle shale; Borehole stress field; Complex loading; Surge pressure; Tensile caving; Wellbore stability,,"As the drilling depth of shale's oil and gas wells increases worldwide, the problem of borehole collapse and instability becomes increasingly serious. Due to the high content of brittle minerals in deep shale, the complex situation of an underground collapse of a site is often manifested as borehole wall caving and falling. On the basis of the deep shale of China's Longmaxi formation, we developed a simulation experiment involving the complex loading mechanics of underground working conditions. The influence of loading and unloading confining pressure speeds and the sealing properties of drilling fluid on the mechanical properties of rock were analyzed. We established the dynamic changes in borehole formation, combining seepage and pore pressure, the effective stress field around the well, and a method of evaluating wellbore stability in deep shale gas horizontal wells. The results show that the deep shale of the Longmaxi formation has a high brittle mineral content and is prone to brittle fracturing along parallel bedding surfaces under downhole pressure. The effective liquid column pressure at the bottom of the wells change noticeably under different working conditions. Changes in bottom hole fluid column pressure are the cause of the complicated situation of well leakage and overflow in the horizontal sections of the Longmaxi formation. The effective support confining pressure of borehole wall rock differs with different tripping out speeds. The faster the tripping out is, the less the support confining pressure of the wellbore rock and the easier it is to induce the rock to break down along the bedding. The effective sealing property of drilling fluid also affects wellbore stability. A good sealing property of drilling fluid can improve the supporting effect of the fluid on borehole wall rock and improve its resistance strength. On the whole, the pressure of the bottom hole liquid column is effectively controlled during drilling in the Longmaxi formation; this can avoid complicated situations such as well leakage. The results of this study provide a theoretical basis for the study of wellbore stability in deep shale formations during the drilling process.",1,1,5
Drilling,Rock,"Sadeghi, Amir Noabahar; Arikan, Kutluk Bilge; Ozbek, Mehmet Efe","Torsional model of the drill string, and real-time prediction of the bit rotational speed and the torque on bit, in an oil well drilling tower",Drill-string modelling; Bottom-hole assembly (BHA) parameters; Measuring of the BHA Parameters; Predicting of the BHA Parameters; Observer design,,"In an oil well drilling tower, the Bottom Hole Assembly (BHA) data is needed to optimize the controllable variables such as weight on bit and bit rotational speed for obtaining the optimum drilling rate. In order to acquire the data of the BHA, a simple and low-cost method, can be predicting of these parameters. In this study, first the torsional modelling of the drill string is implemented by dividing its length to some equal sections, then the effects of dividing on the estimation accuracy are evaluated. Using an ADRC (Active Disturbance Rejection Controller) in the vertical and rotational motions dynamics, some proper observers to predict the bit rotational speed, rock stiffness and torque on bit, in real-time are designed and presented. Dividing the drill string length to more sections, leads to design high order observer, so the performance of the designed observers with different orders, are compared and analysed. Employing the integral square error analysis, it is revealed, dividing the drill string length to more sections, leads more accurate in the prediction of bit rotational speed, but not more effect on the estimated rock stiffness, and torque on bit. Also it is shown that increasing of the observer bandwidth, leads to more accurate in the estimation, but concludes the estimation be more sensitive to the sensor noise. Employing the presented observers in this study to estimate the BHA data, in addition to enhance the drill quality and safety, the controllable variables are optimized, and consequently the whole drilling process can be robustly controlled, with no needs to the expensive measurement systems at the BHA.",1,1,1
Drilling,Drill String,"Li, Wei; Huang, Genlu; Yu, Fan; Ni, Hongjian; Jiang, Wu; Zhang, Xiaobing",Modeling and numerical study on drillstring lateral vibration for air drilling in highly-deviated wells,Drillstring dynamics; Lateral vibration; Finite element model; Bottom hole assembly; Air drilling,DYNAMIC-MODEL; STICK-SLIP; FRICTION; MOTIONS,"The combination of directional well technique and air drilling has been regarded as an effective technique for drilling engineering. Given the currently inadequate understanding of drillstring lateral vibration for air drilling in highly-deviated wells, the modeling and numerical study is conducted. Therefore, a new finite element (FE) model with full-dimensional beam elements was built in the paper, which combined the advantage of FE method and beam-column theory to avoid complicated derivation and solution. The model also included contact model, static-kinetic friction model, mass eccentricity, and Rayleigh damping. To verify the stability and applicability of the model, a numerical simulation was conducted to study the effects of rotation speed, weight on bit (WOB), well inclination, friction coefficient, and stabilizer (STB) on lateral vibration for air drilling in highly-deviated wells. Besides, the effects of drilling mud on lateral vibration were discussed. The results show that the FE model can be used effectively to analyze drillstring lateral vibration. Meanwhile, rotation speed and friction coefficient have promoting effects on lateral vibration, full-packed STB has a suppressing effect, while WOB has a relatively small effect. Moreover, well inclination has a suppressing effect on lateral displacement, and a promoting effect on lateral acceleration. Compared with mud drilling, the lateral displacement and lateral acceleration of air drilling are obviously large. When air drilling is used in highly-deviated wells, a smaller rotation speed is proposed as long as it satisfies the ROP demand, and a slightly larger WOB is proposed as long as it does not lead to drillstring buckling, and full-packed STBs are proposed to limit lateral vibration. In addition, the formations with large friction coefficients can make lateral vibration more violent, and the drilling process needs more attention. Furthermore, increasing the lubricity of the circulating medium is recommended to reduce lateral vibration. The study in this paper can help to further develop drillstring dynamics, understand lateral vibration characteristics, and select suitable parameters for air drilling in highly-deviated wells.",3,3,5
Drilling,Drill String,"Rajabali, Farid; Moradi, Hamed; Vossoughi, Gholamreza",Coupling analysis and control of axial and torsional vibrations in a horizontal drill string,Horizontal drilling; Dynamic model; Coupled axial and torsional vibrations; Mode summation method; Stability; Control design,DYNAMICS; UNCERTAINTY,"Vertical drilling methods have been often used for oil and gas extraction so far. In some places, for further extraction and access to the locations that cannot be obtained by the vertical drilling (due to its restrictions); horizontal drilling has become more popular. In horizontal drilling, a variety of longitudinal, torsional and lateral vibrations occur. These vibrations, if left uncontrolled, can damage the drilling rig and equipment, as well as reduce the efficiency of the drilling process and increase the processing time. The purpose of this research is to obtain the coupled axial and torsional vibration equations by analysing the vibrational modes in the horizontal section of the horizontal drilling. The obtained equations, which are in the form of continuous vibrations, are discretized by the mode summation method, and then the stability of the horizontal drilling string is investigated, and the controller is designed to stabilize the unstable process. In this research, the friction coefficient has been modeled randomly to be closer to the actual conditions. The controller was initially designed with four inputs, and then its inputs were reduced to the two inputs. First, the feedback linearization approach plus the pole placement method have been used to design the controller. To show the efficiency of the controller performance, uncertainties in the parameters of the forces are considered.",3,3,3
Drilling,Drill String,"Li, Wei; Huang, Genlu; Ni, Hongjian; Yu, Fan; Huang, Bin; Jiang, Wu",Experimental study and mechanism analysis of the motion states of bottom hole assembly during rotary drilling,Drill string dynamics; Lateral vibration; Motion state; Bottom hole assembly; Mechanism analysis,DYNAMIC-MODEL; VIBRATION; FRICTION; WELL,"Lateral vibration of bottom hole assembly (BHA) severely affects the drilling efficiencies of downhole tools and even leads to downhole accidents. To further study the lateral motion states of BHA during rotary drilling, a new experimental setup was built based on the similarity criterion that was derived using the Buckingham p-theorem. Meanwhile, four characteristic parameters were introduced to distinguish the types of motion states and highlight their dynamic characteristics. Moreover, a systematical experiment was conducted to analyze the effects of well inclination, rotation speed, weight on bit (WOB), measurement position, and friction coefficient on the motion states. In addition, the occurrence mechanism of the motion states was explained through the principle of least energy dissipation, and the numerical simulation was conducted to calculate the energy dissipation. The results show that the motion states in vertical wells contain forward whirl, random motion, and backward whirl, and the main motion state in deviated wells is circular arc swing. The rotation speed and friction coefficient have major effects and WOB has moderate effects on the motion states in vertical wells. The larger rotation speed, friction coefficient, and WOB, the easier is the occurrence of backward whirl. Meanwhile, well inclination has suppressing effects on lateral vibration, while rotation speed and friction coefficient have promoting effects. WOB has promoting effects on lateral vibration in vertical wells and relatively small effects in deviated wells. The stabilizer can effectively limit lateral vibration. Moreover, the change of the motion states depends on which motion state consumes the least external work. In particular, the conditions of forming backward whirl are more rigorous than those of maintaining backward whirl. Thus backward whirl is a stable motion state and is difficult to stop once it occurs. In this paper, the study can help to understand the dynamic characteristics and occurrence mechanism of the motion states during rotary drilling.",3,3,3
Drilling,Drill String,"Ramba, Viswanth; Selvaraju, Senthil; Subbiah, Senthilmurugan; Palanisamy, Muthukumar",A robust anomaly detection methodology using predicted hookload and neutral point for oil well drilling,Drilling mechanics; Non-productive time (NPT); Hookload; Sheave efficiency; Weight on bit; Neutral point,FRICTION,"The prediction of downhole complications during drilling process is one of the essential tasks to reduce oil well drilling costs. It will be achieved by implementing an optimized drilling strategy such as optimal design of wellbore and real-time monitoring of drilling operations. In current practice, the torque and drag, drill string stresses are calculated during the well planning phase to predict and prevent complications that might be encountered during the drilling phase and also to optimize the well trajectory. In this study, the methodology and applicability of the modified 3-Dimensional friction model for estimation of real-time hookload were established. A bottom-up approach is employed, where real-time weight-on-bit is utilized to estimate the neutral point. Further, the neutral point is utilized to determine the load acting at the surface and deadline. Moreover, the factors affecting the position of hookload measurement at the deadline and throughout the rig structure were grouped to form a metric termed as ''Rig Uncertainty Compensation"" (RUC) factor. Further, it is observed from the drilling data that the hookload is mainly dependent on the direction of block movement, global friction factor, sheave efficiency, weight parameter and RUC factor of rig structure. Therefore, the above-mentioned model parameters are tuned to improve the accuracy of the hookload prediction at the deadline. Additionally, the developed model is integrated with a Decision Support System (DSS) that provides support to the driller in real-time. The methodology will minimize the potential downhole drilling hazards by employing a DSS through analysing the dynamic predictions of hookload and neutral point. The proposed hookload model is validated for both vertical and directional wells during the rotary drilling operation using standard drilling data.",3,3,0
Drilling,Drill String,"Liu, Keman",Model and control method of a downhole electromagnetic transmitter for EM-MWD system,Electromagnetic measurement while drilling; Single-phase inverter; Downhole electromagnetic transmitter; Model; PI regulator,CONTROL STRATEGY; SINGLE; BOREHOLE; FIELD,"Downhole electromagnetic transmitter is an important part of EM-MWD system, which can send low-frequency EM waves data from a downhole tool to surface in real time for oil and gas exploration. In order to reduce the volume and weight of the downhole electromagnetic transmitter and improve the depth and accuracy of petroleum exploration, a novel downhole electromagnetic transmitter topology for electromagnetic MWD system is designed. Aiming at the complex and changeable characteristics of load impedance of transmitter, an equivalent load model for downhole electromagnetic transmitter is established with drill string, casing, drill-bit, drilling fluid and formation being taken into account. Because the attenuation characteristic of electromagnetic signal in the wellbore is similar to that of capacitor discharge, the characteristic of electromagnetic channel can be equivalent to the combination of capacitance and resistance. Then, in order to ensure that the downhole electromagnetic transmitter will produce the nominal load voltage, irrespective of disturbances such as variations in the lithium batteries voltage, perturbations in the switching times, and the load, a dual-loop real-time feedback control scheme with an outer voltage loop and an inner current loop is proposed. Simulation and experimental results with laboratory prototype demonstrate the effectiveness of the control method for downhole electromagnetic transmitter. It also ensures the downhole electromagnetic transmitter's excellent stability and the accuracy of the established equivalent load model as well as its ability to meet the requirements of practical field deep exploration. The findings of our work can help for better understanding of approximate load model of downhole electromagnetic transmitter. Furthermore, it will be of great significance for designing control algorithm of downhole electromagnetic transmitter for different areas or boreholes, achieving the purpose of increasing transmission depth. The research results can be used to improve the design and optimization of electromagnetic MWD measurement system in the aspects of improving the control accuracy of the transmitter, saving energy and increasing the transmission depth.",2,3,5
Drilling,Drill String,"Omojuwa, Emmanuel; Ahmed, Ramadan",Analytical modeling of axial oscillation-supported drillstrings in high-angle wells,Axial oscillations; Directional drilling; Oscillation tools; Borehole; Friction reduction; Modeling; Displacement excitation,FRICTION-REDUCING PERFORMANCE; REDUCTION; TOOL,"Downhole vibrations generated from axial oscillation tools (AOTs) in axial oscillation-supported drillstrings (AOSDs) has become one of the efficient means of reducing friction and improving weight transfer during sliding operations in horizontal and extended-reach wells. Dynamic modeling of AOT-excited drillstrings is needed for validating the functionality of axial oscillation tools during surface tests and predicting their response under downhole conditions. An analytical model is presented in this study to predict the behavior of axial oscillation-supported drillstrings working under downhole and surface conditions. The model is useful to perform parametric studies, downhole data correlation and placement study of AOTs along the drillstring in horizontal and extended-reach wells. Unlike existing models, the nonlinear equation of motion is derived from a model damped in a viscous medium with Coulomb friction and subjected to displacement excitation. The model also accounts for the spring rate of the axial oscillation tool. The displacement excitation is obtained from the spring rate, which is a critical input to the model. The nonlinear damping is approximated with an equivalent viscous damping coefficient to obtain an analytical solution. The developed model in this study is validated with published experimental measurements obtained from field-scale drillstrings. Correlations between predicted and measured axial displacement and accelerations at different excitation frequencies, pressure drops and spring rates show an approximate average deviation of 14.5%. Also, results from this study strongly accentuates that flow rate is the most critical operating parameter for axial oscillation tools because it affects the amplitude of pressure drop, excitation force, and operating frequency of AOTs.",2,2,2
Drilling,Drill String,"Lukin, Nikolas; Moura, Rafael Traldi; Alves, Marcilio; Bruenig, Michael; Driemeier, Larissa",Analysis of API S-135 steel drill pipe cutting process by blowout preventer,Offshore drilling; BlowOut preventer; Finite element method; Failure model; Experimental tests,DUCTILE FRACTURE; DAMAGE; PLASTICITY; CRITERION; BEHAVIOR; SHEARING; FAILURE; MODEL,"In offshore oil exploration, the use of a Dynamic Positioning System (DPS) to maintain the platform at a fixed point regardless of the influence of the environment has become common practice. In the event of failure, however, the drill string inside BOP (BlowOut Preventer) must be cut and safely disconnected from the platform. Therefore, it is evident the need for an accurate and realistic virtual model of this failure process. Numerical model analysis, in addition to avoiding expensive and complex experimental tests, allows, through post-processing tools, a detailed understanding of all phases of the failure process. The present work aims to characterize the API S-135 steel, as material commonly used to manufacturing drill strings. The material parameters for the Johnson-Cook model (J-C) are obtained from experimental tensile tests on dog bone and 3-point bending beams specimens with different notch radii, covering a wide range of stress triaxialities. Experimental tests and numerical simulations were compared by means of stress-strain curves, Digital Image Correlation (DIC) and Surface Electron Microscopy (SEM) to validate the model. The material model is applied to simulate the pipe cutting process and to predict the required force for the BOP to cut drill pipes with different geometries, which in comparison to experimental tests permitted to determine BOP internal frictions. Additionally, the numerical simulation also allowed a better understanding of the cutting process here presented as well, coherent to J-C model and SEM imaging of a similar cut tube in BOP.",2,3,1
Drilling,Drill String,"Chen, Jingkai; Zhang, Yanting; Zheng, Zhibin; Liu, Zhendong; Huang, Lumeng",Dynamic analysis of top-excited vibration assisted stuck release in vertical borehole with fatigue-like model,Stuck pipe; Axial vibration; Shear stress distribution; Fatigue-like release model,STICK-SLIP VIBRATIONS; TORSIONAL VIBRATION; ROCK JOINTS; STABILITY ANALYSIS; SHEAR MECHANISM; ROOT CAUSE; DRILL; FRICTION; PERFORMANCE; BEHAVIORS,"Stuck release operation is one of the largest contributions for the increase of non-productive time and consequently the increase of the well cost. Traditional stuck release operations including the jarring operations, changing flow rate, varying mud density are expensive and time-consuming. Recently, a surface vibration apparatus is introduced to the drilling industry and the stuck release time is highly reduced with this new apparatus. In this paper, a fatigue-like stuck release model is introduced to analyze the release mechanism of the stuck pipe excited by the vibration agitator. First, the drill string vibration behavior subjected to surface vibration agitator is analyzed. The natural frequencies and mode shapes are calculated analytically. The damping effect of drill mud is intensively investigated by assuming the laminar flow and Newtonian fluid. Second, the shear stress distribution on the stuck section is proposed analytically and verified with numerical examples. The influence of the shear parameter on the shear stress distribution is discussed and calibrated for certain configuration. Third, the stuck release behavior subjected to cyclic load is modeled with fatigue-like model, which is characterized by the formation release strength and stress factor. The stuck release process is progressive and three stuck release stages are identified. Finally, the top-excited drill string vibration is coupled with the release process on the stuck section. The top-excited vibration assisted stuck release system is modeled numerically. The stuck release processes operated at different resonant excitations are discussed. This paper casts light on the theoretical explanation of the vibration assisted stuck release mechanism and is important in optimizing the stuck release operations.",2,3,1
Drilling,Drill String,"Li, Meng; Hu, Shuli; Su, Kanhua; Wan, Lifu; Guo, Xiaole; He, Huiqun; Chen, Weiqing",Orientation load prediction method based on randomness/stochasticity of multi-source parameters in coiled tubing drilling,Coiled tubing drilling; Orientation load; Uncertainty method; Randomness; Orienter,TORQUE; DRAG,"Well trajectory control is always the key point of directional drilling. Downhole parameters measurements and BHA (bottom hole assembly) configuration and adjustment have the vital and coupling effect on realizing effective and efficient trajectory control. However, error exists universally in both of these phases. Compared with previous fixed value prediction models on controlling parameters prediction, uncertainty analysis based method will make the prediction results more reasonable and meaningful to control the BHA performance. With the consideration of the randomness of downhole multi-source parameters in coiled tubing drilling, an uncertainty prediction method for orientation load at a certain confidence level is proposed. Based on the beamcolumn theory, the probability and statistics theory is introduced and the distribution forms of main parameters are counted statistically. The probability density function and cumulative probability function of the orientation load prediction model when pump off and pump on in coiled tubing drilling are derived. The lognormal distribution has better correlation with the probability function of the orientation load, and the analysis on the confidence interval of the orientation load is described. Then, several relevant validation experiments are carried out, and the prediction of uncertain orientation load in coiled tubing drilling is also made. Several conclusions are made regarding to the field trial results. The randomness of weight on bit, friction coefficient of the interfacial between drill string and borehole wall or drill string and casing and tool face angle are the principal factors affecting the uncertainty of orientation load in coiled tubing drilling. The orientation load predicted with the uncertainty method is not a single curve or a single value, but an interval with a certain confidence level. The width of interval window is determined by the accuracy and precision of parameters information. The higher the confidence level is, the wider the predicted interval of orientation load and the larger the uncertainty range become. Compared with the predicted results of the uncertainty method, an error exists in the result of traditional single-value calculation method. The error varies with the change of weight on bit and formations and can be positive or negative. Meanwhile, retrieving more accurate principal original dada, e.g. WOB, formation properties, will make the uncertainty of the prediction lower. This orientation load prediction method is helpful to improve the efficiency of directional drilling in coiled tubing drilling.",1,1,5
Drilling,Drill String,"Wang, Qing; Guan, Zhichuan; Zhang, Bo; Liu, Yongwang; Li, Cheng",Multilevel method based on improved radar chart to evaluate acoustic frequency spectrum in periodic pipe structure,Downhole information; Acoustic propagation; Frequency spectrum characteristic; Comprehensive evaluation; Radar chart; Tensile stress,SIGNAL EXTRACTION; TRANSMISSION,"It is one of the most promising measures to transmit downhole information by acoustic wave through drill string However, the transmission distance and quality of acoustic signals in field conditions are still not satisfied because the acoustic frequency spectrum in drill string is vulnerable to interference. This paper studied acoustic frequency spectrum characteristics in periodic drill string by experiments under different axial tensile stresses. The multilevel method is established to evaluate frequency spectrum through drill string based on improved radar chart. The impact of axial tensile stress on spectrum characteristics is analyzed by the proposed method. The results indicate that the tensile stress has remarkable impact on the acoustic frequency spectrum and passband characteristics. The spectrum characteristics change with axial stress. These changes are mainly reflected in the position, width and attenuation of different passbands. And the extent of changes is distinct to different passbands. Both the evaluation indicators of each passband and spectrum are balance change with increasing axial tensile stress. The spectrum quality is excellent in the range of 17-134 MPa for axial tensile stress in drill string. And when the stress exceeds 152 MPa, methods such as adjusting the carrier frequency and relay installation location are necessary to improve the transmission quality of acoustic signals.",1,1,4
Drilling,Drill String,"Sadeghi, Amir Noabahar; Arikan, Kutluk Bilge; Ozbek, Mehmet Efe","Torsional model of the drill string, and real-time prediction of the bit rotational speed and the torque on bit, in an oil well drilling tower",Drill-string modelling; Bottom-hole assembly (BHA) parameters; Measuring of the BHA Parameters; Predicting of the BHA Parameters; Observer design,,"In an oil well drilling tower, the Bottom Hole Assembly (BHA) data is needed to optimize the controllable variables such as weight on bit and bit rotational speed for obtaining the optimum drilling rate. In order to acquire the data of the BHA, a simple and low-cost method, can be predicting of these parameters. In this study, first the torsional modelling of the drill string is implemented by dividing its length to some equal sections, then the effects of dividing on the estimation accuracy are evaluated. Using an ADRC (Active Disturbance Rejection Controller) in the vertical and rotational motions dynamics, some proper observers to predict the bit rotational speed, rock stiffness and torque on bit, in real-time are designed and presented. Dividing the drill string length to more sections, leads to design high order observer, so the performance of the designed observers with different orders, are compared and analysed. Employing the integral square error analysis, it is revealed, dividing the drill string length to more sections, leads more accurate in the prediction of bit rotational speed, but not more effect on the estimated rock stiffness, and torque on bit. Also it is shown that increasing of the observer bandwidth, leads to more accurate in the estimation, but concludes the estimation be more sensitive to the sensor noise. Employing the presented observers in this study to estimate the BHA data, in addition to enhance the drill quality and safety, the controllable variables are optimized, and consequently the whole drilling process can be robustly controlled, with no needs to the expensive measurement systems at the BHA.",1,1,1
Drilling,Oil and Gas,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Drilling,Oil and Gas,"Wang, Kai; Hu, Yinan; Yang, Kui; Qin, Min; Li, Yichen; Liu, Gang; Wang, Gang",Experimental evaluation of rock disintegration detection in drilling by a new acoustic sensor method,Acoustic analysis; Broken rocks; Lithological identification; Drilling,FAULT-DETECTION; VIBRATION; IDENTIFICATION; SIGNAL,"A simple and reliable method for monitoring the rock properties in drilling is recognized as a global challenge, especially for cluster and infill development well drilling in oil and gas production. To improve the existing limitations in the detection of formation lithology in drilling systems, an acoustic sensor approach for rock disintegration in the drilling using a polycrystalline diamond compact (PDC) drill bit is developed and evaluated. In this paper, we report the application of a special acoustic sensor device to qualitatively survey rock disintegration by rotary drilling. In this work, an acoustic focusing component is designed to assist a condenser microphone in detecting signals emerging in the process of drilling as an integrating information resource. A time-frequency with zoom fast-Fourier-transform analysis method is presented to recognize the acoustic signal features in breaking different rocks. Additionally, principal component analysis and Support Vector Machine method are used to check the qualitative analysis results for the monitored rock information. An experimental investigation considered four types of rock broken by a PDC drill bit with drilling weights ranging from 5 to 12.5 kN and drilling rates ranging from 64 to 128 r/min. To verify the reliability and accuracy of our acoustic rock detection method, two sensors installed in the orthogonal direction are examined. Furthermore, the coherent analysis was used to reveal the correlation of the output auto-correlation spectrum for each measurement. The results show that there is a good average percentage of lithology calculated by the time-frequency analysis results between the acoustic signal features and different types of rock. Accordingly, the acoustic sensor approach can help enhance the detection of rock properties in drilling systems, laying the foundation for quantitative lithology identification in more complex drilling.",3,3,4
Drilling,Oil and Gas,"Rajabali, Farid; Moradi, Hamed; Vossoughi, Gholamreza",Coupling analysis and control of axial and torsional vibrations in a horizontal drill string,Horizontal drilling; Dynamic model; Coupled axial and torsional vibrations; Mode summation method; Stability; Control design,DYNAMICS; UNCERTAINTY,"Vertical drilling methods have been often used for oil and gas extraction so far. In some places, for further extraction and access to the locations that cannot be obtained by the vertical drilling (due to its restrictions); horizontal drilling has become more popular. In horizontal drilling, a variety of longitudinal, torsional and lateral vibrations occur. These vibrations, if left uncontrolled, can damage the drilling rig and equipment, as well as reduce the efficiency of the drilling process and increase the processing time. The purpose of this research is to obtain the coupled axial and torsional vibration equations by analysing the vibrational modes in the horizontal section of the horizontal drilling. The obtained equations, which are in the form of continuous vibrations, are discretized by the mode summation method, and then the stability of the horizontal drilling string is investigated, and the controller is designed to stabilize the unstable process. In this research, the friction coefficient has been modeled randomly to be closer to the actual conditions. The controller was initially designed with four inputs, and then its inputs were reduced to the two inputs. First, the feedback linearization approach plus the pole placement method have been used to design the controller. To show the efficiency of the controller performance, uncertainties in the parameters of the forces are considered.",3,3,3
Drilling,Oil and Gas,Yin Yanshu; Hu Xun; Huang Jixin; Feng Wenjie; Wang Linxin; Duan Taizhong; Zhao Lei; Zhang Wenbiao,"A three-dimensional model of deep-water turbidity channel in Plutonio oilfield, Angola: From training image generation, optimization to multi-point geostatistical modelling",Multi-point geostatistics; Training image; Alluvsim; Optimization method; The Plutonio oilfield in Angola,SIMULATION; RESERVOIRS; DISTANCE,"The deep-water turbidity channel system in the Oligocene O73 sand layer in the Plutonio oilfield in Angola of west Africa has good oil and gas reservoir capability. As the well spacing is large due to operation cost, and the seismic resolution of the target layer is relatively low, identification of turbidity channel boundary was difficult. To establishes a fine model is a problem faced by the modelers. In this paper, a complete multi-point geostatistical modeling flowchart is presented for the construction of fine deep-water turbidity channel model. According to the investigation of seismic, well logging, drilling data and references in the study area, the genesis, reservoir scale, lithofacies type, morphological characteristics and evolution of the deep-water turbidity channel of the target layer were obtained. The improved Alluvsim algorithm was utilized to generate a set of adaptive deep-water turbidity channel training images with specified curvatures. Net-to-gross, variogram and a high-order statistics method based on the single data event were compared to evaluate and sort the training images. Then, the Snesim method was utilized to construct the models using the sorted compatible training images with a same set of parameters. At last, the quality of different models was compared based on the seismic attribute slices and a composite correlation coefficient optimization method based on seismic data. The results suggest that the improved Alluvsim algorithm can reproduce the channel morphology and stacking patterns better. Compared with the first-order and second-order statistics comparison method, the method using higher-order statistics of single data event taken spatial patterns into consideration and sorted training images better. The reservoir model was established using the optimal selected training image which has a high correlation with seismic attributes, and the model is more consistent with the characteristics of subsurface reservoirs. At the same time, this paper also provides a complete research program for the application of multi-point geostatistical modeling method which is from training image generation, optimal training image selection and multi-point geostatistics modeling to realizations selection for practical subsurface reservoir modelling.",3,3,2
Drilling,Oil and Gas,"Ge, Dong; Peng, Jianming; Li, Keke; Huang, Chaoyang; Lian, Moke; Yang, Zhenglong",Influence of water-based drilling fluids on the performance of the fluidic down-the-hole hammer,Fluidic DTH hammer; Percussion drilling; Output power; Motion characteristic; Pressure drop; Water-based drilling fluids,,"Fluidic down-the-hole (DTH) hammer is a recently explored percussion drilling tool for the production of boreholes in hard rock. It has been proven efficient for exploration core drilling, geothermal drilling, and oil and gas drilling. Previous studies of this hammer have concentrated on its performance operating with clear water rather than water-based drilling fluids with additives. As the first step to filling the gap of knowledge in this area, this study was designed to explore only the performance of an SC86-H fluidic DTH hammer driven by water-based drilling fluids with various temperatures and different contents of bentonite and barite. Such performance was characterized in terms of output power, motion characteristic and operating pressure drop, and compared with that driven by water. The results showed that the output power of the SC86-H type hammer driven by drilling fluids with bentonite content <3% was better than that driven by water thanks to the lubrication effect in the fit clearance, whereas with bentonite content >= 3%, its output power was in the range or below that driven by water due to the elevation of the hydraulic losses and the frictional drag. Its operating pressure drop is only insignificantly influenced by the bentonite content. As the weighting agents in the drilling fluids, the barite particles impeded the smooth motion of the piston. However, the increased impact energy and output power can entirely offset the disadvantage mentioned above. Temperature affects the performance of the SC86-H type hammer by influencing the viscosity and density of the drilling fluids. Some optimal schemes are suggested for the rational design and application of the fluidic DTH hammer in practice. In summary, the SC86-H type hammer operated well in the drilling fluids with realistic fluid power levels. It means that the fluidic DTH hammer has good adaptation and robustness, which is favorable to practical application.",2,2,9
Drilling,Oil and Gas,"Liu, Keman",Model and control method of a downhole electromagnetic transmitter for EM-MWD system,Electromagnetic measurement while drilling; Single-phase inverter; Downhole electromagnetic transmitter; Model; PI regulator,CONTROL STRATEGY; SINGLE; BOREHOLE; FIELD,"Downhole electromagnetic transmitter is an important part of EM-MWD system, which can send low-frequency EM waves data from a downhole tool to surface in real time for oil and gas exploration. In order to reduce the volume and weight of the downhole electromagnetic transmitter and improve the depth and accuracy of petroleum exploration, a novel downhole electromagnetic transmitter topology for electromagnetic MWD system is designed. Aiming at the complex and changeable characteristics of load impedance of transmitter, an equivalent load model for downhole electromagnetic transmitter is established with drill string, casing, drill-bit, drilling fluid and formation being taken into account. Because the attenuation characteristic of electromagnetic signal in the wellbore is similar to that of capacitor discharge, the characteristic of electromagnetic channel can be equivalent to the combination of capacitance and resistance. Then, in order to ensure that the downhole electromagnetic transmitter will produce the nominal load voltage, irrespective of disturbances such as variations in the lithium batteries voltage, perturbations in the switching times, and the load, a dual-loop real-time feedback control scheme with an outer voltage loop and an inner current loop is proposed. Simulation and experimental results with laboratory prototype demonstrate the effectiveness of the control method for downhole electromagnetic transmitter. It also ensures the downhole electromagnetic transmitter's excellent stability and the accuracy of the established equivalent load model as well as its ability to meet the requirements of practical field deep exploration. The findings of our work can help for better understanding of approximate load model of downhole electromagnetic transmitter. Furthermore, it will be of great significance for designing control algorithm of downhole electromagnetic transmitter for different areas or boreholes, achieving the purpose of increasing transmission depth. The research results can be used to improve the design and optimization of electromagnetic MWD measurement system in the aspects of improving the control accuracy of the transmitter, saving energy and increasing the transmission depth.",2,3,5
Drilling,Oil and Gas,"Okesanya, Temi; Abdukarimov, Aibek; Kuru, Ergun",Generalized models for predicting the drag coefficient and settling velocity of rigid spheres in viscoelastic and viscoinelastic power-law fluids,Settling velocity; Elasticity; Non-Newtonian fluids; Particle Transport; Modeling,SPHERICAL-PARTICLES; DRILLING-FLUIDS; BED EXPANSION; ELASTICITY; CUTTINGS; FALL; FLOW,"The design and optimization of several fluid-particle transport systems often require the determination of particle settling velocity in non-Newtonian fluids. These fluid-particle transport systems are encountered in a wide variety of industrial processes including drill cuttings transport in oil and gas well drilling operations and proppant transport in hydraulic fracturing operations. Current conventional approaches to estimate settling velocity in these non-Newtonian fluids often exclude the effect of elasticity on particle settling which can lead to erroneous estimation. It is therefore imperative to devise an accurate means to mathematically account for the fluid elasticity in particle settling in viscoelastic fluids. An experimental study was conducted to measure the settling velocity of spherical particles in viscoelastic and viscoinelastic power-law type fluids. Using a semi-mechanistic approach, explicit mathematical models were developed for estimating drag coefficient and particle settling velocity in viscoelastic fluids and viscoinelastic fluids. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoelastic and viscoinelastic power-law type fluids intended at augmenting the present corpus of experimental data in literature. ii.) To develop new drag coefficient and particle Reynolds number correlations that are applicable to viscoelastic and viscoinelastic power-law type fluids and, iii.) To present a general explicit approach for predicting settling velocities of particles in viscoelastic and viscoinelastic fluids. Particle Image Shadowgraphy (PIS) was used to measure the settling velocities of the spherical particles (Specific gravity 2.5-7.7; Diameters: 0.71-4.00 mm) in Hydrolyzed Polyacrylamide and Tylose solutions of varying elastic properties. Rheological characterization of the fluids was carried out using the C-VOR Bohlin Rheometer. Experimental results from this study were combined with various data published in the literature to create an extensive database and widen the scope for empirical analysis. The database had a consistency index (k) range of 0.012-6.773 Pa.s(n) and a fluid behavior index (n) range of 0.370-0.940. New drag coefficient and Reynold number correlations for particles settling in viscoelastic and viscoinelastic power-law fluids were developed by using a semi-mechanistic approach, which also included the fluid elasticity effect quantified in terms of the longest relaxation time. The newly developed correlations and an advanced statistical modeling program (OriginPro 9.0) were used to mathematically create explicit models that can be used for predicting particle settling velocity in viscoelastic and viscoinelastic fluids. Comparative analysis showed that an increase in the fluid elasticity gave a corresponding decrease in the particle Reynolds number and dampened the particle settling velocity in viscoelastic fluids. This dampening effect can be attributed to the unique ability of elastic fluids to partially or fully regain their original structure after deformation. Furthermore, statistical analysis showed that the presented new models predict settling velocity accurately with a very low with a Percentage Mean Absolute Error of about 7.5% and 30% for viscoinelastic and viscoelastic fluids respectively. The proposed models also exhibited Root Mean Square Error (RMSE) values of 0.04 m/s and 0.009 m/s for viscoinelastic and viscoinelastic fluids respectively.",2,2,1
Drilling,Oil and Gas,"Wang, Xianglei; Liu, Xiuquan; Zhang, Shenyan; Chen, Guoming; Chang, Yuanjiang",Study on mud discharge after emergency disconnection of deepwater drilling risers,Riser; Emergency disconnection; Mud discharge; CFD,FLOW; CFD; PREDICTION,"Mud is often discharged into seawater after emergency disconnection of risers in offshore oil and gas drilling engineering. The discharged mud needs to be simulated accurately since it can produce a huge load on risers. Several mud discharge models have been proposed, such as Young's slug model, SFM model, WFC model and one-dimensional finite volume model. However, the mud is taken as a one-dimensional rigid body in existing mud discharge models. As a consequence, the radial velocity of mud, the mixing interface between mud and seawater, and mud discharge in complicated riser flow channels cannot be simulated. In this paper, a more accurate and applicable three-dimensional (3D) computational fluid dynamics (CFD) model is established to simulate the mud discharge process. The proposed method is demonstrated by its application to a case. It turns out that the actual mud discharge process can be simulated based on the 3D CFD model. Characteristics of the mud discharge including the radial velocity, axial velocity and the interface between two fluids are calculated based on the 3D CFD model, which improves the understanding of the mud discharge. Besides, the applicability of each mud discharge model is determined through model comparison. The influence of key factors including drill pipes with pipe joints, riser inner diameter, mud density and mud dynamic viscosity on the mud discharge is also analyzed based on the 3D CFD model.",2,2,1
Drilling,Oil and Gas,"Zhang, Sen; Diao, Binbin; Gao, Deli",Numerical simulation and sensitivity analysis of accurate ranging of adjacent wells while drilling,Adjacent well; Accurate measurement; Double-layer radial medium; Magnetic field distribution; Relative positional relationship,,"Cluster well drilling technology is the key to large-scale development of unconventional oil and gas, but it is difficult to measure the distance of adjacent wells accurately by using off-the-shelf tilting tools and algorithms. Therefore, this paper proposes a novel algorithm for accurate ranging of adjacent wells while drilling. Firstly, a double-layer radial medium model, a magnetic field distribution law model and a relative position relationship model were established. Then, by solving the above model, the accumulation discipline of low-frequency current on the casing and the distribution law of the magnetic field around the casing are revealed. The calculation method of the relative position relationship is also obtained. The model is also compared with the experimental data of previous scholars to verify its effectiveness. Finally, the sensitivity analysis of the electric field strength in the radial direction, the current distribution on the casing and the magnetic field strength of the measuring point were carried out. The analysis results show that the electric field strength in the radial direction has obvious jump at the interface between the drilling fluid and the formation; the current on the casing and the distribution of the surrounding magnetic field are affected by the current intensity, the conductivity of the drilling fluid, the distance between the wells, the size of the wellbore, and the relative inclination angle of the well; in addition, in the short-distance measurement process, as the distance from electrode to probe is greater than 60 m, the relative well angle of construction well and production well should be controlled within 3 degrees to avoid collision. The research shows that the algorithm can provide theoretical basis for the high-precision measurement of clusters and infill wells.",2,3,0
Drilling,Oil and Gas,"Cui, Shuai; Liu, Houbin; Meng, Yingfeng; Fan, Yu; Wang, Jiajun; Han, Zhengbo",Study on mechanical properties and wellbore stability of deep brittle shale,Deep brittle shale; Borehole stress field; Complex loading; Surge pressure; Tensile caving; Wellbore stability,,"As the drilling depth of shale's oil and gas wells increases worldwide, the problem of borehole collapse and instability becomes increasingly serious. Due to the high content of brittle minerals in deep shale, the complex situation of an underground collapse of a site is often manifested as borehole wall caving and falling. On the basis of the deep shale of China's Longmaxi formation, we developed a simulation experiment involving the complex loading mechanics of underground working conditions. The influence of loading and unloading confining pressure speeds and the sealing properties of drilling fluid on the mechanical properties of rock were analyzed. We established the dynamic changes in borehole formation, combining seepage and pore pressure, the effective stress field around the well, and a method of evaluating wellbore stability in deep shale gas horizontal wells. The results show that the deep shale of the Longmaxi formation has a high brittle mineral content and is prone to brittle fracturing along parallel bedding surfaces under downhole pressure. The effective liquid column pressure at the bottom of the wells change noticeably under different working conditions. Changes in bottom hole fluid column pressure are the cause of the complicated situation of well leakage and overflow in the horizontal sections of the Longmaxi formation. The effective support confining pressure of borehole wall rock differs with different tripping out speeds. The faster the tripping out is, the less the support confining pressure of the wellbore rock and the easier it is to induce the rock to break down along the bedding. The effective sealing property of drilling fluid also affects wellbore stability. A good sealing property of drilling fluid can improve the supporting effect of the fluid on borehole wall rock and improve its resistance strength. On the whole, the pressure of the bottom hole liquid column is effectively controlled during drilling in the Longmaxi formation; this can avoid complicated situations such as well leakage. The results of this study provide a theoretical basis for the study of wellbore stability in deep shale formations during the drilling process.",1,1,5
Drilling,Oil and Gas,"Nwanwe, O., I; Teodoriu, C.",Matrix selection and comparison for selecting drilling methods and technologies for a wide range of applications,Decision matrix tool; Drilling methods and technologies; Drilling cost; Management,,"Oil and gas well construction requires application of an appropriate pair of drilling method and drilling technology that will ensure that the process is conducted safely and cost effectively. Selection of an appropriate drilling method and technology is a lengthy and tedious process which if not properly handled can cause erroneous decisions to be made. This can result to serious drilling problems that can cause additional cost for the company in providing solutions to these problems which are undesirable and should be avoided. In this study, a review of a wide range of drilling methods and technologies was conducted as well as a description of formations which are suitable candidates for their individual application are presented. Ratings for each drilling method and technology against each formation criteria developed on the basis of their candidate selection are also presented. Incorporating the ratings into the decision matrix model and using Visual Basic Programming language, a selection system was developed for selecting drilling methods and technologies using formation description, drilling cost and drilling time as selection criteria. This selection system will assist engineers in making fast and effective decisions regarding the drilling method and technology pair required for drilling a given formation or borehole section. The concept is proving to be useful in those areas where new discoveries are made or as for geothermal drilling in which insufficient nearby well data is available.",1,1,3
Drilling,Oil and Gas,"Moussa, Tamer; Dehghanpour, Hassan; Fu, Yingkun; Ezulike, Obinna",The use of flowback data for estimating dynamic fracture volume and its correlation with completion-design parameters: Eagle Ford cases,Initial effective fracture volume; Characteristic fracture-closure rate; Multivariate analysis; Multiple linear regression analysis; Completion design parameters; Flowback data analysis,,"Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (V-ef), and 2) investigate the existence of correlations between CDPs and V-ef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume (V-efi) using harmonic-decline (HD)model. Second, we estimate the loss in V-ef (V-loss) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast V-ef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with V-efi and FCR. The developed correlation between V-efi and CDPs shows that the gross perforated interval (GPI) has the most significant effect on V-efi. The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.",1,1,1
Drilling,Drill Cuttings,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Drilling,Drill Cuttings,"Zhang, Yang; Lu, Fengming; Cai, Mingjun; Yang, Yongqiang; Li, Ji; Guo, Zhiqiao; Wang, Rui; Zheng, Rongji",Physical simulation experiments of remaining oil distribution and production in alluvial fans controlled by dynamic and static factors,Alluvial fan; Dynamic and static factors; Physical simulation experiment for water flooding; Remaining oil distribution and production; Cangdong sag,DEBRIS-FLOW; BASIN; FIELD; INTERCALATION; SEDIMENTATION; PERFORATION; RESERVOIRS; SATURATION; EVOLUTION; VALLEY,"In order to study the remaining oil distribution and production in alluvial fans controlled by both static geologic factors and dynamic development factors, 2D and 3D macroscopic physical models have been constructed for the alluvial fan reservoirs in the eastern part of Cangdong sag, Bohai Bay Basin, China. Through considering static reservoir architecture and dynamic displacement rate, perforation position, well type, and well pattern, 7 water flooding physical simulation experiments have been finished, and the remaining oil distribution and production in oilfields with ultra-high water cut controlled by both dynamic and static factors were revealed. The study shows that without considering the economic benefits, drilling horizontal well, drilling infilled vertical well, increasing displacement rate, and plugging off water flooded layers at the initial stage of ultra-high water cut exhibited decreased performance in remaining oil production. After the dynamic factors adjustment, the remaining oil distribution and production is mainly controlled by the interlayer position, reservoir rhythm and the combination relationship between dynamic and static factors. When more injector-producer groups are located in the same single sand body, and the oil wells are uniformly drilled in single sand of different types, the oil recovery efficiency will be higher, and the distribution of the remaining oil will be more uniform. According to the experimental results, the remaining oil controlled by braided sand island and braided river channel could be divided into three types, and the corresponding measures to tap the potential were proposed.",3,3,2
Drilling,Drill Cuttings,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Drilling,Drill Cuttings,"Hussain, Maaruf; Amao, Abduljamiu Olalekan; Al-Ramadan, Khalid; Negara, Ardiansyah; Saleh, Tawfik A.",Non-destructive techniques for linking methodology of geochemical and mechanical properties of rock samples,Geochemical; Mechanical properties; Rock; Well,HYDRAULIC FRACTURE PROPAGATION; COMPRESSIVE STRENGTH; POROSITY; EQUOTIP; FIELD; RESERVOIR; BEHAVIOR; SHALE,"Inadequate conventional core data, increasing cost of native sampling techniques, economic downturn in the oil sector, sparse distribution of modern well log suites in horizontal wells, and data acquisition challenges are few among the reasons driving innovation in the use of drill cuttings for determining rock properties and adequate characterization of reservoir units. In this paper, we propose a rock strength proxy based on the correlation between rock strength and elemental geochemistry. The technique uses a combination of X-ray fluorescence and rebound impulse hammer measurements to establish links between the geochemical and mechanical properties of the sampled rocks. We identified five chemo-mechanical facies (CMF) that are formation specific. Furthermore, a cross-validation approach was used to build a predictive model based on acquired elemental and impulse hammer measurements. Consequently, the model was used to predict elastic property and results were encouraging with R-2 of 0.83, 0.87, and 0.89 for training, validation, and testing respectively. This proposed method was developed using core plugs retrieved from subsurface formations. It will be useful for examples in rapid assessment of drill cuttings for the determination of rock strength, especially where the only available data is elemental geochemical data.",3,3,0
Drilling,Drill Cuttings,"Yang, Yingxin; Song, Dongdong; Ren, Haitao; Huang, Kuilin; Zuo, Long","Study of a new impregnated diamond bit for drilling in complex, highly abrasive formation",Impregnated bit; Micro-drill test; Cutting elements; Cutting efficiency; Wear resistance,,"The failure of an impregnated bit used in the Xujiahe formation was analyzed, and the major factors determining bit failure were diamond granularity and concentration. Micro-drilling tests with impregnated cutters of different diamond granularities and concentrations were conducted. The results show that the cutting efficiency of cutting elements decreases with increasing diamond granularity increases with increasing diamond concentration; the wear resistance of cutting elements increases with increasing diamond granularity with increasing diamond concentration. Based on a comprehensive analysis of the test results, the optimum formulation parameters of diamond granularity and concentration were determined to achieve the best cutting efficiency and wear resistance, and a new impregnated bit was designed and tested in the Xujiahe formation, which has a footage of 88.46 m, rate of penetration (ROP) of 1.38/h, and drilling time of 64.19 h, which were 74.3%, 30%, and 35.1% higher, respectively. Compared with conventional impregnated bits, the cutting efficiency and working life of the new impregnated bit are significantly increased, providing technical support to efforts to increase the ROP of impregnated bits in complex and highly abrasive formations in west Sichuan and Xinjiang.",2,3,8
Drilling,Drill Cuttings,"Chen, Pengju; Miska, Stefan; Yu, Mengjiao; Ozbayoglu, Evren",Poroelastic modeling of cutting bottom-hole rock - Part I: Stress state of bottom-hole rock,Far field in-situ stresses; Cutting rock; Poroelasticity; Directional drilling; Bottom-hole rock; MSE,,"This is the first part of a series of two papers modeling cutting bottom-hole rock during drilling. This paper studies the stress state of a bottom-hole rock that a downhole bit is drilling. A bottom-hole rock underground is subjected to far field in-situ stresses. During drilling process, the rock materials above the bottom-hole rock are gradually removed and replaced with drilling fluid, thus altering the stress state of the bottom-hole rock. In this paper, a model is developed based on the theory of Linear Poroelasticity to calculate the evolution of stresses and pore pressure in a bottom-hole rock during drilling process. The bottom-hole rock under consideration can be selected at any depth underground. To solve the model, superposition principle and finite difference method are employed. The model is also extended for inclined wellbores in arbitrary directions. A series of case studies with various drilling parameters in different formations are presented. The results show that during drilling bottom-hole rock will expand, leading to the pore pressure decrease if formation has a low permeability. The pore pressure decrease in a bottom-hole rock will increase differential pressure, eventually increasing difficulties in drilling. The results show that low permeability formation drilled with a greater rate of penetration will lead to a lower pore pressure in a bottom-hole rock. Moreover, during air drilling in hard formation, the pore pressure decreases significantly in bottom-hole rock.",2,2,2
Drilling,Drill Cuttings,"Petri Junior, Irineu; dos Santos, Jessika M.; Ataide, Carlos H.; Duarte, Claudio R.",A novel method to determine total petroleum hydrocarbon (TPH) and water contents in reservoir drill cuttings,Soxhlet extraction; Hybrid method; Petroleum content; Drill cuttings; Retort method,SOLVENT-EXTRACTION; CONTAMINATED SOIL; REMEDIATION; BIOREMEDIATION; BIODEGRADATION; DEGRADATION,"It is very well known that crude oil is extracted from the earth crust by drilling process and when the drill bit reaches the oil reservoir, the drill cuttings are being mixed with oil. The reservoir drill cuttings with oil are hazardous to the environment and cannot be disposed as such and an appropriate method is needed for disposal. To perform an appropriate disposal, it is necessary to determine the toxicity of reservoir drill cuttings by the polycyclic aromatic hydrocarbons or total petroleum hydrocarbon contents. A standard for evaluation of heavy and light petroleum content in a sample is not available, and some alternative techniques require specialized operators and facilities suitable for the equipment; therefore, they have a high cost. For this reason, an innovative technique based on Soxhlet extraction and retort method is named as hybrid method, which was developed to determine the petroleum levels in reservoir drill cuttings to have better control of disposal. The optimal extraction and drying time for different solvents, the influence of the oil content and gravity were evaluated to validate the method. The results showed that the hybrid method could accurately determine the petroleum and water content of the reservoir drill cuttings with error less than 1%, for an extraction with hexane or dichloromethane/acetone solution for 24 h, with solvent renewal in a half of total time and 3 h of oven drying. The method can be employed as an alternative technique to determine petroleum content when it is below 15%, which is cheaper and more practical than current methods. Thus the disposal control of drill cuttings containing oil can be improved and besides making the petroleum content analysis technique more accessible and useful.",2,2,1
Drilling,Drill Cuttings,"Okesanya, Temi; Abdukarimov, Aibek; Kuru, Ergun",Generalized models for predicting the drag coefficient and settling velocity of rigid spheres in viscoelastic and viscoinelastic power-law fluids,Settling velocity; Elasticity; Non-Newtonian fluids; Particle Transport; Modeling,SPHERICAL-PARTICLES; DRILLING-FLUIDS; BED EXPANSION; ELASTICITY; CUTTINGS; FALL; FLOW,"The design and optimization of several fluid-particle transport systems often require the determination of particle settling velocity in non-Newtonian fluids. These fluid-particle transport systems are encountered in a wide variety of industrial processes including drill cuttings transport in oil and gas well drilling operations and proppant transport in hydraulic fracturing operations. Current conventional approaches to estimate settling velocity in these non-Newtonian fluids often exclude the effect of elasticity on particle settling which can lead to erroneous estimation. It is therefore imperative to devise an accurate means to mathematically account for the fluid elasticity in particle settling in viscoelastic fluids. An experimental study was conducted to measure the settling velocity of spherical particles in viscoelastic and viscoinelastic power-law type fluids. Using a semi-mechanistic approach, explicit mathematical models were developed for estimating drag coefficient and particle settling velocity in viscoelastic fluids and viscoinelastic fluids. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoelastic and viscoinelastic power-law type fluids intended at augmenting the present corpus of experimental data in literature. ii.) To develop new drag coefficient and particle Reynolds number correlations that are applicable to viscoelastic and viscoinelastic power-law type fluids and, iii.) To present a general explicit approach for predicting settling velocities of particles in viscoelastic and viscoinelastic fluids. Particle Image Shadowgraphy (PIS) was used to measure the settling velocities of the spherical particles (Specific gravity 2.5-7.7; Diameters: 0.71-4.00 mm) in Hydrolyzed Polyacrylamide and Tylose solutions of varying elastic properties. Rheological characterization of the fluids was carried out using the C-VOR Bohlin Rheometer. Experimental results from this study were combined with various data published in the literature to create an extensive database and widen the scope for empirical analysis. The database had a consistency index (k) range of 0.012-6.773 Pa.s(n) and a fluid behavior index (n) range of 0.370-0.940. New drag coefficient and Reynold number correlations for particles settling in viscoelastic and viscoinelastic power-law fluids were developed by using a semi-mechanistic approach, which also included the fluid elasticity effect quantified in terms of the longest relaxation time. The newly developed correlations and an advanced statistical modeling program (OriginPro 9.0) were used to mathematically create explicit models that can be used for predicting particle settling velocity in viscoelastic and viscoinelastic fluids. Comparative analysis showed that an increase in the fluid elasticity gave a corresponding decrease in the particle Reynolds number and dampened the particle settling velocity in viscoelastic fluids. This dampening effect can be attributed to the unique ability of elastic fluids to partially or fully regain their original structure after deformation. Furthermore, statistical analysis showed that the presented new models predict settling velocity accurately with a very low with a Percentage Mean Absolute Error of about 7.5% and 30% for viscoinelastic and viscoelastic fluids respectively. The proposed models also exhibited Root Mean Square Error (RMSE) values of 0.04 m/s and 0.009 m/s for viscoinelastic and viscoinelastic fluids respectively.",2,2,1
Drilling,Drill Cuttings,"Lukin, Nikolas; Moura, Rafael Traldi; Alves, Marcilio; Bruenig, Michael; Driemeier, Larissa",Analysis of API S-135 steel drill pipe cutting process by blowout preventer,Offshore drilling; BlowOut preventer; Finite element method; Failure model; Experimental tests,DUCTILE FRACTURE; DAMAGE; PLASTICITY; CRITERION; BEHAVIOR; SHEARING; FAILURE; MODEL,"In offshore oil exploration, the use of a Dynamic Positioning System (DPS) to maintain the platform at a fixed point regardless of the influence of the environment has become common practice. In the event of failure, however, the drill string inside BOP (BlowOut Preventer) must be cut and safely disconnected from the platform. Therefore, it is evident the need for an accurate and realistic virtual model of this failure process. Numerical model analysis, in addition to avoiding expensive and complex experimental tests, allows, through post-processing tools, a detailed understanding of all phases of the failure process. The present work aims to characterize the API S-135 steel, as material commonly used to manufacturing drill strings. The material parameters for the Johnson-Cook model (J-C) are obtained from experimental tensile tests on dog bone and 3-point bending beams specimens with different notch radii, covering a wide range of stress triaxialities. Experimental tests and numerical simulations were compared by means of stress-strain curves, Digital Image Correlation (DIC) and Surface Electron Microscopy (SEM) to validate the model. The material model is applied to simulate the pipe cutting process and to predict the required force for the BOP to cut drill pipes with different geometries, which in comparison to experimental tests permitted to determine BOP internal frictions. Additionally, the numerical simulation also allowed a better understanding of the cutting process here presented as well, coherent to J-C model and SEM imaging of a similar cut tube in BOP.",2,3,1
Drilling,Drill Cuttings,"Buckman, Jim; Chudi, Obinna; Lewis, Helen; Couples, Gary; Huang, Tianshen; Jiang, Zeyun","Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",Pore occlusion; Pore network model; Digital rock model; Quartz cementation; Permeability,,"Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36-51%, and the earlier Miocene samples have a porosity of around 18-35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234-1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",2,2,1
Drilling,Mud,"Li, Wei; Huang, Genlu; Yu, Fan; Ni, Hongjian; Jiang, Wu; Zhang, Xiaobing",Modeling and numerical study on drillstring lateral vibration for air drilling in highly-deviated wells,Drillstring dynamics; Lateral vibration; Finite element model; Bottom hole assembly; Air drilling,DYNAMIC-MODEL; STICK-SLIP; FRICTION; MOTIONS,"The combination of directional well technique and air drilling has been regarded as an effective technique for drilling engineering. Given the currently inadequate understanding of drillstring lateral vibration for air drilling in highly-deviated wells, the modeling and numerical study is conducted. Therefore, a new finite element (FE) model with full-dimensional beam elements was built in the paper, which combined the advantage of FE method and beam-column theory to avoid complicated derivation and solution. The model also included contact model, static-kinetic friction model, mass eccentricity, and Rayleigh damping. To verify the stability and applicability of the model, a numerical simulation was conducted to study the effects of rotation speed, weight on bit (WOB), well inclination, friction coefficient, and stabilizer (STB) on lateral vibration for air drilling in highly-deviated wells. Besides, the effects of drilling mud on lateral vibration were discussed. The results show that the FE model can be used effectively to analyze drillstring lateral vibration. Meanwhile, rotation speed and friction coefficient have promoting effects on lateral vibration, full-packed STB has a suppressing effect, while WOB has a relatively small effect. Moreover, well inclination has a suppressing effect on lateral displacement, and a promoting effect on lateral acceleration. Compared with mud drilling, the lateral displacement and lateral acceleration of air drilling are obviously large. When air drilling is used in highly-deviated wells, a smaller rotation speed is proposed as long as it satisfies the ROP demand, and a slightly larger WOB is proposed as long as it does not lead to drillstring buckling, and full-packed STBs are proposed to limit lateral vibration. In addition, the formations with large friction coefficients can make lateral vibration more violent, and the drilling process needs more attention. Furthermore, increasing the lubricity of the circulating medium is recommended to reduce lateral vibration. The study in this paper can help to further develop drillstring dynamics, understand lateral vibration characteristics, and select suitable parameters for air drilling in highly-deviated wells.",3,3,5
Drilling,Mud,"Xu, Bingwei; Zhou, Shouwei; He, Faqi; Wang, Fubin; Guo, Jianchu",Using particle image velocimetry to evaluate the displacement efficiency of drilling mud in horizontal well cementing,Cementing; Particle image velocimetry; Eccentricity; Displacement efficiency; Horizontal wells,ANNULAR DISPLACEMENTS; COMPLETION FLUIDS; OIL-WELL; MODEL; FLOW,"For a horizontal well cementing, successful displacement of the drilling mud from the annulus using the cement slurry were paramount for achieving zonal isolation. This study evaluated the displacement efficiency of drilling mud from the annulus by applying particle image velocimetry incorporating the development of a large-scale displacement efficiency device. Displacement efficiency measurements revealed that increasing the injection displacement and reducing the eccentricity cleans up residual drilling mud and significantly improves displacement efficiency. Slurry density significantly affected displacement efficiency, because high- and lightdensity slurries were shown to lead to low velocities and to increase the boundary layer thickness of the drilling mud. High injection displacement swirling flows were found to be more effective for reducing drilling mud adhesion to the casing and wellbore walls. The eccentric annuli tended to result in a narrow channel, which results significantly reducing the displacement efficiency owed to the laminar fluid flow.",3,3,3
Drilling,Mud,"Lichinga, Kevin Nsolloh; Maagi, Mtaki Thomas; Ntawanga, Athanas Christopher; Hao, Haiyang; Gu, Jun",A novel preflush to improve shear bond strength at cement-formation interface and zonal isolation,Cement-formation interface; Water-based mud; Filtercake; Preflush; Shear bond strength; Zonal isolation,OIL,"The effective removal of filtercake during the oil-well cementing job is of utmost importance for the reduction of well integrity problems during well drilling and production activities. Poor removal of filtercake will lead to a failure in the ability of the cement to provide zonal isolation at the cement-formation interface (CFI), during completion and for the well's lifetime. Several chemical mechanisms (chelating agents, acids, enzymes, and oxidizers) have been widely employed to remove filtercake. Nonetheless, at certain circumstances, these strategies have drawbacks that can adversely impact oil-well productivity. This research introduces a novel preflush (KV-IIA as well as KV-IIB) developed in the laboratory to transform the water-based filtercake at CFI into cement-based materials to enhance shear bonding. KV-IIA solution contained 16% CaCl2, and 1% Alkyl Polyglucoside (APG-1214), while KV-IIB fluid comprised 1% Alkyl Polyglucoside (APG-0810), 12% NaOH, 15% Na2SiO3 and water. Simulated wellbores (SWB) with porosity and permeability of 18% and 150'10(-3) mu m(2) respectively, were also used. The results showed the Reynold numbers for the preflushes KV-IIA and KV-IIB were 46,509 and 29,660 respectively. Since Reynold numbers are greater than 4000 value, the flow regime in the annulus is turbulent. The reactions among H3AlO42 and H3SiO4 from alkali-dissolved reaction, Ca2+, Na+ and H3SiO4 in the KV-II solution, and Ca2+ and OH from cement slurry form the natrolite and calcium silicate hydrate (CSH) with different silicate-calcium ratio. Based on that, the wellbore shear bond strength (SBS) and the cementing quality were improved. Analysis of the FTIR demonstrated that the CFI of the specimens tested produced additional cement binder material which resulted in increased bonding strength. The results of this work are anticipated to provide insights into the bond strengthening mechanisms in water-based mud that could help cementing specialists customize the preflushes to enhance the rock-cement bonding for better annular sealing to ensure a long-term zonal isolation.",3,3,3
Drilling,Mud,"Wang, HanYi; Sharma, Mukul M.",A rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure,In-situ stress; Pore pressure; Hydraulic fracturing; RIFT; DFIT; Effective fracture volume,ELASTIC COMPLIANCES; FRACTURE-COMPLIANCE; CAPROCK INTEGRITY; CONDUCTIVITY; STIMULATION; FIELD,"Extended leak-off test (XLOT) and pump-in and flow-back test (PIFB) are commonly used during drilling operations to estimate minimum stress. These estimates are adversely affected by hoop stress and drilling mud. Diagnostic Fracture Injection Tests (DFIT) can estimate both in-situ stress and pore pressure, but it takes days or weeks to conduct the test in low permeability formations. In this study, we present a novel rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure. Our new approach not only provides an unambiguous way to estimate in-situ stress (even in naturally fractured formations where DFIT fails to do so), but also allows us to estimate pore pressure with data from a test that lasts only a few hours, in addition, the effective fracture volume can also be estimated. Both simulations and field cases are presented to demonstrate the advantages of RIFT, along with a discussion of cautions and the potential pitfalls when designing and executing RIFT.",3,3,0
Drilling,Mud,"Aghli, Ghasem; Moussavi-Harami, Reza; Tokhmechi, Behzad","Integration of sonic and resistivity conventional logs for identification of fracture parameters in the carbonate reservoirs (A case study, Carbonate Asmari Formation, Zagros Basin, SW Iran)",Fractures; Image logs; Sonic logs; Reservoir parameters; Resistivity logs,SITU STRESS DIRECTION; FOLD-THRUST BELT; IMAGE LOGS; OIL-FIELD; POROSITY; DENSITY; CORE,"Between all available methods for fractures evaluation, core and image logs are prime methods. However, both of these data are very expensive and practically available in less than 10% of drilled wells. Therefore, a less expensive and quick method would be very helpful for fracture analysis. The main aim of this study is to identify the fracture parameters in the carbonate reservoirs, i.e. fracture density and fracture aperture, using a combination of sonic, resistivity and other conventional logs which commonly available in all wells. For this aim, fractures and their parameters were precisely determined on the image logs in 6 wells from carbonate Asmari Formation as a typical fractured reservoir in the world. Then, the effect of fracture parameters on the sonic and resistivity logs were used to identify fracture parameters in the wells with no core and image logs. Results indicate that the zones with high fracture density and aperture are easily detectable by conventional logs. On the other hand, the behavior of these logs is a function of fracture parameters in the fractured intervals, especially in the zones with high fracture aperture. Separation between shallow (RLA2) and deep (RLA5) resistivity logs along with their cross plot are very reliable indicators for fractured intervals. Sonic transit time rapidly increases where fractures density or aperture increased as well. In this study, a combination of sonic and neutron porosity logs have also been used to determine the effect of fracture aperture, as the main effective factor on the reservoir properties. Furthermore, full waveforms in some studied wells combined with sonic transit time to improve the results of fractures evaluation. Using sonic and resistivity along with neutron porosity and gamma ray logs provides a reliable method for describing the fracture parameters which shows high correlation with image logs results. Due to the high impact of fracture aperture on both reservoir quality and conventional log responses, determination of this parameter is more crucial than other fracture parameters. This method is also applicable for OBM (Oil Base Mud) image tools which conventionally cannot detect fracture aperture.",2,2,3
Drilling,Mud,"Chen, Jingkai; Zhang, Yanting; Zheng, Zhibin; Liu, Zhendong; Huang, Lumeng",Dynamic analysis of top-excited vibration assisted stuck release in vertical borehole with fatigue-like model,Stuck pipe; Axial vibration; Shear stress distribution; Fatigue-like release model,STICK-SLIP VIBRATIONS; TORSIONAL VIBRATION; ROCK JOINTS; STABILITY ANALYSIS; SHEAR MECHANISM; ROOT CAUSE; DRILL; FRICTION; PERFORMANCE; BEHAVIORS,"Stuck release operation is one of the largest contributions for the increase of non-productive time and consequently the increase of the well cost. Traditional stuck release operations including the jarring operations, changing flow rate, varying mud density are expensive and time-consuming. Recently, a surface vibration apparatus is introduced to the drilling industry and the stuck release time is highly reduced with this new apparatus. In this paper, a fatigue-like stuck release model is introduced to analyze the release mechanism of the stuck pipe excited by the vibration agitator. First, the drill string vibration behavior subjected to surface vibration agitator is analyzed. The natural frequencies and mode shapes are calculated analytically. The damping effect of drill mud is intensively investigated by assuming the laminar flow and Newtonian fluid. Second, the shear stress distribution on the stuck section is proposed analytically and verified with numerical examples. The influence of the shear parameter on the shear stress distribution is discussed and calibrated for certain configuration. Third, the stuck release behavior subjected to cyclic load is modeled with fatigue-like model, which is characterized by the formation release strength and stress factor. The stuck release process is progressive and three stuck release stages are identified. Finally, the top-excited drill string vibration is coupled with the release process on the stuck section. The top-excited vibration assisted stuck release system is modeled numerically. The stuck release processes operated at different resonant excitations are discussed. This paper casts light on the theoretical explanation of the vibration assisted stuck release mechanism and is important in optimizing the stuck release operations.",2,3,1
Drilling,Mud,"Tikhonov, Vadim S.; Indrupskiy, Ilya M.; Bukashkina, Olga S.",Effects of phase transitions on nonstationary liquid-gas flow in a well during gas kicks,MPD; Liquid-gas flow; Phase transitions; Kinematic-wave model; Numerical solution; Dynamic analysis,RAPID MULTIPHASE FLOW; 2-PHASE FLOW; DRIFT-FLUX; NONEQUILIBRIUM RELAXATION; SLUG FLOW; MODEL,"The paper presents a model of nonstationary liquid-gas flow in a well considering non-equilibrium phase transitions. The problem is topical for Managed Pressure Drilling (MPD) with lightweight oil-based mud in case of a gas kick. The model accounts for the relaxation character of gas dissolution and separation at phase transitions in the liquid-gas system. A numerical solution method has been proposed, which is based on the kinematic-wave model. The paper provides examples of gassy and bubbly area evolution and hydrodynamic flow parameters during a gas kick. The effect of backpressure on the velocity of gas kick and bottomhole pressure has been analyzed. It has been demonstrated that consideration of phase transitions considerably affects the gas kick process and the bubbly-gassy area rising to the wellhead.",2,2,1
Drilling,Mud,"Wang, Xianglei; Liu, Xiuquan; Zhang, Shenyan; Chen, Guoming; Chang, Yuanjiang",Study on mud discharge after emergency disconnection of deepwater drilling risers,Riser; Emergency disconnection; Mud discharge; CFD,FLOW; CFD; PREDICTION,"Mud is often discharged into seawater after emergency disconnection of risers in offshore oil and gas drilling engineering. The discharged mud needs to be simulated accurately since it can produce a huge load on risers. Several mud discharge models have been proposed, such as Young's slug model, SFM model, WFC model and one-dimensional finite volume model. However, the mud is taken as a one-dimensional rigid body in existing mud discharge models. As a consequence, the radial velocity of mud, the mixing interface between mud and seawater, and mud discharge in complicated riser flow channels cannot be simulated. In this paper, a more accurate and applicable three-dimensional (3D) computational fluid dynamics (CFD) model is established to simulate the mud discharge process. The proposed method is demonstrated by its application to a case. It turns out that the actual mud discharge process can be simulated based on the 3D CFD model. Characteristics of the mud discharge including the radial velocity, axial velocity and the interface between two fluids are calculated based on the 3D CFD model, which improves the understanding of the mud discharge. Besides, the applicability of each mud discharge model is determined through model comparison. The influence of key factors including drill pipes with pipe joints, riser inner diameter, mud density and mud dynamic viscosity on the mud discharge is also analyzed based on the 3D CFD model.",2,2,1
Drilling,Hydraulic Fracture,"Hussain, Maaruf; Amao, Abduljamiu Olalekan; Al-Ramadan, Khalid; Negara, Ardiansyah; Saleh, Tawfik A.",Non-destructive techniques for linking methodology of geochemical and mechanical properties of rock samples,Geochemical; Mechanical properties; Rock; Well,HYDRAULIC FRACTURE PROPAGATION; COMPRESSIVE STRENGTH; POROSITY; EQUOTIP; FIELD; RESERVOIR; BEHAVIOR; SHALE,"Inadequate conventional core data, increasing cost of native sampling techniques, economic downturn in the oil sector, sparse distribution of modern well log suites in horizontal wells, and data acquisition challenges are few among the reasons driving innovation in the use of drill cuttings for determining rock properties and adequate characterization of reservoir units. In this paper, we propose a rock strength proxy based on the correlation between rock strength and elemental geochemistry. The technique uses a combination of X-ray fluorescence and rebound impulse hammer measurements to establish links between the geochemical and mechanical properties of the sampled rocks. We identified five chemo-mechanical facies (CMF) that are formation specific. Furthermore, a cross-validation approach was used to build a predictive model based on acquired elemental and impulse hammer measurements. Consequently, the model was used to predict elastic property and results were encouraging with R-2 of 0.83, 0.87, and 0.89 for training, validation, and testing respectively. This proposed method was developed using core plugs retrieved from subsurface formations. It will be useful for examples in rapid assessment of drill cuttings for the determination of rock strength, especially where the only available data is elemental geochemical data.",3,3,0
Drilling,Hydraulic Fracture,"Wang, HanYi; Sharma, Mukul M.",A rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure,In-situ stress; Pore pressure; Hydraulic fracturing; RIFT; DFIT; Effective fracture volume,ELASTIC COMPLIANCES; FRACTURE-COMPLIANCE; CAPROCK INTEGRITY; CONDUCTIVITY; STIMULATION; FIELD,"Extended leak-off test (XLOT) and pump-in and flow-back test (PIFB) are commonly used during drilling operations to estimate minimum stress. These estimates are adversely affected by hoop stress and drilling mud. Diagnostic Fracture Injection Tests (DFIT) can estimate both in-situ stress and pore pressure, but it takes days or weeks to conduct the test in low permeability formations. In this study, we present a novel rapid injection flowback test (RIFT) to estimate in-situ stress and pore pressure. Our new approach not only provides an unambiguous way to estimate in-situ stress (even in naturally fractured formations where DFIT fails to do so), but also allows us to estimate pore pressure with data from a test that lasts only a few hours, in addition, the effective fracture volume can also be estimated. Both simulations and field cases are presented to demonstrate the advantages of RIFT, along with a discussion of cautions and the potential pitfalls when designing and executing RIFT.",3,3,0
Drilling,Hydraulic Fracture,"Li, Yanliang; Peng, Jianming; Zhang, Guang; Yang, Zhenglong; Li, Keke",Study on perforation performance of abrasive water jet enhanced by percussive drilling,AWJ Perforation; Percussive drilling; Perforation performance; Impact cracks,HYDRAULIC FRACTURE INITIATION; GEOTHERMAL-ENERGY; PRESSURE; TECHNOLOGY; STIMULATION; MECHANISM; IMPACT; SHALE,"Geothermal energy is abundant and has a high economic development value. Perforation would need to be utilized to establish fluid channels between the borehole and geothermal reservoirs. In the present paper, it is proposed to use percussive drilling to create impact cracks near the borehole to improve abrasive water jet (AWJ) perforation performance. Two groups of the specimen were used for experiments. One was the specimen near the borehole after conventional rotary drilling (G1), the other was the specimen near the borehole after percussive drilling (G2). The optimal parameters of AWJ perforation assisted by percussive drilling were obtained. Through evaluation of AWJ perforation performance, it was found that the perforation depth, diameter and volume of G2 were 1.5 times, 1.3 times and 2 times of the G1, respectively. Besides, there were many internal cracks in G2, which interweave with each other and form a crack network. The results indicated that the impact cracks could change the mechanical properties of the granite near the borehole, then reduce the difficulty of AWJ perforation and improve the perforation performance. All the above merits can provide important technical support for reducing the fracturing pressure, increasing fluid flow and enhancing heat exchange efficiency between geothermal reservoir and borehole.",2,2,6
Drilling,Hydraulic Fracture,"Zeng, Fanhui; Zhang, Yu; Guo, Jianchun; Zhang, Qiang; Chen, Zhangxin; Xiang, Jianhua; Zheng, Yunchuan",Optimized completion design for triggering a fracture network to enhance horizontal shale well production,Horizontal shale well; Completion design; Modified alternate fracturing; Fracture network; Field application,HYDRAULIC FRACTURES; PERFORATION CLUSTERS; INITIATION PRESSURE; NATURAL-FRACTURE; BARNETT SHALE; FLUID-FLOW; PROPAGATION; GROWTH; COMPLEXITY; INTERFACES,"Horizontal well drilling accompanied by multicluster fracturing is unlocking shale gas resources. It is essential to create a large-scale fracture network connecting the reservoir to the wellbore by activating the preexisting natural fractures (NFs) through well completion optimization. Coupling the geomechanical characteristics of a shale formation to achieve the maximum stimulated reservoir volume (SRV), we develop a new completion optimization pattern for a single horizontal wellbore called modified alternate fracturing. The new model is a combination of conventional simultaneous and alternate fracturing. Unlike the previous studies that mainly concentrated on predicting the quasistatic dilation of NF failure, the presented paper assesses the dynamic evolution progression of NF growth under different failure criteria. Additionally, an analysis of how the modified alternate fracturing influences the fracture network is performed. The results demonstrate that a NF may be crossed, opened or slipped by an approaching hydraulic fracture (HF), depending on the tensile or shear stresses exerted on the NF. The combination of perforation parameter optimization and injection rate real-time control is able to utilize induced stresses to form a complex fracture network. A field application reveals that the modified well completion pattern performed better than conventional simultaneous fracturing due to increasing the near-wellbore and far-field fracture complexity. In addition, no additional equipment such as bridge plugs or coiled tubingis needed during operation, reducing potential issues.",2,3,3
Drilling,Hydraulic Fracture,"Okesanya, Temi; Abdukarimov, Aibek; Kuru, Ergun",Generalized models for predicting the drag coefficient and settling velocity of rigid spheres in viscoelastic and viscoinelastic power-law fluids,Settling velocity; Elasticity; Non-Newtonian fluids; Particle Transport; Modeling,SPHERICAL-PARTICLES; DRILLING-FLUIDS; BED EXPANSION; ELASTICITY; CUTTINGS; FALL; FLOW,"The design and optimization of several fluid-particle transport systems often require the determination of particle settling velocity in non-Newtonian fluids. These fluid-particle transport systems are encountered in a wide variety of industrial processes including drill cuttings transport in oil and gas well drilling operations and proppant transport in hydraulic fracturing operations. Current conventional approaches to estimate settling velocity in these non-Newtonian fluids often exclude the effect of elasticity on particle settling which can lead to erroneous estimation. It is therefore imperative to devise an accurate means to mathematically account for the fluid elasticity in particle settling in viscoelastic fluids. An experimental study was conducted to measure the settling velocity of spherical particles in viscoelastic and viscoinelastic power-law type fluids. Using a semi-mechanistic approach, explicit mathematical models were developed for estimating drag coefficient and particle settling velocity in viscoelastic fluids and viscoinelastic fluids. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoelastic and viscoinelastic power-law type fluids intended at augmenting the present corpus of experimental data in literature. ii.) To develop new drag coefficient and particle Reynolds number correlations that are applicable to viscoelastic and viscoinelastic power-law type fluids and, iii.) To present a general explicit approach for predicting settling velocities of particles in viscoelastic and viscoinelastic fluids. Particle Image Shadowgraphy (PIS) was used to measure the settling velocities of the spherical particles (Specific gravity 2.5-7.7; Diameters: 0.71-4.00 mm) in Hydrolyzed Polyacrylamide and Tylose solutions of varying elastic properties. Rheological characterization of the fluids was carried out using the C-VOR Bohlin Rheometer. Experimental results from this study were combined with various data published in the literature to create an extensive database and widen the scope for empirical analysis. The database had a consistency index (k) range of 0.012-6.773 Pa.s(n) and a fluid behavior index (n) range of 0.370-0.940. New drag coefficient and Reynold number correlations for particles settling in viscoelastic and viscoinelastic power-law fluids were developed by using a semi-mechanistic approach, which also included the fluid elasticity effect quantified in terms of the longest relaxation time. The newly developed correlations and an advanced statistical modeling program (OriginPro 9.0) were used to mathematically create explicit models that can be used for predicting particle settling velocity in viscoelastic and viscoinelastic fluids. Comparative analysis showed that an increase in the fluid elasticity gave a corresponding decrease in the particle Reynolds number and dampened the particle settling velocity in viscoelastic fluids. This dampening effect can be attributed to the unique ability of elastic fluids to partially or fully regain their original structure after deformation. Furthermore, statistical analysis showed that the presented new models predict settling velocity accurately with a very low with a Percentage Mean Absolute Error of about 7.5% and 30% for viscoinelastic and viscoelastic fluids respectively. The proposed models also exhibited Root Mean Square Error (RMSE) values of 0.04 m/s and 0.009 m/s for viscoinelastic and viscoinelastic fluids respectively.",2,2,1
Drilling,Hydraulic Fracture,"Moussa, Tamer; Dehghanpour, Hassan; Fu, Yingkun; Ezulike, Obinna",The use of flowback data for estimating dynamic fracture volume and its correlation with completion-design parameters: Eagle Ford cases,Initial effective fracture volume; Characteristic fracture-closure rate; Multivariate analysis; Multiple linear regression analysis; Completion design parameters; Flowback data analysis,,"Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (V-ef), and 2) investigate the existence of correlations between CDPs and V-ef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume (V-efi) using harmonic-decline (HD)model. Second, we estimate the loss in V-ef (V-loss) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast V-ef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with V-efi and FCR. The developed correlation between V-efi and CDPs shows that the gross perforated interval (GPI) has the most significant effect on V-efi. The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.",1,1,1
Drilling,Hydraulic Fracture,"Zeng, Zhengwen; Harouaka, Abdallah",A new method for assessing stage-based hydraulic fracturing quality in Wolfcamp formation of Permian Basin,Permian basin Wolfcamp formation; Largest tight oil play in the world; Slick-water hydraulic fracturing; Stage-by-stage fracturing quality; Stress-shadow effects,WELL; PERFORMANCE,"In 2018 US Geological Survey assessed Wolfcamp formation in Permian Basin at west Texas and southwest New Mexico, USA as the world's largest tight oil play that has the most technically recoverable reserves. This is the result of favorable combination of tectonic activities and the depositional environments in the Paleozoic period. Three major cycles of tectonic movements controlled the creation of Permian Basin and its sub-basins. Frequent seawater inundations and retreats caused cyclic changes in depositional environments from Pennsylvania to early Permian ages, leading to the formation of an organic rich, tight and thick formation, the highly heterogeneous Wolfcamp play. Advanced completion technology of combining horizontal drilling with multi-stage massive hydraulic fracturing is needed for the commercial development of Wolfcamp play. Successful application of advanced completion technology in Wolfcamp faces two challenges: stage-after-stage cumulative stressshadow effects and localized heterogeneity in lithofacies and reservoir quality. The ""one-for-all"" fracturing design needs to be able to fine-tune stage-by-stage based on real-time feedback from fracturing quality of previous stage. Existing methods, from production logging to micro-seismic mapping, cannot provide real-time feedback of stage-based treatment quality. We propose a new method in this paper. The new method is based on the assumption that constant density of slick-water at shut-in intervals during hydraulic fracturing allows an accurate calculation of bottom-hole pressure from surface treatment pressure and true vertical depth at each stage. Using real-time on-site monitored surface treatment pressures during shut-in intervals at the end of pad and flush injections, stage-by-stage fracturing quality are calculated. Two Wolfcamp case studies in Midland Basin at Reagan County, Texas show that the new method can be used to quantify stage-based treatment qualities. Stage-based fracturing qualities from this new method are consistent with stage-based treatment results evaluated using other methods.",1,1,1
Drilling,ROP,"Li, Wei; Huang, Genlu; Yu, Fan; Ni, Hongjian; Jiang, Wu; Zhang, Xiaobing",Modeling and numerical study on drillstring lateral vibration for air drilling in highly-deviated wells,Drillstring dynamics; Lateral vibration; Finite element model; Bottom hole assembly; Air drilling,DYNAMIC-MODEL; STICK-SLIP; FRICTION; MOTIONS,"The combination of directional well technique and air drilling has been regarded as an effective technique for drilling engineering. Given the currently inadequate understanding of drillstring lateral vibration for air drilling in highly-deviated wells, the modeling and numerical study is conducted. Therefore, a new finite element (FE) model with full-dimensional beam elements was built in the paper, which combined the advantage of FE method and beam-column theory to avoid complicated derivation and solution. The model also included contact model, static-kinetic friction model, mass eccentricity, and Rayleigh damping. To verify the stability and applicability of the model, a numerical simulation was conducted to study the effects of rotation speed, weight on bit (WOB), well inclination, friction coefficient, and stabilizer (STB) on lateral vibration for air drilling in highly-deviated wells. Besides, the effects of drilling mud on lateral vibration were discussed. The results show that the FE model can be used effectively to analyze drillstring lateral vibration. Meanwhile, rotation speed and friction coefficient have promoting effects on lateral vibration, full-packed STB has a suppressing effect, while WOB has a relatively small effect. Moreover, well inclination has a suppressing effect on lateral displacement, and a promoting effect on lateral acceleration. Compared with mud drilling, the lateral displacement and lateral acceleration of air drilling are obviously large. When air drilling is used in highly-deviated wells, a smaller rotation speed is proposed as long as it satisfies the ROP demand, and a slightly larger WOB is proposed as long as it does not lead to drillstring buckling, and full-packed STBs are proposed to limit lateral vibration. In addition, the formations with large friction coefficients can make lateral vibration more violent, and the drilling process needs more attention. Furthermore, increasing the lubricity of the circulating medium is recommended to reduce lateral vibration. The study in this paper can help to further develop drillstring dynamics, understand lateral vibration characteristics, and select suitable parameters for air drilling in highly-deviated wells.",3,3,5
Drilling,ROP,"Yang, Yingxin; Song, Dongdong; Ren, Haitao; Huang, Kuilin; Zuo, Long","Study of a new impregnated diamond bit for drilling in complex, highly abrasive formation",Impregnated bit; Micro-drill test; Cutting elements; Cutting efficiency; Wear resistance,,"The failure of an impregnated bit used in the Xujiahe formation was analyzed, and the major factors determining bit failure were diamond granularity and concentration. Micro-drilling tests with impregnated cutters of different diamond granularities and concentrations were conducted. The results show that the cutting efficiency of cutting elements decreases with increasing diamond granularity increases with increasing diamond concentration; the wear resistance of cutting elements increases with increasing diamond granularity with increasing diamond concentration. Based on a comprehensive analysis of the test results, the optimum formulation parameters of diamond granularity and concentration were determined to achieve the best cutting efficiency and wear resistance, and a new impregnated bit was designed and tested in the Xujiahe formation, which has a footage of 88.46 m, rate of penetration (ROP) of 1.38/h, and drilling time of 64.19 h, which were 74.3%, 30%, and 35.1% higher, respectively. Compared with conventional impregnated bits, the cutting efficiency and working life of the new impregnated bit are significantly increased, providing technical support to efforts to increase the ROP of impregnated bits in complex and highly abrasive formations in west Sichuan and Xinjiang.",2,3,8
Drilling,ROP,"Najjarpour, Mohammad; Jalalifar, Hossein; Norouzi-Apourvari, Saeid",The effect of formation thickness on the performance of deterministic and machine learning models for rate of penetration management in inclined and horizontal wells,Rate of penetration; Machine learning; Deterministic models; Data-driven methods; Trust-region method; Particle swarm optimization algorithm,RANDOM FORESTS; REGRESSION TREES; DECISION TREES; DRILLING EFFICIENCY; NEURAL-NETWORKS; IN-FIELD; CLASSIFICATION; PREDICTION; OPTIMIZATION,"Rate of penetration (ROP) is one of the most important parameters in reducing drilling expenditure. In this paper, a ROP management study has been conducted for a well in Southwest of Iran. As a part of this study, the best approach for ROP prediction was determined by comparing the performance of several methods and particle swarm optimization (PSO) algorithm was implemented for optimization of ROP. This paper highlights the effects of formation thickness and the magnitude of working data-set on the performance of different algorithms which are being used for ROP management studies, especially in horizontal and inclined wells. This topic has special importance, when the results show a massive difference in thin and thick formations for some ROP prediction methods. Comparing the results of different ROP prediction methods showed that hybrid Bingham model has the best performance in ROP prediction; only if a powerful mathematical tool like trust-region method is being used for the determination of its unknown coefficients. This superiority was not generalized in all individual formations and there were different results in the cases of thin and thick formations; so, application of the bag-of-algorithms strategy by using the most accurate method in each formation is suggested for the prediction of ROP. Performing this ROP management project resulted in the prediction of ROP with a total relative error of 13.59% and also 48.30% improvement in ROP.",2,2,7
Drilling,ROP,"Geekiyanage, Suranga Chaminda Hemba; Loeken, Erik A.; Sui, Dan",Architectures and algorithms of an autonomous small-scale drilling agent,Drilling systems automation; Autonomous agent; Applied artificial intelligence; ROP optimization; Laboratory rig,OPTIMIZATION; PENETRATION,"This paper describes the core architectures and algorithms of an autonomous small-scale drilling agent. The agent operates in a laboratory rig, demonstrating drilling scenarios with limited or even no human intervention. The work illustrates its performance through self-coordinating state transition, Rate of Penetration (ROP, drilling speed) optimization capability, formation classification, and drilling incidents management. The agent is an original rule-based system, and its control architecture utilizes finite states automation. The novel ROP optimization strategy employs a gradient search in Weight on Bit (WOB)-rotational speed (RPM, Revolutions per Minute) control parameter space. It generates an increasing ROP trend with time and requires re-iteration at abrupt formation changes. Several drilling incidents are managed using 'if-then' logic-based activity decomposition. A key learning outcome from the study is the comprehension of the requirement of standard software architecture and Applications Programming Interfaces (API) for continuous research and development of the agent. Such interfaces enhance interoperability between systems and stimulate innovative thinking among independent developers to produce a better-faster set of algorithms. Laboratory testing and evaluation is an essential part of promoting the adaptation of digital technologies for drilling automation. Such studies are a useful, safe, and cost-effective solution for testing, integrating and improving hardware, software, and data management before expensive full-scale testing and integration.",2,2,0
Drilling,Real Time,"Liu, Keman",Model and control method of a downhole electromagnetic transmitter for EM-MWD system,Electromagnetic measurement while drilling; Single-phase inverter; Downhole electromagnetic transmitter; Model; PI regulator,CONTROL STRATEGY; SINGLE; BOREHOLE; FIELD,"Downhole electromagnetic transmitter is an important part of EM-MWD system, which can send low-frequency EM waves data from a downhole tool to surface in real time for oil and gas exploration. In order to reduce the volume and weight of the downhole electromagnetic transmitter and improve the depth and accuracy of petroleum exploration, a novel downhole electromagnetic transmitter topology for electromagnetic MWD system is designed. Aiming at the complex and changeable characteristics of load impedance of transmitter, an equivalent load model for downhole electromagnetic transmitter is established with drill string, casing, drill-bit, drilling fluid and formation being taken into account. Because the attenuation characteristic of electromagnetic signal in the wellbore is similar to that of capacitor discharge, the characteristic of electromagnetic channel can be equivalent to the combination of capacitance and resistance. Then, in order to ensure that the downhole electromagnetic transmitter will produce the nominal load voltage, irrespective of disturbances such as variations in the lithium batteries voltage, perturbations in the switching times, and the load, a dual-loop real-time feedback control scheme with an outer voltage loop and an inner current loop is proposed. Simulation and experimental results with laboratory prototype demonstrate the effectiveness of the control method for downhole electromagnetic transmitter. It also ensures the downhole electromagnetic transmitter's excellent stability and the accuracy of the established equivalent load model as well as its ability to meet the requirements of practical field deep exploration. The findings of our work can help for better understanding of approximate load model of downhole electromagnetic transmitter. Furthermore, it will be of great significance for designing control algorithm of downhole electromagnetic transmitter for different areas or boreholes, achieving the purpose of increasing transmission depth. The research results can be used to improve the design and optimization of electromagnetic MWD measurement system in the aspects of improving the control accuracy of the transmitter, saving energy and increasing the transmission depth.",2,3,5
Drilling,Real Time,"Yin, Qishuai; Yang, Jin; Xu, Guoxian; Xie, Renjun; Tyagi, Mayank; Li, Lilin; Zhou, Xu; Hu, Nanding; Tong, Gang; Fu, Chao; Pang, Da",Field experimental investigation of punch-through for different operational conditions during the jack-up rig spudcan penetration in sand overlying clay,Field experiment; Spudcan penetration; Punch-through; Sand overlying clay; Bearing capacity,BEARING CAPACITY; FOUNDATIONS; CONDUCTOR; SOIL,"The jack-up rig is the most widely applied mobile platform in the shallow-water offshore drilling. Since several predetermined target wells are in the soil stratum of sand overlying clay, the punch-through accidents occur frequently during the jack-up rig spudcan penetration leading to disastrous consequences and sometimes even casualties. Although a few centrifugal model experiments and indoor large-scale experiments have been conducted to simulate the spudcan penetration, these experiments expose significant knowledge gaps that deviate from the actual field operations due to the limitations of a constant displacement speed plan instead of multi-stage preloading plan. In this study, seventeen (17) field experiments simulating spudcan installation in sand overlying clay in in-situ soil strata in the intertidal sea of the Bohai Bay are reported to address the knowledge gaps. A systematic study of the spudcan penetration is presented through key influencing factors such as soil strength ratio of upper sand to lower clay, geometric ratio of spudcan diameter to upper sand thickness, ballasting speed and holding period time. Results indicate that the ultimate (peak) soil bearing capacity increases almost quadratically with the increase in strength ratio of upper sand to lower clay; the final spudcan penetration resistance decreases as a power law relationship with the increase in geometric ratio of spudcan diameter to upper sand thickness; the instantaneous spudcan penetration velocity increases as a logarithmic function with the increase in ballasting speed and the pore water pressure decreases as an exponential function with the increase in holding period time. From these experiments, three novel schemes are proposed to prevent the punch-through. Lastly, this study provides a design basis and theoretical guidance for precise calculations of the ultimate bearing capacity, accurate analysis of punch-through risk and effective prevention of the punch-through accidents in the real jack-up rig.",2,2,2
Drilling,Real Time,"Skalle, Pal; Aamodt, Agnar",Petrol 18 946: Downhole failures revealed through ontology engineering,Oil well drilling; big data; process failure and error; ontology engineering,,"Frequency of failures occurring during offshore oil-well drilling do not diminish over time, probably due to increased operational complexity. The volume and frequency of information generated during the drilling process are high. Every few seconds around 30 drilling parameters are recorded and stored. There will always be a need for new, smart solutions to drilling challenges. Present approaches to drilling challenges apply various types of knowledge generated by the operation; wellbore geometry, fluid info, lithology of the sediments, time-based drilling parameters, drilling equipment data, etc. In our research said knowledge is generalized into general concepts, and structured to form a knowledge model of the drilling process. This model is referred to as a drilling ontology, and we report how methods of knowledge modeling and ontology engineering have been used in developing the model, and subsequently how the model has been applied to predict downhole failures during drilling. The knowledge model and the drilling data are combined in the following manner: Data agents are surveilling drilling data. Deviatoric behavior of the drilling parameters are being detected and formed into symptoms. Symptoms trigger other concepts embedded in the ontology by means of linked cause-effect relationships. The end concept of the relationship path will always be one or several failure states. Tests show that reasoning within the ontology produces the highest probability of the failure identical with the real failure. The causes behind the failure can be retrieved from the ontology and applied in a useful manner in combatting the failure. The testing process also shows that this program is a potential supplement to warning against threatening failures before they occur.",2,2,0
Drilling,Lost Circulation,"She, Jiping; Zhang, Hao; Kang, Yili; Feng, Yin; Zhong, Ying; Yang, Bin",Cusp catastrophe model for plugging pressure prediction of lost circulation control in fractured reservoirs,Fractured reservoirs; Lost circulation; Cusp catastrophe; Maximum plugging pressure; Plugging zone,FRICTION COEFFICIENT,"Lost circulation is one of the most common and costly problems in drilling. The stability of the plugging zone is a key factor determining the lost circulation control. In this paper, an analytical model is derived based on the catastrophic theory, which considers key parameters affecting the stability of the plugging zone, such as formation parameters, contact parameters and plugging zone parameters. The maximum plugging pressure (MPP) can be calculated by this model to quantitatively evaluate the stability of the plugging zone. The validation case shows that the calculation result is in good agreement with the experimental measurement. In addition, the sensitivity analysis is performed and shows that the length of the plugging zone, the sliding friction coefficient of the fracture surface and the Young's modulus of plugging zone are positively correlated with MPP, but the shear height of plugging zone, sliding friction coefficient of lost circulation materials (LCMs) and Poisson's ratio of the plugging zone are negatively correlated with MPP. The model can be used to predict the MPP in lost circulation control and considered as a reference for the optimization of the LCMs and plugging program.",3,4,4
Drilling,Lost Circulation,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Drilling,Lost Circulation,"Wang, Peng; Ni, Hongjian; Liu, Haoge; Zhao, Bo",A novel wellbore strengthening method by using rotary jet while drilling,Lost circulation; Wellbore strengthening; Mechanism; Rotary jet; Field test,LOST-CIRCULATION; STRESS,Lost circulation is one of the most common and costly problems in drilling operations. Improving the wellbore strengthening by plugging drilling induced fractures using rotary jet method is a novel and effective method to mitigate lost circulation. A stress analysis model based on elastic-plastic mechanics was established to reveal the wellbore strengthening mechanism of rotary jet plugging while drilling. The structure of rotary jet tool was proposed and mixture multiphase flow model was adopted to optimize the structure of the modulation unit of rotary jet. The field tests of engineering prototype were carried out in 81/2 '' interval of three wells. Satisfactory plugging results verify the effectiveness of rotary jet plugging and wellbore strengthening technology.,2,2,1
Drilling,Mediterranean Sea,"Merey, Sukru",Geomechanical wellbore stability analysis for the wells drilled in the shallow sediments of the Mediterranean Sea,Wellbore stability; Hoop stress; Reservoir geomechanics; Gas hydrates; Mediterranean sea,NATURAL-GAS; HYDRATE; ORIENTATION; MAGNITUDE; FAILURE; ENERGY; BASIN; AREA; LOGS,"Gas hydrates are considered as near-future energy resources in the world. Due to high gas hydrate potential of the Mediterranean Sea, gas hydrate exploration wells are expected to be drilled. In this study, for the first time, the caliper logs of the wells drilled during ODP (Ocean Drilling Program) Leg 160 and ODP Leg 161 in the Eastern and Western Mediterranean Sea were evaluated together with the python codes predicting wellbore stresses, unconfined compressive strength (C-o) and lower-hemisphere projection. The required C-o in the Eastern Mediterranean Sea ranges from 60 psia to 2250 psia from seafloor to target depth. However, the estimated C-o of the sediments in the Eastern Mediterranean in this study by using the python codes developed in this study and the caliper logs of ODP Leg 160 ranges from 15 psia to 1250 psia with depth. Similarly, the required C-o to keep the wells in gauge and the estimated C-o of the sediments in ODP Leg 161 range between 100-12000 psi and 30-11000 psia, respectively. Mostly, C-o values of the sediments were less than the required C-o values for stable wellbore so extensive washouts were detected both in the wells of ODP Leg 160 and Leg 161. This is because the sediments within gas hydrate stability zone in the Mediterranean Sea are weak and almost unconsolidated. Moreover, in this study, it was shown that it is possible to reduce the degree of washouts by increasing the density of drilling fluid until fracture pressure. According to the estimations in this study, the wellbore enlargements for the wells in ODP Leg 160 and ODP Leg 161 were mostly reduced below 2 inches, below which better wellbore stability conditions, better well log data and better casing cement quality might be obtained.",2,2,2
Drilling,Mediterranean Sea,"Merey, Sukru",Estimation of fracture pressure gradients in the shallow sediments of the Mediterranean Sea by using ODP Leg 160 and Leg 161 data,Fracture pressure; Pore pressure; Gas hydrates; Shallow sediments; Drilling; Well log,NATURAL-GAS; HYDRATE; BASIN; ORIENTATION; PREDICTION; PARAMETERS; RESERVOIRS; MAGNITUDE,"Pore pressure gradient and fracture gradient are two of the most important parameters while making well drilling design. Hence, in this study, these gradients were estimated for the Mediterranean Sea shallow sediments where gas hydrate might exist by using ODP Leg 160 and ODP Leg 161 data (mainly density logs). The density logs obtained during these drilling programs were used to estimate fracture pressure gradients. In this study, pore pressure gradient intervals in the Eastern Mediterranean Sea and the Western Mediterranean Sea were estimated as 0.433-0.484 psi/ft and 0.459-0.460 psi/ft, respectively. It was found that geothermal gradients of the holes drilled in the Western Mediterranean Sea sediments are quite high (up to 128 degrees C/km) but the maximum geothermal gradient observed in the Eastern Mediterranean Sea is 12.85 degrees C/km. The estimated fracture pressure gradient ranges in the Eastern Mediterranean Sea and the Western Mediterranean Sea shallow sediments are 0.604-0.659 psi/ft and 0.675 psi/ft-0.766 psi/ft. For the first time, the fracture gradients in the shallow sediments (where gas hydrate might exist) of the Mediterranean Sea were predicted in this study. These fracture gradients are suggested for the drilling and well completion designs of gas hydrate wells in the conditions of the Mediterranean Sea.",1,1,1
Drilling,Pressure Gradient,"Krishna, Shwetank; Ridha, Syahrir; Vasant, Pandian; Ilyas, Suhaib Umer; Irawan, Sonny; Gholami, Raoof",Explicit flow velocity modelling of yield power-law fluid in concentric annulus to predict surge and swab pressure gradient for petroleum drilling applications,Couette-Poiseuille flow; Drilling; Flow velocity modelling; Yield power-law fluid; Surge/ Swab pressure,COUETTE-POISEUILLE FLOW; HERSCHEL-BULKLEY FLUIDS; LAMINAR; DISPLACEMENT; EQUATIONS; WELLS,"Exact prediction and controlling of surge/swab pressure are required during drilling of hydrocarbon reservoirs and other geological formations that often leads to well control challenges. The existing methods to predict the surge/swab pressure gradient in the wellbore are much implicitly developed, which further reduces the model accuracy. Therefore, the present research aims to develop a novel analytical model by incorporating the explicit flow velocity equations to further improve the efficiency in predicting the surge pressure gradient. The governing flow velocity equations are developed for a concentric annulus exhibiting Couette-Poiseuille flow phenomenon that subsequently used in designing a new analytical model for yield power-law fluids to predict surge pressure gradient. Detailed analysis for the validation of a newly developed model is performed using existing predictive models and experimental data of surge pressure. The statistical analysis exhibits satisfactory outcomes with a maximum error of 5.61% and R-2 of 0.988. A detailed analysis on the effect of relevant parameters on surge/swab pressure is also presented. The impact of fluid behaviour index and diameter ratio is found to be highly dependent on surge pressure under varying tripping speeds compared to other drilling parameters such as fluid yield point and consistency index.",1,1,4
Drilling,Pressure Gradient,"Merey, Sukru",Estimation of fracture pressure gradients in the shallow sediments of the Mediterranean Sea by using ODP Leg 160 and Leg 161 data,Fracture pressure; Pore pressure; Gas hydrates; Shallow sediments; Drilling; Well log,NATURAL-GAS; HYDRATE; BASIN; ORIENTATION; PREDICTION; PARAMETERS; RESERVOIRS; MAGNITUDE,"Pore pressure gradient and fracture gradient are two of the most important parameters while making well drilling design. Hence, in this study, these gradients were estimated for the Mediterranean Sea shallow sediments where gas hydrate might exist by using ODP Leg 160 and ODP Leg 161 data (mainly density logs). The density logs obtained during these drilling programs were used to estimate fracture pressure gradients. In this study, pore pressure gradient intervals in the Eastern Mediterranean Sea and the Western Mediterranean Sea were estimated as 0.433-0.484 psi/ft and 0.459-0.460 psi/ft, respectively. It was found that geothermal gradients of the holes drilled in the Western Mediterranean Sea sediments are quite high (up to 128 degrees C/km) but the maximum geothermal gradient observed in the Eastern Mediterranean Sea is 12.85 degrees C/km. The estimated fracture pressure gradient ranges in the Eastern Mediterranean Sea and the Western Mediterranean Sea shallow sediments are 0.604-0.659 psi/ft and 0.675 psi/ft-0.766 psi/ft. For the first time, the fracture gradients in the shallow sediments (where gas hydrate might exist) of the Mediterranean Sea were predicted in this study. These fracture gradients are suggested for the drilling and well completion designs of gas hydrate wells in the conditions of the Mediterranean Sea.",1,1,1
Drilling,Remaining Oil,"Zhang, Yang; Lu, Fengming; Cai, Mingjun; Yang, Yongqiang; Li, Ji; Guo, Zhiqiao; Wang, Rui; Zheng, Rongji",Physical simulation experiments of remaining oil distribution and production in alluvial fans controlled by dynamic and static factors,Alluvial fan; Dynamic and static factors; Physical simulation experiment for water flooding; Remaining oil distribution and production; Cangdong sag,DEBRIS-FLOW; BASIN; FIELD; INTERCALATION; SEDIMENTATION; PERFORATION; RESERVOIRS; SATURATION; EVOLUTION; VALLEY,"In order to study the remaining oil distribution and production in alluvial fans controlled by both static geologic factors and dynamic development factors, 2D and 3D macroscopic physical models have been constructed for the alluvial fan reservoirs in the eastern part of Cangdong sag, Bohai Bay Basin, China. Through considering static reservoir architecture and dynamic displacement rate, perforation position, well type, and well pattern, 7 water flooding physical simulation experiments have been finished, and the remaining oil distribution and production in oilfields with ultra-high water cut controlled by both dynamic and static factors were revealed. The study shows that without considering the economic benefits, drilling horizontal well, drilling infilled vertical well, increasing displacement rate, and plugging off water flooded layers at the initial stage of ultra-high water cut exhibited decreased performance in remaining oil production. After the dynamic factors adjustment, the remaining oil distribution and production is mainly controlled by the interlayer position, reservoir rhythm and the combination relationship between dynamic and static factors. When more injector-producer groups are located in the same single sand body, and the oil wells are uniformly drilled in single sand of different types, the oil recovery efficiency will be higher, and the distribution of the remaining oil will be more uniform. According to the experimental results, the remaining oil controlled by braided sand island and braided river channel could be divided into three types, and the corresponding measures to tap the potential were proposed.",3,3,2
Drilling,Remaining Oil,"Moussa, Tamer; Dehghanpour, Hassan; Fu, Yingkun; Ezulike, Obinna",The use of flowback data for estimating dynamic fracture volume and its correlation with completion-design parameters: Eagle Ford cases,Initial effective fracture volume; Characteristic fracture-closure rate; Multivariate analysis; Multiple linear regression analysis; Completion design parameters; Flowback data analysis,,"Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (V-ef), and 2) investigate the existence of correlations between CDPs and V-ef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume (V-efi) using harmonic-decline (HD)model. Second, we estimate the loss in V-ef (V-loss) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast V-ef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with V-efi and FCR. The developed correlation between V-efi and CDPs shows that the gross perforated interval (GPI) has the most significant effect on V-efi. The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.",1,1,1
Drilling,Wear,"Yang, Yingxin; Song, Dongdong; Ren, Haitao; Huang, Kuilin; Zuo, Long","Study of a new impregnated diamond bit for drilling in complex, highly abrasive formation",Impregnated bit; Micro-drill test; Cutting elements; Cutting efficiency; Wear resistance,,"The failure of an impregnated bit used in the Xujiahe formation was analyzed, and the major factors determining bit failure were diamond granularity and concentration. Micro-drilling tests with impregnated cutters of different diamond granularities and concentrations were conducted. The results show that the cutting efficiency of cutting elements decreases with increasing diamond granularity increases with increasing diamond concentration; the wear resistance of cutting elements increases with increasing diamond granularity with increasing diamond concentration. Based on a comprehensive analysis of the test results, the optimum formulation parameters of diamond granularity and concentration were determined to achieve the best cutting efficiency and wear resistance, and a new impregnated bit was designed and tested in the Xujiahe formation, which has a footage of 88.46 m, rate of penetration (ROP) of 1.38/h, and drilling time of 64.19 h, which were 74.3%, 30%, and 35.1% higher, respectively. Compared with conventional impregnated bits, the cutting efficiency and working life of the new impregnated bit are significantly increased, providing technical support to efforts to increase the ROP of impregnated bits in complex and highly abrasive formations in west Sichuan and Xinjiang.",2,3,8
Drilling,Wear,"Jin, Chunyu; Qian, Feng; Feng, Fuping",Effect of variable drill pipe sizes on casing wear collapse strength,Drill pipe size; Compound wear; Casing collapse strength,,"Casing wear, on the process of drilling complex structure well, has resulted in the casing collapse strength being weaker, which could be one of the important causes of casing damage accidents. For the complex structure wells with variable drill pipe size, a bigger error would occur if the casing wear is calculated by the single size crescent wear model. In this paper, based on the hypothesis of the single size crescent wear and the size of the drill pipe joints being involved in wear, we have established two geometric models, named compound sharp wear and compound blunt wear and deduced the casing collapse strength formula considering the compound wear. Meanwhile, how the compound wear rained influence on casing collapse strength was also analyzed with two methods-analytical and finite element analysis. At the same wear depth, for the collapse strength, there are not many differences between the compound crescent wear casing and the single crescent wear casing with minimum wear radius and the maximum error, less than 5%, would decrease as the wear depth increased. That was why we regarded the latter as an approximation of the former to calculate the collapse strength of compound wear casing in our study, which will provide references for the deformation mechanism and strength analysis of casing section in complex cases.",1,1,6
Crude Oil,Heavy Oil,"Salehpour, Mohammad; Riazi, Masoud; Malayeri, M. Reza; Seyyedi, Mojtaba",CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage,"Carbon capture, and storage (CCS); Carbon capture, utilization, and storage (CCUS); Carbonated water injection; Heavy asphaltic crude oil; Water-in-oil emulsion; Enhanced oil recovery",PORE-SCALE MECHANISMS; WATER INJECTION; INTERFACIAL-TENSION; WETTABILITY ALTERATION; CO2 INJECTION; PERFORMANCE; SECONDARY; SCENARIOS; EMULSIONS; DIOXIDE,"Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsioninduced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.",3,3,4
Crude Oil,Heavy Oil,"Luan, Jian; Dong, Pingchuan; Zheng, Jilong",Experimental studies on reaction laws during the process of air injection into the oil reservoirs with low permeability,Low permeability sandstone oil reservoir; Air injection; Static experiments; Low temperature oxidation; Formula,PERFORMANCE; IOR,"The low permeability oil reservoirs are widely distributed in the world, but difficult to develop with the traditional methods due to the low permeability and poor injection properties. Air injection technique not only has the common characteristics of other gas injection techniques, but also can improve the quality of crude oil in situ because of the oxidative ability of the injected air, with a unique advantage in developing low permeability reservoirs. In order to study the reaction regularity between the hydrocarbon components in crude oil under different conditions with the oxygen in the injected air, this experiment is designed for a low permeability sandstone reservoir. In this experiment, one set of self-designed static low-temperature oxidation equipment (including injection pump and high-temperature high-pressure reactor with sampling outlets) has been used. Through analysis of the results of the chromatography for over 60 oil and gas samples, conclusions can be made that after low temperature oxidation (LTO) reactions between the crude oil and the oxygen in the injected air, the concentration of the heavy components in crude oil decreased, and the concentration of the light components increased. By injecting oxygen-reduced air with 8% of oxygen, the concentration of the heavy components of crude oil in the target reservoir reduced most obviously. The formation water and associated gas can hinder the pyrolysis of heavy components, while the minerals in the formation can accelerate the pyrolysis process. The relationship between the carbon atoms number in each of the most consumed hydrocarbon molecule and different LTO reaction conditions has been proposed. According to the sensitivity analysis, it is believed that the influence of the formation water on the LTO reactions is greater than that of minerals in the formation, and influence of associated gas is less than that of minerals. Finally, combined the related physical and chemical theories, a LTO chemical reaction equation has been put forward for the targeted low permeability oil reservoir. The conclusions of the studies can provide some references for the indoor experiments and field applications of air injection in the future.",3,3,2
Crude Oil,Heavy Oil,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Crude Oil,Heavy Oil,"Behnous, Dounya; Palma, Andre; Zeraibi, Noureddine; Coutinho, Joao A. P.",Modeling asphaltene precipitation in Algerian oilfields with the CPA EoS,Asphaltene; Cubic plus association; Equation of state; Live oil,CUBIC-PLUS-ASSOCIATION; PC-SAFT CHARACTERIZATION; PHASE-BEHAVIOR; GAS INJECTION; CRUDE OILS; RESINS; PREDICTION; STABILITY,"One of the major flow assurance problems afflicting the oil industry is the asphaltene precipitation during the production, transportation and storage of oil. The precipitation of these heavy compounds is responsible for changes in crude oil properties, increases in oil viscosity, and formation of deposits that reduce oil production and disable equipment leading to significant operational costs. In Algeria, the deposition of asphaltene in reservoirs and pipelines is a severe problem. During production the depressurization of reservoir fluid and the variations of thermodynamic conditions create the need to frequently pig the lines and, in some cases, to inject solvents and dispersants to maintain the production. The understanding of the asphaltene behavior and the prediction of its deposition in flow conditions is crucial to implement appropriate strategies for the prevention or remediation, especially in the wellbore region. In this work we used the CPA EoS to describe the asphaltene phase envelope and predict the PT regions of stability for five Algerian live oils. The model provides a very good description of the experimental behavior of live oils without and with gas injection. The sensitivity to SARA analysis data and its effect on the asphaltene phase boundaries were also analyzed.",3,3,1
Crude Oil,Heavy Oil,"Petri Junior, Irineu; dos Santos, Jessika M.; Ataide, Carlos H.; Duarte, Claudio R.",A novel method to determine total petroleum hydrocarbon (TPH) and water contents in reservoir drill cuttings,Soxhlet extraction; Hybrid method; Petroleum content; Drill cuttings; Retort method,SOLVENT-EXTRACTION; CONTAMINATED SOIL; REMEDIATION; BIOREMEDIATION; BIODEGRADATION; DEGRADATION,"It is very well known that crude oil is extracted from the earth crust by drilling process and when the drill bit reaches the oil reservoir, the drill cuttings are being mixed with oil. The reservoir drill cuttings with oil are hazardous to the environment and cannot be disposed as such and an appropriate method is needed for disposal. To perform an appropriate disposal, it is necessary to determine the toxicity of reservoir drill cuttings by the polycyclic aromatic hydrocarbons or total petroleum hydrocarbon contents. A standard for evaluation of heavy and light petroleum content in a sample is not available, and some alternative techniques require specialized operators and facilities suitable for the equipment; therefore, they have a high cost. For this reason, an innovative technique based on Soxhlet extraction and retort method is named as hybrid method, which was developed to determine the petroleum levels in reservoir drill cuttings to have better control of disposal. The optimal extraction and drying time for different solvents, the influence of the oil content and gravity were evaluated to validate the method. The results showed that the hybrid method could accurately determine the petroleum and water content of the reservoir drill cuttings with error less than 1%, for an extraction with hexane or dichloromethane/acetone solution for 24 h, with solvent renewal in a half of total time and 3 h of oven drying. The method can be employed as an alternative technique to determine petroleum content when it is below 15%, which is cheaper and more practical than current methods. Thus the disposal control of drill cuttings containing oil can be improved and besides making the petroleum content analysis technique more accessible and useful.",2,2,1
Crude Oil,Heavy Oil,"Akmaz, Solmaz; Alpak, Ayse Ceyda; Haktanir, Mert; Yasar, Muzaffer",Comparison of molecular properties of saturate and aromatic fractions of Turkish and Iraqi crude oil residues,Crude oil residue; Saturate fraction; Aromatic fraction; Sub-fractionation; Structural characterization,PEROXIDE PRESOAKING PRIOR; EQUIVALENT BOILING-POINT; MASS-SPECTROMETRY; HEAVY PETROLEUMS; STRUCTURAL-CHARACTERIZATION; HPLC SEPARATION; CHROMATOGRAPHY; ADSORPTION; CALCITE; RESINS,"The chemical characterization of crude oil fractions is important for the petroleum research and complex structure of crude oil residue keeps studies ongoing. An analytical method which gives the composition of residue is not available yet and a combination of facile methods that elucidates the structure of residue is the most important in the petroleum research. This work reveals the detailed analyses of saturate and aromatic fractions of the selected crude oil atmospheric residues (ARs). Molecular structure of the saturate and the aromatic fractions was investigated by a combination of High-Performance Liquid Chromatography (HPLC) and nuclear magnetic resonance (NMR) spectroscopy techniques. In this study, saturate and aromatic fractions were physically divided into sub-fractions by HPLC and sub-fractions were examined in depth according to the hydrogen type using H-1 NMR. Moreover, AR maltenes and their saturates were analyzed by High Temperature-Simulated Distillation (HT-SIMDIS), in order to deduce carbon number (CN) ranges of the AR distillation cut points in weight percentages. The study revealed the distribution of aliphatic and aromatic hydrogen types in sub-fractions of the saturates and the aromatics of the selected ARs. Mono, di- and tri-aromatic hydrogen types of each sub-fraction were also disclosed. For all subfractions, total aromaticity increases in the order of increasing elution sequence. Celikli AR maltene fraction has molecules that have CN in the range of 14-30 or less for half of its total weight and contains mostly low boiling structures.",2,2,0
Crude Oil,Heavy Oil,"Lopez, Daniel; Zabala, Richard D.; Cardenas, Jose C.; Lopera, Sergio H.; Riazi, Masoud; Franco, Camilo A.; Cortes, Farid B.",A novel design of silica-based completion nanofluids for heavy oil reservoirs,Adsorption; Completion nanofluid; Interfacial tension; Silica nanoparticles; Surfactant; Wettability,WETTABILITY ALTERATION; INTERFACIAL-TENSION; SURFACE-ROUGHNESS; NANOPARTICLES; GAS; RECOVERY; WATER; ADSORPTION; PRODUCTIVITY; MODEL,"The main objective of this manuscript is the design of completion nanofluids (NanoCF) using silica nanoparticles based on the impact on the capillary number for being applied in heavy crude oil reservoirs. Six types of silica nanoparticles with different chemical nature were characterized by dynamic light scattering (DLS), point of zero charge (pHpzc), Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), surface area (S-BET), X-ray diffraction (XRD) and total surface acidity through temperature-programmed desorption of NH3 (TPD-NH3). Adsorption isotherms were constructed for understanding the non-ionic surfactant interaction with nanoparticles and rock surfaces, showing that a high adsorption affinity of the surfactant onto the rock surface, leaving less than 24% of free surfactant molecules able to migrate to the water/oil interface. Nevertheless, nanoparticle addition onto completion fluids (CF) could reduce the adsorbed surfactant onto the rock surface by 75%, which means more molecules of surfactant at the interface due to the nature of the obtained nanoparticles (NPS). The nanoparticles were selected based on the capillary number, showing that the best material reduced the interfacial tension between heavy crude oil and CF more than 76% and have the capacity to modify an initial oil-wet state to a water-wet rock surface. Finally, a coreflooding test was carried out at reservoir conditions (158 degrees F and 6.89 MPa) for evaluating the best completion nanofluid design based on the static tests, showing an increase of the oil effective permeability of 37% and incremental oil recovery of 3% in comparison to the completion fluid without nanoparticles. For the first time, novel completion nanofluids could allow stimulating the well from the beginning of the productive life.",2,2,0
Crude Oil,Heavy Oil,"Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Liu, Yigang; Liu, Zhezhi",Oxidation characteristics of heavy oil and its SARA fractions during combustion using TG-FTIR,Oxidation characteristics; Heavy oil; SARA fractions; Combustion; TG-FTIR,LOW-TEMPERATURE OXIDATION; IN-SITU COMBUSTION; CRUDE-OIL; THERMAL-DECOMPOSITION; KINETIC-ANALYSIS; PYROLYSIS; BEHAVIOR; MECHANISM; LIGHT; PARAMETERS,"The oxidation reactions between air and crude oils play a key role in in-situ combustion (ISC). This study is intended to explore the oxidation characteristics of one heavy oil and its SARA fractions by thermogravimetry associated with Fourier transform infrared spectroscopy (TG-FTIR). The results indicated the release behavior of typical evolved gases (hydrocarbons, CO2, CO, and H2O) during oxidation for the oil and its SARA fractions existed huge difference because of different structures and compositions. The heavy oil encountered appreciable weight loss at the low temperature oxidation (LTO) region where hydrocarbons, CO2, H2O, etc., were released. Quite a few coke could be formed from the LTO residue of heavy oil during fuel deposition (FD), thus resulting in a pronounced high temperature oxidation (HTO) stage characterized with apparent mass loss and one notably sharp peak of CO2. Saturates experienced a great amount of mass loss and release of hydrocarbons in the LTO regime. Aromatics showed obvious LTO and FD intervals in terms of mass loss and evolved gases, but its most of intermediate products during FD were evaporated with the temperature leading to the occurrence of weak HTO reactions. Resins was subjected to a small amount of mass loss and release of hydrocarbons and H2O in the LTO interval, and some of its intermediate products during FD formed coke through condensation reactions, which consequently led to a pronounced HTO stage. For asphaltenes, almost no hydrocarbons, CO2 and CO were released in the LTO region, and most of intermediate products at the initial FD stage condensed with each other to form coke. During HTO of asphaltenes, an extremely distinctive peak of CO2 and a small shoulder peak of CO and H2O were observed, verifying the occurrence of fierce combustion reactions.",1,1,4
Crude Oil,Heavy Oil,"Niu, Jun; Liu, Shuo; Xu, Jing-yu",Investigation into atomization spray blending property in heavy crude oil extraction under laboratory conditions,Heavy crude oil extraction; Atomization spray; Blending; Viscosity reduction; Droplet behavior,VISCOSITY; BREAKUP; RECOVERY; SIZE,"In this study, the atomization blending property for heavy crude oil extraction was systematically investigated both numerically and experimentally. In the experiment conducted, the blending behavior was simulated using hydraulic oil and spray with 1:10 light phase-gas atomize volume flow rate ratio in an equipment sharing the same scale as the on-site production. A Malvern Insitec droplet size analyzer was applied for the droplet size measurement, and a quick closing valve method was applied for the phase fraction measurement. A numerical simulation combined with a population balance model and the RNG k-epsilon model was performed under both the corresponding operating conditions and a high-pressure drop environment to further investigate the blending procedure. The results show that the atomization spray blending performs better than the equivalent pure gas lifting method with more crude oil carried at the exit. Under 0.6 m(3)/h light phase inlet conditions, spray blending brings 8% more heavy crude than gas lifting, and the improvement rises as inlet flow rate increases. Both a droplet and liquid film are present in the casing space before blending for the spray liquid phase. In addition, the light phase droplet diameter decreases with an increase in the inlet flow rates in the lifting pipe after blending. Moreover, the blending behavior differs under various light phase inlet flow rates, while the mixture viscosity is reduced by 50% for the atomization spray method. Each of these factors was shown to be beneficial for refining the blending used in a heavy crude oil extraction technique.",1,2,2
Crude Oil,Heavy Oil,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Crude Oil,Heavy Oil,"dos Santos, Lorena A.; Ribeiro, Daniel da C.; Romero, Oldrich J.",Heavy oil transportation through steam heating: An analytical and numerical approach,Viscous oils; Concentric steam pipe; Heat transfer; Steam quality; Flow assurance,NEWTONIAN FLOW CHARACTERIZATION; WATER-ALUMINA NANOFLUID; NATURAL-CONVECTION FLOW; CRUDE-OIL; VISCOSITY; BEHAVIOR; ANNULUS; MODEL,"Amongst the innumerable challenges that permeate the production chain of heavy oils, the transportation stage deserves to be highlighted. Due to its high viscosity, heavy oils exhibit considerable flow resistance, requiring auxiliary mechanisms to enable its transportation via pipelines. This study analyzes a concentric pipeline configuration, in which steam flows through the inner pipe and oil flows through the annular space of the oil pipe. The main goal is to investigate the impacts of steam insertion, concentric coupling dimensions, thermal insulation, steam quality and system horizontal length on the main parameters of flow control: oil temperature and viscosity. As a secondary parameter, oil initial pressure required to ensure flow completion is also discussed. In this intent, a numerical approach is applied with software Ansys CFX in a tridimensional, steady state simulation. A second objective is to estimate the main parameters of interest by an analytical approach, using the thermal resistance model associated with the epsilon - NTU method. The goal is to determine if, given a similar coupling scenario and the absence of computational resources, oil temperature and viscosity can be estimated by direct calculations within an acceptable range of deviation from the numerical approach. Heat transfer rates are also estimated as secondary parameters. Numerical results for a 1-m length system reveal that steam insertion elevates the average oil temperature in 1.2%, reducing its average viscosity and initial flow pressure by 8.7% and 24.2%, respectively. From the previous scenario, a reduction of 24.6% in the oil pipe/steam pipe radius ratio results in an additional 1.2% temperature increase and 4.7% viscosity reduction. On the other hand, reducing steam quality in 30% implicates an average oil viscosity 2.4% higher. In a 4-m system, a convective cell pattern is observed, in which oil heating and viscosity reduction reaches its peak at the central upper region of the annular space, highlighting cooler and denser deposits in the lower section of the system and a nonlinear heating process. Maximum deviations between numerical and analytical approaches in oil temperature and viscosity estimates are 1.3% and 15.6%, respectively, which indicate the latter as a suitable calculation method for small systems in the absence of numerical resources. Deviations are mainly attributed to the neglect of natural convection, gravitational and steam turbulence effects, which contribute for a non-homogeneous heating of oil.",1,1,1
Crude Oil,Heavy Oil,"Gupta, Ishank; Rai, Chandra; Tinni, Ali; Sondergeld, Carl",Using dry pyrolysis to understand crude oil production characteristics and calculate tortuosity in unconventional shales,SRA; Diffusion; Tortuosity; Insitu Fractionation; Shales,THERMAL EXTRACTION; SURFACE-AREA; DIFFUSION; BINARY,"In situ fractionation in shales means differential movement of the light versus heavy components of the crude oil in the shale formation. This can be due to multiple phenomenon like molecular sieving, varying diffusion coefficients for different hydrocarbon components and multi-component adsorption all acting simultaneously. Many companies have reported change in composition of produced fluid with time. Insitu fractionation is important because it has strong implications on EOR, both selecting the timing of EOR, and the solvent for EOR. Additionally, simulators for history matching, prediction and optimizing well spacing, must account for this effect. Earlier studies have proved the occurrence of the insitu fractionation both experimentally using GC-MS (gas chromatography and mass spectrometry) and theoretically using molecular dynamic simulations. However, cores are available in limited number of wells and, tools and measurements required to understand insitu fractionation are both time consuming and very expensive. We have found that dry pyrolysis can be used to effectively study insitu fractionation, the advantage being it is cheap and fast. The same experiment can be used to calculate effective diffusion coefficient and tortuosity. The study was done on samples from Berea sandstone, and Eagle Ford and Wolfcamp shales covering a wide range of petmphysical properties. The point source solution of the diffusivity equation was used to back out the effective diffusion coefficients. The effective diffusion coefficients determined for Berea, Wolfcamp and Eagle Ford samples were 5.38E-11 m(2)/s, 2.61E-11 m(2)/s and 5.35E-12 m(2)/s, respectively. These coefficients were then used to calculate the tortuosity of the samples which were validated by the resistivity measurements. The tortuosity values for the Berea, Wolfcamp and Eagle Ford samples were determined to be 3.1, 3.4 and 7.1, respectively. Tortuosity and diffusion coefficients are of paramount importance especially given the fact that permeability measurements in shales are unreliable and Knudsen diffusion and ordinary diffusion have to be integrated with Darcy flow to model production behavior in shales.",1,1,1
Crude Oil,Heavy Oil,"Kok, Mustafa Versan; Varfolomeev, Mikhail A.; Nurgaliev, Danis K.",The effect of water on combustion behavior of crude oils,Water content; Crude oil; Combustion; TGA; DSC; Kinetic analysis,LOW-TEMPERATURE; OXIDATION,"The ramped temperature oxidation experiments were performed on heavy and light crude oil samples using the TGA and DSC instruments. The crude oils were mixed with different weight percentages (10%, 20%, and 30%) of water, as a result of which six different water-oil mixtures were prepared. The samples were heated up to 800 degrees C with three heating rates 20, 25, 30 degrees C/min. Two reaction regions, particularly the low temperature oxidation (LTO) and high temperature oxidation (HTO), were identified in TGA and DSC results. The LTO region can be divided into two subzones as before and after around 150 degrees C. In the first subzone, up to around 150 degrees C, the endothermic distillation process took place. The results showed that light crude oil and its mixtures had lower reaction starting and ending temperatures, and peak temperatures compared to heavy crude oil and its mixtures. As the water amount in the mixtures were increased, the reaction and peak temperatures shifted to lower temperatures. The kinetic analysis was also performed applying the Ozawa-Flynn-Wall (OFW), Kissenger-Akahira-Sunose (KAS), and ASTM kinetic methods. The activation energies and Arrhenius constants based on the TGA and DSC results were calculated accordingly. The light crude oil and its water mixtures had lower activation energy and Arrhenius constants compared to heavy crude oil and its mixtures. As the amount of water in the mixture was increased, the activation energy and Arrhenius constant decreased, which indicated that the presence of water in the crude oil increases its ability to combust more efficiently.",1,1,1
Crude Oil,Pressure,"Szczerba, Marek; McCarty, Douglas K.; Derkowski, Arkadiusz; Kowalik, Mariola",Molecular dynamics simulations of interactions of organic molecules found in oil with smectite: Influence of brine chemistry on oil recovery,Molecular dynamics; Oil shale; Porosity; Low salinity water flooding,SALINITY; CHARGE; WATER; SURFACES; POROSITY; ILLITE,"The study is aimed at employing molecular dynamics simulations to study the interactions between smectite and major oil constituents, along with the impact of different brine chemistry (type of cation in a solution) and ionic strength on the compound mobility in fine pores. Clay minerals with smectitic type of mineral outer surface (smectite, illite-smectite, illite) are major constituents in many unconventional oil and gas reservoirs. Therefore, smectite was used as a model compound to test interactions of oil compounds with mineral surfaces. Natural crude oil is a complex mixture, which - for the purpose of simulating an influence of surrounding fluid on its interactions with smectite surfaces - needs to be simplified. The following molecules were selected as organic model compounds: decane, quinolone, nonanoic acid, benzamide, and heptylamine. Various protonation states were considered. The first two sets of simulations showed remarkably different interactions of the selected organic molecules with the smectite surface. In the first one, three water/oil coverage models of the surface were considered. In the second one, two different pore sizes were taken into account: 3 nm and 5 nm. Significant differences were readably visible between polar and non-polar organic molecules. Also, the degree of protonation was found to be a crucial factor affecting the molecules' affinity to the mineral surface. The molecules that are well soluble in cyclohexane (here representing crude hydrocarbons phase) formed droplets in the water phase, whereas organic compounds miscible in water were concentrated at the water-monolayer film on the smectite surface. Neutral organic molecules in the interlayer influences hydration spheres of the cations and their distance from the surface, while organic cations tend to substitute for inorganic ones. The third set of calculations aimed at testing mobility of organic model compounds within a wide-open smectite interlayer space (acting as a narrow pore model), under one-dimensional pressure. The results show significant differences in the pressure that allows expulsion of organic molecules in different systems and different ions from a narrow slit. The mobility of oil compounds depends mainly on differences in the type of molecules and the size of effective hydration sphere of the cations adsorbed on a mineral surface, which is clearly visible in the simulations.",3,3,5
Crude Oil,Pressure,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Crude Oil,Pressure,"Bu, Yuhuan; Tian, Leiju; Guo, Bingliang; Wang, Chunyu; Sun, Baojiang",Experiment and simulation on the integrity of cement ring interface in deep water shallow formation,Casing internal pressure; Integrity; Cement ring; Marine shallow formation; Shrinkage; Test device,,"The integrity of cement ring interface is critical for the safe production of crude oil and nature gas and the protection of marine environment in deep water shallow formation. Due to the slow hydration speed of the cement under low temperature and the low compaction of the weakly consolidated formation, the casing-cement-formation interfaces are prone to generate micro-annulus. In this paper, a device for testing the interface radial bond strength was designed. The test results showed that the cement-casing interface radial bond strength gradually increased with the increase of curing temperature, and the cement-formation interface radial bond strength increased with the decrease of water content in the formation. Based on ABAQUS finite element software, the tensile stress on the cement-casing interface during the reduction of casing internal pressure, and the tensile stress on the cement-formation interface during the hardening and shrinking process of cement were studied. When the casing internal pressure reduced, the hardened cement with high elastic modulus generated greater tensile stress on the cement-casing interface. The casing internal pressure reduction should not exceed 2.49, 2.75 and 5.41 MPa at the formation temperature of 4, 7 and 10 degrees C, respectively. In addition, the cement slurry used in this paper can be well bonded with the weakly consolidated formation in deep water shallow formation. This paper is of great significance to study the failure mechanism of cement ring interface integrity in deep water shallow formation, and has guidance for proposing corresponding rationalization suggestions and measures.",3,3,2
Crude Oil,Pressure,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Crude Oil,Pressure,"Naeem, Mohammad Hossein Towfighi; Dehaghani, Amir Hossein Saeedi",Evaluation of the performance of oil as a membrane during low-salinity water injection; focusing on type and concentration of salts,Smart water; Low-salinity water; Semi-permeable membrane; Osmotic pressure gradient,WETTABILITY; EOR; SANDSTONE,"Injection of low-salinity or smart water into the reservoir is one of the most common EOR techniques. This technique leads to more oil recovery in comparison to reservoir water and seawater injection. Several mechanisms explain the reasons for this increased recovery level, the most important of which is the wettability alteration towards water-wet conditions. However, in recent years, further mechanisms have been added to the previous ones as the main or complementary mechanism. One of these newly added mechanisms is the performance of oil as a semi-permeable membrane between connate and low-salinity waters. According to this mechanism, water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure (difference in chemical potential), which works as the driving force, until the system moves toward equilibrium in concentration. Introducing water molecules into connate water causes the swelling of connate water, and eventually moves the oil towards the pore throats. In this study, experiments have been performed on capillary tubes, while ignoring the effect of fluid-rock interactions to investigate the proposed theory. Experimental results confirmed the role of osmotic theory. Furthermore, a decrease in the salinity of the low-salinity water causes the oil-droplets' displacement to increase, whereas further reductions in the salinity of the injected water cause lower displacements. Therefore, there is an optimum value of low-salinity water concentration to obtain the highest possible oil drop displacement. The optimum values for the tested samples in this study were about 5000-10000 ppm. Additionally, it was found that among all of the essential seawater salts, potassium chloride leads to the highest oil drop displacement; and among oil samples, heptane showed better membrane-like performance in comparison to toluene and crude oil.",3,3,0
Crude Oil,Pressure,"Li, Lei; Hao, Yongmao; Lv, Yuting; Wang, Chengwei; Yao, Chuanjin; Zhao, Qingmin; Xiao, Pufu",Experimental investigation on low-velocity seepage characteristics and influencing factors in a shale oil reservoir,,NON-DARCY FLOW; APPARENT PERMEABILITY; GAS-TRANSPORT; NANOPORES; MULTISCALE; MODEL; ADSORPTION; MULTICOMPONENT; PERFORMANCE; SIMULATION,"The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10(-4) ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, microfractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs.",2,2,11
Crude Oil,Pressure,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Crude Oil,Pressure,"Khalid, Mozamil; Sultan, Abdullah; Noui-Mehidi, Mohamed Nabil; Al-Sarkhi, Abdelsalam; Salim, Omer",Effect of Nano-Clay Cloisite 20A on water-in-oil stable emulsion flow at different temperatures,Water-in-oil; Emulsion; Nano-Clay; Pressure drop reduction; Stable-emulsion,CRUDE-OIL; SALINITY; BEHAVIOR,"In Enhanced Oil Recovery (EOR) operations, water-in-oil emulsions are often used to ensure good sweep of the crude in the flooding process. Dispersions of 70% water in 30% oil (diesel) were extensively used to move the crude in the porous medium with good results. The present paper is concerned with a study on the influence of Cloisite 20A Nano-Clay particles particularly on the hydrodynamic performance and the stability of water-in-oil emulsions at different temperatures between 25 degrees C and 45 degrees C. The experimental results showed that the presence of Cloisite 20A stabilized the water-in-oil emulsions compared to the dispersion without Nano-Clay. It was found that the Nano-Clay concentration affects the emulsion viscosity depending on mainly the water volume fractions. In general, small quantities of the Nano-Clay reduce emulsion viscosity, while higher concentrations of the Nano-Clay resulted in a clear increase of the emulsion viscosity. The results also revealed the percentage of pressure drop reduction at different temperatures as a function of the concentration of Nano-clays, oil/water ratios and emulsion flowrates. The influence of fluid temperature on pressure drop reduction is higher than the influence of Nano-Clay concentration especially at low flowrate.",2,2,2
Crude Oil,Pressure,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Crude Oil,Pressure,"dos Santos, Lorena A.; Ribeiro, Daniel da C.; Romero, Oldrich J.",Heavy oil transportation through steam heating: An analytical and numerical approach,Viscous oils; Concentric steam pipe; Heat transfer; Steam quality; Flow assurance,NEWTONIAN FLOW CHARACTERIZATION; WATER-ALUMINA NANOFLUID; NATURAL-CONVECTION FLOW; CRUDE-OIL; VISCOSITY; BEHAVIOR; ANNULUS; MODEL,"Amongst the innumerable challenges that permeate the production chain of heavy oils, the transportation stage deserves to be highlighted. Due to its high viscosity, heavy oils exhibit considerable flow resistance, requiring auxiliary mechanisms to enable its transportation via pipelines. This study analyzes a concentric pipeline configuration, in which steam flows through the inner pipe and oil flows through the annular space of the oil pipe. The main goal is to investigate the impacts of steam insertion, concentric coupling dimensions, thermal insulation, steam quality and system horizontal length on the main parameters of flow control: oil temperature and viscosity. As a secondary parameter, oil initial pressure required to ensure flow completion is also discussed. In this intent, a numerical approach is applied with software Ansys CFX in a tridimensional, steady state simulation. A second objective is to estimate the main parameters of interest by an analytical approach, using the thermal resistance model associated with the epsilon - NTU method. The goal is to determine if, given a similar coupling scenario and the absence of computational resources, oil temperature and viscosity can be estimated by direct calculations within an acceptable range of deviation from the numerical approach. Heat transfer rates are also estimated as secondary parameters. Numerical results for a 1-m length system reveal that steam insertion elevates the average oil temperature in 1.2%, reducing its average viscosity and initial flow pressure by 8.7% and 24.2%, respectively. From the previous scenario, a reduction of 24.6% in the oil pipe/steam pipe radius ratio results in an additional 1.2% temperature increase and 4.7% viscosity reduction. On the other hand, reducing steam quality in 30% implicates an average oil viscosity 2.4% higher. In a 4-m system, a convective cell pattern is observed, in which oil heating and viscosity reduction reaches its peak at the central upper region of the annular space, highlighting cooler and denser deposits in the lower section of the system and a nonlinear heating process. Maximum deviations between numerical and analytical approaches in oil temperature and viscosity estimates are 1.3% and 15.6%, respectively, which indicate the latter as a suitable calculation method for small systems in the absence of numerical resources. Deviations are mainly attributed to the neglect of natural convection, gravitational and steam turbulence effects, which contribute for a non-homogeneous heating of oil.",1,1,1
Crude Oil,Migration,"Song, Fan; Su, Nina; Kong, Xingwu; Liu, Changjiang; Song, Chenfei","Sedimentary characteristics of humid alluvial fan and its control on hydrocarbon accumulation: A case study on the northern margin of the Junggar Basin, west China",Humid alluvial fan; Junggar Basin; Hala'alt mountain; Braided river channel; Sedimentary characteristics; Hydrocarbon accumulation,TRIASSIC RESERVOIRS; NORTHWEST CHINA; CRUDE OILS; MAHU SAG; ORIGIN; PROVENANCE; MIGRATION; SYSTEM; DELTA; AREA,"Alluvial fans in humid regions are different from arid alluvial fans for the special sedimentary characteristics and distribution pattern. In this paper, we systematically studied the sedimentary facies of Jurassic Badaowan Formation in the northern margin piedmont belt of Junggar Basin based on the comprehensive analysis of geological and geophysical data acquired. The results show that under the comprehensive influences of tectonic setting, paleo-provenance and paleo-climate, large-scaled humid alluvial fans are developed in the piedmont belt of Hala'alt mountain. The fluvial activity of alluvial fan is stronger and more stable in the humid type than that in the arid type. Three subfacies are identified in the humid alluvial fan, i.e. the upper fan, middle fan and lower fan. The middle fan can be further divided into braided river channel and the peat bog. Then we build the sedimentary facies model based on the microfacies types and distributions. This model is significantly different from arid alluvial fan in lithologic features, sedimentary sequences, distribution scales and microfacies match patterns. The reservoir distribution is mainly controlled by the favorable microfacies, lithofacies and depositional fabric. We suggest that the braided river channel glutenite lithofacies and grit lithofacies in the middle fan subfacies are the most favorable reservoir facies belt for hydrocarbon accumulation.",2,3,3
Crude Oil,Migration,"Zhu, Chuanzhen; Gang, Wenzhe; Zhao, Xianzheng; Wang, Yifan; Chen, Guo; Pu, Xiugang","The preferential pathways of oil migration in the Qi-nan slope belt of Bohai Bay Basin, China: Insights from integrated analyses using geochemical and morphology tools",Oil family; Pyrrolic nitrogen compounds; Geochemical tracing of hydrocarbon migration; Preferential migration pathways; Qi-nan slope belt; Bohai Bay Basin,PYRROLIC NITROGEN-COMPOUNDS; PETROLEUM MIGRATION; HYDROCARBON MIGRATION; QIKOU SAG; BOZHONG SUBBASIN; ORDOS BASIN; CRUDE OILS; ACCUMULATION; FIELD; CONSTRAINTS,"The Qi-nan Slope belt is located in the southwestern Qikou Sag in the Bohai Bay Basin and has had relatively little oil and gas exploration. The mechanism of oil migration remains unclear due to the lack of understanding of the oil-oil relationship, the definition of oil migration pathways, and the controversy over the contributing source rocks. Based on hierarchical cluster analysis, the crude oils in the Qi-nan Slope are divided into three groups (A, B and C) with different geochemical compositions. Group A oils, including Class A(1) and Class A(2) biodegraded oils, and Group C oils are contributed by Es-1(x) and Es-3 source rocks with different organic facies, and distributions are limited to the WXZ oilfield in the western slope. Group B oils, including Class B-1 and Class B-2 biodegraded oils, mainly originated from Es-1(x) source rocks and are widely distributed in the southern slope. The significant correlation between the relative migration distance (RMD) of oils and pyrrolic nitrogen compounds, rather than the parameters related to oil maturity, indicates that the pyrrolic nitrogen compounds can effectively trace oil migration directions in the Qi-nan Slope, and 1,8-DMC/2,6-DMC is the best indicator. For oil migration conduits, no large-scale faults developed in the inner part of the slope, and the oil-gas test results from major wells on the seismic profiles suggest that oils are mostly concentrated in Es-1(x) with no obvious vertical migration in this area. Therefore, we speculate that the Es-1(x) sand body provided the migration pathway for crude oil and controlled its uneven accumulation in the slope area. The isopleth map of the 1,8-DMC/2,6-DMC ratio, the distribution characteristics of the oil test results from major wells and the morphology of the Es-1(x) transporting layer suggest that the overall migration direction of oil was dispersedly from the Qi-nan Sub-sag to the southern areas of the slope and that structural ridges provided preferential migration pathways for hydrocarbon accumulation.",2,2,2
Crude Oil,Migration,"Song, Jianyang; Huo, Zhipeng; Fu, Guang; Hu, Ming; Sun, Tongwen; Liu, Zhe; Wang, Wei; Liu, Luofu","Petroleum migration and accumulation in the Liuchu area of Raoyang Sag, Bohai Bay Basin, China",Biomarkers; Migration and accumulation modeling; Migration direction; Physical characteristics of crude oil; Vertical migration,HYDROCARBON MIGRATION; MOLECULAR-PARAMETERS; DONGYING DEPRESSION; NITROGEN-COMPOUNDS; TOARCIAN SHALES; SOURCE ROCKS; PARIS BASIN; OIL-FIELD; SECONDARY; DISTRIBUTIONS,"This study focused on vertical migration of petroleum in the Liuchu area, China. The physical properties of petroleum and changes in the geochemical characteristics of the study area were also investigated. Biomarkers such as, nitrogen compounds, n-alkanes, triterpenoids, steroids, hopanes, and cholestanes were analyzed in this regard. Petro-physical characteristics, such as, density, viscosity, concentrations of wax, resin, and sulfur of oil were studied. The rNa(+)/rCl(-) ratio of Ed(2) formation water ranged from 0.25 to 5.7, oil density of Ed(2) formation ranged from 0.85 to 0.95 g/cm(3), and oil resin concentration 10-50%, oil wax content in Ed(2) formation ranged from 2 to 29% were lower than that of Es1. The rNa(+)/rCl(-) ratio and mineralization of formation water data were examined to demonstrate the migration pathways. Geochemical and crude oil physical indexes were utilized to investigate the relationship between petroleum migration and seismic data. Cholestane alpha beta beta, alpha alpha alpha cholestane, diacholestane, steroid, and low ring terpenes in the formation were utilized to trace petroleum migration. Recent studies on petroleum maturity of have focused on comparison of source rocks and have reported that the maturity effects of source rock and reservoir oil are weak while those effects are high in the Liuchu aera. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The alpha alpha alpha C-29 (20S)/(20S + 20R) and C-29 (beta beta)/alpha alpha + beta beta) ratios ranged from 0.2 to 0.35 Further, C-31 (22S)/(22S + 22R), C-32(22S)/(22S + 22R), and C-29 (20S)/(20S + 20R) ratios ranged from 0.3 to 0.8, and 0.131 and 0.81, respectively. Petroleum migrated along migration channels. This suggested that vertical migration occurred after formation of the source rock fault and lateral migration occurred along the sandbody. Reservoir sandstone content, overlying mudstone content, and thickness of caprock are likely limited lateral petroleum migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The results of this study enabled optimization of uncertain petroleum migration pathways and improved the petroleum migration and accumulation model.",2,2,1
Crude Oil,Migration,"Jiang, Wenlong; Imin, Ablimit; Wang, Xueyong; Wang, Tao; Guo, Wenjian","Geochemical characterization and quantitative identification of mixed-source oils from the Baikouquan and Lower Wuerhe Formations in the eastern slope of the Mahu Sag, Junggar Basin, NW China",Mixed oil; Chemometrics; Alternating least square; Mahu sag; Junggar basin,LOWER INDUS BASIN; CRUDE OILS; PETROLEUM GEOCHEMISTRY; CRETACEOUS ROCKS; TARIM BASIN; FIELD; ORIGIN,"The quantitative identification of mixed-source oil is a popular yet difficult topic in current petroleum geochemistry research. The mixed-source oils of the Baikouquan and Lower Wuerhe formations in the eastern slope of the Mahu Sag of Junggar Basin were used as a typical example in this study. Quantitative research on mixed oils was carried out in the study area and good results were obtained using an approach combining organic geochemistry and chemometrics. The results of crude oil geochemistry research show that mixed-source crude oil is ubiquitous in the study area. After comprehensive analysis, it is likely that there are three endmembers in the current mixed-source oils. Two of the endmembers may represent mainly the contribution of the early and late source rocks of the Permian Fengcheng Formation and are dominated by late filled crude oil. However, the third endmember is quite different. Its hydrocarbons may have come from the source rocks of the Permian Lower Wuerhe Formation or the source rocks of the Fengcheng Formation under different lithofacies and sedimentary environments. The study area is dominated by hydrocarbons that accumulated from the Fengcheng Formation. Although the proportion of hydrocarbons generated in the late stage is not high, it plays a very important role in hydrocarbon migration and accumulation. This comprehensive comparative study shows that the chemometric method can play an important role in calculating the proportion of mixed-source oil and in endmember analysis.",2,2,0
Crude Oil,Migration,"Han, Qiuya; Li, Meijun; Liu, Xiaoqiang; Jiang, Weidong; Shi, Shengbao; Tang, Youjun; He, Daxiang",Fractionation of alkylated carbazoles in petroleum during subsurface migration: Evidence from molecular simulation and application in sandstone reservoirs,Geo-chromatographic fractionation; Alkylcarbazole; Petroleum migration orientation; Molecular dynamics simulation; Sandstone reservoir,CHROMATOGRAPHIC SEPARATION SCHEMES; AROMATIC HETEROCYCLE FRACTIONS; PYRROLIC NITROGEN-COMPOUNDS; IN-SOURCE ROCKS; CRUDE OILS; BEIBUWAN BASIN; BENZOCARBAZOLE DISTRIBUTIONS; RAPID CHARACTERIZATION; DYNAMICS SIMULATION; ORGANIC-COMPOUNDS,"Carbazole (CA) and alkylated carbazoles are common nitrogen-containing heterocyclic aromatic compounds widely found in crude oils and sedimentary rocks extracts. Their geochemical significances in petroleum exploration have been widely investigated in previous studies. Using density functional theory (DFT) and molecular dynamics (MD) simulation, we calculated the polarity of alkylated carbazole isomers/homologues and their adsorption energy with water and alpha-quartz, respectively. The calculated results show that there are significant differences in migration fractionation effects for alkylated carbazole isomers/homologues. This study confirmed the validity of previously proposed carbazole migration indicators, i.e. 4-/1-MCA (the relative abundance of 4-methylcarbazole to 1-methylcarbazole), 2,5-/1,8-DMCA (2,5-dimethylcarbazole to 1,8-dimethylcarbazole) and 2,4-/1,8-DMCA (2,4-dimethylcarbazole to 1,8-dimethylcarbazole) on the basis of quantum chemistry and molecular simulation. All these three parameters have been successfully applied in a lacustrine sandstone reservoir in the Fushan Depression, Beibuwan Basin (South China Sea). The calculations of Gibbs free energy show that the differences in thermal stability between the isomers of alkylcarbazoles can be negligible. The source input and depositional environment have no significant effect on these indicators for oils from a same oil family. Hence, the values of these parameters are mainly controlled by subsurface petroleum migration processes. Therefore, the molecular parameters relative to alkylated carbazoles can be used as practically effective geochemical markers to trace the oil filling orientation and pathways for subsurface oil migration.",1,2,6
Crude Oil,Migration,"Chen, Junqing; Ma, Kuiyou; Pang, Xiongqi; Yang, Haijun","Secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin",Tarim basin; Lunnan area; Ordovician carbonate; Hydrocarbon secondary migration,PALEOZOIC MARINE PETROLEUM; LOWER INDUS BASIN; TABEI UPLIFT; CRUDE OILS; NW CHINA; GEOCHEMICAL CHARACTERIZATION; TAZHONG UPLIFT; ORIGIN; ACCUMULATION; GAS,"The study on the secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area has been a challenge caused by limited geologic records as direct physical evidence, and physical simulations are difficult to conduct since the parameters of realistic geologic conditions are rare. Based on the analysis of the regional structure, and by integrating the study on the fluid properties and benzocarbazole nitrogen compounds parameters, the secondary hydrocarbon migration in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin, were investigated. The results indicated oil density show gradually increasing trends from Lungudong Fault to the Middle Slope in eastern Lunnan Uplift; while the trend is converse from southwest of Lunxi and Sangtamu Faults to the Middle Slope in western area. The benzocarbazole nitrogen compounds contents of Ordovician reservoir oil exhibit gradually increasing trends from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope. The wax contents, gas dryness coefficients and gas/oil ratios show decreasing trends from east to west and away from the Lungudong Fault and Sangtamu Fault. The crude oil generated at the late Hercynian stage (about 290 Ma ago) in the Lunnan area migrated along the directions from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope; the gas formed at the late Himalayan stage (about 208 Ma ago) migrated from the east to west laterally, and along the natural gas invasion faults Lungudong Fault and Sangtamu Fault upwards vertically.",1,1,4
Crude Oil,Migration,"Li, Jingfei; Zhang, Zhiyao; Zhu, Guangyou; Li, Tingting; Zhao, Kun; Chi, Linxian; Yan, Huihui","The origin and accumulation of ultra-deep oil in Halahatang area, northern Tarim Basin",Giant oil accumulations; Ultra-deep strata; GCxGC-TOFMS; Halahatang area; Tarim basin,TABEI UPLIFT; NW CHINA; HYDROCARBON ACCUMULATION; DIAMONDOID HYDROCARBONS; THERMAL-CRACKING; CRATONIC REGION; TAZHONG AREA; NATURAL-GAS; CRUDE OILS; PETROLEUM,"The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000-8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.",1,2,0
Crude Oil,Degrees C.,"Bu, Yuhuan; Tian, Leiju; Guo, Bingliang; Wang, Chunyu; Sun, Baojiang",Experiment and simulation on the integrity of cement ring interface in deep water shallow formation,Casing internal pressure; Integrity; Cement ring; Marine shallow formation; Shrinkage; Test device,,"The integrity of cement ring interface is critical for the safe production of crude oil and nature gas and the protection of marine environment in deep water shallow formation. Due to the slow hydration speed of the cement under low temperature and the low compaction of the weakly consolidated formation, the casing-cement-formation interfaces are prone to generate micro-annulus. In this paper, a device for testing the interface radial bond strength was designed. The test results showed that the cement-casing interface radial bond strength gradually increased with the increase of curing temperature, and the cement-formation interface radial bond strength increased with the decrease of water content in the formation. Based on ABAQUS finite element software, the tensile stress on the cement-casing interface during the reduction of casing internal pressure, and the tensile stress on the cement-formation interface during the hardening and shrinking process of cement were studied. When the casing internal pressure reduced, the hardened cement with high elastic modulus generated greater tensile stress on the cement-casing interface. The casing internal pressure reduction should not exceed 2.49, 2.75 and 5.41 MPa at the formation temperature of 4, 7 and 10 degrees C, respectively. In addition, the cement slurry used in this paper can be well bonded with the weakly consolidated formation in deep water shallow formation. This paper is of great significance to study the failure mechanism of cement ring interface integrity in deep water shallow formation, and has guidance for proposing corresponding rationalization suggestions and measures.",3,3,2
Crude Oil,Degrees C.,"Dias, Heloisa P.; Barros, Eliane, V; Gomes, Alexandre O.; Moura, Robson R.; Pinto, Fernanda E.; Goncalves, Arlan S.; Aquije, Gloria M. F., V; Xu, Zhenghe; Romao, Wanderson","Corrosion rate studies of AISI 1020 steel using linear, cyclic, and aromatic naphthenic acid standards",Naphthenic acid; TAN; Carbon steel; Corrosion rate; SEM/EDX; AFM,CRUDE-OIL; CARBON-STEEL; MASS-SPECTROMETRY; SULFUR-COMPOUNDS; SPECTROSCOPY; DEGRADATION,"The use of total acid number (TAN) to measure the acidity of crude oil samples is a common practice. Daily practice in petroleum refineries shows that oil with a TAN less than 0.5 mg KOH g(-1) can usually have unexpected corrosive behavior. Although naphthenic corrosion has been studied for many years, its process is not entirely understood. Therefore, this study investigated the influence of linear, cyclic and aromatic NAs molecules, evaluating the effect of their concentrations, molar weight (M-w), structural and electronic properties on the corrosion rate of AISI 1020 steel samples at 320 degrees C. The type and extension of corrosion were determined by surface characterization of the sample using optical microscopy (LM), atomic force microscopy (AFM), and scanning electron microscopy (SEM). The results showed that even when TAN was below the detection limit, the corrosion rate (CR) value was significant (CR < 0.19 mm year(-1)) and considered high for the industry. For concentrations of benzoic (BENA) and stearic (STA) acids higher than 5000 ppm, the corrosion rate varied proportionally with the TAN. Also, there was an inverse proportional correlation between molecular weight (M-w), the number of aromatic rings and NAs corrosiveness. In general, NAs standards containing a lower molar volume were found to cause a higher corrosion rate. SEM micrographs revealed changes in the surface area of all samples exposed to linear, cyclic and aromatic NAs, indicating the formation of a protective layer under the surface of the carbon steel specimen. AFM imaging showed drastic changes in the topographic profile and phase images characterized by the formation of valleys and peaks, as well as variations in the mechanical properties of the surface of the AISI 1020 steel sample. Results obtained in this study confirm the influence of the electronicstructural properties of the molecules of organic acids on the naphthenic corrosion.",3,3,1
Crude Oil,Degrees C.,"Qu, Ming; Hou, Jirui; Liang, Tuo; Raj, Infant; Yang, Yulong; Qi, Pengpeng","Synthesis of alpha-starch based nanogel particles and its application for long-term stabilizing foam in high-salinity, high-temperature and crude oil environment",Nanogel particle; Foam stability; Viscoelasticity; High temperature tolerance; High salinity tolerance; Crude oil tolerance,RECOVERY; MIXTURES; FLUID; WATER; CO2,"Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using a-starch, acrylamide, N,N'-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T-90 as indicators at temperature of 30-120 degrees C, salinity of 0-240 g/L and oil percentage of 0-50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery.",2,2,3
Crude Oil,Degrees C.,"Wu, Nan; Wang, Jian; Cai, Zhongxian; Luo, Zhong; Lu, Xuesong; Ma, Xingzhi; Liu, Xianfeng","Discovery of Sinian source rocks in proterozoic in the Tarim Basin, NW China",Tarim basin; Kuruktag; Sinian source rocks; Hydrocarbon generation; Bitumen,ORGANIC-MATTER; CRUDE OILS; MATURITY PARAMETERS; THERMAL MATURITY; SICHUAN BASIN; GEOCHEMICAL CHARACTERISTICS; TRICYCLIC TERPANES; VELKERRI FORMATION; MCARTHUR BASIN; GRAND-CANYON,"As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50-60 degrees C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin.",2,2,3
Crude Oil,Degrees C.,"Khalid, Mozamil; Sultan, Abdullah; Noui-Mehidi, Mohamed Nabil; Al-Sarkhi, Abdelsalam; Salim, Omer",Effect of Nano-Clay Cloisite 20A on water-in-oil stable emulsion flow at different temperatures,Water-in-oil; Emulsion; Nano-Clay; Pressure drop reduction; Stable-emulsion,CRUDE-OIL; SALINITY; BEHAVIOR,"In Enhanced Oil Recovery (EOR) operations, water-in-oil emulsions are often used to ensure good sweep of the crude in the flooding process. Dispersions of 70% water in 30% oil (diesel) were extensively used to move the crude in the porous medium with good results. The present paper is concerned with a study on the influence of Cloisite 20A Nano-Clay particles particularly on the hydrodynamic performance and the stability of water-in-oil emulsions at different temperatures between 25 degrees C and 45 degrees C. The experimental results showed that the presence of Cloisite 20A stabilized the water-in-oil emulsions compared to the dispersion without Nano-Clay. It was found that the Nano-Clay concentration affects the emulsion viscosity depending on mainly the water volume fractions. In general, small quantities of the Nano-Clay reduce emulsion viscosity, while higher concentrations of the Nano-Clay resulted in a clear increase of the emulsion viscosity. The results also revealed the percentage of pressure drop reduction at different temperatures as a function of the concentration of Nano-clays, oil/water ratios and emulsion flowrates. The influence of fluid temperature on pressure drop reduction is higher than the influence of Nano-Clay concentration especially at low flowrate.",2,2,2
Crude Oil,Degrees C.,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Crude Oil,Degrees C.,"Kok, Mustafa Versan; Varfolomeev, Mikhail A.; Nurgaliev, Danis K.",The effect of water on combustion behavior of crude oils,Water content; Crude oil; Combustion; TGA; DSC; Kinetic analysis,LOW-TEMPERATURE; OXIDATION,"The ramped temperature oxidation experiments were performed on heavy and light crude oil samples using the TGA and DSC instruments. The crude oils were mixed with different weight percentages (10%, 20%, and 30%) of water, as a result of which six different water-oil mixtures were prepared. The samples were heated up to 800 degrees C with three heating rates 20, 25, 30 degrees C/min. Two reaction regions, particularly the low temperature oxidation (LTO) and high temperature oxidation (HTO), were identified in TGA and DSC results. The LTO region can be divided into two subzones as before and after around 150 degrees C. In the first subzone, up to around 150 degrees C, the endothermic distillation process took place. The results showed that light crude oil and its mixtures had lower reaction starting and ending temperatures, and peak temperatures compared to heavy crude oil and its mixtures. As the water amount in the mixtures were increased, the reaction and peak temperatures shifted to lower temperatures. The kinetic analysis was also performed applying the Ozawa-Flynn-Wall (OFW), Kissenger-Akahira-Sunose (KAS), and ASTM kinetic methods. The activation energies and Arrhenius constants based on the TGA and DSC results were calculated accordingly. The light crude oil and its water mixtures had lower activation energy and Arrhenius constants compared to heavy crude oil and its mixtures. As the amount of water in the mixture was increased, the activation energy and Arrhenius constant decreased, which indicated that the presence of water in the crude oil increases its ability to combust more efficiently.",1,1,1
Crude Oil,Surface,"Szczerba, Marek; McCarty, Douglas K.; Derkowski, Arkadiusz; Kowalik, Mariola",Molecular dynamics simulations of interactions of organic molecules found in oil with smectite: Influence of brine chemistry on oil recovery,Molecular dynamics; Oil shale; Porosity; Low salinity water flooding,SALINITY; CHARGE; WATER; SURFACES; POROSITY; ILLITE,"The study is aimed at employing molecular dynamics simulations to study the interactions between smectite and major oil constituents, along with the impact of different brine chemistry (type of cation in a solution) and ionic strength on the compound mobility in fine pores. Clay minerals with smectitic type of mineral outer surface (smectite, illite-smectite, illite) are major constituents in many unconventional oil and gas reservoirs. Therefore, smectite was used as a model compound to test interactions of oil compounds with mineral surfaces. Natural crude oil is a complex mixture, which - for the purpose of simulating an influence of surrounding fluid on its interactions with smectite surfaces - needs to be simplified. The following molecules were selected as organic model compounds: decane, quinolone, nonanoic acid, benzamide, and heptylamine. Various protonation states were considered. The first two sets of simulations showed remarkably different interactions of the selected organic molecules with the smectite surface. In the first one, three water/oil coverage models of the surface were considered. In the second one, two different pore sizes were taken into account: 3 nm and 5 nm. Significant differences were readably visible between polar and non-polar organic molecules. Also, the degree of protonation was found to be a crucial factor affecting the molecules' affinity to the mineral surface. The molecules that are well soluble in cyclohexane (here representing crude hydrocarbons phase) formed droplets in the water phase, whereas organic compounds miscible in water were concentrated at the water-monolayer film on the smectite surface. Neutral organic molecules in the interlayer influences hydration spheres of the cations and their distance from the surface, while organic cations tend to substitute for inorganic ones. The third set of calculations aimed at testing mobility of organic model compounds within a wide-open smectite interlayer space (acting as a narrow pore model), under one-dimensional pressure. The results show significant differences in the pressure that allows expulsion of organic molecules in different systems and different ions from a narrow slit. The mobility of oil compounds depends mainly on differences in the type of molecules and the size of effective hydration sphere of the cations adsorbed on a mineral surface, which is clearly visible in the simulations.",3,3,5
Crude Oil,Surface,"Klimenko, Alexandra; Molinier, Valerie; Bourrel, Maurice",Mechanisms underlying the adhesion of crude oil to mineral surfaces: Relevance of oil-brine interactions,Wettability; Low salinity; Contact angle; Washburn capillary rise method; Flotation test,ORGANIC-ACIDS; CONTACT-ANGLE; WETTABILITY; WATER; RECOVERY; ADSORPTION; SANDSTONE; SALINITY; CALCITE,"The wettability state of mineral surface relative to water and oil is a key factor for crude oil recovery from reservoirs. It appears particularly relevant to EOR by low salinity brine, where change towards water wettability is often presented as a crucial factor. The purpose of this paper is to demonstrate the importance of the adsorption onto the mineral surface of species extracted from crude oils by the aqueous phase. The transfer of endogenous oil species during oil-water contact is evidenced by Total Organic Carbon, pH, interfacial tension and surface tension measurements for three different crude oils. The impact of the presence of these species on the wettability state of solid surfaces (silica and carbonate) is studied by using n-octane as a probe liquid. Contact angle measurements, Washburn capillary rise and flotation tests were carried out to evidence the hydrophobation of the surface. Interfacial tension is systematically taken into account to interpret contact angle and capillary rise results by calculating the adhesion tension, a quantity of thermodynamic significance. The effect of changes of water composition (salinity, pH) on oil adhesion is carefully investigated, and the efficiency of low salinity brine to decrease the adhesion of oil to the substrate, i.e. to remove the organic species adsorbed onto the surface, is evaluated. The importance of running wettability measurements with synthetic brine previously equilibrated with the crude oil is demonstrated.",3,3,4
Crude Oil,Surface,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Crude Oil,Surface,"Dias, Heloisa P.; Barros, Eliane, V; Gomes, Alexandre O.; Moura, Robson R.; Pinto, Fernanda E.; Goncalves, Arlan S.; Aquije, Gloria M. F., V; Xu, Zhenghe; Romao, Wanderson","Corrosion rate studies of AISI 1020 steel using linear, cyclic, and aromatic naphthenic acid standards",Naphthenic acid; TAN; Carbon steel; Corrosion rate; SEM/EDX; AFM,CRUDE-OIL; CARBON-STEEL; MASS-SPECTROMETRY; SULFUR-COMPOUNDS; SPECTROSCOPY; DEGRADATION,"The use of total acid number (TAN) to measure the acidity of crude oil samples is a common practice. Daily practice in petroleum refineries shows that oil with a TAN less than 0.5 mg KOH g(-1) can usually have unexpected corrosive behavior. Although naphthenic corrosion has been studied for many years, its process is not entirely understood. Therefore, this study investigated the influence of linear, cyclic and aromatic NAs molecules, evaluating the effect of their concentrations, molar weight (M-w), structural and electronic properties on the corrosion rate of AISI 1020 steel samples at 320 degrees C. The type and extension of corrosion were determined by surface characterization of the sample using optical microscopy (LM), atomic force microscopy (AFM), and scanning electron microscopy (SEM). The results showed that even when TAN was below the detection limit, the corrosion rate (CR) value was significant (CR < 0.19 mm year(-1)) and considered high for the industry. For concentrations of benzoic (BENA) and stearic (STA) acids higher than 5000 ppm, the corrosion rate varied proportionally with the TAN. Also, there was an inverse proportional correlation between molecular weight (M-w), the number of aromatic rings and NAs corrosiveness. In general, NAs standards containing a lower molar volume were found to cause a higher corrosion rate. SEM micrographs revealed changes in the surface area of all samples exposed to linear, cyclic and aromatic NAs, indicating the formation of a protective layer under the surface of the carbon steel specimen. AFM imaging showed drastic changes in the topographic profile and phase images characterized by the formation of valleys and peaks, as well as variations in the mechanical properties of the surface of the AISI 1020 steel sample. Results obtained in this study confirm the influence of the electronicstructural properties of the molecules of organic acids on the naphthenic corrosion.",3,3,1
Crude Oil,Surface,"Huang, Weiqiu; Wang, Shuang; Jing, Haibo; Wang, Cheng; Sun, Xianhang; Zhou, Ning; Fang, Jie; Fu, Lipei",A calculation method for simulation and evaluation of oil vapor diffusion and breathing loss in a dome roof tank subjected to the solar radiation,Dome roof tank; Oil static breathing loss; Heat transfer; Mass transfer; Solar radiation; Computational fluid dynamics (CFD),NUMERICAL-SIMULATION; STORAGE TANKS; HEAT-TRANSFER; CRUDE-OIL; EXPOSURE; FLOW,"The dome roof tank (DRT) is always a main equipment for oil products storage. However, the mechanism of the heat and mass transfer for the oil vapor-air in the tank gas space remains unclear when the DRT is subjected to the solar radiation. Therefore, by considering storage conditions (e.g., the solar radiation intensity and liquid height) and taking n-hexane as a representative of light oils, and based on the Fluent software and user-defined functions (UDFs) programming, a two-dimensional calculation method and the relevant theoretical model were numerically developed to simulate and reveal the transfer mechanism under the complex storage process. Meanwhile, the feasibility of the model was verified by a self-built experimental platform for the DRT evaporation loss investigation. Under the solar radiation to a 1000 m(3) DRT, the simulation results show: (1) The gas space temperature distribution can be accurately calculated, and the average temperature decreases with increasing liquid level; (2) There is a distinct counterclockwise eddy and an evident velocity boundary layer close to the wall and roof of the gas space, and the maximal gas velocity is within 0.08-0.49 m s(-1), which is closely related with the storage liquid height and time; (3) The vapor concentration in the gas space increases from top to bottom with an obvious high-concentration layer near the liquid surface, and the average concentration increases with increasing liquid level and storage time; (4) The static breathing losses increase positively with the liquid level. The mean daily loss rates for n-hexane are approximately 7.37 g t(-1), 20.9 g t(-1), and 6.36 g t(-1) for the spring equinox, summer solstice, and winter solstice, respectively. Further, the year-mean daily loss rates are about-11.5 g t(-1), and 20.1 g t(-1) for n-hexane and gasoline, respectively, and the correspondingly the total loss rates for a year are about 4.2 kg t(-1) and 7.35 kg t(-1). The research results can provide important theoretical support and design reference for reducing the breathing loss and improving the enterprise management level.",2,2,1
Crude Oil,Surface,"Lopez, Daniel; Zabala, Richard D.; Cardenas, Jose C.; Lopera, Sergio H.; Riazi, Masoud; Franco, Camilo A.; Cortes, Farid B.",A novel design of silica-based completion nanofluids for heavy oil reservoirs,Adsorption; Completion nanofluid; Interfacial tension; Silica nanoparticles; Surfactant; Wettability,WETTABILITY ALTERATION; INTERFACIAL-TENSION; SURFACE-ROUGHNESS; NANOPARTICLES; GAS; RECOVERY; WATER; ADSORPTION; PRODUCTIVITY; MODEL,"The main objective of this manuscript is the design of completion nanofluids (NanoCF) using silica nanoparticles based on the impact on the capillary number for being applied in heavy crude oil reservoirs. Six types of silica nanoparticles with different chemical nature were characterized by dynamic light scattering (DLS), point of zero charge (pHpzc), Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), surface area (S-BET), X-ray diffraction (XRD) and total surface acidity through temperature-programmed desorption of NH3 (TPD-NH3). Adsorption isotherms were constructed for understanding the non-ionic surfactant interaction with nanoparticles and rock surfaces, showing that a high adsorption affinity of the surfactant onto the rock surface, leaving less than 24% of free surfactant molecules able to migrate to the water/oil interface. Nevertheless, nanoparticle addition onto completion fluids (CF) could reduce the adsorbed surfactant onto the rock surface by 75%, which means more molecules of surfactant at the interface due to the nature of the obtained nanoparticles (NPS). The nanoparticles were selected based on the capillary number, showing that the best material reduced the interfacial tension between heavy crude oil and CF more than 76% and have the capacity to modify an initial oil-wet state to a water-wet rock surface. Finally, a coreflooding test was carried out at reservoir conditions (158 degrees F and 6.89 MPa) for evaluating the best completion nanofluid design based on the static tests, showing an increase of the oil effective permeability of 37% and incremental oil recovery of 3% in comparison to the completion fluid without nanoparticles. For the first time, novel completion nanofluids could allow stimulating the well from the beginning of the productive life.",2,2,0
Crude Oil,Surface,"Khajepour, Hamideh; Amiri, Hossein Ali Akhlaghi; Ayatollahi, Shahab","Effects of salinity, ion type, and aging time on the crude oil-brine interfacial properties under gravity condition",Fluid-fluid interface; Interfacial properties; Rest time; Spreading time; Salinity,IN-WATER EMULSIONS; 2-PHASE FLOW; COALESCENCE; ASPHALTENE; TENSION; RECOVERY; DROPLETS; SYSTEMS; RESIN; VISCOELASTICITY,"In this study, the impacts of salinity, ion type, and aging process were investigated on coalescence and spreading of crude oil interfaces (including an oil droplet and an oil film) under gravity, through drop rest time measurement techniques, aided by an image analysis system. Three different salt solutions of NaCl, Na2SO4, and MgCl2 were studied at different ionic strengths, ranged from 1% to 150% of Persian Gulf seawater ionic strength. According to the results, aging the oil droplet in the brine increased the interfacial rigidity. Addition of a gas phase - by thinning the surface oil film - almost doubled both rest time and spreading time values. In the aged mode, the presence of salt in the water phase increased both rest time and spreading time, depending on the salt type and concentration. Increasing salinity, especially in the case of MgCl2 and Na2SO4 salt solutions, resulted in higher interfacial rigidity and lower oil-brine interfacial tension.",1,1,1
Crude Oil,Injection,"Salehpour, Mohammad; Riazi, Masoud; Malayeri, M. Reza; Seyyedi, Mojtaba",CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage,"Carbon capture, and storage (CCS); Carbon capture, utilization, and storage (CCUS); Carbonated water injection; Heavy asphaltic crude oil; Water-in-oil emulsion; Enhanced oil recovery",PORE-SCALE MECHANISMS; WATER INJECTION; INTERFACIAL-TENSION; WETTABILITY ALTERATION; CO2 INJECTION; PERFORMANCE; SECONDARY; SCENARIOS; EMULSIONS; DIOXIDE,"Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsioninduced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.",3,3,4
Crude Oil,Injection,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Crude Oil,Injection,"Luan, Jian; Dong, Pingchuan; Zheng, Jilong",Experimental studies on reaction laws during the process of air injection into the oil reservoirs with low permeability,Low permeability sandstone oil reservoir; Air injection; Static experiments; Low temperature oxidation; Formula,PERFORMANCE; IOR,"The low permeability oil reservoirs are widely distributed in the world, but difficult to develop with the traditional methods due to the low permeability and poor injection properties. Air injection technique not only has the common characteristics of other gas injection techniques, but also can improve the quality of crude oil in situ because of the oxidative ability of the injected air, with a unique advantage in developing low permeability reservoirs. In order to study the reaction regularity between the hydrocarbon components in crude oil under different conditions with the oxygen in the injected air, this experiment is designed for a low permeability sandstone reservoir. In this experiment, one set of self-designed static low-temperature oxidation equipment (including injection pump and high-temperature high-pressure reactor with sampling outlets) has been used. Through analysis of the results of the chromatography for over 60 oil and gas samples, conclusions can be made that after low temperature oxidation (LTO) reactions between the crude oil and the oxygen in the injected air, the concentration of the heavy components in crude oil decreased, and the concentration of the light components increased. By injecting oxygen-reduced air with 8% of oxygen, the concentration of the heavy components of crude oil in the target reservoir reduced most obviously. The formation water and associated gas can hinder the pyrolysis of heavy components, while the minerals in the formation can accelerate the pyrolysis process. The relationship between the carbon atoms number in each of the most consumed hydrocarbon molecule and different LTO reaction conditions has been proposed. According to the sensitivity analysis, it is believed that the influence of the formation water on the LTO reactions is greater than that of minerals in the formation, and influence of associated gas is less than that of minerals. Finally, combined the related physical and chemical theories, a LTO chemical reaction equation has been put forward for the targeted low permeability oil reservoir. The conclusions of the studies can provide some references for the indoor experiments and field applications of air injection in the future.",3,3,2
Crude Oil,Injection,"Behnous, Dounya; Palma, Andre; Zeraibi, Noureddine; Coutinho, Joao A. P.",Modeling asphaltene precipitation in Algerian oilfields with the CPA EoS,Asphaltene; Cubic plus association; Equation of state; Live oil,CUBIC-PLUS-ASSOCIATION; PC-SAFT CHARACTERIZATION; PHASE-BEHAVIOR; GAS INJECTION; CRUDE OILS; RESINS; PREDICTION; STABILITY,"One of the major flow assurance problems afflicting the oil industry is the asphaltene precipitation during the production, transportation and storage of oil. The precipitation of these heavy compounds is responsible for changes in crude oil properties, increases in oil viscosity, and formation of deposits that reduce oil production and disable equipment leading to significant operational costs. In Algeria, the deposition of asphaltene in reservoirs and pipelines is a severe problem. During production the depressurization of reservoir fluid and the variations of thermodynamic conditions create the need to frequently pig the lines and, in some cases, to inject solvents and dispersants to maintain the production. The understanding of the asphaltene behavior and the prediction of its deposition in flow conditions is crucial to implement appropriate strategies for the prevention or remediation, especially in the wellbore region. In this work we used the CPA EoS to describe the asphaltene phase envelope and predict the PT regions of stability for five Algerian live oils. The model provides a very good description of the experimental behavior of live oils without and with gas injection. The sensitivity to SARA analysis data and its effect on the asphaltene phase boundaries were also analyzed.",3,3,1
Crude Oil,Injection,"Naeem, Mohammad Hossein Towfighi; Dehaghani, Amir Hossein Saeedi",Evaluation of the performance of oil as a membrane during low-salinity water injection; focusing on type and concentration of salts,Smart water; Low-salinity water; Semi-permeable membrane; Osmotic pressure gradient,WETTABILITY; EOR; SANDSTONE,"Injection of low-salinity or smart water into the reservoir is one of the most common EOR techniques. This technique leads to more oil recovery in comparison to reservoir water and seawater injection. Several mechanisms explain the reasons for this increased recovery level, the most important of which is the wettability alteration towards water-wet conditions. However, in recent years, further mechanisms have been added to the previous ones as the main or complementary mechanism. One of these newly added mechanisms is the performance of oil as a semi-permeable membrane between connate and low-salinity waters. According to this mechanism, water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure (difference in chemical potential), which works as the driving force, until the system moves toward equilibrium in concentration. Introducing water molecules into connate water causes the swelling of connate water, and eventually moves the oil towards the pore throats. In this study, experiments have been performed on capillary tubes, while ignoring the effect of fluid-rock interactions to investigate the proposed theory. Experimental results confirmed the role of osmotic theory. Furthermore, a decrease in the salinity of the low-salinity water causes the oil-droplets' displacement to increase, whereas further reductions in the salinity of the injected water cause lower displacements. Therefore, there is an optimum value of low-salinity water concentration to obtain the highest possible oil drop displacement. The optimum values for the tested samples in this study were about 5000-10000 ppm. Additionally, it was found that among all of the essential seawater salts, potassium chloride leads to the highest oil drop displacement; and among oil samples, heptane showed better membrane-like performance in comparison to toluene and crude oil.",3,3,0
Crude Oil,Injection,"Qu, Ming; Hou, Jirui; Liang, Tuo; Raj, Infant; Yang, Yulong; Qi, Pengpeng","Synthesis of alpha-starch based nanogel particles and its application for long-term stabilizing foam in high-salinity, high-temperature and crude oil environment",Nanogel particle; Foam stability; Viscoelasticity; High temperature tolerance; High salinity tolerance; Crude oil tolerance,RECOVERY; MIXTURES; FLUID; WATER; CO2,"Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using a-starch, acrylamide, N,N'-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T-90 as indicators at temperature of 30-120 degrees C, salinity of 0-240 g/L and oil percentage of 0-50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery.",2,2,3
Crude Oil,Injection,"Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Crude Oil,"Low Temperature Oxidation,Low-temperature Oxidation","Luan, Jian; Dong, Pingchuan; Zheng, Jilong",Experimental studies on reaction laws during the process of air injection into the oil reservoirs with low permeability,Low permeability sandstone oil reservoir; Air injection; Static experiments; Low temperature oxidation; Formula,PERFORMANCE; IOR,"The low permeability oil reservoirs are widely distributed in the world, but difficult to develop with the traditional methods due to the low permeability and poor injection properties. Air injection technique not only has the common characteristics of other gas injection techniques, but also can improve the quality of crude oil in situ because of the oxidative ability of the injected air, with a unique advantage in developing low permeability reservoirs. In order to study the reaction regularity between the hydrocarbon components in crude oil under different conditions with the oxygen in the injected air, this experiment is designed for a low permeability sandstone reservoir. In this experiment, one set of self-designed static low-temperature oxidation equipment (including injection pump and high-temperature high-pressure reactor with sampling outlets) has been used. Through analysis of the results of the chromatography for over 60 oil and gas samples, conclusions can be made that after low temperature oxidation (LTO) reactions between the crude oil and the oxygen in the injected air, the concentration of the heavy components in crude oil decreased, and the concentration of the light components increased. By injecting oxygen-reduced air with 8% of oxygen, the concentration of the heavy components of crude oil in the target reservoir reduced most obviously. The formation water and associated gas can hinder the pyrolysis of heavy components, while the minerals in the formation can accelerate the pyrolysis process. The relationship between the carbon atoms number in each of the most consumed hydrocarbon molecule and different LTO reaction conditions has been proposed. According to the sensitivity analysis, it is believed that the influence of the formation water on the LTO reactions is greater than that of minerals in the formation, and influence of associated gas is less than that of minerals. Finally, combined the related physical and chemical theories, a LTO chemical reaction equation has been put forward for the targeted low permeability oil reservoir. The conclusions of the studies can provide some references for the indoor experiments and field applications of air injection in the future.",3,3,2
Crude Oil,"Low Temperature Oxidation,Low-temperature Oxidation","Zhao, Shuai; Pu, Wanfen; Varfolomeev, Mikhail A.; Liu, Yigang; Liu, Zhezhi",Oxidation characteristics of heavy oil and its SARA fractions during combustion using TG-FTIR,Oxidation characteristics; Heavy oil; SARA fractions; Combustion; TG-FTIR,LOW-TEMPERATURE OXIDATION; IN-SITU COMBUSTION; CRUDE-OIL; THERMAL-DECOMPOSITION; KINETIC-ANALYSIS; PYROLYSIS; BEHAVIOR; MECHANISM; LIGHT; PARAMETERS,"The oxidation reactions between air and crude oils play a key role in in-situ combustion (ISC). This study is intended to explore the oxidation characteristics of one heavy oil and its SARA fractions by thermogravimetry associated with Fourier transform infrared spectroscopy (TG-FTIR). The results indicated the release behavior of typical evolved gases (hydrocarbons, CO2, CO, and H2O) during oxidation for the oil and its SARA fractions existed huge difference because of different structures and compositions. The heavy oil encountered appreciable weight loss at the low temperature oxidation (LTO) region where hydrocarbons, CO2, H2O, etc., were released. Quite a few coke could be formed from the LTO residue of heavy oil during fuel deposition (FD), thus resulting in a pronounced high temperature oxidation (HTO) stage characterized with apparent mass loss and one notably sharp peak of CO2. Saturates experienced a great amount of mass loss and release of hydrocarbons in the LTO regime. Aromatics showed obvious LTO and FD intervals in terms of mass loss and evolved gases, but its most of intermediate products during FD were evaporated with the temperature leading to the occurrence of weak HTO reactions. Resins was subjected to a small amount of mass loss and release of hydrocarbons and H2O in the LTO interval, and some of its intermediate products during FD formed coke through condensation reactions, which consequently led to a pronounced HTO stage. For asphaltenes, almost no hydrocarbons, CO2 and CO were released in the LTO region, and most of intermediate products at the initial FD stage condensed with each other to form coke. During HTO of asphaltenes, an extremely distinctive peak of CO2 and a small shoulder peak of CO and H2O were observed, verifying the occurrence of fierce combustion reactions.",1,1,4
Crude Oil,"Low Temperature Oxidation,Low-temperature Oxidation","Pei, Shufeng; Huang, Lijuan; Zhang, Liang; Ren, Shaoran",Experimental study on thermal cracking reactions of ultra-heavy oils during air injection assisted in-situ upgrading process,Ultra-heavy oil; Thermal cracking; Low temperature oxidation reaction; Kinetic modeling; In-situ upgrading; In-situ combustion,LOW-TEMPERATURE OXIDATION; NUMERICAL-SIMULATION; RECOVERY MECHANISM; STEAM STIMULATION; CRUDE-OIL; COMBUSTION; LIGHT; PERFORMANCE; RESERVOIRS; FIELD,"In-situ upgrading (ISU) via down-hole heating can be an effective technique for exploitation of heavy oil reservoirs. In order to increase the heat transfer rate and reservoir energy, air or gas injection assisted in-situ upgrading process (AAISU) has been proposed. In the AAISU process, and also in the traditional in-situ combustion (ISC) process, complex thermal cracking reactions of heavy oils occur along with low temperature oxidation (LTO) in the presence of air or oxygen at high pressure conditions. In comparison with the conventional oil cracking or pyrolysis in refinery (without or with less oxygen), it has been concerned that low temperature oxidation of oil components during air injection may have some impacts on their cracking reactions. In this study, thermal cracking experiments of ultra-heavy oils in small batch reactor as well as thermogravimetry analysis (TGA) experiments have been conducted under high pressure in the presence of air and nitrogen to simulate the AAISU process. The starting temperature for cracking, the products of cracking reactions, reaction rate, and the influence of temperature and pressure on reaction kinetics have been investigated in order to reveal the influence of LTO on cracking reaction and to clarify the confusions. The experimental results demonstrated that the presence of air has some kind negative effect on the cracking of oils compared with that in the presence of nitrogen. For a typical ultra-heavy oil, the minimum starting temperature for cracking is around 350 degrees C in the presence of air at 3.2 MPa for a reaction time of over 30 days, while the starting temperature is around 325 degrees C when nitrogen is present. Less light oil components produced and lower cracking reaction rate (about 20-30%) were observed when air was present in comparison with that of nitrogen at the same pressure. That means higher activation energy is required to activate the thermal cracking reaction of oils when air or LTO reactions are involved.",1,1,2
Crude Oil,"Low Temperature Oxidation,Low-temperature Oxidation","Kok, Mustafa Versan; Varfolomeev, Mikhail A.; Nurgaliev, Danis K.",The effect of water on combustion behavior of crude oils,Water content; Crude oil; Combustion; TGA; DSC; Kinetic analysis,LOW-TEMPERATURE; OXIDATION,"The ramped temperature oxidation experiments were performed on heavy and light crude oil samples using the TGA and DSC instruments. The crude oils were mixed with different weight percentages (10%, 20%, and 30%) of water, as a result of which six different water-oil mixtures were prepared. The samples were heated up to 800 degrees C with three heating rates 20, 25, 30 degrees C/min. Two reaction regions, particularly the low temperature oxidation (LTO) and high temperature oxidation (HTO), were identified in TGA and DSC results. The LTO region can be divided into two subzones as before and after around 150 degrees C. In the first subzone, up to around 150 degrees C, the endothermic distillation process took place. The results showed that light crude oil and its mixtures had lower reaction starting and ending temperatures, and peak temperatures compared to heavy crude oil and its mixtures. As the water amount in the mixtures were increased, the reaction and peak temperatures shifted to lower temperatures. The kinetic analysis was also performed applying the Ozawa-Flynn-Wall (OFW), Kissenger-Akahira-Sunose (KAS), and ASTM kinetic methods. The activation energies and Arrhenius constants based on the TGA and DSC results were calculated accordingly. The light crude oil and its water mixtures had lower activation energy and Arrhenius constants compared to heavy crude oil and its mixtures. As the amount of water in the mixture was increased, the activation energy and Arrhenius constant decreased, which indicated that the presence of water in the crude oil increases its ability to combust more efficiently.",1,1,1
Crude Oil,Bohai Bay Basin,"Wang, Qi; Hao, Fang; Xu, Changgui; Zou, Huayao","Paleolimnological environments and the formation of high quality source rocks in the Bohai Bay Basin: An integrated geochemical study of biomarkers, stable carbon and oxygen isotopes, and trace elements",Source rocks; Biomarkers; Carbon isotopic compositions; Bohai Bay basin (BBB),LACUSTRINE SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; SHIJIUTUO UPLIFT; ORGANIC-MATTER; EVAL PYROLYSIS; LIAODONG BAY; LAKE; PETROLEUM; EVOLUTION,"Fourteen Paleogene rock samples from the Bohai Bay Basin, including samples from the third member of the Oligocene Dongying Formation (Ed(3)) and the third member of the Eocene Shahejie Formation (Es-3), underwent total organic carbon (TOC) analysis, Rock-Eval pyrolysis, stable carbon (delta C-13(carb)) and oxygen isotope (delta O-18(carb)) analysis of carbonates, stable carbon isotope analysis of organic matter (delta C-13(om)), biomarker and trace element compositional analysis to reconstruct paleolimnological environments and investigate the factors that control the occurrence of high quality source rocks. The Rock-Eval and TOC results revealed that the source rocks meet the standard for good to excellent source rocks. The biomarker parameters and trace elements suggest that warm and humid paleolimnological conditions prevailed during the deposition of Es-3. In addition, heavier values of delta C-13(om) and light values of delta O-18(carb) indicate the existence of a hydrologically open paleolake with high primary productivity, which is supported by relatively high 4-methyl sterane index values and high barium/calcium (Ba/Ca) ratios. Ed(3) rocks formed under less reducing and more acidic conditions, which is supported by high pristane/phytane, C-27 diasteranes/C-27 regular steranes and kaolinite/illite ratios and low strontium/barium (Sr/Ba) and vanadium/chromium (V/Cr) ratios. Moreover, Ed(3) is characterized by a relatively high input of terrestrial organic matter under humid but cooler settings. A long-term positive shift of delta O-18(carb) revealed by the Ed(3) samples is associated with changes in oxygen isotopic composition of inflow water (higher precipitation) and temperature (colder). The conditions of both high productivity and enhanced preservation controlled the distribution of good source rocks in the Bohai Bay Basin (BBB). Es-3 is more likely linked with high primary productivity, which resulted in an overall positive shift in delta C-13(om), whereas Ed(3y) may be more related to favourable preservation conditions associated with relatively high sedimentation rates.",2,3,3
Crude Oil,Bohai Bay Basin,"Zhu, Chuanzhen; Gang, Wenzhe; Zhao, Xianzheng; Wang, Yifan; Chen, Guo; Pu, Xiugang","The preferential pathways of oil migration in the Qi-nan slope belt of Bohai Bay Basin, China: Insights from integrated analyses using geochemical and morphology tools",Oil family; Pyrrolic nitrogen compounds; Geochemical tracing of hydrocarbon migration; Preferential migration pathways; Qi-nan slope belt; Bohai Bay Basin,PYRROLIC NITROGEN-COMPOUNDS; PETROLEUM MIGRATION; HYDROCARBON MIGRATION; QIKOU SAG; BOZHONG SUBBASIN; ORDOS BASIN; CRUDE OILS; ACCUMULATION; FIELD; CONSTRAINTS,"The Qi-nan Slope belt is located in the southwestern Qikou Sag in the Bohai Bay Basin and has had relatively little oil and gas exploration. The mechanism of oil migration remains unclear due to the lack of understanding of the oil-oil relationship, the definition of oil migration pathways, and the controversy over the contributing source rocks. Based on hierarchical cluster analysis, the crude oils in the Qi-nan Slope are divided into three groups (A, B and C) with different geochemical compositions. Group A oils, including Class A(1) and Class A(2) biodegraded oils, and Group C oils are contributed by Es-1(x) and Es-3 source rocks with different organic facies, and distributions are limited to the WXZ oilfield in the western slope. Group B oils, including Class B-1 and Class B-2 biodegraded oils, mainly originated from Es-1(x) source rocks and are widely distributed in the southern slope. The significant correlation between the relative migration distance (RMD) of oils and pyrrolic nitrogen compounds, rather than the parameters related to oil maturity, indicates that the pyrrolic nitrogen compounds can effectively trace oil migration directions in the Qi-nan Slope, and 1,8-DMC/2,6-DMC is the best indicator. For oil migration conduits, no large-scale faults developed in the inner part of the slope, and the oil-gas test results from major wells on the seismic profiles suggest that oils are mostly concentrated in Es-1(x) with no obvious vertical migration in this area. Therefore, we speculate that the Es-1(x) sand body provided the migration pathway for crude oil and controlled its uneven accumulation in the slope area. The isopleth map of the 1,8-DMC/2,6-DMC ratio, the distribution characteristics of the oil test results from major wells and the morphology of the Es-1(x) transporting layer suggest that the overall migration direction of oil was dispersedly from the Qi-nan Sub-sag to the southern areas of the slope and that structural ridges provided preferential migration pathways for hydrocarbon accumulation.",2,2,2
Crude Oil,Bohai Bay Basin,"Song, Jianyang; Huo, Zhipeng; Fu, Guang; Hu, Ming; Sun, Tongwen; Liu, Zhe; Wang, Wei; Liu, Luofu","Petroleum migration and accumulation in the Liuchu area of Raoyang Sag, Bohai Bay Basin, China",Biomarkers; Migration and accumulation modeling; Migration direction; Physical characteristics of crude oil; Vertical migration,HYDROCARBON MIGRATION; MOLECULAR-PARAMETERS; DONGYING DEPRESSION; NITROGEN-COMPOUNDS; TOARCIAN SHALES; SOURCE ROCKS; PARIS BASIN; OIL-FIELD; SECONDARY; DISTRIBUTIONS,"This study focused on vertical migration of petroleum in the Liuchu area, China. The physical properties of petroleum and changes in the geochemical characteristics of the study area were also investigated. Biomarkers such as, nitrogen compounds, n-alkanes, triterpenoids, steroids, hopanes, and cholestanes were analyzed in this regard. Petro-physical characteristics, such as, density, viscosity, concentrations of wax, resin, and sulfur of oil were studied. The rNa(+)/rCl(-) ratio of Ed(2) formation water ranged from 0.25 to 5.7, oil density of Ed(2) formation ranged from 0.85 to 0.95 g/cm(3), and oil resin concentration 10-50%, oil wax content in Ed(2) formation ranged from 2 to 29% were lower than that of Es1. The rNa(+)/rCl(-) ratio and mineralization of formation water data were examined to demonstrate the migration pathways. Geochemical and crude oil physical indexes were utilized to investigate the relationship between petroleum migration and seismic data. Cholestane alpha beta beta, alpha alpha alpha cholestane, diacholestane, steroid, and low ring terpenes in the formation were utilized to trace petroleum migration. Recent studies on petroleum maturity of have focused on comparison of source rocks and have reported that the maturity effects of source rock and reservoir oil are weak while those effects are high in the Liuchu aera. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The alpha alpha alpha C-29 (20S)/(20S + 20R) and C-29 (beta beta)/alpha alpha + beta beta) ratios ranged from 0.2 to 0.35 Further, C-31 (22S)/(22S + 22R), C-32(22S)/(22S + 22R), and C-29 (20S)/(20S + 20R) ratios ranged from 0.3 to 0.8, and 0.131 and 0.81, respectively. Petroleum migrated along migration channels. This suggested that vertical migration occurred after formation of the source rock fault and lateral migration occurred along the sandbody. Reservoir sandstone content, overlying mudstone content, and thickness of caprock are likely limited lateral petroleum migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The results of this study enabled optimization of uncertain petroleum migration pathways and improved the petroleum migration and accumulation model.",2,2,1
Crude Oil,Bohai Bay Basin,"Ma, Ling; Zhang, Yang; Zhang, Zhihuan; Zhang, Guanlong; Wang, Shengzhu","The geochemical characteristics of the Fengcheng Formation source rocks from the Halaalate area, Junggar Basin, China",Lacustrine source rock; Biomarkers; Stable carbon isotopes; Organic geochemistry; Fengcheng Formation; Junggar Basin,LACUSTRINE SOURCE ROCKS; PERMIAN LUCAOGOU FORMATION; PHOTIC ZONE EUXINIA; BOHAI BAY BASIN; ORGANIC-MATTER; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; PETROGRAPHIC CHARACTERISTICS; DONGYING DEPRESSION; PETROLEUM SYSTEMS,"The organic-rich sediments of the Fengcheng Formation in the Halaalate area, Junggar Basin, China are important source rocks and significant tight oil exploration targets. However, their geochemical characteristics have not been well documented. The hydrocarbon generation potential, genetic type of kerogen, organic matter (OM) sources, depositional conditions, and thermal maturity have been investigated based on a sample set of 11 mudstones. These source rock samples represent good to very good hydrocarbon generation potential, and primarily contain type I to II kerogen. The major organic input sources to the Fengcheng Formation from algae and bacteria were identified using stable carbon isotopes and biomarkers. Limited higher plant input can be inferred from trace amount of terrigenous OM biomarkers and minor contents of vitrinites and inertinites. The Fengcheng sediments were deposited under hypersaline and anoxic environments. Paleoclimate was arid during the deposition of the Fengcheng Formation. The presence of evaporites, mineral-bituminous gmundmasses (MBG), alginites and microbial mats also supports these conclusions about depositional environments and biological source. The OM enrichment in the studied samples are attributed to the reducing environments, the booming of algae and the important bacterial contribution. Vitrinite reflectance and T max suggest a low thermal maturity of the studied Fengcheng sediments, in agreement with maturity-related hopane and sterane ratios and detection of hop-17(21)-enes. In a consideration of the quantity, quality and maturity of OM and their large thickness, the Fengcheng sediments have a good petroleum exploration potential.",1,1,7
Crude Oil,"Enhanced Oil Recovery,Enhanced Oil-recovery","Salehpour, Mohammad; Riazi, Masoud; Malayeri, M. Reza; Seyyedi, Mojtaba",CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage,"Carbon capture, and storage (CCS); Carbon capture, utilization, and storage (CCUS); Carbonated water injection; Heavy asphaltic crude oil; Water-in-oil emulsion; Enhanced oil recovery",PORE-SCALE MECHANISMS; WATER INJECTION; INTERFACIAL-TENSION; WETTABILITY ALTERATION; CO2 INJECTION; PERFORMANCE; SECONDARY; SCENARIOS; EMULSIONS; DIOXIDE,"Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsioninduced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.",3,3,4
Crude Oil,"Enhanced Oil Recovery,Enhanced Oil-recovery","Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Crude Oil,"Enhanced Oil Recovery,Enhanced Oil-recovery","Qu, Ming; Hou, Jirui; Liang, Tuo; Raj, Infant; Yang, Yulong; Qi, Pengpeng","Synthesis of alpha-starch based nanogel particles and its application for long-term stabilizing foam in high-salinity, high-temperature and crude oil environment",Nanogel particle; Foam stability; Viscoelasticity; High temperature tolerance; High salinity tolerance; Crude oil tolerance,RECOVERY; MIXTURES; FLUID; WATER; CO2,"Foam has been widely used as a proven technology in enhanced oil recovery by improving the mobility of the injected gas. However, its further application has been retarded owing to the limited stability in high salinity, high temperature and crude oil conditions. Traditional agents for foam stabilization including surfactants, polymers are unable to stabilize foam for long term under harsh conditions. In this work, the nanogel particles with high viscoelasticity were synthesized to stabilize foam for more than one year through a free radical reaction method using a-starch, acrylamide, N,N'-methylene bisacrylamide, potassium persulfate. The diameter of nanogel particles was 30 nm. The stability of foam stabilized by nanogel particles was evaluated by using foam volume and T-90 as indicators at temperature of 30-120 degrees C, salinity of 0-240 g/L and oil percentage of 0-50 wt%. Moreover, the rheological properties of foam were also measured to study the mechanisms of foam stability under different conditions. The results demonstrated that foam stabilized by nanogel particles exhibited excellent resistance to high salinity, high temperature and crude oil. Thus, the synthesized nanogel particles can be used as a potential candidate for stabilizing foam in enhanced oil recovery.",2,2,3
Crude Oil,"Enhanced Oil Recovery,Enhanced Oil-recovery","Khalid, Mozamil; Sultan, Abdullah; Noui-Mehidi, Mohamed Nabil; Al-Sarkhi, Abdelsalam; Salim, Omer",Effect of Nano-Clay Cloisite 20A on water-in-oil stable emulsion flow at different temperatures,Water-in-oil; Emulsion; Nano-Clay; Pressure drop reduction; Stable-emulsion,CRUDE-OIL; SALINITY; BEHAVIOR,"In Enhanced Oil Recovery (EOR) operations, water-in-oil emulsions are often used to ensure good sweep of the crude in the flooding process. Dispersions of 70% water in 30% oil (diesel) were extensively used to move the crude in the porous medium with good results. The present paper is concerned with a study on the influence of Cloisite 20A Nano-Clay particles particularly on the hydrodynamic performance and the stability of water-in-oil emulsions at different temperatures between 25 degrees C and 45 degrees C. The experimental results showed that the presence of Cloisite 20A stabilized the water-in-oil emulsions compared to the dispersion without Nano-Clay. It was found that the Nano-Clay concentration affects the emulsion viscosity depending on mainly the water volume fractions. In general, small quantities of the Nano-Clay reduce emulsion viscosity, while higher concentrations of the Nano-Clay resulted in a clear increase of the emulsion viscosity. The results also revealed the percentage of pressure drop reduction at different temperatures as a function of the concentration of Nano-clays, oil/water ratios and emulsion flowrates. The influence of fluid temperature on pressure drop reduction is higher than the influence of Nano-Clay concentration especially at low flowrate.",2,2,2
Crude Oil,Low Permeability,"Luan, Jian; Dong, Pingchuan; Zheng, Jilong",Experimental studies on reaction laws during the process of air injection into the oil reservoirs with low permeability,Low permeability sandstone oil reservoir; Air injection; Static experiments; Low temperature oxidation; Formula,PERFORMANCE; IOR,"The low permeability oil reservoirs are widely distributed in the world, but difficult to develop with the traditional methods due to the low permeability and poor injection properties. Air injection technique not only has the common characteristics of other gas injection techniques, but also can improve the quality of crude oil in situ because of the oxidative ability of the injected air, with a unique advantage in developing low permeability reservoirs. In order to study the reaction regularity between the hydrocarbon components in crude oil under different conditions with the oxygen in the injected air, this experiment is designed for a low permeability sandstone reservoir. In this experiment, one set of self-designed static low-temperature oxidation equipment (including injection pump and high-temperature high-pressure reactor with sampling outlets) has been used. Through analysis of the results of the chromatography for over 60 oil and gas samples, conclusions can be made that after low temperature oxidation (LTO) reactions between the crude oil and the oxygen in the injected air, the concentration of the heavy components in crude oil decreased, and the concentration of the light components increased. By injecting oxygen-reduced air with 8% of oxygen, the concentration of the heavy components of crude oil in the target reservoir reduced most obviously. The formation water and associated gas can hinder the pyrolysis of heavy components, while the minerals in the formation can accelerate the pyrolysis process. The relationship between the carbon atoms number in each of the most consumed hydrocarbon molecule and different LTO reaction conditions has been proposed. According to the sensitivity analysis, it is believed that the influence of the formation water on the LTO reactions is greater than that of minerals in the formation, and influence of associated gas is less than that of minerals. Finally, combined the related physical and chemical theories, a LTO chemical reaction equation has been put forward for the targeted low permeability oil reservoir. The conclusions of the studies can provide some references for the indoor experiments and field applications of air injection in the future.",3,3,2
Crude Oil,Low Permeability,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Crude Oil,Low Permeability,"Li, Lei; Hao, Yongmao; Lv, Yuting; Wang, Chengwei; Yao, Chuanjin; Zhao, Qingmin; Xiao, Pufu",Experimental investigation on low-velocity seepage characteristics and influencing factors in a shale oil reservoir,,NON-DARCY FLOW; APPARENT PERMEABILITY; GAS-TRANSPORT; NANOPORES; MULTISCALE; MODEL; ADSORPTION; MULTICOMPONENT; PERFORMANCE; SIMULATION,"The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10(-4) ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, microfractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs.",2,2,11
Crude Oil,Fengcheng Formation,"Jiang, Wenlong; Imin, Ablimit; Wang, Xueyong; Wang, Tao; Guo, Wenjian","Geochemical characterization and quantitative identification of mixed-source oils from the Baikouquan and Lower Wuerhe Formations in the eastern slope of the Mahu Sag, Junggar Basin, NW China",Mixed oil; Chemometrics; Alternating least square; Mahu sag; Junggar basin,LOWER INDUS BASIN; CRUDE OILS; PETROLEUM GEOCHEMISTRY; CRETACEOUS ROCKS; TARIM BASIN; FIELD; ORIGIN,"The quantitative identification of mixed-source oil is a popular yet difficult topic in current petroleum geochemistry research. The mixed-source oils of the Baikouquan and Lower Wuerhe formations in the eastern slope of the Mahu Sag of Junggar Basin were used as a typical example in this study. Quantitative research on mixed oils was carried out in the study area and good results were obtained using an approach combining organic geochemistry and chemometrics. The results of crude oil geochemistry research show that mixed-source crude oil is ubiquitous in the study area. After comprehensive analysis, it is likely that there are three endmembers in the current mixed-source oils. Two of the endmembers may represent mainly the contribution of the early and late source rocks of the Permian Fengcheng Formation and are dominated by late filled crude oil. However, the third endmember is quite different. Its hydrocarbons may have come from the source rocks of the Permian Lower Wuerhe Formation or the source rocks of the Fengcheng Formation under different lithofacies and sedimentary environments. The study area is dominated by hydrocarbons that accumulated from the Fengcheng Formation. Although the proportion of hydrocarbons generated in the late stage is not high, it plays a very important role in hydrocarbon migration and accumulation. This comprehensive comparative study shows that the chemometric method can play an important role in calculating the proportion of mixed-source oil and in endmember analysis.",2,2,0
Crude Oil,Fengcheng Formation,"Ma, Ling; Zhang, Yang; Zhang, Zhihuan; Zhang, Guanlong; Wang, Shengzhu","The geochemical characteristics of the Fengcheng Formation source rocks from the Halaalate area, Junggar Basin, China",Lacustrine source rock; Biomarkers; Stable carbon isotopes; Organic geochemistry; Fengcheng Formation; Junggar Basin,LACUSTRINE SOURCE ROCKS; PERMIAN LUCAOGOU FORMATION; PHOTIC ZONE EUXINIA; BOHAI BAY BASIN; ORGANIC-MATTER; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; PETROGRAPHIC CHARACTERISTICS; DONGYING DEPRESSION; PETROLEUM SYSTEMS,"The organic-rich sediments of the Fengcheng Formation in the Halaalate area, Junggar Basin, China are important source rocks and significant tight oil exploration targets. However, their geochemical characteristics have not been well documented. The hydrocarbon generation potential, genetic type of kerogen, organic matter (OM) sources, depositional conditions, and thermal maturity have been investigated based on a sample set of 11 mudstones. These source rock samples represent good to very good hydrocarbon generation potential, and primarily contain type I to II kerogen. The major organic input sources to the Fengcheng Formation from algae and bacteria were identified using stable carbon isotopes and biomarkers. Limited higher plant input can be inferred from trace amount of terrigenous OM biomarkers and minor contents of vitrinites and inertinites. The Fengcheng sediments were deposited under hypersaline and anoxic environments. Paleoclimate was arid during the deposition of the Fengcheng Formation. The presence of evaporites, mineral-bituminous gmundmasses (MBG), alginites and microbial mats also supports these conclusions about depositional environments and biological source. The OM enrichment in the studied samples are attributed to the reducing environments, the booming of algae and the important bacterial contribution. Vitrinite reflectance and T max suggest a low thermal maturity of the studied Fengcheng sediments, in agreement with maturity-related hopane and sterane ratios and detection of hop-17(21)-enes. In a consideration of the quantity, quality and maturity of OM and their large thickness, the Fengcheng sediments have a good petroleum exploration potential.",1,1,7
Flow Rate,Water,"Kim, Hyunho; Kim, Jakyung; Seo, Yutaek",Economic benefit of methane hydrate reformation management in transport pipeline by reducing thermodynamic hydrate inhibitor injection,Gas hydrates; Methane production; Hydrate re-formation; Mono ethylene glycol; Life cycle cost; Regeneration process,NATURAL-GAS HYDRATE; WATER-FLOW; CARBON-DIOXIDE; HIGH-PRESSURE; DISSOCIATION; SEPARATION; STORAGE; DEPRESSURIZATION; DESALINATION; NANOBUBBLES,"Hydrate reformation is an inherent risk in a methane hydrate production system because dissociated water and methane flow through transport pipelines simultaneously. In this study, comprehensive experiments using high-pressure autoclaves are performed to investigate the effect of reducing the concentration of thermodynamic hydrate inhibitor on hydrate reformation characteristics. In order to simulate the production of methane hydrates, these are formed and dissociated in the preliminary stage; thereafter, the hydrates are reformed from dissociated water. Although dissociated water and fresh water are found to have similar formation rates, they have a major difference in relative torque, especially in the early stage of hydrate formation. The instant rise of the relative torque in the dissociated water is observed to be up to 2.5; thereafter, it remains approximately 3.0 until hydrate conversion reaches 28 vol%. This trend is different from that in fresh water, where a steady increase in relative torque with sudden spikes is observed. These results clearly show the high risk of hydrate blockage in the transport pipelines of a methane hydrate production system; hence, the injection of hydrate inhibitor is necessary. In this study, monoethylene glycol (MEG) is the selected thermodynamic hydrate inhibitor; its concentration is maintained below a specific value to completely avoid hydrate formation. Despite the occurrence of hydrate reformation, a stable relative torque is observed in a 20 wt% MEG concentration, where the conversion of water to hydrate approximately reaches 40 vol%. For a 10 wt% MEG concentration, a sudden increase in relative torque of up to 2.0 is observed in the early stage of hydrate formation; this suggests that the foregoing is less effective in sustaining flowability. Compared to fresh water, the addition of a 20 wt% MEG to dissociated water results in a more stable torque. Once the performance of the MEG concentration reduction is confirmed, the MEG regeneration process is designed accordingly by using both multiphase flow and process simulation models. A life cycle cost (LCC) analysis is conducted by estimating the capital expenditures (CAPEX) and operating expenditures (OPEX) of the MEG regeneration process. Considering both CAPEX and OPEX, the LCC for complete inhibition (35 wt%) is 90.15 MUSD (million United States dollars); however, for the 20 and 10 wt% MEG concentrations, the LCC values are reduced to 86.79 and 84.58 MUSD, respectively. The foregoing suggests the potential economic benefit of methane hydrate reformation management to avoid blockage.",3,3,8
Flow Rate,Water,"Ma, Longjie; Yu, Qingchun",Dynamic behaviors of methane adsorption on partially saturated shales,Partially saturated shales; Methane adsorption dynamic behavior; Dynamic adsorption model; Gas flow control stage; Transition stage; Interface interaction stage,NORTHEASTERN BRITISH-COLUMBIA; EASTERN QAIDAM BASIN; NATURAL-GAS; CARBON-DIOXIDE; PORE STRUCTURE; GEOLOGICAL CONTROLS; UNCONVENTIONAL GAS; POROUS CARBONS; DIFFUSION; WATER,"The dynamic behavior of methane adsorption onto shales plays an important role in many resource and environmental problems. Previous studies have mainly analyzed gas diffusion, but the studies have also shown that the adsorption process consists of multiple forms of gas movement. In fact, water always exists in shale, but the process of methane adsorption onto partially saturated shales has received little attention. To study the movement behavior of methane in the adsorption process and determine how water influences the dynamic behaviors of methane adsorption, a dynamic adsorption model (DAM) was proposed. In this study, dynamic adsorption experiments involving three shale samples with four water saturation levels were conducted. Based on the experiments, 48 adsorption process curves were obtained. The dynamic adsorption process was divided into three stages based on the curves. The first stage occurred when the adsorption amount reached 50% of the equilibrium adsorption amount, and the corresponding time range was t < t(50); the second occurred when the adsorption amount increased from 50% to 80%, and the corresponding time range was t(50) < t < t(50); and the third occurred when the adsorption amount increased from 80% to 100%, and the corresponding time range was t(80) < t < t(1)(00). These stages were defined as the gas flow control stage, transition stage and interface interaction stage, respectively. The basis for this determination was that the adsorption rate was mainly controlled by the gas flow, gas flow and interface interaction, and interface interactions during these stages, respectively. The experimental data were fitted with the unipore diffusion model (UNM) based on Fick's second law and the modified unipore diffusion model (MM). The results showed that the UNM was better fit to the gas flow control stage but cannot describe the entire adsorption process. The MM was well fit to the dry shale methane adsorption process, although the wet shale fitting effect was inferior to that of the DAM. Analysis of the effect of water on the adsorption rate in each stage revealed that the inhibition of water acted against the methane gas flow more strongly than against the interface interaction. The effective pore volume (the fraction of pores not occupied by water molecules that could be reached by methane molecules) had a strong positive correlation with the adsorption rate in the early stage of the adsorption process, whereas the correlation was weak in the later stage. Under low water saturation conditions, the reduction of the adsorption rate due to the increase in the unit water saturation was larger, whereas this effect was smaller under high water saturation conditions. Gas flow was greatly affected by water in the clay matrix, whereas the interface interaction was less affected. The pattern was diametrically opposite in the organic matrix.",3,4,7
Flow Rate,Water,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Flow Rate,Water,"Zhang, Dailu; Zhang, Hongbing; Rui, Jianwen; Pan, Yixin; Liu, Xingbin; Shang, Zuoping",Prediction model for the transition between oil-water two-phase separation and dispersed flows in horizontal and inclined pipes,Stratified flow; Annular flow; Dispersed flow; Mixed froude number; Prediction model of transition,DROPLET ENTRAINMENT,"There are two important flow patterns associated with horizontal and deviated wells: separation flows, which include stratified and annular flows, and dispersed flows. Because various types of flow patterns often exchange with each other under certain conditions, it is of great significance for improving the efficiency of oil transportation to develop prediction models describing the transition between oil-water stratified and annular or dispersed flows. Owing to the variable flow rate, water content, and pipeline inclination, the transition characteristics and prediction models for the transition from stratified to annular or dispersed flows are not clear. Therefore, in this study, relevant experiments were carried out and the transition characteristics were investigated to establish a new prediction model. In the transition from a stratified to annular flow, the prediction model for the transition boundaries and criteria is based on mixed Froude numbers. In contrast to previous studies, it was found in these experiments that the mixed Froude number is not constant when conversion between stratified flow and annular flow occurs. Instead, the mixed Froude number is related to the inlet water content and the pipeline inclination. The transition boundaries predicted by the proposed model are in good agreement with the experimental results. Based on the existing two-dimensional interfacial wave shearing mechanism, the three-dimensional interfacial wave shear deformation mechanism is elucidated. In the transition from stratified to dispersed flows, the external force on the flow direction of the interfacial wave, which includes the drag force, interfacial tension, gravity, and buoyancy, is theoretically derived by analysing the force situation before and after deformation of the two-phase interfacial wave. A prediction model for the deformation of the interfacial wave is developed, and the relationships between the external force and wave amplitude or wavelength are analysed with the prediction model. The results indicate that deformation is more likely to occur as the inclination angle of the well increases, the interfacial wave becomes unstable with increasing amplitude, and droplet formation occurs with long waves.",3,3,4
Flow Rate,Water,"Skiba, Sergey; Strukov, Dmitry; Sagidullin, Aleksei; Adamova, Tatyana; Stoporev, Andrey; Svarovskaya, Lidia; Strelets, Larisa; Altunina, Lubov; Manakov, Andrey",Impact of biodegradation of oil on the kinetics of gas hydrate formation and decomposition,Gas hydrate; Biodegradation; Self-preservation; Kinetics,METHANE HYDRATE; SELF-PRESERVATION; ACIDIC COMPOUNDS; CRUDE OILS; DISSOCIATION; CRYSTALLIZATION; POINT,"Nowadays the biological methods based on utilization of bacteria for different purposes in oilfields are becoming more and more popular because these methods potentially may become a cheaper alternative to chemical treatments. Gas hydrates formation in pipelines is the one of the main flow assurance problems. In previous works it has been shown that some biodegraded oils can have components that may act as natural Anti-Agglomerants. These natural Anti-Agglomerants can prevent hydrate particles from agglomeration which allow the particles to flow downstream along with oil in form of slurry. But there is lack of understanding of how products of oil biodegradation affect the kinetic aspects of hydrate nucleation, formation and decomposition. This information might be useful for development of new approached of treatment of the hydrate related issues in oil pipelines. Impact of the changes in component composition of crude oil caused by biodegradation process on the kinetics of gas hydrates nucleation, formation and decomposition has been studied with different methods. It was demonstrated that the changes of chemical composition of crude oil caused by biodegradation can have a strong impact on the hydrate nucleation rates at static conditions. Almost twofold decrease of hydrate nucleation rate was observed in the experiments with the water-in-oil emulsion for the biodegraded oils compared to one obtained with emulsion in the original crude oil. At the same time, no significant effect of biodegradation on the hydrate film growth rates at static conditions was observed. Similar tangential and normal hydrate film growth rates were obtained in experiments with both crude oil and with biodegraded oil. Initial growth rates of hydrate in stirring emulsions were an order of magnitude higher for water emulsions in the biodegraded oil compared to ones for the original crude oil. The studies of the decomposition rates of hydrates at sub-zero temperatures and at dynamic conditions showed that the products of vital activity of bacteria promoted self-preservation of hydrates dispersed in the biodegraded oil.",3,3,3
Flow Rate,Water,"Shabani, Ali; Sisakhti, Hossein; Sheikhi, Sobhan; Barzegar, Farzad",A reactive transport approach for modeling scale formation and deposition in water injection wells,Scale precipitation and deposition; Thermodynamic condition; Wellbore; PHREEQC,PERMEABILITY REDUCTION; GEOTHERMAL WELLS; FINES MIGRATION; CALCIUM-SULFATE; TEMPERATURE; SEAWATER; WELLBORE; DECLINE; PHREEQC; IMPACT,"Petroleum industry is moving toward enhancing oil recovery methods, especially water-based methods, including low salinity and smart water flooding which water with an optimized composition is injected into the reservoir for improving oil recovery. Injection of water into the target formation is also a common operation in geothermal energy production. As the water is being injected into the reservoir, pressure and temperature change along the well column and cause scale formation. Mineral scale precipitation and deposition is a common problem for water injection wells which reduces the effective radius of the wellbore and affects the injection efficiency. In this paper, modeling scale precipitation and deposition in a pipe flow system by coupling of species transport model and a geochemical software package (PHREEQC) is investigated. The results of the proposed method were matched with experimental data. The model has been used for prediction of scale precipitation and deposition profile along with water injection wells during low salinity waterflooding. The results show deposition of calcium carbonate scale in the bottom section of the water injection wells. Higher temperature, higher salinity and more rate fluctuation cause an increase in scale precipitation and deposition in the wellbore condition.",3,3,2
Flow Rate,Water,"Guo, Jianchun; Liu, Zhuang; Gou, Bo; Zeng, Mingyong",Study of wellbore heat transfer considering fluid rheological effects in deep well acidizing,Wellbore heat transfer; Deep gas well; Acidizing; Rheology property; Bottom-hole temperature,TEMPERATURES; CIRCULATION; INJECTION; MODEL,"Real-time understanding of the wellbore temperature is a prerequisite for the acidizing treatment design. Fluid flow regime variation caused by fluid rheological property has a great influence on wellbore temperature distribution. According to the physical situation in the acidizing process, the wellbore and formation heat transfer model considering fluid rheological effects is established, the validity of the model is verified by comparing with monitoring data and previous research results. The results indicate that fluid rheology will cause the transition of flow regime, which leads to the variation of heat transfer efficiency. Considering wellbore original water is benefit for accurately predicting bottom-hole temperature. Injection rate has a great influence on fluid flow regime. A critical injection rate with the highest cooling efficiency exists in the low range of pumping rate condition. The findings above can provide theoretical insights for the deep well acidizing, and the model built in this paper is applied in field wellbore temperature simulation.",3,3,2
Flow Rate,Water,"Skjefstad, Havard S.; Dudek, Marcin; Oye, Gisle; Stanko, Milan",The effect of upstream inlet choking and surfactant addition on the performance of a novel parallel pipe oil-water separator,Oil-water separation; Droplet size distribution; Surfactant; Inlet choking; Separation efficiency,CRUDE-OIL; SIZE DISTRIBUTIONS; GRAVITY SEPARATOR; IN-OIL; STABILITY; EMULSIONS; DROP,"This paper reports the effect of inlet choking and addition of surfactant on the performance of a parallel pipe oil-water separator. These two issues can have a strong effect on oil-water separation in real hydrocarbon production systems. Experiments were performed with Exxsol (TM) D60 and salt water. Three choke settings were tested for flow rates in the range 300-500 L/min, with three inlet water cuts and three water extraction rates. The test matrix was run with and without added surfactant. The oil-water distribution and behaviour within the separator is also studied. Droplet size measurements were performed at the separator inlet for droplet size distribution generation in the form of cumulative volume plots. The study shows that inlet choking has an overall negative effect on separator performance, especially for water-continuous inlet regimes. The maximum decrease in performance due to choking was 14 pp, while it was 4 pp due to addition of surfactant.",3,3,0
Flow Rate,Water,"Luo, Xiao; Quoc Nguyen; DiCarlo, David",Experimental study on the formation damage caused by gas fracturing fluids,Formation damage; Permeability reduction; Fracturing gas; Compositional flow; Computed tomography; Flowback,LOW-PERMEABILITY; WATER; IMBIBITION; OIL,"Fracturing often results in a fluid invasion into the formation because the fracturing pressure is always greater than the reservoir pressure. The invaded fluid causes formation damage, oil permeability reduction, and potentially reduces production rates. We conduct experiments by invading gas into oil-saturated cores and vary the properties of the oil. We quantify the formation damage through pressure and saturation measurements. In addition, we model the experiment with a compositional fractional flow model, and the results show the formation damage caused by gas is cleared through dissolution transport. The results suggest that the time to clear depends on the fluid properties and the production rate.",3,3,0
Flow Rate,Water,"Wang, Kai; Li, Chenpei; Li, Yanhui; Lu, Jinling; Wang, Yueshe; Luo, Xingqi",A fully coupled model of hydrodynamic -chemical -electrochemical processes for CO 2 uniform corrosion in multi -physics environment,CO 2 uniform corrosion; Multi-physics model; Flow effect; Multi-ion transport; Multi-component reactions,CARBON-DIOXIDE CORROSION; MILD-STEEL; PART 1; ELEVATED-TEMPERATURES; INCUBATION PERIOD; AQUEOUS-SOLUTIONS; PASSIVE METALS; WATER; OIL; PREDICTION,"Carbon dioxide uniform corrosion occurs widely in the petroleum industry and threatens the safe production and transportation of petroleum resources. It is a complex issue involving a variety of physical, chemical and elec- trochemical processes in multiple temporal and spatial scales. A fully coupled model, taking into account all involved processes in a coupled fashion, such as fluid flow, multi -ion transport, multi -component chemical/ electrochemical reactions, is established to comprehensively investigate the mechanism of CO 2 corrosion in multi -physics environment. The reliability of this model is validated by the good consistency between the pre- dicted corrosion rates and the experimental results in the literature, and this model performs better in corrosion rate prediction than the previous models due to the explicit solution for the convective mass transfer. Based on this fully coupled model, the corrosion mechanism in the multi -physics coupled environments is revealed in terms of the time -dependent ion concentration field, mass transfer and electrode reaction kinetics. The inter- relationship between the corrosion kinetics and the flow effect is explored. The results indicate that the time - dependent corrosion behavior is determined by the combined effect of the solution chemistry and electrical field. By accelerating the mass transport of corrosive species and the involved multi -component reactions, the fluid flow can significantly promote the corrosion process, while the promotion effect weakens gradually at higher flow velocities. Additionally, the flow effect at lower pH values is much more pronounced due to the transformation of the predominant controlling factors for electrode kinetics.",2,2,11
Flow Rate,Water,"Khalid, Mozamil; Sultan, Abdullah; Noui-Mehidi, Mohamed Nabil; Al-Sarkhi, Abdelsalam; Salim, Omer",Effect of Nano-Clay Cloisite 20A on water-in-oil stable emulsion flow at different temperatures,Water-in-oil; Emulsion; Nano-Clay; Pressure drop reduction; Stable-emulsion,CRUDE-OIL; SALINITY; BEHAVIOR,"In Enhanced Oil Recovery (EOR) operations, water-in-oil emulsions are often used to ensure good sweep of the crude in the flooding process. Dispersions of 70% water in 30% oil (diesel) were extensively used to move the crude in the porous medium with good results. The present paper is concerned with a study on the influence of Cloisite 20A Nano-Clay particles particularly on the hydrodynamic performance and the stability of water-in-oil emulsions at different temperatures between 25 degrees C and 45 degrees C. The experimental results showed that the presence of Cloisite 20A stabilized the water-in-oil emulsions compared to the dispersion without Nano-Clay. It was found that the Nano-Clay concentration affects the emulsion viscosity depending on mainly the water volume fractions. In general, small quantities of the Nano-Clay reduce emulsion viscosity, while higher concentrations of the Nano-Clay resulted in a clear increase of the emulsion viscosity. The results also revealed the percentage of pressure drop reduction at different temperatures as a function of the concentration of Nano-clays, oil/water ratios and emulsion flowrates. The influence of fluid temperature on pressure drop reduction is higher than the influence of Nano-Clay concentration especially at low flowrate.",2,2,2
Flow Rate,Water,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Flow Rate,Water,"Qin, Hao; Dai, Jiacai; Liu, Xiangjun; Yang, Guofeng; Pei, Yang; Gou, Shunchao; Chen, Meng",Slip behaviours and evaluation of interpretative model of oil/water two-phase flow in a large-diameter pipe,Production logging; Oil/water flow; Slip behaviour; Interpretative model; Water holdup,OIL-WATER 2-PHASE; SLUG-LIQUID-HOLDUP; DRIFT-FLUX MODEL; MECHANISTIC MODEL; PRESSURE-DROP; VERTICAL PIPE; VELOCITY; PATTERNS; BUBBLES,"Mixtures of oil and water are common in oil-producing wells. When the oilfield has a mid-late exploitation status, the production of oil and water gradually decreases and the comprehensive water content sharply increases with time. An accurate evaluation of the volumetric flow rate of each phase in the pipe is of importance for diagnosing production problems, developing an engineering design, and guiding reservoir management activities. In this study, the slip behaviours we investigated based on the high-quality experimental data obtained from a multi-phase flow loop with a large-diameter (inner diameter: 5.5 inch) vertical pipe with low flow rates (<30 m(3)/d). Furthermore, the interpretation accuracies of five interpretative models of vertical oil/water flow ware comprehensively evaluated. The results show that the slip trends to increase with decreasing flow rates. However, it was found that, when the flow rate is less than 7 m3/d, the flow rate minimally affects the slip. Additionally, the variation tendency of the slip velocity as a function of the water holdup is not stable, hence, a reasonable interpretative model should be selected according to the water holdup. The slip velocity gradually increased, and was found to be nearly linear, and the slip model proposed by Hasan and Kabir (1999) demonstrated the best adaptability under the conditions of the tested data and a water holdup of less than 0.9. The slip velocity exponentially increased with increasing water holdup and the modified drift-flux model proposed by Wu et al. (1992) was found to be more appropriate under the condition that the water holdup exceeds 0.9. Overall (i.e. for all of the test data), the Hasan model (1999) yielded better processing results for the vertical oil/water flow system under the condition of low flow rates. The analysis in this study provides better insight into the slip between the oil and water phases in a two-phase flow system with a low flow rate. In addition, the interpretative model with the best predictive capability is highlighted in this paper.",1,1,3
Flow Rate,Pressure Gradient,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Flow Rate,Pressure Gradient,"Andersen, Pal O.; Zhou, Yingfang",Steady state relative permeability experiments with capillary end effects: Analytical solutions including derivation of the intercept method,Capillary end effects; SCAL; Steady state experiment; Generalized capillary number; Analytical solutions; Intercept method,,"Steady state relative permeability experiments are performed by coinjection of two (or more) immiscible fluids. The relative permeabilities can be calculated directly from the stabilized pressure drop and saturation of the core if capillary end effects and transient effects are negligible. In most cases such conditions are difficult to obtain. This work presents an analytical solution in form of explicit expressions for the spatial profiles of pressure gradients and saturation, average saturation and pressure drop for a core being injected simultaneously with two phases at steady state when capillary end effects are significant. When arbitrary saturation functions are applied, such parameters and distributions can only by obtained by numerical integration. By assumption of simplified saturation function correlations the differential equation describing steady state can be integrated. A new dimensionless capillary number N is obtained which contains the fluid and rock parameters, but also the saturation function parameters (relative permeability and capillary pressure), fluid viscosities, injected flow fraction, total flow rate and more. It is shown that when this number is of magnitude 1, end effects cover parts of the core, but parts of the core are also unaffected. For N > 10 the end effects are negligible, while for N < 10 end effects are dominant. This paper gives the first formal proof of the intercept method from basic assumptions. It is shown that when the inlet saturation is sufficiently close to that of a no capillary pressure situation; the average saturation changes linearly with the inverse of total rate towards the saturation corresponding to no capillary forces; also, the pressure drop divided by the pressure drop of a no end effect situation goes linearly towards 1 with the inverse of total rate.",3,3,3
Flow Rate,Pressure Gradient,"Santos, M. P. P. C.; Carvalho, M. S.",Pore network model for retrograde gas flow in porous media,Pore-network models; Gas-condensate; Capillary condensation; Compositional reservoir simulation,CONDENSATE; VISCOSITY,"Gas well deliverability in retrograde gas reservoirs is affected by the appearance of a liquid phase near the wellbore when the bottom-hole pressure is below the dew point. At low enough pressure gradients, the liquid phase may bridge the pore throats, blocking the gas phase flow, leading to what is known as condensate blockage. If the pressure gradient is above a critical value, the capillary forces cannot block the gas flow and the condensate bridges are displaced. Gas production can be estimated using reservoir-scale simulation of the retrograde gas flow near producing wells using relative permeability curves that take into account the different physical phenomena and their dependence on local pressure, temperature and pressure gradient (capillary number). Pore-scale simulators can be used to model retrograde gas flow through porous media and to determine the gas and liquid phases relative permeability curves as a function of different flow parameters. Here, a fully-implicit isothermal compositional pore-scale network model is presented for retrograde gas flow in porous media at high capillary number, at which capillary forces are neglected. The flow pattern in each capillary changes from a single-phase gas flow to a two-phase core-annular flow regime when the pressure and the fluid composition reach a critical condition based on the thermodynamics of the fluid mixture. Newton's method is used to solve the non-linear flow and thermodynamics equations to calculate the pressure distribution and the flow rate of each component through the network. The model was used to predict gas-liquid relative permeability at high capillary number from a depletion process in a 2D network. The results show the evolution of the condensate saturation at different conditions and how the gas permeability falls abruptly at a certain condensate saturation.",3,3,0
Flow Rate,Pressure Gradient,"Li, Lei; Hao, Yongmao; Lv, Yuting; Wang, Chengwei; Yao, Chuanjin; Zhao, Qingmin; Xiao, Pufu",Experimental investigation on low-velocity seepage characteristics and influencing factors in a shale oil reservoir,,NON-DARCY FLOW; APPARENT PERMEABILITY; GAS-TRANSPORT; NANOPORES; MULTISCALE; MODEL; ADSORPTION; MULTICOMPONENT; PERFORMANCE; SIMULATION,"The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10(-4) ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, microfractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs.",2,2,11
Flow Rate,Pressure Gradient,"Zhu, Jianting",Impact of yield stress and fractal characteristics on the flow of Bingham fluid through fracture network,Bingham fluid; Newtonian fluid; Yield stress; Fractured reservoir; Fractal dimension; Flowrate ratio,STARTING PRESSURE-GRADIENT; EFFECTIVE PERMEABILITY; GAS-RESERVOIRS; MODEL; MECHANICS; WELL,"Flow process of a fluid with yield stress in fractured reservoirs is important in petroleum recovery. In this study, a new approach is proposed to study the combined effect of Bingham fluid properties and fractal characteristics on the flow of a Bingham fluid through a fractal fracture network. Both the aperture and trace length of fractures are distributed according to the power-law fractal distribution with distinct fractal dimensions. The relative effect on the flowrate of Bingham fluid in the network by the Bingham fluid properties and fractal characteristics compared to the Newtonian counterpart is examined. The results demonstrate that the flowrate of Bingham fluid through the network increases quickly with the pressure head gradient since large fractures are first activated which are responsible to quickly increase the Bingham fluid flowrate. The flowrate ratio of the Bingham fluid over Newtonian fluid decreases with the fractal dimension of aperture since the Bingham fluid flowrate decreases with increasing fractal dimension at a faster rate than the Newtonian fluid. A larger ratio of minimum over maximum apertures in the fractal network results in a larger flowrate ratio of the Bingham fluid over Newtonian fluid. The trace length fractal parameters do not affect the flowrate ratio of the Bingham fluid over the Newtonian fluid due to the fact that these parameters affect the actual flowrate for both types of fluid to the same extent.",2,2,0
Flow Rate,Pressure Gradient,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Flow Rate,Heat Transfer,"Xiao, Caiyun; Ni, Hongjian; Shi, Xian; Wang, Ruihe",A fracture initiation model for carbon dioxide fracturing considering the bottom hole pressure and temperature condition,CO2 fracturing; Fracture initiation; Wellbore flow model; Pressure transmission; Parameter optimization,CO2 INJECTION; HEAT-TRANSFER; PROPAGATION; STATE; SEQUESTRATION; MECHANISM; EQUATION; STORAGE; WELLS; FLOW,"The properties of CO2 under different conditions significantly affect the breakdown pressure during CO2 fracturing. In this study, the fracture initiation model is combined with real bottom-hole temperature-pressure condition by considering CO2 borehole pressurization rate. The results show that the breakdown pressure can be reduced by 26.2%-35.5%. With a constant pump rate of 0.5 m(3)/min, bottom-hole pressure exceeds the breakdown pressure at approximately 408s, meanwhile, bottom-hole temperature decreases by 4.38% and borehole pressurization rate expands by 2.4 times. As the pump rate increases, the pressurization rate reaches its peak at a pump rate of 6.0 m(3)/min, and the downtrend is delayed with inlet pressure increasing. Case study shows that the breakdown pressure predicted by the new model agrees well with in-situ data, and the range of optimal inlet pump rate is 1.9-2.5 m(3)/min under the in-situ inlet condition (T-0 = 258 K and p(0) = 6 MPa). Furthermore, the range of optimal inlet pump rate expands with inlet pressure increasing and shrinks with inlet temperature increasing. This new initiation pressure model can provide more insights for CO2 fracturing mechanisms and design.",3,3,2
Flow Rate,Heat Transfer,"Guo, Jianchun; Liu, Zhuang; Gou, Bo; Zeng, Mingyong",Study of wellbore heat transfer considering fluid rheological effects in deep well acidizing,Wellbore heat transfer; Deep gas well; Acidizing; Rheology property; Bottom-hole temperature,TEMPERATURES; CIRCULATION; INJECTION; MODEL,"Real-time understanding of the wellbore temperature is a prerequisite for the acidizing treatment design. Fluid flow regime variation caused by fluid rheological property has a great influence on wellbore temperature distribution. According to the physical situation in the acidizing process, the wellbore and formation heat transfer model considering fluid rheological effects is established, the validity of the model is verified by comparing with monitoring data and previous research results. The results indicate that fluid rheology will cause the transition of flow regime, which leads to the variation of heat transfer efficiency. Considering wellbore original water is benefit for accurately predicting bottom-hole temperature. Injection rate has a great influence on fluid flow regime. A critical injection rate with the highest cooling efficiency exists in the low range of pumping rate condition. The findings above can provide theoretical insights for the deep well acidizing, and the model built in this paper is applied in field wellbore temperature simulation.",3,3,2
Flow Rate,Heat Transfer,"Yang, Mou; Yang, Lvchao; Wang, Tao; Chen, Yuanhang; Yang, Chao; Li, Lanxu",Estimating formation leakage pressure using a coupled model of circulating temperature-pressure in an eccentric annulus,Leakage pressure; Eccentric annulus; Transient temperature; Coupled model of temperature and pressure,NON-NEWTONIAN FLUIDS; HEAT-TRANSFER; TRANSIENT TEMPERATURE; HERSCHEL-BULKLEY; FLOW; WELLBORE; LAMINAR; LOSSES; WELLS; OIL,"The eccentric annulus represents the majority of real-life situations and is attributed to a continuous change of hole-deviation angle and azimuth angle with well depth, leading to a difference in fluid flow and heat transfer mechanisms, compared with a concentric annulus. Errors resulting from ignoring the effect of eccentricity on wellbore circulating pressure and equivalent circulating density can lead to formation leakage. Based on a close relationship between circulating pressure and leakage pressure, a practical approach to predicting formation leakage pressure was established in the eccentric annulus, after running the casing, through the gradual increase of the flow rate and back pressure at the wellhead. Based on the conservation principle of energy and mass, and considering the collective effect of lost circulation and an eccentric annulus on wellbore temperature and pressure, a transient heat transfer model and a fluid flow model were developed and solved to estimate leakage pressure accurately. The numerical solution results were presented, analyzed and tested using a practical example. The results indicated that, with increasing flow rate, annulus pressure increases and temperature decreases. Temperature and pressure in the wellbore have a significant influence on the properties of the rheological parameters of Herschel-Bulkley fluid. Additionally, pressure loss and the equivalent circulating density (ECD) in the annulus were further elevated by setting back pressure at the wellhead, compared with an increase of flow rate. Most relevant is that the validity of the established method was verified through both monitored and calculated data.",2,3,5
Flow Rate,Heat Transfer,"Huang, Weiqiu; Wang, Shuang; Jing, Haibo; Wang, Cheng; Sun, Xianhang; Zhou, Ning; Fang, Jie; Fu, Lipei",A calculation method for simulation and evaluation of oil vapor diffusion and breathing loss in a dome roof tank subjected to the solar radiation,Dome roof tank; Oil static breathing loss; Heat transfer; Mass transfer; Solar radiation; Computational fluid dynamics (CFD),NUMERICAL-SIMULATION; STORAGE TANKS; HEAT-TRANSFER; CRUDE-OIL; EXPOSURE; FLOW,"The dome roof tank (DRT) is always a main equipment for oil products storage. However, the mechanism of the heat and mass transfer for the oil vapor-air in the tank gas space remains unclear when the DRT is subjected to the solar radiation. Therefore, by considering storage conditions (e.g., the solar radiation intensity and liquid height) and taking n-hexane as a representative of light oils, and based on the Fluent software and user-defined functions (UDFs) programming, a two-dimensional calculation method and the relevant theoretical model were numerically developed to simulate and reveal the transfer mechanism under the complex storage process. Meanwhile, the feasibility of the model was verified by a self-built experimental platform for the DRT evaporation loss investigation. Under the solar radiation to a 1000 m(3) DRT, the simulation results show: (1) The gas space temperature distribution can be accurately calculated, and the average temperature decreases with increasing liquid level; (2) There is a distinct counterclockwise eddy and an evident velocity boundary layer close to the wall and roof of the gas space, and the maximal gas velocity is within 0.08-0.49 m s(-1), which is closely related with the storage liquid height and time; (3) The vapor concentration in the gas space increases from top to bottom with an obvious high-concentration layer near the liquid surface, and the average concentration increases with increasing liquid level and storage time; (4) The static breathing losses increase positively with the liquid level. The mean daily loss rates for n-hexane are approximately 7.37 g t(-1), 20.9 g t(-1), and 6.36 g t(-1) for the spring equinox, summer solstice, and winter solstice, respectively. Further, the year-mean daily loss rates are about-11.5 g t(-1), and 20.1 g t(-1) for n-hexane and gasoline, respectively, and the correspondingly the total loss rates for a year are about 4.2 kg t(-1) and 7.35 kg t(-1). The research results can provide important theoretical support and design reference for reducing the breathing loss and improving the enterprise management level.",2,2,1
Flow Rate,Heat Transfer,"dos Santos, Lorena A.; Ribeiro, Daniel da C.; Romero, Oldrich J.",Heavy oil transportation through steam heating: An analytical and numerical approach,Viscous oils; Concentric steam pipe; Heat transfer; Steam quality; Flow assurance,NEWTONIAN FLOW CHARACTERIZATION; WATER-ALUMINA NANOFLUID; NATURAL-CONVECTION FLOW; CRUDE-OIL; VISCOSITY; BEHAVIOR; ANNULUS; MODEL,"Amongst the innumerable challenges that permeate the production chain of heavy oils, the transportation stage deserves to be highlighted. Due to its high viscosity, heavy oils exhibit considerable flow resistance, requiring auxiliary mechanisms to enable its transportation via pipelines. This study analyzes a concentric pipeline configuration, in which steam flows through the inner pipe and oil flows through the annular space of the oil pipe. The main goal is to investigate the impacts of steam insertion, concentric coupling dimensions, thermal insulation, steam quality and system horizontal length on the main parameters of flow control: oil temperature and viscosity. As a secondary parameter, oil initial pressure required to ensure flow completion is also discussed. In this intent, a numerical approach is applied with software Ansys CFX in a tridimensional, steady state simulation. A second objective is to estimate the main parameters of interest by an analytical approach, using the thermal resistance model associated with the epsilon - NTU method. The goal is to determine if, given a similar coupling scenario and the absence of computational resources, oil temperature and viscosity can be estimated by direct calculations within an acceptable range of deviation from the numerical approach. Heat transfer rates are also estimated as secondary parameters. Numerical results for a 1-m length system reveal that steam insertion elevates the average oil temperature in 1.2%, reducing its average viscosity and initial flow pressure by 8.7% and 24.2%, respectively. From the previous scenario, a reduction of 24.6% in the oil pipe/steam pipe radius ratio results in an additional 1.2% temperature increase and 4.7% viscosity reduction. On the other hand, reducing steam quality in 30% implicates an average oil viscosity 2.4% higher. In a 4-m system, a convective cell pattern is observed, in which oil heating and viscosity reduction reaches its peak at the central upper region of the annular space, highlighting cooler and denser deposits in the lower section of the system and a nonlinear heating process. Maximum deviations between numerical and analytical approaches in oil temperature and viscosity estimates are 1.3% and 15.6%, respectively, which indicate the latter as a suitable calculation method for small systems in the absence of numerical resources. Deviations are mainly attributed to the neglect of natural convection, gravitational and steam turbulence effects, which contribute for a non-homogeneous heating of oil.",1,1,1
Flow Rate,Multiple Wells,"Ma, Longjie; Yu, Qingchun",Dynamic behaviors of methane adsorption on partially saturated shales,Partially saturated shales; Methane adsorption dynamic behavior; Dynamic adsorption model; Gas flow control stage; Transition stage; Interface interaction stage,NORTHEASTERN BRITISH-COLUMBIA; EASTERN QAIDAM BASIN; NATURAL-GAS; CARBON-DIOXIDE; PORE STRUCTURE; GEOLOGICAL CONTROLS; UNCONVENTIONAL GAS; POROUS CARBONS; DIFFUSION; WATER,"The dynamic behavior of methane adsorption onto shales plays an important role in many resource and environmental problems. Previous studies have mainly analyzed gas diffusion, but the studies have also shown that the adsorption process consists of multiple forms of gas movement. In fact, water always exists in shale, but the process of methane adsorption onto partially saturated shales has received little attention. To study the movement behavior of methane in the adsorption process and determine how water influences the dynamic behaviors of methane adsorption, a dynamic adsorption model (DAM) was proposed. In this study, dynamic adsorption experiments involving three shale samples with four water saturation levels were conducted. Based on the experiments, 48 adsorption process curves were obtained. The dynamic adsorption process was divided into three stages based on the curves. The first stage occurred when the adsorption amount reached 50% of the equilibrium adsorption amount, and the corresponding time range was t < t(50); the second occurred when the adsorption amount increased from 50% to 80%, and the corresponding time range was t(50) < t < t(50); and the third occurred when the adsorption amount increased from 80% to 100%, and the corresponding time range was t(80) < t < t(1)(00). These stages were defined as the gas flow control stage, transition stage and interface interaction stage, respectively. The basis for this determination was that the adsorption rate was mainly controlled by the gas flow, gas flow and interface interaction, and interface interactions during these stages, respectively. The experimental data were fitted with the unipore diffusion model (UNM) based on Fick's second law and the modified unipore diffusion model (MM). The results showed that the UNM was better fit to the gas flow control stage but cannot describe the entire adsorption process. The MM was well fit to the dry shale methane adsorption process, although the wet shale fitting effect was inferior to that of the DAM. Analysis of the effect of water on the adsorption rate in each stage revealed that the inhibition of water acted against the methane gas flow more strongly than against the interface interaction. The effective pore volume (the fraction of pores not occupied by water molecules that could be reached by methane molecules) had a strong positive correlation with the adsorption rate in the early stage of the adsorption process, whereas the correlation was weak in the later stage. Under low water saturation conditions, the reduction of the adsorption rate due to the increase in the unit water saturation was larger, whereas this effect was smaller under high water saturation conditions. Gas flow was greatly affected by water in the clay matrix, whereas the interface interaction was less affected. The pattern was diametrically opposite in the organic matrix.",3,4,7
Flow Rate,Multiple Wells,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Flow Rate,Multiple Wells,"Ahmadi, Rouhollah; Shahrabi, Jamal; Aminshahidy, Babak",Forecasting multiple-well flow rates using a novel space-time modeling approach,STARMA; ARIMA; Spatial clustering; Flow rate pattern; Autoregressive; Moving average,IDENTIFICATION; REPRESENTATION; SYSTEMS,"A different approach based on existing spatiotemporal models is developed in this research for forecasting the production flow rates of a group of adjacent wells in a reservoir. Unlike the previous single-well analysis techniques, this new methodology tries to forecast the flow rates of a number of producing wells located in a certain neighborhood. It also takes into account the variety of flow rate patterns that may take place during the production period of the wells. Regarding the time-series nature of flow rate data and the spatial relationships between multiple wells in a proximity, the Space-Time Auto-Regressive Moving-Average technique, abbreviated as STARMA, is borrowed to employ in this research to capture the spatial inter-relationships of the wells and model the flow rate data of multiple wells simultaneously. Partitioning the field into different groups of adjacent wells based on the similarity of flow rate patterns is also recommended using the spatial clustering algorithms as an enhancing part of the proposed methodology. The capability of the proposed approach in forecasting the flow rates of multiple wells is verified using the real data of a case study including 38 active oil producing wells located in a reservoir in South West Iran. The forecasts generated by the proposed method are finally compared with the predictions obtained by the current ARIMA techniques. Based on findings of this research, the proposed space time modeling of multiple well flow rates helps in estimating the more accurate forecasts, when the single well analysis techniques fail in predicting the real trend of future flow rates.",2,2,1
Flow Rate,Multiple Wells,"Kozhagulova, Ashirgul; Nguyen Hop Minh; Zhao, Yong; Fok, Sai Cheong",Experimental and Analytical Investigation of Sand Production in Weak formations for Multiple Well Shut-Ins,Weak formation; Sand production; Experimental testing; Analytical prediction; Well shut-in; Ustyurt-Buzachi,ROCK FAILURE; MODEL; PRESSURE; CRITERIA; ONSET,"Sand production is a severe problem in oilfields and is majorly associated with weak and unconsolidated formations. Therefore, identifying the expected amount and rate of sand has been approached by different analytical and numerical prediction methods. Within them the former requires less computational time and therefore being widely used. However, despite some of the analytical models proved to be fairly predictive for sand production during steady-state flow, they cannot be used directly for the wells with complex production profiles. The current study focuses on the experimental investigation of the sand production pattern during well production and shut-in periods. The laboratory work was conducted on artificial sandstone replicating weak Cretaceous formations in Kazakhstan using customized High Pressure Consolidation System (HPCS) for sand production experiments. HPCS accommodates a sandstone sample of a large diameter to diminish boundary effect when the fluid is injected. The tests were conducted at different overburden stresses as well as pressure drawdowns in several well shut-in runs. The paper presents a modification of the classical steady-state flow analytical solution incorporating field and fluid conditions as well as the dependence on the well shut-in runs. The model showed good convergence with the experimental and well data.",2,2,1
Flow Rate,Multiple Wells,"Ashrafi, Taha; Saberi, Mohammad Hossein; ZareNezhad, Bahman","1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran",Basin modeling; Source rock evaluation; Sarchahan formation; Coastal fars; Southern Iran,FOLD-THRUST BELT; ZAGROS MOUNTAINS; PERSIAN-GULF; CONTIGUOUS OFFSHORE; LATEST ORDOVICIAN; NATURAL-GAS; ORIGIN; STRATIGRAPHY; RESERVOIRS; BASEMENT,"One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the ""hot shales"" of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m(2) since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.",1,1,2
Flow Rate,Multiple Wells,"Childers, D. P. E.; Wu, X.",Forecasting oil well performance in tight formation using the connected reservoir storage model,,,"Tight reservoir development requires complex fracture networks to economically produce hydrocarbons. The accurate prediction of a production well regarding this type of reservoir is not only critical for reservoir management but also challenging due to multiple and compound flow mechanisms. For wells producing from tight formations, curve fitting based forecasting models are destined to fail in the long term because they do not capture flow mechanisms or the physics governing fluid flow in the reservoir. Based on diffusivity theory, this paper presents the Connected Reservoir Storage Model (CRSM) employing only production rate and bottomhole flowing pressure (BHFP) to derive the reservoir behavior and can be used to predict production performance under variable operating conditions. This approach is easy to implement as the CRSM can be determined with no foreknowledge of reservoir geometry or reservoir parameters. The novelty of the CRSM is utilizing only production data to characterize extreme tight formations for performance forecasting under variable operational conditions. This paper will demonstrate the ability of the CRSM to predict production performance and compare the result to two classical empirical techniques currently used in unconventional reservoir predictions, and the validation is done via numerical simulation. Based on the CRSM, this paper also reveals the interrelated paradigms among well performance, increasing reservoir connected volume, and rate forecasts with uncertainties.",1,1,0
Flow Rate,Multiphase Flow,"Kim, Hyunho; Kim, Jakyung; Seo, Yutaek",Economic benefit of methane hydrate reformation management in transport pipeline by reducing thermodynamic hydrate inhibitor injection,Gas hydrates; Methane production; Hydrate re-formation; Mono ethylene glycol; Life cycle cost; Regeneration process,NATURAL-GAS HYDRATE; WATER-FLOW; CARBON-DIOXIDE; HIGH-PRESSURE; DISSOCIATION; SEPARATION; STORAGE; DEPRESSURIZATION; DESALINATION; NANOBUBBLES,"Hydrate reformation is an inherent risk in a methane hydrate production system because dissociated water and methane flow through transport pipelines simultaneously. In this study, comprehensive experiments using high-pressure autoclaves are performed to investigate the effect of reducing the concentration of thermodynamic hydrate inhibitor on hydrate reformation characteristics. In order to simulate the production of methane hydrates, these are formed and dissociated in the preliminary stage; thereafter, the hydrates are reformed from dissociated water. Although dissociated water and fresh water are found to have similar formation rates, they have a major difference in relative torque, especially in the early stage of hydrate formation. The instant rise of the relative torque in the dissociated water is observed to be up to 2.5; thereafter, it remains approximately 3.0 until hydrate conversion reaches 28 vol%. This trend is different from that in fresh water, where a steady increase in relative torque with sudden spikes is observed. These results clearly show the high risk of hydrate blockage in the transport pipelines of a methane hydrate production system; hence, the injection of hydrate inhibitor is necessary. In this study, monoethylene glycol (MEG) is the selected thermodynamic hydrate inhibitor; its concentration is maintained below a specific value to completely avoid hydrate formation. Despite the occurrence of hydrate reformation, a stable relative torque is observed in a 20 wt% MEG concentration, where the conversion of water to hydrate approximately reaches 40 vol%. For a 10 wt% MEG concentration, a sudden increase in relative torque of up to 2.0 is observed in the early stage of hydrate formation; this suggests that the foregoing is less effective in sustaining flowability. Compared to fresh water, the addition of a 20 wt% MEG to dissociated water results in a more stable torque. Once the performance of the MEG concentration reduction is confirmed, the MEG regeneration process is designed accordingly by using both multiphase flow and process simulation models. A life cycle cost (LCC) analysis is conducted by estimating the capital expenditures (CAPEX) and operating expenditures (OPEX) of the MEG regeneration process. Considering both CAPEX and OPEX, the LCC for complete inhibition (35 wt%) is 90.15 MUSD (million United States dollars); however, for the 20 and 10 wt% MEG concentrations, the LCC values are reduced to 86.79 and 84.58 MUSD, respectively. The foregoing suggests the potential economic benefit of methane hydrate reformation management to avoid blockage.",3,3,8
Flow Rate,Multiphase Flow,"Soulat, A.; Douarche, F.; Flauraud, E.",A modified well index to account for shear-thinning behaviour in foam EOR simulation,Multiphase flow; Porous media; Foam; Shear-thinning; Injectivity; Well index; Enhanced oil recovery; Upscaling,STEADY-STATE; INJECTIVITY; MODEL; GAS,"An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shear-thinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements. We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on coarser grids when compared to a sufficiently refined reference grid. In order to correct these errors we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address. This modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. Our proposed solution, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour. Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.",3,3,2
Flow Rate,Multiphase Flow,"Ghasemi, Mohammad; Al-Safran, Eissa",Integrated reservoir/wellbore production model for oil field asphaltene deposition management,Integrated modeling; Asphaltene precipitation and deposition; Micellization model; Equation-of-state; Transport mechanism,THERMODYNAMIC MICELLIZATION MODEL; EQUATION-OF-STATE; PARTICLE DEPOSITION; PRECIPITATION; FLOW; PRESSURE; SAFT,"Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity, poor understanding, and inadequate predictive tools. A literature review study on asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition taking into account the effect of their interaction on asphaltene deposition. In addition, most of the existing studies are focused on either modeling the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupling reservoir and wellbore production models, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model to ensure accurate phase behavior and volumetric calculations, and to tune the thermodynamic asphaltene precipitation model. A field case input data is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing. The proposed model predicted the location and growth of asphaltene deposition thickness with time and space in the inner production-tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop and decreasing flowrate. Sensitivity analyses to investigate several parameters such as depletion drive mechanism, asphaltene particle size, and injection of CO2 rich gas on asphaltene deposition show excellent results that are aligned with the physical and theoretical understanding of asphaltene deposition. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which affects project economics and safety.",3,3,0
Flow Rate,Multiphase Flow,"Santim, C. G. S.; Fulchignoni, L. P.; Rosa, E. S.; Gaspari, E. F.",Transient multiphase flow modeling and validation in a real production system with high CO2 content using the drift-flux model,Three-phase flow; Drift-flux model; Non-isothermal model; Transient; Production system,FRICTIONAL PRESSURE-DROP; GAS-LIQUID FLOW; 2-PHASE FLOW; SLUG FLOW; LONG BUBBLES; TRANSITIONS; VISCOSITY; VELOCITY; MOTION,"This study presents a transient multiphase flow simulator based on the non-isothermal Drift-Flux model that aims to reproduce oil and gas production systems. The mathematical model consists of three mass conservation equations, one equation for the momentum mixture and one equation to reproduce the energy conservation of the gas-liquid-liquid mixture, assuming mass transfer between the produced liquid and gas phases and neglecting the slip between the liquid phases. The solver utilizes the finite volume method with a semi-implicit approach making use of the upwind first order scheme with staggered grid. Liquid holdup and liquid amount between the liquid phases are evaluated explicitly whereas the coupling between velocities and pressure fields is implicit by building a global matrix. The temperature field is obtained in an uncoupled way after the volumetric fraction, mass flow rates and pressure calculus. For the sake of validation of the solver, the simulated profiles of pressure, temperature and liquid holdup along the production line are compared with those given by the reference benchmark for multiphase flow simulation in the Oil & Gas industry, OLGA (R) (OiL and GAs simulator), and real field data in the steady-state regime of an offshore oil producer well with high CO2 content. The influence of input parameters on the simulation results is investigated. A sensitivity analysis is performed on the fluid modeling, considering the Black-Oil model making use of two different R-s correlations and the compositional approach. The influence of drift parameters on the numerical solutions is also verified. Liquid holdup, pressure and temperature trends are analyzed upstream and downstream of the master valve as well as in the well bottom and on the separator regions. Finally, important production procedures such as well shutdown and start-up are analyzed. The main motivation is to verify the solver capability to reproduce the multiphase flow behavior during the oil and gas production, especially for a fluid with high GOR and high amount of CO2.",2,2,0
Flow Rate,Multiphase Flow,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Flow Rate,Shale,"Ma, Longjie; Yu, Qingchun",Dynamic behaviors of methane adsorption on partially saturated shales,Partially saturated shales; Methane adsorption dynamic behavior; Dynamic adsorption model; Gas flow control stage; Transition stage; Interface interaction stage,NORTHEASTERN BRITISH-COLUMBIA; EASTERN QAIDAM BASIN; NATURAL-GAS; CARBON-DIOXIDE; PORE STRUCTURE; GEOLOGICAL CONTROLS; UNCONVENTIONAL GAS; POROUS CARBONS; DIFFUSION; WATER,"The dynamic behavior of methane adsorption onto shales plays an important role in many resource and environmental problems. Previous studies have mainly analyzed gas diffusion, but the studies have also shown that the adsorption process consists of multiple forms of gas movement. In fact, water always exists in shale, but the process of methane adsorption onto partially saturated shales has received little attention. To study the movement behavior of methane in the adsorption process and determine how water influences the dynamic behaviors of methane adsorption, a dynamic adsorption model (DAM) was proposed. In this study, dynamic adsorption experiments involving three shale samples with four water saturation levels were conducted. Based on the experiments, 48 adsorption process curves were obtained. The dynamic adsorption process was divided into three stages based on the curves. The first stage occurred when the adsorption amount reached 50% of the equilibrium adsorption amount, and the corresponding time range was t < t(50); the second occurred when the adsorption amount increased from 50% to 80%, and the corresponding time range was t(50) < t < t(50); and the third occurred when the adsorption amount increased from 80% to 100%, and the corresponding time range was t(80) < t < t(1)(00). These stages were defined as the gas flow control stage, transition stage and interface interaction stage, respectively. The basis for this determination was that the adsorption rate was mainly controlled by the gas flow, gas flow and interface interaction, and interface interactions during these stages, respectively. The experimental data were fitted with the unipore diffusion model (UNM) based on Fick's second law and the modified unipore diffusion model (MM). The results showed that the UNM was better fit to the gas flow control stage but cannot describe the entire adsorption process. The MM was well fit to the dry shale methane adsorption process, although the wet shale fitting effect was inferior to that of the DAM. Analysis of the effect of water on the adsorption rate in each stage revealed that the inhibition of water acted against the methane gas flow more strongly than against the interface interaction. The effective pore volume (the fraction of pores not occupied by water molecules that could be reached by methane molecules) had a strong positive correlation with the adsorption rate in the early stage of the adsorption process, whereas the correlation was weak in the later stage. Under low water saturation conditions, the reduction of the adsorption rate due to the increase in the unit water saturation was larger, whereas this effect was smaller under high water saturation conditions. Gas flow was greatly affected by water in the clay matrix, whereas the interface interaction was less affected. The pattern was diametrically opposite in the organic matrix.",3,4,7
Flow Rate,Shale,"Fan, Liyao; Li, Lei; Su, Yuliang; Cai, Mingyu; Tang, Meirong; Gao, Xiaogang; Chen, Zheng; Wang, Chengwei",CO2-prepad injection EOR simulation and sensitivity analysis considering miscibility and geomechanics in tight oil reservoirs,Tight oil; CO2 pre-pad injection; Enhanced oil recovery; Sensitivity analysis; Coupled fluid-solid,CARBON-DIOXIDE; SHALE GAS; MODEL; CO2; RECOVERY; TENSION; FLUIDS,"Injecting CO2 pre-pad into tight reservoirs before hydraulic fracturing is a promising way to improve the productivity of single well. In this method, CO2 should be injected into the formation at a high rate. Also the miscibility of CO2 and oil with the changes of intricate geomechanics during this process are complex. Meanwhile, the geological and operating parameters have a dramatic influence to oil production and is lack of systematic research. In this study, a fluid model of crude oil was established to evaluate the impact of CO2 on oil volume and viscosity. Then, a compositional numerical model coupled miscibility and geomechanics were set up to analyze enhanced oil recovery (EOR) potential under different miscible degree with in-situ stress field. Ultimately, in accordance with multiple nonlinear regression production forecast models, Sobol, FAST (Fourier Amplitude Sensitivity Test), and DGSM (derivation-based Global Sensitivity Measure) methods were utilized to study the main factors affecting cumulative production. The results shown that CO2 almost has the same effect on the volume of these tight oil and has the most significant effect on the viscosity of crude oil we studied by comparing. The production of miscible flooding is 38.2% and 16.4% higher than that of immiscible and near-miscible flooding, respectively. The formation were compacted during production especially in the early stage, hence the production of the model with geomechanics was 23.3% less than the model of nongeomechanics. The first-order sensitivity indexes of bottom-hole flow pressure, reservoir thickness and fracture conductivity are about 0.808, 0.176 and 0.004 respectively obtained by Sobol method, consistent with two other methods. This result shows that bottom-hole flow pressure, reservoir thickness and fracture conductivity are the most important factors affecting production, and bottom-hole flow pressure has the most significant impact on production. This work investigates how miscibility and geomechanics effect on production as well as clarified the factors affecting production for CO2 pre-pad injection, providing vital insights into operating in tight reservoirs for oil field.",3,3,3
Flow Rate,Shale,"Li, Lei; Hao, Yongmao; Lv, Yuting; Wang, Chengwei; Yao, Chuanjin; Zhao, Qingmin; Xiao, Pufu",Experimental investigation on low-velocity seepage characteristics and influencing factors in a shale oil reservoir,,NON-DARCY FLOW; APPARENT PERMEABILITY; GAS-TRANSPORT; NANOPORES; MULTISCALE; MODEL; ADSORPTION; MULTICOMPONENT; PERFORMANCE; SIMULATION,"The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10(-4) ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, microfractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs.",2,2,11
Flow Rate,Shale,"Li, Yaxiong; Liu, Xiangui; Gao, Shusheng; Duan, Xianggang; Hu, Zhiming; Chen, Xueke; Shen, Rui; Guo, Hekun; An, Weiguo",A generalized model for gas flow prediction in shale matrix with deduced coupling coefficients and its macroscopic form based on real shale pore size distribution experiments,Shale gas; Comprehensive flow mechanism scheme; Coupling coefficient; Generalized model; Macroscopic form,GEOTHERMAL-ENERGY EXTRACTION; SLIP-FLOW; TIGHT GAS; PERMEABILITY; DIFFUSION; TRANSPORT; CO2; PERFORMANCE; SIMULATION; NANOPORES,"As an unconventional natural gas resource, shale gas is attracting increasing attention worldwide because of its potential to strengthen global energy security and reduce carbon emissions. The shale gas flow in nanopores is one of the main concerns affecting its development process. However, due to the strong nonlinearity and complexity of gas flow at the nanoscale, there is no satisfactory consensus on a physically sound flow mechanism scheme and its corresponding coupling method. Furthermore, although the integration method using specific functions has been proposed to facilitate the consideration of various pore sizes in shale matrix, the real shale experiments are rarely involved to realize this integration method with definitely determined parameters. In this study, the concept of ""wall-associated diffusion"" is firstly utilized to clarify the relationship among several flow mechanisms, and thereby a comprehensive flow mechanism scheme differing from common research is proposed, which physically considers both the division of mechanical mechanisms in nanopores and partition of flow space. Besides, the deficiencies in the mathematical models of viscous flow and several diffusion processes for flow description are illustrated. Using the molecular collision frequency expressions, a new coupling coefficient-based flow model in nanopores is derived to eliminate the aforementioned deficiencies by strengthening the correspondence between the flow models and Knudsen number (Kn), which is applicable in the full flow regime scope and avoids segment processing. Furthermore, based on the pore size distribution experiments of the real shale samples from a gas field, the fitting parameters needed for the macroscopic form of the above coupled model are obtained, so as to establish an integration method-based unified model for gas flow prediction in shale matrix. Results show that the prediction accuracy of the new model for the two tested shale samples is at least 2.2 times higher than several typical models and is also 1.9 and 7.5 times more accurate than the model without coupling coefficients, respectively. And the application of the proposed model to the flow experiment on another shale sample at higher pressure levels is in accordance with these observations. Interestingly, as temperature increases, the flow rate decreases with minor amplitudes. Under the conditions studied, the pressure change can cause over 10 times variation of the flow rate, revealing measures should be taken to maintain relatively high reservoir pressures to guarantee appreciable gas production from matrix if the other factors remain unchanged. In addition, the difference between the average flow shape in the whole rock and the gas motion in the pore of mean radius is revealed. Sounder in theoretical bases and better in application effects, the proposed model is expected to be of practical significance for guiding shale gas reservoir development.",2,2,2
Flow Rate,Shale,"Ashrafi, Taha; Saberi, Mohammad Hossein; ZareNezhad, Bahman","1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran",Basin modeling; Source rock evaluation; Sarchahan formation; Coastal fars; Southern Iran,FOLD-THRUST BELT; ZAGROS MOUNTAINS; PERSIAN-GULF; CONTIGUOUS OFFSHORE; LATEST ORDOVICIAN; NATURAL-GAS; ORIGIN; STRATIGRAPHY; RESERVOIRS; BASEMENT,"One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the ""hot shales"" of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m(2) since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.",1,1,2
Flow Rate,Heavy Oil,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Flow Rate,Heavy Oil,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Flow Rate,Heavy Oil,"Niu, Jun; Liu, Shuo; Xu, Jing-yu",Investigation into atomization spray blending property in heavy crude oil extraction under laboratory conditions,Heavy crude oil extraction; Atomization spray; Blending; Viscosity reduction; Droplet behavior,VISCOSITY; BREAKUP; RECOVERY; SIZE,"In this study, the atomization blending property for heavy crude oil extraction was systematically investigated both numerically and experimentally. In the experiment conducted, the blending behavior was simulated using hydraulic oil and spray with 1:10 light phase-gas atomize volume flow rate ratio in an equipment sharing the same scale as the on-site production. A Malvern Insitec droplet size analyzer was applied for the droplet size measurement, and a quick closing valve method was applied for the phase fraction measurement. A numerical simulation combined with a population balance model and the RNG k-epsilon model was performed under both the corresponding operating conditions and a high-pressure drop environment to further investigate the blending procedure. The results show that the atomization spray blending performs better than the equivalent pure gas lifting method with more crude oil carried at the exit. Under 0.6 m(3)/h light phase inlet conditions, spray blending brings 8% more heavy crude than gas lifting, and the improvement rises as inlet flow rate increases. Both a droplet and liquid film are present in the casing space before blending for the spray liquid phase. In addition, the light phase droplet diameter decreases with an increase in the inlet flow rates in the lifting pipe after blending. Moreover, the blending behavior differs under various light phase inlet flow rates, while the mixture viscosity is reduced by 50% for the atomization spray method. Each of these factors was shown to be beneficial for refining the blending used in a heavy crude oil extraction technique.",1,2,2
Flow Rate,Heavy Oil,"dos Santos, Lorena A.; Ribeiro, Daniel da C.; Romero, Oldrich J.",Heavy oil transportation through steam heating: An analytical and numerical approach,Viscous oils; Concentric steam pipe; Heat transfer; Steam quality; Flow assurance,NEWTONIAN FLOW CHARACTERIZATION; WATER-ALUMINA NANOFLUID; NATURAL-CONVECTION FLOW; CRUDE-OIL; VISCOSITY; BEHAVIOR; ANNULUS; MODEL,"Amongst the innumerable challenges that permeate the production chain of heavy oils, the transportation stage deserves to be highlighted. Due to its high viscosity, heavy oils exhibit considerable flow resistance, requiring auxiliary mechanisms to enable its transportation via pipelines. This study analyzes a concentric pipeline configuration, in which steam flows through the inner pipe and oil flows through the annular space of the oil pipe. The main goal is to investigate the impacts of steam insertion, concentric coupling dimensions, thermal insulation, steam quality and system horizontal length on the main parameters of flow control: oil temperature and viscosity. As a secondary parameter, oil initial pressure required to ensure flow completion is also discussed. In this intent, a numerical approach is applied with software Ansys CFX in a tridimensional, steady state simulation. A second objective is to estimate the main parameters of interest by an analytical approach, using the thermal resistance model associated with the epsilon - NTU method. The goal is to determine if, given a similar coupling scenario and the absence of computational resources, oil temperature and viscosity can be estimated by direct calculations within an acceptable range of deviation from the numerical approach. Heat transfer rates are also estimated as secondary parameters. Numerical results for a 1-m length system reveal that steam insertion elevates the average oil temperature in 1.2%, reducing its average viscosity and initial flow pressure by 8.7% and 24.2%, respectively. From the previous scenario, a reduction of 24.6% in the oil pipe/steam pipe radius ratio results in an additional 1.2% temperature increase and 4.7% viscosity reduction. On the other hand, reducing steam quality in 30% implicates an average oil viscosity 2.4% higher. In a 4-m system, a convective cell pattern is observed, in which oil heating and viscosity reduction reaches its peak at the central upper region of the annular space, highlighting cooler and denser deposits in the lower section of the system and a nonlinear heating process. Maximum deviations between numerical and analytical approaches in oil temperature and viscosity estimates are 1.3% and 15.6%, respectively, which indicate the latter as a suitable calculation method for small systems in the absence of numerical resources. Deviations are mainly attributed to the neglect of natural convection, gravitational and steam turbulence effects, which contribute for a non-homogeneous heating of oil.",1,1,1
Flow Rate,Leakage,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Flow Rate,Leakage,"Yang, Mou; Yang, Lvchao; Wang, Tao; Chen, Yuanhang; Yang, Chao; Li, Lanxu",Estimating formation leakage pressure using a coupled model of circulating temperature-pressure in an eccentric annulus,Leakage pressure; Eccentric annulus; Transient temperature; Coupled model of temperature and pressure,NON-NEWTONIAN FLUIDS; HEAT-TRANSFER; TRANSIENT TEMPERATURE; HERSCHEL-BULKLEY; FLOW; WELLBORE; LAMINAR; LOSSES; WELLS; OIL,"The eccentric annulus represents the majority of real-life situations and is attributed to a continuous change of hole-deviation angle and azimuth angle with well depth, leading to a difference in fluid flow and heat transfer mechanisms, compared with a concentric annulus. Errors resulting from ignoring the effect of eccentricity on wellbore circulating pressure and equivalent circulating density can lead to formation leakage. Based on a close relationship between circulating pressure and leakage pressure, a practical approach to predicting formation leakage pressure was established in the eccentric annulus, after running the casing, through the gradual increase of the flow rate and back pressure at the wellhead. Based on the conservation principle of energy and mass, and considering the collective effect of lost circulation and an eccentric annulus on wellbore temperature and pressure, a transient heat transfer model and a fluid flow model were developed and solved to estimate leakage pressure accurately. The numerical solution results were presented, analyzed and tested using a practical example. The results indicated that, with increasing flow rate, annulus pressure increases and temperature decreases. Temperature and pressure in the wellbore have a significant influence on the properties of the rheological parameters of Herschel-Bulkley fluid. Additionally, pressure loss and the equivalent circulating density (ECD) in the annulus were further elevated by setting back pressure at the wellhead, compared with an increase of flow rate. Most relevant is that the validity of the established method was verified through both monitored and calculated data.",2,3,5
Flow Rate,Leakage,"Lv, Xiaoxiao; Wang, Hanxiang; Liu, Yanxin; Chen, Shengshan; Lan, Wenjian; Sun, Bingyu",A novel method of output metering with dynamometer card for SRPS under fault conditions,Sucker rod pumping; Polished rod; Valve leakage; Dynamometer card; Output metering,ROD; MODEL; DIAGNOSIS,"Remote monitoring of sucker rod pumping system (SRPS) based on polished rod dynamometer cards (DC) is an effective means to reduce the operating costs and realize the real-time control. Nevertheless, how to obtain the working process and the production rate of SRPS from polished rod DC is always a puzzle because of complex down-hole motions. The typical solution for this problem is deriving the pump DC via the wave equation to achieve the effective stroke of plunger. But some key parameters involved in this approach such as valve leakage and the fill factor are difficult to determine accurately, especially under fault conditions, which may influence the accuracy of output metering. In order to address this tough issue, in this paper, a novel method of output metering with DC is proposed based on quantitative analysis of fault. The method consists of two parts, the first part is an approach to simulate the working process of SRPS under fault conditions, specifically it's an improved simulation model characterized by a set of fault parameters, which is presented through analyzing the mechanisms of sucker rod pumps at normal and several faulty scenarios. And the second part is a method implemented by genetic optimization algorithm to determine the fault parameters set of the actual SRPS. Using parameters of typical well, the analysis of effects of faults on SRPS is carried out. The simulation results show that valves leakage reduces the flow rate of liquid significantly in the period of effective stroke, which leads to the distortion of output metering results of effective stroke method. Compared with single faults, coupling faults aggravate the production reduction of SRPS. Furthermore, when the well fluid contains gas, the impact of traveling valve leakage on the reduction of production is greater than that of standing valve leakage, but the consequence is opposite when formation energy is insufficient. Besides, the carbon fiber rod and fiberglass rod SRPS are more sensitive to valve leakage, while the steel rod and wire rope SRPS are more sensitive to the condition of insufficient liquid supply. Eventually, the proposed method is verified experimentally through the productive parameters and measured DC of actual wells collected from an oilfield. The obtained results demonstrate the effectiveness of the proposed method for output metering and fault diagnosis as well.",2,2,1
Flow Rate,Leakage,"Huq, Farhana; Viig, Sissel Opsahl; Brandvoll, Oyvind; Johansen, Ingar; Medeiros Junior, Iris; Gomes Teixeira, Marco Antonio",Development of a passive sampling technique for offshore CO2 monitoring: Preliminary results from laboratory experiments,Passive sampler; Perfluorocarbon; Tracer; CO2 monitoring; Seafloor; Marine environment,PERFLUOROCARBON TRACERS; GEOCHEMICAL TRACERS; CARBON-DIOXIDE; RESERVOIR; SEQUESTRATION; POLLUTANTS; CAPACITY; AQUIFERS; LEAKAGE; FLOW,"Monitoring of sequestered CO2 at storage sites is essential to provide assurance of long-term storage integrity. Thus, the objective of this study was to develop a sorbent-based offshore monitoring concept to monitor CO2 leakage during CO2-EOR operations. The study site, where the CO2 -EOR operation is planned to be undertaken, is located in the pre-salt layer offshore Brazil. Perfluorocarbons (PFCs) were selected as tracers for monitoring possible CO2 leakage. A passive sampling technique was proposed to adsorb the injected tracer. Several commercially available sampler materials were initially chosen, among which Carboxen 569 placed inside a polyethersulphone (PES) membrane was tested and selected to be the preferred passive sampler combination. In order to perform tracer uptake rate experiments, a flow through experimental setup was built, optimized and tested under in-situ conditions of 300 bar and 15 degrees C. In addition, a desorption unit was designed to quantify the tracer amount sorbed to the sampler during the experiments. The developed passive sampler combination proved to be successful in sorbing the tracers. The phase distribution of the tracer candidates in a CO2-water-oil system were investigated in a slimtube setup. It is shown that the PFCs have a shorter travel time through the system than CO2 and will potentially provide a warning of CO2 leakage from the reservoir. Although the developed technique successfully proved the proposed concept of monitoring CO2 leakage, further testing to investigate the life cycle of the sampler will be necessary to apply this technique at field scale.",1,1,4
Flow Rate,Reaction,"Wang, Kai; Li, Chenpei; Li, Yanhui; Lu, Jinling; Wang, Yueshe; Luo, Xingqi",A fully coupled model of hydrodynamic -chemical -electrochemical processes for CO 2 uniform corrosion in multi -physics environment,CO 2 uniform corrosion; Multi-physics model; Flow effect; Multi-ion transport; Multi-component reactions,CARBON-DIOXIDE CORROSION; MILD-STEEL; PART 1; ELEVATED-TEMPERATURES; INCUBATION PERIOD; AQUEOUS-SOLUTIONS; PASSIVE METALS; WATER; OIL; PREDICTION,"Carbon dioxide uniform corrosion occurs widely in the petroleum industry and threatens the safe production and transportation of petroleum resources. It is a complex issue involving a variety of physical, chemical and elec- trochemical processes in multiple temporal and spatial scales. A fully coupled model, taking into account all involved processes in a coupled fashion, such as fluid flow, multi -ion transport, multi -component chemical/ electrochemical reactions, is established to comprehensively investigate the mechanism of CO 2 corrosion in multi -physics environment. The reliability of this model is validated by the good consistency between the pre- dicted corrosion rates and the experimental results in the literature, and this model performs better in corrosion rate prediction than the previous models due to the explicit solution for the convective mass transfer. Based on this fully coupled model, the corrosion mechanism in the multi -physics coupled environments is revealed in terms of the time -dependent ion concentration field, mass transfer and electrode reaction kinetics. The inter- relationship between the corrosion kinetics and the flow effect is explored. The results indicate that the time - dependent corrosion behavior is determined by the combined effect of the solution chemistry and electrical field. By accelerating the mass transport of corrosive species and the involved multi -component reactions, the fluid flow can significantly promote the corrosion process, while the promotion effect weakens gradually at higher flow velocities. Additionally, the flow effect at lower pH values is much more pronounced due to the transformation of the predominant controlling factors for electrode kinetics.",2,2,11
Flow Rate,Reaction,"Lai, Nanjun; Wen, Yiping; Wang, Yong; Zhao, Xubin; Chen, Jinlong; Wang, Dongdong; Wang, Xin; Yu, Tong; Jia, Chao",Calcium carbonate scaling kinetics in oilfield gathering pipelines by using a 1D axial dispersion model,Pipeline scaling; Pulse tracer method; Conductivity method; Reaction kinetics; 1D dispersion model; Scaling prediction,RESIDENCE TIME DISTRIBUTION; FORMATION DAMAGE; PRECIPITATION; PREDICTION; SALINITY; CRYSTALLIZATION; INHIBITION; DEPOSITION; DISTRIBUTIONS; TEMPERATURE,"The dynamic scaling mechanism of calcium carbonate (CaCO3) in pipelines was examined in this work to study the dynamic scaling process in oilfield gathering pipelines. The investigation began by using dynamic scaling analysis equipment to test the fluid flow pattern in a pipeline interior through the pulse tracer method. The average residence time distribution was obtained from this experiment. Then, a 1D dispersion model of scaling fluid was established by considering the constant of the crystallization reaction rate, which was measured by using the electrical conductivity method. Results showed that the average residence time in the pipeline was long when environmental temperature was high and the back-mixing degree was strong. CaCO3 scaling reaction attributed to the first-order reaction and the reaction rate constant at different temperature was acquired in accordance with the principle of chemical reaction kinetics. The conversion rate of CaCO3 scaling reaction inside the pipeline was calculated using a 1D axial dispersion model. By comparing the calculation results with the scaling reaction conversion of the pipeline in practical testing, the average relative error was determined as 12.76%, and the absolute error range was only 1.66-3.26%. This model can accurately predict the dynamic scaling dynamical process of fluid flow in pipelines and provide the necessary basic information for scale prevention and removal treatment in actual construction.",1,1,6
Flow Rate,Reaction,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Flow Rate,Reaction,"Ali, Imran; Gubanov, S., I; Ovchinnikov, K. A.; Olkhovskaya, V. A.; Kovaleva, G. A.; Galunin, Evgeny; Tkachev, Alexey",A dual-well system and thermal-gas-chemical formation treatment: Combined methods for high-viscosity oil production,High-viscosity oil; Dual-well system; Thermal-gas-chemical formation treatment; Model of nonlinear viscoplastic flow; Rheological characteristics of the oil,,"The article deals with the possibility of increasing the flow rate of high-viscosity oil by injecting a binary chemical composition into a dual-well system well. The interaction of the main chemical reagent with the initiator of the exothermic reaction contributes to the heating of the formation within the radius of the bottom hole of the vertical shaft. Due to the risk of irreversible changes in the structure and reduced rock permeability in the contact area of reagents, oil is extracted through the side shaft. Theoretically and experimentally it has been proven that the optimal reservoir temperature at the tapping point can be reached due to the rheological characteristics of high-viscosity oil. The results of hydrodynamic modeling of well production rate and reservoir thermal field for the proposed object of the impact are presented. The optimal parameters of the technological mode are determined and it is confirmed that the criterion for the efficiency of the combined method is the oil production intensification. The study was carried out at the B-2 reservoir of the Bobrikovian horizon in the Samara region (Russia).",1,1,1
Flow Rate,Hydrate,"Kim, Hyunho; Kim, Jakyung; Seo, Yutaek",Economic benefit of methane hydrate reformation management in transport pipeline by reducing thermodynamic hydrate inhibitor injection,Gas hydrates; Methane production; Hydrate re-formation; Mono ethylene glycol; Life cycle cost; Regeneration process,NATURAL-GAS HYDRATE; WATER-FLOW; CARBON-DIOXIDE; HIGH-PRESSURE; DISSOCIATION; SEPARATION; STORAGE; DEPRESSURIZATION; DESALINATION; NANOBUBBLES,"Hydrate reformation is an inherent risk in a methane hydrate production system because dissociated water and methane flow through transport pipelines simultaneously. In this study, comprehensive experiments using high-pressure autoclaves are performed to investigate the effect of reducing the concentration of thermodynamic hydrate inhibitor on hydrate reformation characteristics. In order to simulate the production of methane hydrates, these are formed and dissociated in the preliminary stage; thereafter, the hydrates are reformed from dissociated water. Although dissociated water and fresh water are found to have similar formation rates, they have a major difference in relative torque, especially in the early stage of hydrate formation. The instant rise of the relative torque in the dissociated water is observed to be up to 2.5; thereafter, it remains approximately 3.0 until hydrate conversion reaches 28 vol%. This trend is different from that in fresh water, where a steady increase in relative torque with sudden spikes is observed. These results clearly show the high risk of hydrate blockage in the transport pipelines of a methane hydrate production system; hence, the injection of hydrate inhibitor is necessary. In this study, monoethylene glycol (MEG) is the selected thermodynamic hydrate inhibitor; its concentration is maintained below a specific value to completely avoid hydrate formation. Despite the occurrence of hydrate reformation, a stable relative torque is observed in a 20 wt% MEG concentration, where the conversion of water to hydrate approximately reaches 40 vol%. For a 10 wt% MEG concentration, a sudden increase in relative torque of up to 2.0 is observed in the early stage of hydrate formation; this suggests that the foregoing is less effective in sustaining flowability. Compared to fresh water, the addition of a 20 wt% MEG to dissociated water results in a more stable torque. Once the performance of the MEG concentration reduction is confirmed, the MEG regeneration process is designed accordingly by using both multiphase flow and process simulation models. A life cycle cost (LCC) analysis is conducted by estimating the capital expenditures (CAPEX) and operating expenditures (OPEX) of the MEG regeneration process. Considering both CAPEX and OPEX, the LCC for complete inhibition (35 wt%) is 90.15 MUSD (million United States dollars); however, for the 20 and 10 wt% MEG concentrations, the LCC values are reduced to 86.79 and 84.58 MUSD, respectively. The foregoing suggests the potential economic benefit of methane hydrate reformation management to avoid blockage.",3,3,8
Flow Rate,Hydrate,"Skiba, Sergey; Strukov, Dmitry; Sagidullin, Aleksei; Adamova, Tatyana; Stoporev, Andrey; Svarovskaya, Lidia; Strelets, Larisa; Altunina, Lubov; Manakov, Andrey",Impact of biodegradation of oil on the kinetics of gas hydrate formation and decomposition,Gas hydrate; Biodegradation; Self-preservation; Kinetics,METHANE HYDRATE; SELF-PRESERVATION; ACIDIC COMPOUNDS; CRUDE OILS; DISSOCIATION; CRYSTALLIZATION; POINT,"Nowadays the biological methods based on utilization of bacteria for different purposes in oilfields are becoming more and more popular because these methods potentially may become a cheaper alternative to chemical treatments. Gas hydrates formation in pipelines is the one of the main flow assurance problems. In previous works it has been shown that some biodegraded oils can have components that may act as natural Anti-Agglomerants. These natural Anti-Agglomerants can prevent hydrate particles from agglomeration which allow the particles to flow downstream along with oil in form of slurry. But there is lack of understanding of how products of oil biodegradation affect the kinetic aspects of hydrate nucleation, formation and decomposition. This information might be useful for development of new approached of treatment of the hydrate related issues in oil pipelines. Impact of the changes in component composition of crude oil caused by biodegradation process on the kinetics of gas hydrates nucleation, formation and decomposition has been studied with different methods. It was demonstrated that the changes of chemical composition of crude oil caused by biodegradation can have a strong impact on the hydrate nucleation rates at static conditions. Almost twofold decrease of hydrate nucleation rate was observed in the experiments with the water-in-oil emulsion for the biodegraded oils compared to one obtained with emulsion in the original crude oil. At the same time, no significant effect of biodegradation on the hydrate film growth rates at static conditions was observed. Similar tangential and normal hydrate film growth rates were obtained in experiments with both crude oil and with biodegraded oil. Initial growth rates of hydrate in stirring emulsions were an order of magnitude higher for water emulsions in the biodegraded oil compared to ones for the original crude oil. The studies of the decomposition rates of hydrates at sub-zero temperatures and at dynamic conditions showed that the products of vital activity of bacteria promoted self-preservation of hydrates dispersed in the biodegraded oil.",3,3,3
Flow Rate,Hydrate,"Du, Dai-jun; Pu, Wan-fen; Zhang, Sheng; Jin, Fa-yang; Wang, Sheng-kui; Ren, Fang",Preparation and migration study of graphene oxide-grafted polymeric microspheres: EOR implications,Graphene oxide-grafted polymeric microsphere; Migration; Plugging; Adsorption and desorption,ELASTIC MICROSPHERES; PROFILE CONTROL; POLYACRYLAMIDE; GEL; PERFORMANCE; SYSTEM,"Through an inverse emulsion polymerization technique, graphene oxide-grafted polymeric microspheres (RGO-PMSs) with superior suspension properties, thermostability, hydration swelling, elasticity and strength were developed for in-depth profile control and displacement. RGO-PMSs undergo migration and adsorption in large pores; capture by means of single plugging, coincidence plugging and bridging plugging; and elastic deformation-recovery in small pores to increase seepage resistance. When matching coefficient was 2.11, RGO-PMSs particles could not enter the porous media. However, RGO-PMSs particles entered core samples smoothly and perform plugging when the matching coefficient ranged from 0.78-1.44, while RGO-PMSs particles could not effectively block the pores when the matching coefficient was 0.67. An increase in the injection rate improved RGO-PMSs injectivity while weakening plugging efficiency. Additionally, the increase in the RGO-PMSs concentration and strength enhanced the plugging efficiency. Moreover, RGO-PMSs had a favorable anti-outwash property with a retention ratio of 88.7%, maximum additional flow resistance of 7.12 kPa and additional flow resistance of 4.53 kPa during migration. All the results indicated that RGO-PMSs could be an applicable candidate for in-depth profile control and displacement.",2,2,2
Flow Rate,Fault,"Lv, Xiaoxiao; Wang, Hanxiang; Liu, Yanxin; Chen, Shengshan; Lan, Wenjian; Sun, Bingyu",A novel method of output metering with dynamometer card for SRPS under fault conditions,Sucker rod pumping; Polished rod; Valve leakage; Dynamometer card; Output metering,ROD; MODEL; DIAGNOSIS,"Remote monitoring of sucker rod pumping system (SRPS) based on polished rod dynamometer cards (DC) is an effective means to reduce the operating costs and realize the real-time control. Nevertheless, how to obtain the working process and the production rate of SRPS from polished rod DC is always a puzzle because of complex down-hole motions. The typical solution for this problem is deriving the pump DC via the wave equation to achieve the effective stroke of plunger. But some key parameters involved in this approach such as valve leakage and the fill factor are difficult to determine accurately, especially under fault conditions, which may influence the accuracy of output metering. In order to address this tough issue, in this paper, a novel method of output metering with DC is proposed based on quantitative analysis of fault. The method consists of two parts, the first part is an approach to simulate the working process of SRPS under fault conditions, specifically it's an improved simulation model characterized by a set of fault parameters, which is presented through analyzing the mechanisms of sucker rod pumps at normal and several faulty scenarios. And the second part is a method implemented by genetic optimization algorithm to determine the fault parameters set of the actual SRPS. Using parameters of typical well, the analysis of effects of faults on SRPS is carried out. The simulation results show that valves leakage reduces the flow rate of liquid significantly in the period of effective stroke, which leads to the distortion of output metering results of effective stroke method. Compared with single faults, coupling faults aggravate the production reduction of SRPS. Furthermore, when the well fluid contains gas, the impact of traveling valve leakage on the reduction of production is greater than that of standing valve leakage, but the consequence is opposite when formation energy is insufficient. Besides, the carbon fiber rod and fiberglass rod SRPS are more sensitive to valve leakage, while the steel rod and wire rope SRPS are more sensitive to the condition of insufficient liquid supply. Eventually, the proposed method is verified experimentally through the productive parameters and measured DC of actual wells collected from an oilfield. The obtained results demonstrate the effectiveness of the proposed method for output metering and fault diagnosis as well.",2,2,1
Flow Rate,Fault,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Flow Rate,Fault,"Azamifard, Arash; Ahmadi, Mohammad; Rashidi, Fariborz; Pourfard, Mohammadreza; Dabir, Bahram",QuiltEdge: Novel geostatistical workflow for heterogeneous reservoirs with an innovative combination of multi-variable image quilting and edge property concept to model heterogeneity and flow barriers,Edge property; Permeability texture; Geostatistic; Image quilting; Reservoir heterogeneity; Multiple point statistics,MULTIPLE-POINT GEOSTATISTICS; SEISMIC DATA; SIMULATION; CONDUCTIVITY; ENVIRONMENT; MEDIA; BASIN,"Detailed and accurate techniques which plays a vital role in providing more reliable predictions of reservoir performance are needed for spatial modeling of reservoirs with complex heterogeneity. Additional auxiliary parameters are usually defined to emulate the reservoir complex geometry and high degree of heterogeneity. Edge property concept can be used to model the effect of large-scale flow barriers or highly conductive channels such as sealing or conductive fault planes. In this study, the edge properties are overlaid on a grid of extremely heterogeneous permeability to examine the predictability of the reservoir model. Image quilting is applied to simultaneously build the cell-wise and edge properties of the reservoir model. Image quilting in this study utilizes a multivariable approach for simultaneous cell-wise and edge property modeling. Our proposed approach has been successfully examined on modified SPE 10 benchmark model, where the permeability spatial variation was modified and edge properties were added to represent the large-scale sealing or conductive faults. Several realizations were generated using image quilting technique based on training images. The geological patterns of permeability variation and the large scale barriers or conduits are conveyed properly from training images into reservoir model, even in this extremely heterogeneous studied reservoir. The difference of gas breakthrough time between inferred value of model realizations and the reference model is almost 12 days for minor modifications of famous SPE10 benchmark. Moreover, maximum oil production rate is predicted with more reliability as a consequence of proposed approach. The slope of oil production rate is identical to the reference case for the times after breakthrough. In addition, breakthrough time is estimated efficiently. With this approach (derived from permeability texture concept), the modelled properties become more and more realistic (geologically-consistent realizations) and the reservoir simulation outputs are become more reliable. This approach constrains the variability of geological properties and consequently the uncertainty with reservoir forecast is substantially reduced.",1,1,1
Flow Rate,Analytical Solutions,"Andersen, Pal O.; Zhou, Yingfang",Steady state relative permeability experiments with capillary end effects: Analytical solutions including derivation of the intercept method,Capillary end effects; SCAL; Steady state experiment; Generalized capillary number; Analytical solutions; Intercept method,,"Steady state relative permeability experiments are performed by coinjection of two (or more) immiscible fluids. The relative permeabilities can be calculated directly from the stabilized pressure drop and saturation of the core if capillary end effects and transient effects are negligible. In most cases such conditions are difficult to obtain. This work presents an analytical solution in form of explicit expressions for the spatial profiles of pressure gradients and saturation, average saturation and pressure drop for a core being injected simultaneously with two phases at steady state when capillary end effects are significant. When arbitrary saturation functions are applied, such parameters and distributions can only by obtained by numerical integration. By assumption of simplified saturation function correlations the differential equation describing steady state can be integrated. A new dimensionless capillary number N is obtained which contains the fluid and rock parameters, but also the saturation function parameters (relative permeability and capillary pressure), fluid viscosities, injected flow fraction, total flow rate and more. It is shown that when this number is of magnitude 1, end effects cover parts of the core, but parts of the core are also unaffected. For N > 10 the end effects are negligible, while for N < 10 end effects are dominant. This paper gives the first formal proof of the intercept method from basic assumptions. It is shown that when the inlet saturation is sufficiently close to that of a no capillary pressure situation; the average saturation changes linearly with the inverse of total rate towards the saturation corresponding to no capillary forces; also, the pressure drop divided by the pressure drop of a no end effect situation goes linearly towards 1 with the inverse of total rate.",3,3,3
Flow Rate,Analytical Solutions,"Omojuwa, Emmanuel; Ahmed, Ramadan",Analytical modeling of axial oscillation-supported drillstrings in high-angle wells,Axial oscillations; Directional drilling; Oscillation tools; Borehole; Friction reduction; Modeling; Displacement excitation,FRICTION-REDUCING PERFORMANCE; REDUCTION; TOOL,"Downhole vibrations generated from axial oscillation tools (AOTs) in axial oscillation-supported drillstrings (AOSDs) has become one of the efficient means of reducing friction and improving weight transfer during sliding operations in horizontal and extended-reach wells. Dynamic modeling of AOT-excited drillstrings is needed for validating the functionality of axial oscillation tools during surface tests and predicting their response under downhole conditions. An analytical model is presented in this study to predict the behavior of axial oscillation-supported drillstrings working under downhole and surface conditions. The model is useful to perform parametric studies, downhole data correlation and placement study of AOTs along the drillstring in horizontal and extended-reach wells. Unlike existing models, the nonlinear equation of motion is derived from a model damped in a viscous medium with Coulomb friction and subjected to displacement excitation. The model also accounts for the spring rate of the axial oscillation tool. The displacement excitation is obtained from the spring rate, which is a critical input to the model. The nonlinear damping is approximated with an equivalent viscous damping coefficient to obtain an analytical solution. The developed model in this study is validated with published experimental measurements obtained from field-scale drillstrings. Correlations between predicted and measured axial displacement and accelerations at different excitation frequencies, pressure drops and spring rates show an approximate average deviation of 14.5%. Also, results from this study strongly accentuates that flow rate is the most critical operating parameter for axial oscillation tools because it affects the amplitude of pressure drop, excitation force, and operating frequency of AOTs.",2,2,2
Flow Rate,Analytical Solutions,"Kozhagulova, Ashirgul; Nguyen Hop Minh; Zhao, Yong; Fok, Sai Cheong",Experimental and Analytical Investigation of Sand Production in Weak formations for Multiple Well Shut-Ins,Weak formation; Sand production; Experimental testing; Analytical prediction; Well shut-in; Ustyurt-Buzachi,ROCK FAILURE; MODEL; PRESSURE; CRITERIA; ONSET,"Sand production is a severe problem in oilfields and is majorly associated with weak and unconsolidated formations. Therefore, identifying the expected amount and rate of sand has been approached by different analytical and numerical prediction methods. Within them the former requires less computational time and therefore being widely used. However, despite some of the analytical models proved to be fairly predictive for sand production during steady-state flow, they cannot be used directly for the wells with complex production profiles. The current study focuses on the experimental investigation of the sand production pattern during well production and shut-in periods. The laboratory work was conducted on artificial sandstone replicating weak Cretaceous formations in Kazakhstan using customized High Pressure Consolidation System (HPCS) for sand production experiments. HPCS accommodates a sandstone sample of a large diameter to diminish boundary effect when the fluid is injected. The tests were conducted at different overburden stresses as well as pressure drawdowns in several well shut-in runs. The paper presents a modification of the classical steady-state flow analytical solution incorporating field and fluid conditions as well as the dependence on the well shut-in runs. The model showed good convergence with the experimental and well data.",2,2,1
Flow Rate,Newtonian Fluid,"Chen, Jingkai; Zhang, Yanting; Zheng, Zhibin; Liu, Zhendong; Huang, Lumeng",Dynamic analysis of top-excited vibration assisted stuck release in vertical borehole with fatigue-like model,Stuck pipe; Axial vibration; Shear stress distribution; Fatigue-like release model,STICK-SLIP VIBRATIONS; TORSIONAL VIBRATION; ROCK JOINTS; STABILITY ANALYSIS; SHEAR MECHANISM; ROOT CAUSE; DRILL; FRICTION; PERFORMANCE; BEHAVIORS,"Stuck release operation is one of the largest contributions for the increase of non-productive time and consequently the increase of the well cost. Traditional stuck release operations including the jarring operations, changing flow rate, varying mud density are expensive and time-consuming. Recently, a surface vibration apparatus is introduced to the drilling industry and the stuck release time is highly reduced with this new apparatus. In this paper, a fatigue-like stuck release model is introduced to analyze the release mechanism of the stuck pipe excited by the vibration agitator. First, the drill string vibration behavior subjected to surface vibration agitator is analyzed. The natural frequencies and mode shapes are calculated analytically. The damping effect of drill mud is intensively investigated by assuming the laminar flow and Newtonian fluid. Second, the shear stress distribution on the stuck section is proposed analytically and verified with numerical examples. The influence of the shear parameter on the shear stress distribution is discussed and calibrated for certain configuration. Third, the stuck release behavior subjected to cyclic load is modeled with fatigue-like model, which is characterized by the formation release strength and stress factor. The stuck release process is progressive and three stuck release stages are identified. Finally, the top-excited drill string vibration is coupled with the release process on the stuck section. The top-excited vibration assisted stuck release system is modeled numerically. The stuck release processes operated at different resonant excitations are discussed. This paper casts light on the theoretical explanation of the vibration assisted stuck release mechanism and is important in optimizing the stuck release operations.",2,3,1
Flow Rate,Newtonian Fluid,"Zhu, Jianting",Impact of yield stress and fractal characteristics on the flow of Bingham fluid through fracture network,Bingham fluid; Newtonian fluid; Yield stress; Fractured reservoir; Fractal dimension; Flowrate ratio,STARTING PRESSURE-GRADIENT; EFFECTIVE PERMEABILITY; GAS-RESERVOIRS; MODEL; MECHANICS; WELL,"Flow process of a fluid with yield stress in fractured reservoirs is important in petroleum recovery. In this study, a new approach is proposed to study the combined effect of Bingham fluid properties and fractal characteristics on the flow of a Bingham fluid through a fractal fracture network. Both the aperture and trace length of fractures are distributed according to the power-law fractal distribution with distinct fractal dimensions. The relative effect on the flowrate of Bingham fluid in the network by the Bingham fluid properties and fractal characteristics compared to the Newtonian counterpart is examined. The results demonstrate that the flowrate of Bingham fluid through the network increases quickly with the pressure head gradient since large fractures are first activated which are responsible to quickly increase the Bingham fluid flowrate. The flowrate ratio of the Bingham fluid over Newtonian fluid decreases with the fractal dimension of aperture since the Bingham fluid flowrate decreases with increasing fractal dimension at a faster rate than the Newtonian fluid. A larger ratio of minimum over maximum apertures in the fractal network results in a larger flowrate ratio of the Bingham fluid over Newtonian fluid. The trace length fractal parameters do not affect the flowrate ratio of the Bingham fluid over the Newtonian fluid due to the fact that these parameters affect the actual flowrate for both types of fluid to the same extent.",2,2,0
Porous Media,Water,"Lu, Meng; Connell, Luke Daulton; Pan, Zhejun","Wetting fluid behaviour with phase transition in geological nanopores: Liquid film, capillary condensation and evaporative flow",Nanopores; Tight rocks; Thermodynamics; Phase transition; Unconventional reservoirs,HOMOGENEOUS NUCLEATION; THERMODYNAMIC ANALYSIS; POROUS-MEDIA; SHALE; STABILITY; WALL; NANOFLUIDICS; ADSORPTION; TRANSPORT; INJECTION,"Fluid behaviour in nanoscale pores may significantly deviate from that in its bulk state, because pore-wall effects may have critical influences on fluid properties such that its behaviour becomes surface-controlled. Geologically, study of fluid flow with phase transition (condensation/evaporation) in nanoscale pores is of considerable significance in practice, as understandings of the relevant mechanisms may greatly help optimise operation conditions in field applications. Typical examples include geological disposal of contaminated wastes and recovery of resources from unconventional gas and oil reservoirs. In this text, we present a study to systematically investigate how the fluid behaviour, such as the liquid film formed on a pore-wall, the condensation/evaporation of the fluid and the evaporative flow profile in the pore, depends on the molecular/electrical surface forces and the pore-wall-curvature. Towards this we first formulated a set of extended phase equilibrium relationships following a rigorous thermodynamic procedure in which the relevant pore-wall effects are included. Then, a set of new evaporative flow equations was developed, which improves the original Mahadevan model by taking into account the pore-wall effects engaged. Several laboratory tests published in literature were employed to compare the present model with the Mahadevan model. With the results obtained we discussed the pertinent pore-wall effects on the evaporation behaviour of the water, and it was shown that for the evaporative flow process concerned, these effects are significantly important and considerable deviations would be generated without consideration of them.",3,3,4
Porous Media,Water,"Salehpour, Mohammad; Riazi, Masoud; Malayeri, M. Reza; Seyyedi, Mojtaba",CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage,"Carbon capture, and storage (CCS); Carbon capture, utilization, and storage (CCUS); Carbonated water injection; Heavy asphaltic crude oil; Water-in-oil emulsion; Enhanced oil recovery",PORE-SCALE MECHANISMS; WATER INJECTION; INTERFACIAL-TENSION; WETTABILITY ALTERATION; CO2 INJECTION; PERFORMANCE; SECONDARY; SCENARIOS; EMULSIONS; DIOXIDE,"Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsioninduced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.",3,3,4
Porous Media,Water,"Al Reda, Stephane M.; Yu, Catherine; Berthe, Guillaume; Matray, Jean-Michel",Study of the permeability in the Opalinus clay series (Mont Terri - Switzerland) using the steady state method in Hassler cell,Mont Terri; Opalinus clay; BDB-1 borehole; Gas permeability; Water permeability; Steady state method; Hassler cell; Slippage effect,DIFFUSION-COEFFICIENTS; POROUS-MEDIA; GAS-FLOW; WATER; PARAMETERS; PRESSURE; ROCKS; FAULT,"Mont Terri rock laboratory located in the Northwestern Switzerland is an international platform for applied research in the field of radioactive waste disposal in clayrock formations. A borehole named BDB1 has been drilled in the Opalinus claystone in 2013 to assess its containment properties. Characterization of petrophysical and hydrogeological parameters in the Jurassic shale known as Opalinus Clay were performed by in situ experiments conducted in the rock laboratory of Jura Mountains and on borehole samples. This paper presents the results of laboratory measurements of permeability in a permeameter called Hassler cell by using the steady state method. The study is applied to core samples drilled perpendicular and parallel to the bedding, and involves gas and water permeability measurements. The Hassler cell is an experimental device that allows to put samples under a confining pressure reproducing the in situ one. In all, results were obtained for nine samples over sixteen for gas permeability measurements with values ranging between 6.9 x 10(-21) and 2.3 x 10(-19) m(2) and one sample for water permeability measurements with a value of 1.38 x 10(-20) m(2). Most of the results are in good agreement with previous studies obtained by in situ experiments and using the Poiseuille type law method. The usage of several methods to determine the permeability of the Opalinus clay unit helps to conclude about the accuracy, trueness and precision of the measurements.",3,3,0
Porous Media,Water,"Galindez-Ramirez, G.; Contreras, F. R. L.; Carvalho, D. K. E.; Lyra, P. R. M.",Numerical simulation of two-phase flows in 2-D petroleum reservoirs using a very high-order CPR method coupled to the MPFA-D finite volume scheme,Oil-water displacements; Anisotropic and heterogeneous petroleum reservoirs; High-order approximations; Multipoint Flux Approximation with Diamond Stencil (MPFA-D); Correction Procedure via Reconstruction (CPR); Multidimensional Limiting Process (MLP),DISCONTINUOUS GALERKIN METHODS; POROUS-MEDIA; ELEMENT-METHOD; RECONSTRUCTION; ACCURACY; IMPLICIT; APPROXIMATIONS; FORMULATION; VELOCITY; MESHES,"The focus of the present work is to model the two-phase flow of oil and water in 2-D anisotropic petroleum reservoirs using a novel appropriate combination of a non-orthodox cell-centered Multipoint Flux Approximation with a Diamond Stencil (MPFA-D) finite volume method to discretize the pressure equation coupled to the very high-resolution Correction Procedure via Reconstruction (CPR) scheme for the discretization of the saturation equation. To suppress numerical oscillations (under/overshoots) near shocks, that are typical in higher-order schemes, and to deliver high accuracy in smooth regions of the solution, a hierarchical Multidimensional Limiting Process (MLP) is used in the reconstruction stage. The integration in time is carried out using a third-order Runge-Kutta method. The coupling of the pressure-saturation set of equations is carried out using a classical Implicit Pressure Explicit Saturation (IMPES) procedure. To properly couple the MPFA-D method with the CPR formulation, it is necessary to obtain an adequate velocity reconstruction throughout the control volumes of the mesh. Because the cell-centered finite volume method naturally delivers fluxes across control surfaces of the primal grid, then, we use a reconstruction operator based on the lowest order Raviart-Thomas interpolation functions and the Piola transformation, to get the complete knowledge of the velocity field throughout the domain. Finally, some representative problems were solved to evaluate the accuracy, efficiency, and shock-capturing capabilities of our new numerical methodology.",3,3,0
Porous Media,Water,"Liu, Zhao; Sun, Youhong; Guo, Wei; Li, Qiang",Sealing effects of marginal gas injection on oil shale in situ pyrolysis exploitation,Oil shale; Sealing effect; Marginal gas injection; Methane migration; Water yield,POROUS-MEDIA; CONVERSION; DIFFUSION; YIELD,"Groundwater inrush and outward diffusion of pyrolysis products are two disadvantageous factors for oil shale in situ pyrolysis, leading to the loss of heat injected and groundwater pollution. Therefore, forming a closed in situ pyrolysis system is extremely important. The sealing effects of marginal gas injection were studied by numerical simulation. A two-dimensional model was established according to the engineering geology conditions of the National Pilot Project for Oil Shale in situ Exploitation of China (NPOSE), in which methane was regarded as the representative of pyrolysis products. The migration state of methane in dissolved and gas phases during in situ pyrolysis was revealed. The results showed that proper marginal gas injection pressure can effectively inhibit the outward diffusion of methane. Meanwhile, a marginal gas injection pressure of 0.60 or 0.61 MPa can effectively reduce water yield to similar to 0.5 m(3)/h. Consequently, a closed in situ pyrolysis system can be effectively formed by marginal gas injection, and the mass exchange inside and outside the pyrolysis zone is insulated, ensuring a clean and efficient pyrolysis process.",2,2,7
Porous Media,Water,"Salimi, Hamidreza; Bruining, Johannes; Joekar-Niasar, Vahid",Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities,Percolation theory; Effective-medium approximation; Relative permeability; Pore-network theory; Primary and secondary drainage; Noncircular pore throats,2-PHASE FLOW; POROUS-MEDIA; PERCOLATION THEORY; WETTING LIQUID; LAMINAR-FLOW; IMBIBITION; CORNERS,"Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation-at which there is no infinite cluster of completely filled water pores-but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 x 301 x 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).",2,2,2
Porous Media,Water,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Porous Media,Water,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Porous Media,Water,"Khoshkalam, Yegane; Khosravi, Maryam; Rostami, Behzad",Role of viscous cross-flow and emulsification in recovery of bypassed oil during foam injection in a microfluidic matrix-fracture system,Enhanced oil recovery; Viscous cross-flow; Emulsion; Foam injection; Foam generation mechanisms; Fractured reservoirs,POROUS-MEDIA; SNAP-OFF; MOBILITY CONTROL; GENERATION; DISPLACEMENT; GLASS,"Role of viscous cross-flow and emulsification on foam displacement process, has been experimentally studied in a microfluidic device (consists of homogeneous matrix pattern and a fracture in one side) by changing the injectant type (gas/foam/aqueous solution of surfactant/water) and foam quality and presence of connate water. Two distinct regions have been identified during foam displacement: 1) A dynamic region where gas and foam saturation is low and it mostly consists of aqueous phase. Emulsions of oil phase is generated at the front of dynamic region. 2) A static region where foam saturation is high and fluids' mobility is low. The discussion has been also supported by analysis of calculated oil recovery variation versus foam quality with a bell-shaped trend, matched with foam rheology reported in standard quality scan tests. Foam injection tests and gas injection ones as the case of no viscous cross-flow have been contrasted and the results confirmed the proposed role of viscous drives. Proper condition of emulsification has been discussed in foam injection tests and it has been shown that lack of such conditions in surfactant injection leads to weak emulsification. Moreover, foam generation mechanisms which have been observed during the experiments are snap-off and pinch-off.",1,1,1
Porous Media,Enhanced Oil-recovery,"Salehpour, Mohammad; Riazi, Masoud; Malayeri, M. Reza; Seyyedi, Mojtaba",CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage,"Carbon capture, and storage (CCS); Carbon capture, utilization, and storage (CCUS); Carbonated water injection; Heavy asphaltic crude oil; Water-in-oil emulsion; Enhanced oil recovery",PORE-SCALE MECHANISMS; WATER INJECTION; INTERFACIAL-TENSION; WETTABILITY ALTERATION; CO2 INJECTION; PERFORMANCE; SECONDARY; SCENARIOS; EMULSIONS; DIOXIDE,"Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsioninduced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.",3,3,4
Porous Media,Enhanced Oil-recovery,"Soulat, A.; Douarche, F.; Flauraud, E.",A modified well index to account for shear-thinning behaviour in foam EOR simulation,Multiphase flow; Porous media; Foam; Shear-thinning; Injectivity; Well index; Enhanced oil recovery; Upscaling,STEADY-STATE; INJECTIVITY; MODEL; GAS,"An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shear-thinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements. We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on coarser grids when compared to a sufficiently refined reference grid. In order to correct these errors we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address. This modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. Our proposed solution, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour. Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.",3,3,2
Porous Media,Enhanced Oil-recovery,"Almetwally, Ahmed G.; Jabbari, Hadi",Finite-difference simulation of coreflooding based on a reconstructed CT scan; modeling transient oscillating and pulse decay permeability experiment,Coreflooding; Static Model; Dynamic Simulation; Transient; Permeability; Image processing,ROCK SAMPLES; FLOW; PRESSURE; OIL,"Numerical simulation and experimental research of fluid flow in porous media enhance the practices of petroleum reservoirs' management. Experiments on acquired reservoir-rock samples are conducted for accurate characterization and realization of the insitu hydrocarbon reserves. Implementing precise numerical simulation of those experiments is crucial to acquire accurate conclusions from the obtained experimental results. Coreflooding experiments quantify reservoir rock's storage capacity, measure its transport connectivity, and evaluate recovery methods' effectiveness for that rock. In this paper, a reconstruction image-processing workflow of cores' CT scan is developed to build a finite difference numerical model for simulating coreflooding experiments. In a transient coreflooding experiment, a controlled pressure pulse with a known frequency and amplitude is transmitted to the rock sample. Rock permeability can be quantified by analytically solving the diffusivity flow equation for that experiment. Simulating the transient permeability experiment is very sensitive to the level of details of the pores' structure described in the numerical model. A transient permeability experiment with two different transient modes, sinusoidal oscillation, and pulse decay, was conducted on a standard Berea core sample. The Berea CT scan was image-processed to reconstruct the static porosity and permeability model in Petrel software using a 3D variogram geostatistical population. Injection and production sources were assigned to the finite gridblock, which correspond to flow nozzles of injection and production coreflooding setup's heads. Scheduled flow and controlled-pressure boundary-conditions were imposed on the dynamic model. Eclipse simulator was used to solve the dynamic model and calculate the pressure in each gridblock. The outlet pressure was calculated at each time step by three different realization approaches for porosity and permeability, i.e., from experiments, from statistical analysis for the CT scan, and by the proposed image processing workflow. The simulated outlet pressure from the prosed workflow matched ideally, with a Pearson correlation coefficient of 0.98 and 0.99, the recorded one in the two experiments compared to underestimated or overestimated outlet pressure from the other two traditional realization approaches, i.e., statistical or experimental.",3,3,2
Porous Media,Enhanced Oil-recovery,"Hosseini-Kaldozakh, Seyed Arman; Khamehchi, Ehsan; Dabir, Bahram; Alizadeh, Ali; Mansouri, Zohreh",Rock wettability effect on Colloidal Gas Aphron invasion near wellbore region,Colloidal Gas Aphron drilling fluid; Formation damage; Wettability; Pore blocking,ENHANCED OIL-RECOVERY; DRILLING-FLUID; FORMATION DAMAGE; LIQUID DRAINAGE; POROUS-MEDIUM; STABILITY; TEMPERATURE,"Colloidal Gas Aphron drilling fluid is colloidal dispersions of gas microbubbles, which are designed to reduce the loss of circulation in depleted reservoirs. This fluid creates a robust and elastic micro-bubble network, to block the pores of the formation and minimize filtration loss. In this study, Xanthan Gum (XG) polymer and Sodium Dodecyl Benzene Sulphonate (SDBS) surfactant were the primary materials utilized to generate a water-based Colloidal Gas Aphron drilling fluid. A dynamic and static invasion of prepared Aphron drilling fluid in carbonate rock with different wettabilities was investigated. Moreover, the formation damage induced by the invasion of Aphron fluid to porous media was also studied. Results demonstrated that wettability alteration of a water-wet porous media to oil-wet lead to an increment of differential pressure throughout porous media during Aphron drilling fluid invasion. A significant influence of wettability was also observed on return permeability of carbonate rock. A reduction of 73.53% of carbonate rock permeability was observed in oil-wet core invaded by water-based Aphron drilling fluid.",2,2,2
Porous Media,Enhanced Oil-recovery,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Porous Media,Enhanced Oil-recovery,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Porous Media,Enhanced Oil-recovery,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Porous Media,Enhanced Oil-recovery,"Khoshkalam, Yegane; Khosravi, Maryam; Rostami, Behzad",Role of viscous cross-flow and emulsification in recovery of bypassed oil during foam injection in a microfluidic matrix-fracture system,Enhanced oil recovery; Viscous cross-flow; Emulsion; Foam injection; Foam generation mechanisms; Fractured reservoirs,POROUS-MEDIA; SNAP-OFF; MOBILITY CONTROL; GENERATION; DISPLACEMENT; GLASS,"Role of viscous cross-flow and emulsification on foam displacement process, has been experimentally studied in a microfluidic device (consists of homogeneous matrix pattern and a fracture in one side) by changing the injectant type (gas/foam/aqueous solution of surfactant/water) and foam quality and presence of connate water. Two distinct regions have been identified during foam displacement: 1) A dynamic region where gas and foam saturation is low and it mostly consists of aqueous phase. Emulsions of oil phase is generated at the front of dynamic region. 2) A static region where foam saturation is high and fluids' mobility is low. The discussion has been also supported by analysis of calculated oil recovery variation versus foam quality with a bell-shaped trend, matched with foam rheology reported in standard quality scan tests. Foam injection tests and gas injection ones as the case of no viscous cross-flow have been contrasted and the results confirmed the proposed role of viscous drives. Proper condition of emulsification has been discussed in foam injection tests and it has been shown that lack of such conditions in surfactant injection leads to weak emulsification. Moreover, foam generation mechanisms which have been observed during the experiments are snap-off and pinch-off.",1,1,1
Porous Media,Relative Permeability,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Porous Media,Relative Permeability,"Purswani, Prakash; Karpyn, Zuleima T.; Enab, Khaled; Xue, Yuan; Huang, Xiaolei",Evaluation of image segmentation techniques for image-based rock property estimation,X-ray imaging; Porous media; Image segmentation; Machine learning; WEKA segmentation; MIA clustering,X-RAY MICROTOMOGRAPHY; POROUS-MEDIA; RELATIVE PERMEABILITY; INTERFACIAL AREA; CAPILLARY-PRESSURE; MULTIPHASE FLOW; 2-PHASE FLOW; AIR-WATER; HYSTERESIS; FLUID,"Accurate characterization of rock and fluid properties in porous media using X-ray imaging techniques depends on reliable identification and segmentation of the involved phases. Segmentation is critical for the estimation of porosity, fluid saturations, fluid and rock topology, and pore connectivity, among other pore-scale properties. Therefore, the purpose of this study is to compare the effectiveness of different image segmentation techniques when applied to image data analysis in porous media. Two machine learning based segmentation techniques - a supervised ML technique called Fast Random Forest, and an unsupervised method combining k-means and fuzzy c-means clustering algorithms - were compared using an experimental data set. Comparisons are also presented against traditional thresholding segmentation. In addition, we discuss the potential and limitations of applying deep learning based segmentation algorithms. The performance of the segmentation techniques were compared on estimates of porosity, saturation, and surface area, as well as pore-scale estimates such as fluid-fluid interfacial areas, and Euler characteristic. X-ray micro-computed tomography images for a sintered glass frit, saturated with two-phases (air and brine), were acquired at two different voxel resolutions. The high-resolution images (6 mu m) were used as the benchmark case, while the low-resolution images (18 mu m) were segmented by three segmentation techniques: Fast Random Forest, clustering, and thresholding. The results for porosity and phase saturation from thresholding and from the supervised ML method (i.e. Fast Random Forest) were found to be close to the benchmark case. Segmentation results from the unsupervised ML method (i.e. clustering) were largely unsatisfactory, except for total surface area measurements. The supervised ML segmentation results provided better measurements for air-brine interfacial areas by capturing three-phase interfacial regions. Also, all segmentation techniques resulted in similar measurements for air-phase Euler characteristic confirming poor connectivity of the trapped air phase, although the closest results were obtained by the supervised ML method. Finally, despite the supervised ML segmentation technique being more computationally intensive, it was found to require less user intervention and its implementation was more straightforward. In summary, this work provides insights into different segmentation techniques, their implementation, as well as advantages and limitations with regards to quantitative analysis of pore-scale properties in saturated porous media.",3,3,1
Porous Media,Relative Permeability,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Porous Media,Relative Permeability,"Santos, M. P. P. C.; Carvalho, M. S.",Pore network model for retrograde gas flow in porous media,Pore-network models; Gas-condensate; Capillary condensation; Compositional reservoir simulation,CONDENSATE; VISCOSITY,"Gas well deliverability in retrograde gas reservoirs is affected by the appearance of a liquid phase near the wellbore when the bottom-hole pressure is below the dew point. At low enough pressure gradients, the liquid phase may bridge the pore throats, blocking the gas phase flow, leading to what is known as condensate blockage. If the pressure gradient is above a critical value, the capillary forces cannot block the gas flow and the condensate bridges are displaced. Gas production can be estimated using reservoir-scale simulation of the retrograde gas flow near producing wells using relative permeability curves that take into account the different physical phenomena and their dependence on local pressure, temperature and pressure gradient (capillary number). Pore-scale simulators can be used to model retrograde gas flow through porous media and to determine the gas and liquid phases relative permeability curves as a function of different flow parameters. Here, a fully-implicit isothermal compositional pore-scale network model is presented for retrograde gas flow in porous media at high capillary number, at which capillary forces are neglected. The flow pattern in each capillary changes from a single-phase gas flow to a two-phase core-annular flow regime when the pressure and the fluid composition reach a critical condition based on the thermodynamics of the fluid mixture. Newton's method is used to solve the non-linear flow and thermodynamics equations to calculate the pressure distribution and the flow rate of each component through the network. The model was used to predict gas-liquid relative permeability at high capillary number from a depletion process in a 2D network. The results show the evolution of the condensate saturation at different conditions and how the gas permeability falls abruptly at a certain condensate saturation.",3,3,0
Porous Media,Relative Permeability,"Salimi, Hamidreza; Bruining, Johannes; Joekar-Niasar, Vahid",Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities,Percolation theory; Effective-medium approximation; Relative permeability; Pore-network theory; Primary and secondary drainage; Noncircular pore throats,2-PHASE FLOW; POROUS-MEDIA; PERCOLATION THEORY; WETTING LIQUID; LAMINAR-FLOW; IMBIBITION; CORNERS,"Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation-at which there is no infinite cluster of completely filled water pores-but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 x 301 x 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).",2,2,2
Porous Media,Relative Permeability,"Wu, Yuqi; Tahmasebi, Pejman; Lin, Chengyan; Ren, Lihua; Zhang, Yimin",Quantitative characterization of non-wetting phase in water-wet porous media based on multiphase flow experiment and numerical simulation,Multiphase fluid flow; Residual oil; Fluid physics; Pore-scale modeling; Pore occupancy,PORE-SCALE; RESIDUAL OIL; RELATIVE-PERMEABILITY; 2-PHASE FLOW; RECOVERY; SHALE; TECHNOLOGIES; MULTISCALE; SALINITY; SIZE,"It is of great significance to analyze the distribution characteristics of the non-wetting phase during the multiphase flow and identify the positions of the oil ganglia since it can guide us to design the schemes for improving oil recovery. In this paper, the two-phase (brine and oil) flow experiment and simulation are performed on a water-wet sandstone. A comprehensive analysis of the distribution of the non-wetting (oil) phase in 3D pore space and individual pores are presented. To calculate the pore occupancy of the non-wetting ganglia in every single pore from 3D CT experimental data, we proposed a technique, called the Axis-aligned Bounding Box (AABB) algorithm, to determine which oil blobs exist in a unique pore. The pore-by-pore distribution characteristics of the residual phase are then analyzed based on the experimental and numerical data. The results reveal the large oil clusters are separated into small blobs during the imbibition process, which results in increasing the number of non-wetting ganglia, dropping its connectivity, and increasing the smoothness. Moreover, the larger the volume of one pore, the larger the volume and saturation of residual oil ganglia in the pore are. Furthermore, our analysis based on the experimental and numerical results indicates that most of the non-wetting ganglia reside in the median-size pores. Hence, the finding provides us a piece of significant evidence to better target the pore-spaces for the purpose of increasing the recovery.",2,2,2
Porous Media,Relative Permeability,"Dakhelpour-Ghoveifel, Jalal; Shahverdi, Hamidreza",Prediction of gas-oil capillary pressure of carbonate rock using pore network modeling,Pore network modelling; Pore network history match; Capillary pressure prediction; Pore size distribution,POROUS-MEDIA; FINITE-ELEMENT; 2-PHASE FLOW; RELATIVE PERMEABILITY; MULTIPHASE FLOW; RECONSTRUCTION; SIMULATIONS; SANDSTONE; IMAGES,"This study suggests a frame work to predict the capillary pressure curve of the carbonate rocks using a pore network simulation. A novel pore network manipulation algorithm is introduced to match three curves and predict only one curve (air-oil). This implies that the matching process is much more complicated. In return, more valid results are obtained and the problem of non-uniqueness of statistical PNM approach is mitigated. Finally, a collection of the most significant parameters governing capillary pressure are tabulated. Two plugs with air-mercury, air-oil and water-oil drainage and water-oil imbibition capillary pressure tests are used. Water-oil drainage and imbibition and air-mercury drainage are matched with the same pore network. The pore network is constructed based on a statistical distribution of the network elements. Then, properties of air and oil are input to the pore network to estimate air-oil capillary pressure. Matching three capillary pressure curves using a network is a complicated task to do, especially when no 3D image of the plugs is available. On the other hand, it is evident by the acceptable results that the error of prediction is moderated using the suggested method. This estimation technic is a new application of pore network modeling that can be used for reservoirs with no 3D image of plugs and limited SCAL data.",1,1,1
Porous Media,Shale Gas,"Lu, Meng; Connell, Luke Daulton; Pan, Zhejun","Wetting fluid behaviour with phase transition in geological nanopores: Liquid film, capillary condensation and evaporative flow",Nanopores; Tight rocks; Thermodynamics; Phase transition; Unconventional reservoirs,HOMOGENEOUS NUCLEATION; THERMODYNAMIC ANALYSIS; POROUS-MEDIA; SHALE; STABILITY; WALL; NANOFLUIDICS; ADSORPTION; TRANSPORT; INJECTION,"Fluid behaviour in nanoscale pores may significantly deviate from that in its bulk state, because pore-wall effects may have critical influences on fluid properties such that its behaviour becomes surface-controlled. Geologically, study of fluid flow with phase transition (condensation/evaporation) in nanoscale pores is of considerable significance in practice, as understandings of the relevant mechanisms may greatly help optimise operation conditions in field applications. Typical examples include geological disposal of contaminated wastes and recovery of resources from unconventional gas and oil reservoirs. In this text, we present a study to systematically investigate how the fluid behaviour, such as the liquid film formed on a pore-wall, the condensation/evaporation of the fluid and the evaporative flow profile in the pore, depends on the molecular/electrical surface forces and the pore-wall-curvature. Towards this we first formulated a set of extended phase equilibrium relationships following a rigorous thermodynamic procedure in which the relevant pore-wall effects are included. Then, a set of new evaporative flow equations was developed, which improves the original Mahadevan model by taking into account the pore-wall effects engaged. Several laboratory tests published in literature were employed to compare the present model with the Mahadevan model. With the results obtained we discussed the pertinent pore-wall effects on the evaporation behaviour of the water, and it was shown that for the evaporative flow process concerned, these effects are significantly important and considerable deviations would be generated without consideration of them.",3,3,4
Porous Media,Shale Gas,"Al Reda, Stephane M.; Yu, Catherine; Berthe, Guillaume; Matray, Jean-Michel",Study of the permeability in the Opalinus clay series (Mont Terri - Switzerland) using the steady state method in Hassler cell,Mont Terri; Opalinus clay; BDB-1 borehole; Gas permeability; Water permeability; Steady state method; Hassler cell; Slippage effect,DIFFUSION-COEFFICIENTS; POROUS-MEDIA; GAS-FLOW; WATER; PARAMETERS; PRESSURE; ROCKS; FAULT,"Mont Terri rock laboratory located in the Northwestern Switzerland is an international platform for applied research in the field of radioactive waste disposal in clayrock formations. A borehole named BDB1 has been drilled in the Opalinus claystone in 2013 to assess its containment properties. Characterization of petrophysical and hydrogeological parameters in the Jurassic shale known as Opalinus Clay were performed by in situ experiments conducted in the rock laboratory of Jura Mountains and on borehole samples. This paper presents the results of laboratory measurements of permeability in a permeameter called Hassler cell by using the steady state method. The study is applied to core samples drilled perpendicular and parallel to the bedding, and involves gas and water permeability measurements. The Hassler cell is an experimental device that allows to put samples under a confining pressure reproducing the in situ one. In all, results were obtained for nine samples over sixteen for gas permeability measurements with values ranging between 6.9 x 10(-21) and 2.3 x 10(-19) m(2) and one sample for water permeability measurements with a value of 1.38 x 10(-20) m(2). Most of the results are in good agreement with previous studies obtained by in situ experiments and using the Poiseuille type law method. The usage of several methods to determine the permeability of the Opalinus clay unit helps to conclude about the accuracy, trueness and precision of the measurements.",3,3,0
Porous Media,Shale Gas,"Liu, Zhao; Sun, Youhong; Guo, Wei; Li, Qiang",Sealing effects of marginal gas injection on oil shale in situ pyrolysis exploitation,Oil shale; Sealing effect; Marginal gas injection; Methane migration; Water yield,POROUS-MEDIA; CONVERSION; DIFFUSION; YIELD,"Groundwater inrush and outward diffusion of pyrolysis products are two disadvantageous factors for oil shale in situ pyrolysis, leading to the loss of heat injected and groundwater pollution. Therefore, forming a closed in situ pyrolysis system is extremely important. The sealing effects of marginal gas injection were studied by numerical simulation. A two-dimensional model was established according to the engineering geology conditions of the National Pilot Project for Oil Shale in situ Exploitation of China (NPOSE), in which methane was regarded as the representative of pyrolysis products. The migration state of methane in dissolved and gas phases during in situ pyrolysis was revealed. The results showed that proper marginal gas injection pressure can effectively inhibit the outward diffusion of methane. Meanwhile, a marginal gas injection pressure of 0.60 or 0.61 MPa can effectively reduce water yield to similar to 0.5 m(3)/h. Consequently, a closed in situ pyrolysis system can be effectively formed by marginal gas injection, and the mass exchange inside and outside the pyrolysis zone is insulated, ensuring a clean and efficient pyrolysis process.",2,2,7
Porous Media,Shale Gas,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Porous Media,Shale Gas,"Fang, Bo; Hu, Jinghong; Xu, Jinze; Zhang, Yuan",A semi-analytical model for horizontal-well productivity in shale gas reservoirs: Coupling of multi-scale seepage and matrix shrinkage,Shale gas; Multi-scale seepage; Apparent permeability; Semi-analytical model; Factor analysis,POROUS-MEDIA; APPARENT PERMEABILITY; SURFACE-DIFFUSION; FLOW; ADSORPTION; PERFORMANCE; TRANSPORT,"Matrix permeability is an important parameter in shale gas productivity prediction. However, the permeability affected by multi-scale seepage is difficult to calculate accurately. The object of this study is to develop an integrated apparent permeability model for multi-scale seepage mechanisms. The apparent permeability model considered shale gas flow from shrinkable matrix to fracture system with slip flow, Knudsen diffusion, and surface diffusion. The transport capacity change with different seepage mechanisms under different conditions was specifically analyzed. The importance of each parameter in the apparent permeability model was qualified using Grey correlation method. In addition, a semi-analytical model for horizontal-well productivity was developed to describe shale gas transport inreservoir. The semi-analytical model was solved using Laplace integral transformation and point source method. According to the results based on Grey correlation method, the effects of pore radius and Langmuir volume on dimensionless-type curves were discussed. Compared with the pore radius, the Langmuir volume had more influences on the shape of typical curve. The slip flow played the most important role in gas transport in mesopores and macropores when the pressure was more than 2 MPa and the surface diffusion was the primary transporting mechanism at any pressure in micropores but it can be negligible in macropores. The research result presented that the multi-scale seepage mechanisms would be considered in well tests and shale gas production.",1,1,3
Porous Media,Analytical Solutions,"Liu, Wenchao",Exact analytical solutions of non-Darcy seepage flow problems of one-dimensional Bingham fluid flow in finite long porous media with threshold pressure gradient,Threshold pressure gradient; Exact analytical solution; Finite long porous media; Moving boundary; Bingham fluid; Low-permeable oil reservoirs,LOW-PERMEABILITY RESERVOIR; MOVING BOUNDARY-PROBLEM; TIGHT GAS-RESERVOIRS; YIELD-STRESS FLUIDS; HORIZONTAL WELL; TRANSIENT PRESSURE; FRACTAL MODEL; SHALE; CONSOLIDATION,"In the paper, the study on the exact analytical solution of the moving boundary problem of one-dimensional Bingham fluid seepage flow is extended from the infinite long porous media (Liu a al., 2012) to the finite long porous media. Two exact analytical solutions are presented by appropriately relying on some methods of mathematical physics and mathematical techniques. One is for the model with finite closed outer boundary condition; the other is for the model with finite constant pressure outer boundary condition. The existence and the uniqueness of the exact analytical solutions are also strictly proved theoretically. In addition, the numerical solutions of the two models by the finite difference method are also provided. Through the comparison, it is found that these exact analytical solutions have very excellent agreement with the numerical solutions although few terms of the infinite function series existent in the exact analytical solutions have to be retained for the calculation. Furthermore, for the two models, the effect of the threshold pressure gradient on the transient pressure and the transient pressure derivative at the inner boundary for the whole flow process is analyzed through the analytical solutions. Finally, through the comparison of the relevant model solutions, it is concluded that it is very necessary to incorporate the process of moving boundary for the modeling of non-Darcy Bingham fluid flow in finite long porous media with threshold pressure gradient; otherwise, large errors can be introduced in predicting the transient pressure and the transient pressure derivative in the porous media. The presented work can support solid theoretical foundations for the experiment design of measuring the threshold pressure gradient and the pressure transient analysis in the field of inverse problems in the petroleum engineering, which have been widely involved in the development of low-permeable oil reservoirs and heavy oil reservoirs.",2,2,6
Porous Media,Analytical Solutions,"Gharibi, Farshad; Ashrafizaadeh, Mahmud",Darcy and inertial fluid flow simulations in porous media using the non-orthogonal central moments lattice Boltzmann method,Lattice Boltzmann method; Central moments; Porous media; Permeability prediction; Apparent permeability,PERMEABILITY PREDICTION; PERIODIC ARRAYS; SHALE MATRIX; GAS-FLOW; GEOMETRIES; SCHEMES,"In this study, two-dimensional (2D) and three-dimensional (3D) lattice Boltzmann method (LBM) has been investigated using the non-orthogonal central moments collision method in order to study the Darcy and inertial (non-Darcy) fluid flow in porous media. A GPU parallel CUDA code has been developed and is employed to study the proposed method. A comparative study has been performed between the non-orthogonal central moments method and the Bhatnagar-Groos-Krook (BGK) method to measure the permeability. The effect of selecting sets of relaxation times and no-slip boundary conditions has been investigated using the 2D hexagonal and 3D body-centered cubic (BCC) structure, and an appropriate model has been presented for flow simulation in porous media. The comparison of the permeability obtained by the proposed numerical method with the analytical solutions shows that the proposed model is highly accurate and eliminates the dependence of permeability on the viscosity, which is one of the problems in the LBM. This model's capability has been evaluated to simulate Darcy and inertial flows using 2D hexagonal geometry, 2D granular porous media with a random structure, 3D BCC geometry, 3D porous media with a random structure, and real porous media created by using computed tomography (CT) images. In addition, the apparent permeability, the non-Darcy beta factor, and the onset of non-Darcy flow have been predicted to demonstrate the capability of the proposed method. The results show the high capability of the proposed model for fluid flow simulation in porous media with complex geometries; so, this model can be used as a powerful and stable tool with the capability of fluid flow simulation in porous media from the Darcy regime to large Reynolds numbers and the inertial regime.",2,2,2
Porous Media,Analytical Solutions,"Ishbulatov, Salavat Y.; Kazak, Andrey V.",Multivariate optimization of tight core retrieval schedule based on numerical simulation. A novel approach,Safe core retrieval; Core tripping schedule; Microfracturing; Simulation; Tight rocks; Poroelastic approach,PERMEABILITY; GAS; OIL,"The quality and safety of core recovery determine the success of the petrophysical and geomechanical analyses. It becomes crucial for low-permeable (tight) formations, including shales, where rock stress-strain and strength properties drive well completion and treatment design. There are few technologies providing sample condition monitoring while lifting and protecting the core from deformation/damaging and fluid release. A feasible option is to simulate core tripping and optimize core retrieval parameters such as lifting rate, number, and duration of stops to meet operational requirements (time, cost, rate). The article presents a new approach to solve the safe core tripping problem. Firstly, we discuss the implementation issues of state-of-the-art poroelastic Laplace-inversion-based analytical solutions and numerical approximation models. Then we introduce an approach based on the poroelastic model assuming vertically transversely isotropic permeability. The method features an updated equation for decompression and failure criteria, determined by the properties of the porous media of the rock. We used the obtained solution to simulate typical core tripping scenarios and optimize the core tripping schedule for total retrieval time. Finally, we discuss the account for micro fracturing, core damage mechanics, and improvements of decompression models. In summary, the article makes several practically essential conclusions. The strength properties - not only tensile strength but also fracture toughness of the rock are crucial for finding the optimal safe core tripping regime. The poroelastic simulation shows that tensile stresses cause fracturing of the core inner region; damage initiates from existing (natural or drilling-induced) defects (microfractures, cracks). The presented core tripping algorithm, unlike the existing ones, optimizes the tripping rate-depth profile intelligently depth-by-depth and does not require calculating the whole core lifting case. The application of the approach increases the prediction accuracy, avoids overestimation of the time required for a safe core tripping, and, in principle, allows estimating the degree of core damage.",2,2,2
Porous Media,Analytical Solutions,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Porous Media,Apparent Permeability,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Porous Media,Apparent Permeability,"Gharibi, Farshad; Ashrafizaadeh, Mahmud",Darcy and inertial fluid flow simulations in porous media using the non-orthogonal central moments lattice Boltzmann method,Lattice Boltzmann method; Central moments; Porous media; Permeability prediction; Apparent permeability,PERMEABILITY PREDICTION; PERIODIC ARRAYS; SHALE MATRIX; GAS-FLOW; GEOMETRIES; SCHEMES,"In this study, two-dimensional (2D) and three-dimensional (3D) lattice Boltzmann method (LBM) has been investigated using the non-orthogonal central moments collision method in order to study the Darcy and inertial (non-Darcy) fluid flow in porous media. A GPU parallel CUDA code has been developed and is employed to study the proposed method. A comparative study has been performed between the non-orthogonal central moments method and the Bhatnagar-Groos-Krook (BGK) method to measure the permeability. The effect of selecting sets of relaxation times and no-slip boundary conditions has been investigated using the 2D hexagonal and 3D body-centered cubic (BCC) structure, and an appropriate model has been presented for flow simulation in porous media. The comparison of the permeability obtained by the proposed numerical method with the analytical solutions shows that the proposed model is highly accurate and eliminates the dependence of permeability on the viscosity, which is one of the problems in the LBM. This model's capability has been evaluated to simulate Darcy and inertial flows using 2D hexagonal geometry, 2D granular porous media with a random structure, 3D BCC geometry, 3D porous media with a random structure, and real porous media created by using computed tomography (CT) images. In addition, the apparent permeability, the non-Darcy beta factor, and the onset of non-Darcy flow have been predicted to demonstrate the capability of the proposed method. The results show the high capability of the proposed model for fluid flow simulation in porous media with complex geometries; so, this model can be used as a powerful and stable tool with the capability of fluid flow simulation in porous media from the Darcy regime to large Reynolds numbers and the inertial regime.",2,2,2
Porous Media,Apparent Permeability,"Fang, Bo; Hu, Jinghong; Xu, Jinze; Zhang, Yuan",A semi-analytical model for horizontal-well productivity in shale gas reservoirs: Coupling of multi-scale seepage and matrix shrinkage,Shale gas; Multi-scale seepage; Apparent permeability; Semi-analytical model; Factor analysis,POROUS-MEDIA; APPARENT PERMEABILITY; SURFACE-DIFFUSION; FLOW; ADSORPTION; PERFORMANCE; TRANSPORT,"Matrix permeability is an important parameter in shale gas productivity prediction. However, the permeability affected by multi-scale seepage is difficult to calculate accurately. The object of this study is to develop an integrated apparent permeability model for multi-scale seepage mechanisms. The apparent permeability model considered shale gas flow from shrinkable matrix to fracture system with slip flow, Knudsen diffusion, and surface diffusion. The transport capacity change with different seepage mechanisms under different conditions was specifically analyzed. The importance of each parameter in the apparent permeability model was qualified using Grey correlation method. In addition, a semi-analytical model for horizontal-well productivity was developed to describe shale gas transport inreservoir. The semi-analytical model was solved using Laplace integral transformation and point source method. According to the results based on Grey correlation method, the effects of pore radius and Langmuir volume on dimensionless-type curves were discussed. Compared with the pore radius, the Langmuir volume had more influences on the shape of typical curve. The slip flow played the most important role in gas transport in mesopores and macropores when the pressure was more than 2 MPa and the surface diffusion was the primary transporting mechanism at any pressure in micropores but it can be negligible in macropores. The research result presented that the multi-scale seepage mechanisms would be considered in well tests and shale gas production.",1,1,3
Porous Media,NMR,"Li, Haitao; Hu, Xufei; Deng, Shaogui; Xu, Miaomiao",Fast multidimensional NMR inversion based on randomized singular value decomposition,Multidimensional NMR inversion; NMR data compression; Singular value decomposition; Randomized singular value decomposition; Computational efficiency,RESERVOIR,"Multidimensional NMR inversion has been proposed to improve the capacity of qualitative and quantitative fluids evaluation contained in porous media. However, one reason that restrict the development and application of downhole multidimensional NMR techniques is about the inversion efficiency. Fast and robust inversion algorithm can greatly reduce the downhole NMR logging cost. Taking into consideration the computational efficiency, it is critical to compress the NMR data. Singular value decomposition (SVD) has been recognized as an efficient algorithm for one dimensional (1D) NMR data compression. It is also applicable under certain circumstance for multidimensional NMR inversion, for example, when the NMR kernel matrices are separable. However, in the highly resolution inversion of two dimensional (2D) NMR and three dimensional (3D) NMR, large - scale of kernel matrices would be generated which greatly restrict the application of SVD. In such cases, SVD consumes considerable computational time and memory. We introduce an algorithm, named randomized singular value decomposition (RSVD), as an alternate of SVD. RSVD could produce results that are comparable to the ones produced by SVD. Furthermore, compared with SVD, it requires far less computation time and memory in the large-scale matrix factorization. Sometimes, it is possible to reduce more than 100 times of computation time and memory. Numerous of numerical simulations have been done to demonstrate the robustness and efficiency of multidimensional NMR inversion based on RSVD. We also analyze its anti-noise ability. Because of the highly computational efficiency of RSVD, it deserves widely application promotion in the multidimensional NMR inversion.",3,3,3
Porous Media,NMR,"Gao, Yang; Xiao, Lizhi; Wu, Baosong",TSVD and Tikhonov methods and influence factor analysis for NMR data in shale rock,Shale rock; NMR; Inversion method; Regularization algorithm; Influence factor,SINGULAR-VALUE DECOMPOSITION; INTEGRAL-EQUATIONS; NUMERICAL SOLUTION; POROUS-MEDIA; INVERSION; RELAXATION; DISTRIBUTIONS; REGULARIZATION; KIND,"Nuclear magnetic resonance (NMR) technique is a powerful tool in both conventional and unconventional reservoirs. While signal decays fast in shale reservoirs/rocks and signal-to-noise ratio (SNR) is low. It is necessary to study inversion methods and regularization algorithms which are suited to shale rocks. This work studied two inversion methods (TSVD and Tikhonov) and their related regularization algorithms (BGL, Morozov, GCV and L-curve). Numerical simulations and rock analysis indicated both methods are suited to shale rocks. Especially, Tikhonov is better than TSVD in case SNR is low. We also studied the influences of NMR measurement parameters on the inversion, including SNR, number of T-2 bins, number of echoes and echo space T-E. The numerical simulation and rock analysis are consistent with the theoretical results. Furtherly, we advise the extension into NMR logging in shale reservoirs, it should meet the conditions: SNR >= 5, number of T-2 bins >= 16, number of echoes >= 50, and T-E <= 0. 2 ms. It is possible to acquire fewer echoes in shale reservoirs, which can make logging speed up.",1,2,9
Porous Media,NMR,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Porous Media,"Degrees C,Degrees C.","Wang, Yefei; Zhao, Min; Dong, Xing; Li, Qiang; Yang, Zhen; Ding, Mingchen",Potential of the base-activated persulfate for polymer-plugging removal in low temperature reservoirs,Polymer flooding of reservoirs; Low temperature; Plugging removers; Hydrolyzed polyacrylamide gel; Base-activated persulfate; Corrosion,CHEMICAL DEGRADATION; CONTAMINATED SOIL; HYDROXYL RADICALS; MOLECULAR-WEIGHT; WASTE-WATER; OXIDATION; PEROXYMONOSULFATE; SULFATE; POLYACRYLAMIDE; CHEMISTRY,"Conventional polymer-plugging removers perform badly in low temperature reservoirs and this has prompted researchers to look for more effective removers. In this work, base-activated sodium persulfate (PDS) was used to degrade polymer-plugging. The performance of the novel remover was first compared with that of conventional removers at 35 degrees C. Then, the degradation mechanism involved and factors of influence were investigated by carrying out radical scavenger and single-factor experiments, respectively. Finally, corrosion tests were performed and the ability of the new remover to remove plugging in porous media was investigated by carrying out flooding tests. The results show that the PDS/NaOH system is a much more potent remover at temperatures as low as 35 degrees C (giving a degradation efficiency of 100% compared to 10-70% using conventional removers). Furthermore, the radical scavenger experiments show that Ha is the predominant radical responsible for polymer gel degradation. The degradation efficiency is affected by the concentrations of the PDS and NaOH solutions, the temperature, and also by the salinity of the polymer gel. We also demonstrate that the polymer gel can be completely degraded when its salinity is 30,000 mg/L by optimizing the temperature and concentration of PDS and NaOH. The corrosion rate using PDS/NaOH was found to be 1.085 g m(-2) h(-1) which satisfies the requirements for entry well fluid. In addition, the static plugging degradation and dynamic plugging removal tests show that PDS/NaOH can degrade the plugging effectively and recover the permeability of the sandpack to over 65%. Our results suggest that the PDS/NaOH system is a highly promising plugging remover for use in low-temperature polymer flooding reservoirs and is a good replacement for the ones conventionally used.",3,4,3
Porous Media,"Degrees C,Degrees C.","Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater,Carbonated water; Mutual solvents; Wettability alteration; Imbibition; Methanol; Acetone,SMART WATER INJECTION; INTERFACIAL-TENSION IFT; OIL-RECOVERY; PHASE-BEHAVIOR; CONTACT-ANGLE; POROUS-MEDIA; BRINE; SOLUBILITY; DIOXIDE; IONS,"The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 degrees C in absence of dissolved CO2 at 60.95 degrees and 58.43 degrees, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 degrees C at 36.31 degrees and 32.92 degrees. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.",1,1,3
Porous Media,"Degrees C,Degrees C.","Facanha, J. M. F.; Maqueira, L.; Souza, A. V. O.; Moura, P. G.; Perez-Gramatges, A.",Conservative tracer tests in sandstones and carbonates using a cost-effective fluorescence method,Conservative tracer tests; Swept pore volume; Lithium detection; Fluorescence; Breakthrough curve,SPECTROPHOTOMETRIC DETERMINATION; ION-EXCHANGE; OIL-RECOVERY; LITHIUM; QUINIZARIN; EXTRACTION; TEMPERATURE; SALINITY; FLUIDS,"The use of inorganic ions as conservative tracers in porous media is limited by the need of complex and expensive analytical techniques, such as inductively coupled plasma (ICP), for tracer quantification. In this work, a cost-effective and straightforward in-house method was developed using fluorescence spectroscopy to quantify lithium in a high salinity brine, based on the formation of a complex with quinizarin (Li-Q). The method was adjusted to minimize interferences from Ca2+ and Mg2+ ions in the effluent, and to avoid extensive dilution steps in the quantification procedure. This approach yielded a sub-millimolar detection limit (8.2 x 10(-5) mol L-1) in the conservative tracer tests performed using four different rock samples, namely two sandstone and two carbonate cores, at 13.8 MPa and 20 degrees C. The breakthrough/elution curves obtained for Berea sandstones showed distinct characteristics of homogeneous rocks, such as the sharp increase in lithium concentration, in contrast with the sluggish profile observed for more heterogeneous Indiana limestones. Moreover, the sensitivity of the method allowed to calculate the swept volumes for both cores, which resembled the rock pore volumes measured with nitrogen gas. These results compared well with those obtained using ICP-OES as a reference method (>95% agreement), which demonstrated that the proposed Li-Q fluorescence method can be used as an efficient alternative method to quantify lithium in conservative tracer tests for coreflood studies, significantly reducing time and cost of analysis, with potential to be used for field applications.",1,1,1
Porous Media,Pressure Gradient,"Santos, M. P. P. C.; Carvalho, M. S.",Pore network model for retrograde gas flow in porous media,Pore-network models; Gas-condensate; Capillary condensation; Compositional reservoir simulation,CONDENSATE; VISCOSITY,"Gas well deliverability in retrograde gas reservoirs is affected by the appearance of a liquid phase near the wellbore when the bottom-hole pressure is below the dew point. At low enough pressure gradients, the liquid phase may bridge the pore throats, blocking the gas phase flow, leading to what is known as condensate blockage. If the pressure gradient is above a critical value, the capillary forces cannot block the gas flow and the condensate bridges are displaced. Gas production can be estimated using reservoir-scale simulation of the retrograde gas flow near producing wells using relative permeability curves that take into account the different physical phenomena and their dependence on local pressure, temperature and pressure gradient (capillary number). Pore-scale simulators can be used to model retrograde gas flow through porous media and to determine the gas and liquid phases relative permeability curves as a function of different flow parameters. Here, a fully-implicit isothermal compositional pore-scale network model is presented for retrograde gas flow in porous media at high capillary number, at which capillary forces are neglected. The flow pattern in each capillary changes from a single-phase gas flow to a two-phase core-annular flow regime when the pressure and the fluid composition reach a critical condition based on the thermodynamics of the fluid mixture. Newton's method is used to solve the non-linear flow and thermodynamics equations to calculate the pressure distribution and the flow rate of each component through the network. The model was used to predict gas-liquid relative permeability at high capillary number from a depletion process in a 2D network. The results show the evolution of the condensate saturation at different conditions and how the gas permeability falls abruptly at a certain condensate saturation.",3,3,0
Porous Media,Pressure Gradient,"Liu, Wenchao",Exact analytical solutions of non-Darcy seepage flow problems of one-dimensional Bingham fluid flow in finite long porous media with threshold pressure gradient,Threshold pressure gradient; Exact analytical solution; Finite long porous media; Moving boundary; Bingham fluid; Low-permeable oil reservoirs,LOW-PERMEABILITY RESERVOIR; MOVING BOUNDARY-PROBLEM; TIGHT GAS-RESERVOIRS; YIELD-STRESS FLUIDS; HORIZONTAL WELL; TRANSIENT PRESSURE; FRACTAL MODEL; SHALE; CONSOLIDATION,"In the paper, the study on the exact analytical solution of the moving boundary problem of one-dimensional Bingham fluid seepage flow is extended from the infinite long porous media (Liu a al., 2012) to the finite long porous media. Two exact analytical solutions are presented by appropriately relying on some methods of mathematical physics and mathematical techniques. One is for the model with finite closed outer boundary condition; the other is for the model with finite constant pressure outer boundary condition. The existence and the uniqueness of the exact analytical solutions are also strictly proved theoretically. In addition, the numerical solutions of the two models by the finite difference method are also provided. Through the comparison, it is found that these exact analytical solutions have very excellent agreement with the numerical solutions although few terms of the infinite function series existent in the exact analytical solutions have to be retained for the calculation. Furthermore, for the two models, the effect of the threshold pressure gradient on the transient pressure and the transient pressure derivative at the inner boundary for the whole flow process is analyzed through the analytical solutions. Finally, through the comparison of the relevant model solutions, it is concluded that it is very necessary to incorporate the process of moving boundary for the modeling of non-Darcy Bingham fluid flow in finite long porous media with threshold pressure gradient; otherwise, large errors can be introduced in predicting the transient pressure and the transient pressure derivative in the porous media. The presented work can support solid theoretical foundations for the experiment design of measuring the threshold pressure gradient and the pressure transient analysis in the field of inverse problems in the petroleum engineering, which have been widely involved in the development of low-permeable oil reservoirs and heavy oil reservoirs.",2,2,6
Porous Media,Drilling Fluid,"Wan, Yizhao; Liu, Yuewu; Wu, Nengyou",Numerical pressure transient analysis for unfilled-caved carbonate reservoirs based on Stokes-Darcy coupled theory,Carbonate reservoir; Pressure transient behavior; Stokes-Darcy coupled; Flow in porous media; Numerical simulation,TARIM BASIN; BOUNDARY-CONDITION; MODEL; FLOW; VUGGY; WELL; CAVITY,"Caved carbonate reservoirs are very special because of the strong heterogeneity. The pressure transient behavior of the caved carbonate reservoirs is quite different from the conventional homogeneous or dual medium reservoirs because of the presence of large-scale cavities. There are two types of cavities: filled and unfilled, which dominated the production of the reservoirs. Fluid flow in the unfilled cavity should be described by Stokes' equation rather than Darcy's law. It is needed to better understand the role of the unfilled cavities plays in the pressure transient analysis. The objective of this work is to analyze the pressure transient behavior of the unfilled cavities. A coupled Stokes-Darcy pressure transient model is developed and the finite element method is applied in the solutions of the mathematical models. Then, the numerical pressure transient model is used in the analysis of two typical cases: a well drilled into the unfilled cavity (WIC) and a well not drilled into the unfilled cavity (WOC). The type curves of the WIC model indicate that flow in the unfilled cavity is an oscillated pressure-drop rather than a radial flow. The unfilled cavity that the well drilled into would be considered as an enlarged wellbore which is equivalent to a negative skin factor, as a consequence the wellbore storage coefficient will increase. Main characteristics of type curves for WOC model are the valley on the pressure derivative. A cavity with a larger size and smaller distance from the wellbore would give rise to a deeper valley. Comparative results indicate that unfilled cavities described by the Stokes' equation are not the limit of the filled cavities with extremely large mobility, which was predicted by previous work.",3,3,3
Porous Media,Drilling Fluid,"Hosseini-Kaldozakh, Seyed Arman; Khamehchi, Ehsan; Dabir, Bahram; Alizadeh, Ali; Mansouri, Zohreh",Rock wettability effect on Colloidal Gas Aphron invasion near wellbore region,Colloidal Gas Aphron drilling fluid; Formation damage; Wettability; Pore blocking,ENHANCED OIL-RECOVERY; DRILLING-FLUID; FORMATION DAMAGE; LIQUID DRAINAGE; POROUS-MEDIUM; STABILITY; TEMPERATURE,"Colloidal Gas Aphron drilling fluid is colloidal dispersions of gas microbubbles, which are designed to reduce the loss of circulation in depleted reservoirs. This fluid creates a robust and elastic micro-bubble network, to block the pores of the formation and minimize filtration loss. In this study, Xanthan Gum (XG) polymer and Sodium Dodecyl Benzene Sulphonate (SDBS) surfactant were the primary materials utilized to generate a water-based Colloidal Gas Aphron drilling fluid. A dynamic and static invasion of prepared Aphron drilling fluid in carbonate rock with different wettabilities was investigated. Moreover, the formation damage induced by the invasion of Aphron fluid to porous media was also studied. Results demonstrated that wettability alteration of a water-wet porous media to oil-wet lead to an increment of differential pressure throughout porous media during Aphron drilling fluid invasion. A significant influence of wettability was also observed on return permeability of carbonate rock. A reduction of 73.53% of carbonate rock permeability was observed in oil-wet core invaded by water-based Aphron drilling fluid.",2,2,2
Porous Media,Diffusivity Equation,"Almetwally, Ahmed G.; Jabbari, Hadi",Finite-difference simulation of coreflooding based on a reconstructed CT scan; modeling transient oscillating and pulse decay permeability experiment,Coreflooding; Static Model; Dynamic Simulation; Transient; Permeability; Image processing,ROCK SAMPLES; FLOW; PRESSURE; OIL,"Numerical simulation and experimental research of fluid flow in porous media enhance the practices of petroleum reservoirs' management. Experiments on acquired reservoir-rock samples are conducted for accurate characterization and realization of the insitu hydrocarbon reserves. Implementing precise numerical simulation of those experiments is crucial to acquire accurate conclusions from the obtained experimental results. Coreflooding experiments quantify reservoir rock's storage capacity, measure its transport connectivity, and evaluate recovery methods' effectiveness for that rock. In this paper, a reconstruction image-processing workflow of cores' CT scan is developed to build a finite difference numerical model for simulating coreflooding experiments. In a transient coreflooding experiment, a controlled pressure pulse with a known frequency and amplitude is transmitted to the rock sample. Rock permeability can be quantified by analytically solving the diffusivity flow equation for that experiment. Simulating the transient permeability experiment is very sensitive to the level of details of the pores' structure described in the numerical model. A transient permeability experiment with two different transient modes, sinusoidal oscillation, and pulse decay, was conducted on a standard Berea core sample. The Berea CT scan was image-processed to reconstruct the static porosity and permeability model in Petrel software using a 3D variogram geostatistical population. Injection and production sources were assigned to the finite gridblock, which correspond to flow nozzles of injection and production coreflooding setup's heads. Scheduled flow and controlled-pressure boundary-conditions were imposed on the dynamic model. Eclipse simulator was used to solve the dynamic model and calculate the pressure in each gridblock. The outlet pressure was calculated at each time step by three different realization approaches for porosity and permeability, i.e., from experiments, from statistical analysis for the CT scan, and by the proposed image processing workflow. The simulated outlet pressure from the prosed workflow matched ideally, with a Pearson correlation coefficient of 0.98 and 0.99, the recorded one in the two experiments compared to underestimated or overestimated outlet pressure from the other two traditional realization approaches, i.e., statistical or experimental.",3,3,2
Porous Media,Diffusivity Equation,"Obembe, Abiola D.",A fractional diffusion model for single-well simulation in geological media,Single-well simulation; Fractional calculus; Radial diffusivity equation; Finite difference method; Fractional-order derivative; Grunwald-Letnikov,POROUS-MEDIA; ANOMALOUS DIFFUSION; HEAT-TRANSFER; FLUID-FLOW; PRESSURE; RESERVOIR; EQUATION; DERIVATIVES; GEOMETRY,"In this scholarly work, a novel mathematical model for single-phase, single-well simulation in hydrocarbon reservoirs was established using the fractional calculus theory. Specifically, the existing fractional generalization of Darcy's law is reconstructed by introducing an auxiliary parameter to ensure that the definition of the conventional rock permeability with dimension L-2 was preserved. Subsequently, the newly constructed fractional flux relationship was substituted as a momentum equation in the mass conservation expression in the radial-cylindrical coordinate system. The resulting nonlocal time-radial diffusivity equation was solved numerically using the block-centered finite-difference approximation and adopting the Grunwald-Letnikov formula for the definition of the fractional-order derivative. The developed numerical scheme was verified by comparing the approximate pressure solution against the semi-analytical solution of the simplified nonlocal time-radial diffusivity equation and the classic radial flow diffusivity equation. Furthermore, incremental material balance checks were performed and exhibited to ensure the conservation of mass at each time step. Finally, a detailed sensitivity analysis was performed to evaluate the impact of the order of fractional differentiation on pressure distribution in the reservoir and wellbore. The proposed nonlocal time-radial diffusivity equation proffers a useful model for single-well simulation in geological media that exhibit distorted flow paths and near power-law behaviors.",2,2,1
Porous Media,Clay,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Porous Media,Clay,"Al Reda, Stephane M.; Yu, Catherine; Berthe, Guillaume; Matray, Jean-Michel",Study of the permeability in the Opalinus clay series (Mont Terri - Switzerland) using the steady state method in Hassler cell,Mont Terri; Opalinus clay; BDB-1 borehole; Gas permeability; Water permeability; Steady state method; Hassler cell; Slippage effect,DIFFUSION-COEFFICIENTS; POROUS-MEDIA; GAS-FLOW; WATER; PARAMETERS; PRESSURE; ROCKS; FAULT,"Mont Terri rock laboratory located in the Northwestern Switzerland is an international platform for applied research in the field of radioactive waste disposal in clayrock formations. A borehole named BDB1 has been drilled in the Opalinus claystone in 2013 to assess its containment properties. Characterization of petrophysical and hydrogeological parameters in the Jurassic shale known as Opalinus Clay were performed by in situ experiments conducted in the rock laboratory of Jura Mountains and on borehole samples. This paper presents the results of laboratory measurements of permeability in a permeameter called Hassler cell by using the steady state method. The study is applied to core samples drilled perpendicular and parallel to the bedding, and involves gas and water permeability measurements. The Hassler cell is an experimental device that allows to put samples under a confining pressure reproducing the in situ one. In all, results were obtained for nine samples over sixteen for gas permeability measurements with values ranging between 6.9 x 10(-21) and 2.3 x 10(-19) m(2) and one sample for water permeability measurements with a value of 1.38 x 10(-20) m(2). Most of the results are in good agreement with previous studies obtained by in situ experiments and using the Poiseuille type law method. The usage of several methods to determine the permeability of the Opalinus clay unit helps to conclude about the accuracy, trueness and precision of the measurements.",3,3,0
Porous Media,Steady State,"Soulat, A.; Douarche, F.; Flauraud, E.",A modified well index to account for shear-thinning behaviour in foam EOR simulation,Multiphase flow; Porous media; Foam; Shear-thinning; Injectivity; Well index; Enhanced oil recovery; Upscaling,STEADY-STATE; INJECTIVITY; MODEL; GAS,"An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shear-thinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements. We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on coarser grids when compared to a sufficiently refined reference grid. In order to correct these errors we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address. This modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. Our proposed solution, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour. Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.",3,3,2
Porous Media,Steady State,"Al Reda, Stephane M.; Yu, Catherine; Berthe, Guillaume; Matray, Jean-Michel",Study of the permeability in the Opalinus clay series (Mont Terri - Switzerland) using the steady state method in Hassler cell,Mont Terri; Opalinus clay; BDB-1 borehole; Gas permeability; Water permeability; Steady state method; Hassler cell; Slippage effect,DIFFUSION-COEFFICIENTS; POROUS-MEDIA; GAS-FLOW; WATER; PARAMETERS; PRESSURE; ROCKS; FAULT,"Mont Terri rock laboratory located in the Northwestern Switzerland is an international platform for applied research in the field of radioactive waste disposal in clayrock formations. A borehole named BDB1 has been drilled in the Opalinus claystone in 2013 to assess its containment properties. Characterization of petrophysical and hydrogeological parameters in the Jurassic shale known as Opalinus Clay were performed by in situ experiments conducted in the rock laboratory of Jura Mountains and on borehole samples. This paper presents the results of laboratory measurements of permeability in a permeameter called Hassler cell by using the steady state method. The study is applied to core samples drilled perpendicular and parallel to the bedding, and involves gas and water permeability measurements. The Hassler cell is an experimental device that allows to put samples under a confining pressure reproducing the in situ one. In all, results were obtained for nine samples over sixteen for gas permeability measurements with values ranging between 6.9 x 10(-21) and 2.3 x 10(-19) m(2) and one sample for water permeability measurements with a value of 1.38 x 10(-20) m(2). Most of the results are in good agreement with previous studies obtained by in situ experiments and using the Poiseuille type law method. The usage of several methods to determine the permeability of the Opalinus clay unit helps to conclude about the accuracy, trueness and precision of the measurements.",3,3,0
Pressure Drop,Permeability,"Huang, Shijun; Zhu, Yuanrui; Ding, Junwu; Li, Xingmin; Xue, Yongchao",A semi-analytical model for predicting inflow profile of long horizontal wells in super-heavy foamy oil reservoir,Super-heavy foamy oil; Horizontal well; Semi-analytical model; Formation heterogeneity; Inflow profile; Productivity prediction,RECOVERY STRATEGIES; BEHAVIOR; FLOW,"In most super-heavy oil reservoirs, depletion recovery is one of the important cold recovery methods accompanied by foamy oil production. However, the inflow profiles of horizontal wells in super-heavy foamy oil reservoirs cannot be obtained by conventional methods at present. In this study, a semi-analytical model which couples the wellbore and reservoir was established to predict the inflow profile of horizontal wells in super-heavy foamy oil reservoirs with cold production method. The coupled wellbore/reservoir model is based on the prediction of the dynamic physical property parameters of foamy oil, and employs reservoir engineering methods, such as the microelement, mirror reflection, and potential function methods. The numerical solution was obtained by applying iteration method in MATLAB. Meanwhile, the model accounts for formation heterogeneity along the horizontal well that has never been considered before and pressure drop loss along the horizontal wellbore. The model was applied to a field case, and the calculation results were compared with those predicted by using the Joshi and Furui productivity formulas. It showed that the developed model led to the smallest errors from field production data, which further verifies the accuracy of the model. Moreover, sensitivity analysis is conducted by changing the permeability distribution along the horizontal well and the length of the horizontal section based on the established model. And the results are instructive for horizontal well optimization design. In short, this model is of great significance for productivity calculations, horizontal well design optimization, and production predictions of cold production with horizontal wells in super-heavy oil reservoirs.",3,3,3
Pressure Drop,Permeability,"Andersen, Pal O.; Zhou, Yingfang",Steady state relative permeability experiments with capillary end effects: Analytical solutions including derivation of the intercept method,Capillary end effects; SCAL; Steady state experiment; Generalized capillary number; Analytical solutions; Intercept method,,"Steady state relative permeability experiments are performed by coinjection of two (or more) immiscible fluids. The relative permeabilities can be calculated directly from the stabilized pressure drop and saturation of the core if capillary end effects and transient effects are negligible. In most cases such conditions are difficult to obtain. This work presents an analytical solution in form of explicit expressions for the spatial profiles of pressure gradients and saturation, average saturation and pressure drop for a core being injected simultaneously with two phases at steady state when capillary end effects are significant. When arbitrary saturation functions are applied, such parameters and distributions can only by obtained by numerical integration. By assumption of simplified saturation function correlations the differential equation describing steady state can be integrated. A new dimensionless capillary number N is obtained which contains the fluid and rock parameters, but also the saturation function parameters (relative permeability and capillary pressure), fluid viscosities, injected flow fraction, total flow rate and more. It is shown that when this number is of magnitude 1, end effects cover parts of the core, but parts of the core are also unaffected. For N > 10 the end effects are negligible, while for N < 10 end effects are dominant. This paper gives the first formal proof of the intercept method from basic assumptions. It is shown that when the inlet saturation is sufficiently close to that of a no capillary pressure situation; the average saturation changes linearly with the inverse of total rate towards the saturation corresponding to no capillary forces; also, the pressure drop divided by the pressure drop of a no end effect situation goes linearly towards 1 with the inverse of total rate.",3,3,3
Pressure Drop,Permeability,"Yang, Xin; Zhang, Hongbin; Wu, Wenbo; Gong, Zhihao; Yuan, Weifeng; Feng, Xi-Qiao; Gu, Bin",Gas migration in the reservoirs of ultra-low porosity and permeability based on an improved apparent permeability model,Gas migration; Solid-fluid coupling; Apparent permeability; Stress dependence; Initial deformation state,SHALE-GAS; COAL PERMEABILITY; TRANSPORT MECHANISMS; MATRIX DEFORMATION; STRESS-DEPENDENCE; SURFACE-DIFFUSION; ADSORPTION; FLOW; NANOPORES; METHANE,"An apparent permeability model considering the solid-fluid coupling is established to analyze the gas transport in the reservoirs of ultra-low porosity and permeability. In the new model, multiple flow mechanisms including viscous flow, the dynamic effects induced by gas molecules collision with the pore walls and surface diffusion are taken into account according to the flow distributions. The effect of solid deformation is embodied with the stress dependence model of the intrinsic permeability which is based on the poroelasticity theory, discards the assumption of constant total stress and accounts for the influence of the initial deformation state. Numerical results show that the dynamic effects and surface diffusion can promote the apparent permeability, especially when the pore pressure drops to a low level. The geomechanical deformation generally results in the reduction of the intrinsic permeability while the large sorption strain may induce rebound of the intrinsic permeability. The assumption of constant total stress only slightly affects the permeability, but it eliminates the instantaneous equilibrium stage in the gas migration process. Correct determination of the initial deformation state is critical to evaluate the gas flow capacity. Finally, parametric analysis is conducted to identify the key factors in gas transfer.",3,3,2
Pressure Drop,Permeability,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Pressure Drop,Permeability,"Kanimozhi, B.; Mahalingam, S.; Pranesh, Venkat; Kesavakumar, R.; Senthil, S.; Ravikumar, S.; Pradeep, Shanthi; Senthil, Sandhya; Murugan, Raji",Colloidal release in high temperature porous media with oversaturated fines during supercritical CO2 transport,Colloidal flow; Fines migration; Porous media; Pressure drop; Permeability; Temperature,CHANGE HEAT-TRANSFER; SLOW MIGRATION; IONIC-STRENGTH; OIL-RESERVOIR; FLOW BEHAVIOR; SURFACE; KAOLINITE; PARTICLES; SANDSTONE; INJECTION,"This paper presents the impacts of supercritical CO2 transport in high temperature porous media with over-saturated fines. The latter phenomenon (indicates oversaturated fines) is in which the lift force of the fine particle over pore surface is greater than the gravitational and electrostatic forces combined, where the fines are released from the pore surfaces and transport along with the permeating fluid as colloidal-suspension flow. During transport, the fines are captured in the pore-throats and thereby deteriorating the permeability and decreasing fluid recovery as well. Therefore, three sets of coreflood tests have been conducted to examine the fines mobilization in porous media during supercritical CO2 transport and the results have been compared with the results obtained from the subcritical CO2 flow. Produced suspension-colloids have been sent for microstructural analysis and its outcomes, supported the experimental results. Statistical modelling and literature data were employed and compared for model validation, which revealed high agreement.",3,3,0
Pressure Drop,Permeability,"Zaberi, Husain A.; Lee, Jason J.; Enick, Robert M.; Beckman, Eric J.; Cummings, Stephen D.; Dailey, Chris; Vasilache, Mihai",An experimental feasibility study on the use of CO2-soluble polyfluoroacrylates for CO2 mobility and conformance control applications,CO2 enhanced oil recovery; Polyfluoroacrylate; Mobility control; Conformance control; Polymer adsorption,,"High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.",2,2,1
Pressure Drop,Permeability,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Pressure Drop,Permeability,"Tan, Yongsheng; Li, Haitao; Li, Qi; Zhou, Xiang; Jiang, Beibei; Zhang, Nan; Wang, Xiaowei",Experimental evaluation method for acid injection profiles of horizontal wells during a carbonate acidizing process,Acid injection profile; Horizontal well; Permeability-pore volume multiplier chart; Drawdown-permeability-fluid injection; volume chart; Experimental evaluation method,PEROXIDE PRESOAKING PRIOR; RESERVOIRS; MODEL,"In YB carbonate gas reservoirs, taking acidizing measures for horizontal wells is a common practice. In heterogeneous carbonate reservoirs, the acid injection profile of a horizontal well determines the acid distribution along the horizontal well. However, the present methods are not suitable for reservoirs with high temperatures and strong heterogeneity such as YB carbonate gas reservoirs. This work presents an experimental evaluation method for the acid injection profile of horizontal wells during the carbonate acidizing process. Based on the status of horizontal wells in YB carbonate gas reservoirs, an injection experimental apparatus with horizontal wells was designed and implemented. Experiments on the fluid injection profiles of horizontal wells with different formation types in an YB carbonate gas reservoir were performed, and the effects of the permeability combination, drawdown pressure, and wellbore pressure drop on the fluid injection profiles were studied. From the experimental results, a chart of the experimental drawdown-permeability-fluid injection volume was generated. By combining this chart with the creation of a permeability-pore volume multiplier chart, an experimental evaluation method was developed to evaluate horizontal well acid injection profiles. The findings in this research provide a method for acid injection evaluation and selection of target well segments for acidizing horizontal wells in YB carbonate gas reservoirs and similar oil/gas reservoirs.",1,1,1
Pressure Drop,Surface,"Yang, Xin; Zhang, Hongbin; Wu, Wenbo; Gong, Zhihao; Yuan, Weifeng; Feng, Xi-Qiao; Gu, Bin",Gas migration in the reservoirs of ultra-low porosity and permeability based on an improved apparent permeability model,Gas migration; Solid-fluid coupling; Apparent permeability; Stress dependence; Initial deformation state,SHALE-GAS; COAL PERMEABILITY; TRANSPORT MECHANISMS; MATRIX DEFORMATION; STRESS-DEPENDENCE; SURFACE-DIFFUSION; ADSORPTION; FLOW; NANOPORES; METHANE,"An apparent permeability model considering the solid-fluid coupling is established to analyze the gas transport in the reservoirs of ultra-low porosity and permeability. In the new model, multiple flow mechanisms including viscous flow, the dynamic effects induced by gas molecules collision with the pore walls and surface diffusion are taken into account according to the flow distributions. The effect of solid deformation is embodied with the stress dependence model of the intrinsic permeability which is based on the poroelasticity theory, discards the assumption of constant total stress and accounts for the influence of the initial deformation state. Numerical results show that the dynamic effects and surface diffusion can promote the apparent permeability, especially when the pore pressure drops to a low level. The geomechanical deformation generally results in the reduction of the intrinsic permeability while the large sorption strain may induce rebound of the intrinsic permeability. The assumption of constant total stress only slightly affects the permeability, but it eliminates the instantaneous equilibrium stage in the gas migration process. Correct determination of the initial deformation state is critical to evaluate the gas flow capacity. Finally, parametric analysis is conducted to identify the key factors in gas transfer.",3,3,2
Pressure Drop,Surface,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Pressure Drop,Surface,"Ghasemi, Mohammad; Al-Safran, Eissa",Integrated reservoir/wellbore production model for oil field asphaltene deposition management,Integrated modeling; Asphaltene precipitation and deposition; Micellization model; Equation-of-state; Transport mechanism,THERMODYNAMIC MICELLIZATION MODEL; EQUATION-OF-STATE; PARTICLE DEPOSITION; PRECIPITATION; FLOW; PRESSURE; SAFT,"Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity, poor understanding, and inadequate predictive tools. A literature review study on asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition taking into account the effect of their interaction on asphaltene deposition. In addition, most of the existing studies are focused on either modeling the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupling reservoir and wellbore production models, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model to ensure accurate phase behavior and volumetric calculations, and to tune the thermodynamic asphaltene precipitation model. A field case input data is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing. The proposed model predicted the location and growth of asphaltene deposition thickness with time and space in the inner production-tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop and decreasing flowrate. Sensitivity analyses to investigate several parameters such as depletion drive mechanism, asphaltene particle size, and injection of CO2 rich gas on asphaltene deposition show excellent results that are aligned with the physical and theoretical understanding of asphaltene deposition. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which affects project economics and safety.",3,3,0
Pressure Drop,Surface,"Kanimozhi, B.; Mahalingam, S.; Pranesh, Venkat; Kesavakumar, R.; Senthil, S.; Ravikumar, S.; Pradeep, Shanthi; Senthil, Sandhya; Murugan, Raji",Colloidal release in high temperature porous media with oversaturated fines during supercritical CO2 transport,Colloidal flow; Fines migration; Porous media; Pressure drop; Permeability; Temperature,CHANGE HEAT-TRANSFER; SLOW MIGRATION; IONIC-STRENGTH; OIL-RESERVOIR; FLOW BEHAVIOR; SURFACE; KAOLINITE; PARTICLES; SANDSTONE; INJECTION,"This paper presents the impacts of supercritical CO2 transport in high temperature porous media with over-saturated fines. The latter phenomenon (indicates oversaturated fines) is in which the lift force of the fine particle over pore surface is greater than the gravitational and electrostatic forces combined, where the fines are released from the pore surfaces and transport along with the permeating fluid as colloidal-suspension flow. During transport, the fines are captured in the pore-throats and thereby deteriorating the permeability and decreasing fluid recovery as well. Therefore, three sets of coreflood tests have been conducted to examine the fines mobilization in porous media during supercritical CO2 transport and the results have been compared with the results obtained from the subcritical CO2 flow. Produced suspension-colloids have been sent for microstructural analysis and its outcomes, supported the experimental results. Statistical modelling and literature data were employed and compared for model validation, which revealed high agreement.",3,3,0
Pressure Drop,Surface,"Omojuwa, Emmanuel; Ahmed, Ramadan",Analytical modeling of axial oscillation-supported drillstrings in high-angle wells,Axial oscillations; Directional drilling; Oscillation tools; Borehole; Friction reduction; Modeling; Displacement excitation,FRICTION-REDUCING PERFORMANCE; REDUCTION; TOOL,"Downhole vibrations generated from axial oscillation tools (AOTs) in axial oscillation-supported drillstrings (AOSDs) has become one of the efficient means of reducing friction and improving weight transfer during sliding operations in horizontal and extended-reach wells. Dynamic modeling of AOT-excited drillstrings is needed for validating the functionality of axial oscillation tools during surface tests and predicting their response under downhole conditions. An analytical model is presented in this study to predict the behavior of axial oscillation-supported drillstrings working under downhole and surface conditions. The model is useful to perform parametric studies, downhole data correlation and placement study of AOTs along the drillstring in horizontal and extended-reach wells. Unlike existing models, the nonlinear equation of motion is derived from a model damped in a viscous medium with Coulomb friction and subjected to displacement excitation. The model also accounts for the spring rate of the axial oscillation tool. The displacement excitation is obtained from the spring rate, which is a critical input to the model. The nonlinear damping is approximated with an equivalent viscous damping coefficient to obtain an analytical solution. The developed model in this study is validated with published experimental measurements obtained from field-scale drillstrings. Correlations between predicted and measured axial displacement and accelerations at different excitation frequencies, pressure drops and spring rates show an approximate average deviation of 14.5%. Also, results from this study strongly accentuates that flow rate is the most critical operating parameter for axial oscillation tools because it affects the amplitude of pressure drop, excitation force, and operating frequency of AOTs.",2,2,2
Pressure Drop,Surface,"Zaberi, Husain A.; Lee, Jason J.; Enick, Robert M.; Beckman, Eric J.; Cummings, Stephen D.; Dailey, Chris; Vasilache, Mihai",An experimental feasibility study on the use of CO2-soluble polyfluoroacrylates for CO2 mobility and conformance control applications,CO2 enhanced oil recovery; Polyfluoroacrylate; Mobility control; Conformance control; Polymer adsorption,,"High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.",2,2,1
Pressure Drop,Surface,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Pressure Drop,Transport,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Pressure Drop,Transport,"Qing, Meiyi; Liang, Huaqing; Zhang, Jinjun; Zhan, Honglei",The mechanism of detecting water content in oil-water emulsions using impedance spectroscopy,Impedance spectroscopy; Water content; Oil-water emulsion; Distribution of droplets,DROPLET SIZE; ELECTROCHEMICAL IMPEDANCE; IN-WATER; EMULSIFICATION; DISTRIBUTIONS,"The water content of the oil-water emulsions has a significant impact on the flow pattern and pressure drop law of oil-water two-phase flow, thus more theory and methods are necessary to improve the detection of emulsion. Impedance spectroscopy was employed to detect oil-water emulsions with different water contents. The diffusion frequency extracted from impedance spectroscopy had a linear relationship with the water content of emulsions. In this study, polarization microscope was used to obtain the microstructure characteristics of oil-water emulsions. The increasing water content increased the logarithmic mean size of the droplets in a linear fashion. This led to an increase in the concentration of charged ions in the diffusion layer of the ionic double layer, which significantly influenced the time of the diffusion process. Consequently, impedance spectroscopy can be applied to detect the water content of emulsions and contribute to further understanding the characteristics of multi-phase flow in petroleum reservation and transportation industry.",3,3,5
Pressure Drop,Transport,"Yang, Xin; Zhang, Hongbin; Wu, Wenbo; Gong, Zhihao; Yuan, Weifeng; Feng, Xi-Qiao; Gu, Bin",Gas migration in the reservoirs of ultra-low porosity and permeability based on an improved apparent permeability model,Gas migration; Solid-fluid coupling; Apparent permeability; Stress dependence; Initial deformation state,SHALE-GAS; COAL PERMEABILITY; TRANSPORT MECHANISMS; MATRIX DEFORMATION; STRESS-DEPENDENCE; SURFACE-DIFFUSION; ADSORPTION; FLOW; NANOPORES; METHANE,"An apparent permeability model considering the solid-fluid coupling is established to analyze the gas transport in the reservoirs of ultra-low porosity and permeability. In the new model, multiple flow mechanisms including viscous flow, the dynamic effects induced by gas molecules collision with the pore walls and surface diffusion are taken into account according to the flow distributions. The effect of solid deformation is embodied with the stress dependence model of the intrinsic permeability which is based on the poroelasticity theory, discards the assumption of constant total stress and accounts for the influence of the initial deformation state. Numerical results show that the dynamic effects and surface diffusion can promote the apparent permeability, especially when the pore pressure drops to a low level. The geomechanical deformation generally results in the reduction of the intrinsic permeability while the large sorption strain may induce rebound of the intrinsic permeability. The assumption of constant total stress only slightly affects the permeability, but it eliminates the instantaneous equilibrium stage in the gas migration process. Correct determination of the initial deformation state is critical to evaluate the gas flow capacity. Finally, parametric analysis is conducted to identify the key factors in gas transfer.",3,3,2
Pressure Drop,Transport,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Pressure Drop,Transport,"Ghasemi, Mohammad; Al-Safran, Eissa",Integrated reservoir/wellbore production model for oil field asphaltene deposition management,Integrated modeling; Asphaltene precipitation and deposition; Micellization model; Equation-of-state; Transport mechanism,THERMODYNAMIC MICELLIZATION MODEL; EQUATION-OF-STATE; PARTICLE DEPOSITION; PRECIPITATION; FLOW; PRESSURE; SAFT,"Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity, poor understanding, and inadequate predictive tools. A literature review study on asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition taking into account the effect of their interaction on asphaltene deposition. In addition, most of the existing studies are focused on either modeling the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupling reservoir and wellbore production models, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model to ensure accurate phase behavior and volumetric calculations, and to tune the thermodynamic asphaltene precipitation model. A field case input data is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing. The proposed model predicted the location and growth of asphaltene deposition thickness with time and space in the inner production-tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop and decreasing flowrate. Sensitivity analyses to investigate several parameters such as depletion drive mechanism, asphaltene particle size, and injection of CO2 rich gas on asphaltene deposition show excellent results that are aligned with the physical and theoretical understanding of asphaltene deposition. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which affects project economics and safety.",3,3,0
Pressure Drop,Transport,"Kanimozhi, B.; Mahalingam, S.; Pranesh, Venkat; Kesavakumar, R.; Senthil, S.; Ravikumar, S.; Pradeep, Shanthi; Senthil, Sandhya; Murugan, Raji",Colloidal release in high temperature porous media with oversaturated fines during supercritical CO2 transport,Colloidal flow; Fines migration; Porous media; Pressure drop; Permeability; Temperature,CHANGE HEAT-TRANSFER; SLOW MIGRATION; IONIC-STRENGTH; OIL-RESERVOIR; FLOW BEHAVIOR; SURFACE; KAOLINITE; PARTICLES; SANDSTONE; INJECTION,"This paper presents the impacts of supercritical CO2 transport in high temperature porous media with over-saturated fines. The latter phenomenon (indicates oversaturated fines) is in which the lift force of the fine particle over pore surface is greater than the gravitational and electrostatic forces combined, where the fines are released from the pore surfaces and transport along with the permeating fluid as colloidal-suspension flow. During transport, the fines are captured in the pore-throats and thereby deteriorating the permeability and decreasing fluid recovery as well. Therefore, three sets of coreflood tests have been conducted to examine the fines mobilization in porous media during supercritical CO2 transport and the results have been compared with the results obtained from the subcritical CO2 flow. Produced suspension-colloids have been sent for microstructural analysis and its outcomes, supported the experimental results. Statistical modelling and literature data were employed and compared for model validation, which revealed high agreement.",3,3,0
Pressure Drop,Pressure Gradient,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Pressure Drop,Pressure Gradient,"Andersen, Pal O.; Zhou, Yingfang",Steady state relative permeability experiments with capillary end effects: Analytical solutions including derivation of the intercept method,Capillary end effects; SCAL; Steady state experiment; Generalized capillary number; Analytical solutions; Intercept method,,"Steady state relative permeability experiments are performed by coinjection of two (or more) immiscible fluids. The relative permeabilities can be calculated directly from the stabilized pressure drop and saturation of the core if capillary end effects and transient effects are negligible. In most cases such conditions are difficult to obtain. This work presents an analytical solution in form of explicit expressions for the spatial profiles of pressure gradients and saturation, average saturation and pressure drop for a core being injected simultaneously with two phases at steady state when capillary end effects are significant. When arbitrary saturation functions are applied, such parameters and distributions can only by obtained by numerical integration. By assumption of simplified saturation function correlations the differential equation describing steady state can be integrated. A new dimensionless capillary number N is obtained which contains the fluid and rock parameters, but also the saturation function parameters (relative permeability and capillary pressure), fluid viscosities, injected flow fraction, total flow rate and more. It is shown that when this number is of magnitude 1, end effects cover parts of the core, but parts of the core are also unaffected. For N > 10 the end effects are negligible, while for N < 10 end effects are dominant. This paper gives the first formal proof of the intercept method from basic assumptions. It is shown that when the inlet saturation is sufficiently close to that of a no capillary pressure situation; the average saturation changes linearly with the inverse of total rate towards the saturation corresponding to no capillary forces; also, the pressure drop divided by the pressure drop of a no end effect situation goes linearly towards 1 with the inverse of total rate.",3,3,3
Pressure Drop,Pressure Gradient,"Naeem, Mohammad Hossein Towfighi; Dehaghani, Amir Hossein Saeedi",Evaluation of the performance of oil as a membrane during low-salinity water injection; focusing on type and concentration of salts,Smart water; Low-salinity water; Semi-permeable membrane; Osmotic pressure gradient,WETTABILITY; EOR; SANDSTONE,"Injection of low-salinity or smart water into the reservoir is one of the most common EOR techniques. This technique leads to more oil recovery in comparison to reservoir water and seawater injection. Several mechanisms explain the reasons for this increased recovery level, the most important of which is the wettability alteration towards water-wet conditions. However, in recent years, further mechanisms have been added to the previous ones as the main or complementary mechanism. One of these newly added mechanisms is the performance of oil as a semi-permeable membrane between connate and low-salinity waters. According to this mechanism, water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure (difference in chemical potential), which works as the driving force, until the system moves toward equilibrium in concentration. Introducing water molecules into connate water causes the swelling of connate water, and eventually moves the oil towards the pore throats. In this study, experiments have been performed on capillary tubes, while ignoring the effect of fluid-rock interactions to investigate the proposed theory. Experimental results confirmed the role of osmotic theory. Furthermore, a decrease in the salinity of the low-salinity water causes the oil-droplets' displacement to increase, whereas further reductions in the salinity of the injected water cause lower displacements. Therefore, there is an optimum value of low-salinity water concentration to obtain the highest possible oil drop displacement. The optimum values for the tested samples in this study were about 5000-10000 ppm. Additionally, it was found that among all of the essential seawater salts, potassium chloride leads to the highest oil drop displacement; and among oil samples, heptane showed better membrane-like performance in comparison to toluene and crude oil.",3,3,0
Pressure Drop,Pressure Gradient,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Pressure Drop,Pressure Gradient,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Pressure Drop,Multiphase Flow,"Ghasemi, Mohammad; Al-Safran, Eissa",Integrated reservoir/wellbore production model for oil field asphaltene deposition management,Integrated modeling; Asphaltene precipitation and deposition; Micellization model; Equation-of-state; Transport mechanism,THERMODYNAMIC MICELLIZATION MODEL; EQUATION-OF-STATE; PARTICLE DEPOSITION; PRECIPITATION; FLOW; PRESSURE; SAFT,"Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity, poor understanding, and inadequate predictive tools. A literature review study on asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition taking into account the effect of their interaction on asphaltene deposition. In addition, most of the existing studies are focused on either modeling the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupling reservoir and wellbore production models, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model to ensure accurate phase behavior and volumetric calculations, and to tune the thermodynamic asphaltene precipitation model. A field case input data is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing. The proposed model predicted the location and growth of asphaltene deposition thickness with time and space in the inner production-tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop and decreasing flowrate. Sensitivity analyses to investigate several parameters such as depletion drive mechanism, asphaltene particle size, and injection of CO2 rich gas on asphaltene deposition show excellent results that are aligned with the physical and theoretical understanding of asphaltene deposition. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which affects project economics and safety.",3,3,0
Pressure Drop,Multiphase Flow,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Pressure Drop,Multiphase Flow,"Santim, C. G. S.; Fulchignoni, L. P.; Rosa, E. S.; Gaspari, E. F.",Transient multiphase flow modeling and validation in a real production system with high CO2 content using the drift-flux model,Three-phase flow; Drift-flux model; Non-isothermal model; Transient; Production system,FRICTIONAL PRESSURE-DROP; GAS-LIQUID FLOW; 2-PHASE FLOW; SLUG FLOW; LONG BUBBLES; TRANSITIONS; VISCOSITY; VELOCITY; MOTION,"This study presents a transient multiphase flow simulator based on the non-isothermal Drift-Flux model that aims to reproduce oil and gas production systems. The mathematical model consists of three mass conservation equations, one equation for the momentum mixture and one equation to reproduce the energy conservation of the gas-liquid-liquid mixture, assuming mass transfer between the produced liquid and gas phases and neglecting the slip between the liquid phases. The solver utilizes the finite volume method with a semi-implicit approach making use of the upwind first order scheme with staggered grid. Liquid holdup and liquid amount between the liquid phases are evaluated explicitly whereas the coupling between velocities and pressure fields is implicit by building a global matrix. The temperature field is obtained in an uncoupled way after the volumetric fraction, mass flow rates and pressure calculus. For the sake of validation of the solver, the simulated profiles of pressure, temperature and liquid holdup along the production line are compared with those given by the reference benchmark for multiphase flow simulation in the Oil & Gas industry, OLGA (R) (OiL and GAs simulator), and real field data in the steady-state regime of an offshore oil producer well with high CO2 content. The influence of input parameters on the simulation results is investigated. A sensitivity analysis is performed on the fluid modeling, considering the Black-Oil model making use of two different R-s correlations and the compositional approach. The influence of drift parameters on the numerical solutions is also verified. Liquid holdup, pressure and temperature trends are analyzed upstream and downstream of the master valve as well as in the well bottom and on the separator regions. Finally, important production procedures such as well shutdown and start-up are analyzed. The main motivation is to verify the solver capability to reproduce the multiphase flow behavior during the oil and gas production, especially for a fluid with high GOR and high amount of CO2.",2,2,0
Pressure Drop,Multiphase Flow,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Pressure Drop,Water Content,"Qing, Meiyi; Liang, Huaqing; Zhang, Jinjun; Zhan, Honglei",The mechanism of detecting water content in oil-water emulsions using impedance spectroscopy,Impedance spectroscopy; Water content; Oil-water emulsion; Distribution of droplets,DROPLET SIZE; ELECTROCHEMICAL IMPEDANCE; IN-WATER; EMULSIFICATION; DISTRIBUTIONS,"The water content of the oil-water emulsions has a significant impact on the flow pattern and pressure drop law of oil-water two-phase flow, thus more theory and methods are necessary to improve the detection of emulsion. Impedance spectroscopy was employed to detect oil-water emulsions with different water contents. The diffusion frequency extracted from impedance spectroscopy had a linear relationship with the water content of emulsions. In this study, polarization microscope was used to obtain the microstructure characteristics of oil-water emulsions. The increasing water content increased the logarithmic mean size of the droplets in a linear fashion. This led to an increase in the concentration of charged ions in the diffusion layer of the ionic double layer, which significantly influenced the time of the diffusion process. Consequently, impedance spectroscopy can be applied to detect the water content of emulsions and contribute to further understanding the characteristics of multi-phase flow in petroleum reservation and transportation industry.",3,3,5
Pressure Drop,Water Content,"Ge, Dong; Peng, Jianming; Li, Keke; Huang, Chaoyang; Lian, Moke; Yang, Zhenglong",Influence of water-based drilling fluids on the performance of the fluidic down-the-hole hammer,Fluidic DTH hammer; Percussion drilling; Output power; Motion characteristic; Pressure drop; Water-based drilling fluids,,"Fluidic down-the-hole (DTH) hammer is a recently explored percussion drilling tool for the production of boreholes in hard rock. It has been proven efficient for exploration core drilling, geothermal drilling, and oil and gas drilling. Previous studies of this hammer have concentrated on its performance operating with clear water rather than water-based drilling fluids with additives. As the first step to filling the gap of knowledge in this area, this study was designed to explore only the performance of an SC86-H fluidic DTH hammer driven by water-based drilling fluids with various temperatures and different contents of bentonite and barite. Such performance was characterized in terms of output power, motion characteristic and operating pressure drop, and compared with that driven by water. The results showed that the output power of the SC86-H type hammer driven by drilling fluids with bentonite content <3% was better than that driven by water thanks to the lubrication effect in the fit clearance, whereas with bentonite content >= 3%, its output power was in the range or below that driven by water due to the elevation of the hydraulic losses and the frictional drag. Its operating pressure drop is only insignificantly influenced by the bentonite content. As the weighting agents in the drilling fluids, the barite particles impeded the smooth motion of the piston. However, the increased impact energy and output power can entirely offset the disadvantage mentioned above. Temperature affects the performance of the SC86-H type hammer by influencing the viscosity and density of the drilling fluids. Some optimal schemes are suggested for the rational design and application of the fluidic DTH hammer in practice. In summary, the SC86-H type hammer operated well in the drilling fluids with realistic fluid power levels. It means that the fluidic DTH hammer has good adaptation and robustness, which is favorable to practical application.",2,2,9
Pressure Drop,Water Content,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Pressure Drop,Water Content,"Qin, Hao; Dai, Jiacai; Liu, Xiangjun; Yang, Guofeng; Pei, Yang; Gou, Shunchao; Chen, Meng",Slip behaviours and evaluation of interpretative model of oil/water two-phase flow in a large-diameter pipe,Production logging; Oil/water flow; Slip behaviour; Interpretative model; Water holdup,OIL-WATER 2-PHASE; SLUG-LIQUID-HOLDUP; DRIFT-FLUX MODEL; MECHANISTIC MODEL; PRESSURE-DROP; VERTICAL PIPE; VELOCITY; PATTERNS; BUBBLES,"Mixtures of oil and water are common in oil-producing wells. When the oilfield has a mid-late exploitation status, the production of oil and water gradually decreases and the comprehensive water content sharply increases with time. An accurate evaluation of the volumetric flow rate of each phase in the pipe is of importance for diagnosing production problems, developing an engineering design, and guiding reservoir management activities. In this study, the slip behaviours we investigated based on the high-quality experimental data obtained from a multi-phase flow loop with a large-diameter (inner diameter: 5.5 inch) vertical pipe with low flow rates (<30 m(3)/d). Furthermore, the interpretation accuracies of five interpretative models of vertical oil/water flow ware comprehensively evaluated. The results show that the slip trends to increase with decreasing flow rates. However, it was found that, when the flow rate is less than 7 m3/d, the flow rate minimally affects the slip. Additionally, the variation tendency of the slip velocity as a function of the water holdup is not stable, hence, a reasonable interpretative model should be selected according to the water holdup. The slip velocity gradually increased, and was found to be nearly linear, and the slip model proposed by Hasan and Kabir (1999) demonstrated the best adaptability under the conditions of the tested data and a water holdup of less than 0.9. The slip velocity exponentially increased with increasing water holdup and the modified drift-flux model proposed by Wu et al. (1992) was found to be more appropriate under the condition that the water holdup exceeds 0.9. Overall (i.e. for all of the test data), the Hasan model (1999) yielded better processing results for the vertical oil/water flow system under the condition of low flow rates. The analysis in this study provides better insight into the slip between the oil and water phases in a two-phase flow system with a low flow rate. In addition, the interpretative model with the best predictive capability is highlighted in this paper.",1,1,3
Pressure Drop,CO2,"Ghasemi, Mohammad; Al-Safran, Eissa",Integrated reservoir/wellbore production model for oil field asphaltene deposition management,Integrated modeling; Asphaltene precipitation and deposition; Micellization model; Equation-of-state; Transport mechanism,THERMODYNAMIC MICELLIZATION MODEL; EQUATION-OF-STATE; PARTICLE DEPOSITION; PRECIPITATION; FLOW; PRESSURE; SAFT,"Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity, poor understanding, and inadequate predictive tools. A literature review study on asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition taking into account the effect of their interaction on asphaltene deposition. In addition, most of the existing studies are focused on either modeling the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupling reservoir and wellbore production models, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model to ensure accurate phase behavior and volumetric calculations, and to tune the thermodynamic asphaltene precipitation model. A field case input data is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing. The proposed model predicted the location and growth of asphaltene deposition thickness with time and space in the inner production-tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop and decreasing flowrate. Sensitivity analyses to investigate several parameters such as depletion drive mechanism, asphaltene particle size, and injection of CO2 rich gas on asphaltene deposition show excellent results that are aligned with the physical and theoretical understanding of asphaltene deposition. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which affects project economics and safety.",3,3,0
Pressure Drop,CO2,"Kanimozhi, B.; Mahalingam, S.; Pranesh, Venkat; Kesavakumar, R.; Senthil, S.; Ravikumar, S.; Pradeep, Shanthi; Senthil, Sandhya; Murugan, Raji",Colloidal release in high temperature porous media with oversaturated fines during supercritical CO2 transport,Colloidal flow; Fines migration; Porous media; Pressure drop; Permeability; Temperature,CHANGE HEAT-TRANSFER; SLOW MIGRATION; IONIC-STRENGTH; OIL-RESERVOIR; FLOW BEHAVIOR; SURFACE; KAOLINITE; PARTICLES; SANDSTONE; INJECTION,"This paper presents the impacts of supercritical CO2 transport in high temperature porous media with over-saturated fines. The latter phenomenon (indicates oversaturated fines) is in which the lift force of the fine particle over pore surface is greater than the gravitational and electrostatic forces combined, where the fines are released from the pore surfaces and transport along with the permeating fluid as colloidal-suspension flow. During transport, the fines are captured in the pore-throats and thereby deteriorating the permeability and decreasing fluid recovery as well. Therefore, three sets of coreflood tests have been conducted to examine the fines mobilization in porous media during supercritical CO2 transport and the results have been compared with the results obtained from the subcritical CO2 flow. Produced suspension-colloids have been sent for microstructural analysis and its outcomes, supported the experimental results. Statistical modelling and literature data were employed and compared for model validation, which revealed high agreement.",3,3,0
Pressure Drop,CO2,"Zaberi, Husain A.; Lee, Jason J.; Enick, Robert M.; Beckman, Eric J.; Cummings, Stephen D.; Dailey, Chris; Vasilache, Mihai",An experimental feasibility study on the use of CO2-soluble polyfluoroacrylates for CO2 mobility and conformance control applications,CO2 enhanced oil recovery; Polyfluoroacrylate; Mobility control; Conformance control; Polymer adsorption,,"High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.",2,2,1
Pressure Drop,CO2,"Santim, C. G. S.; Fulchignoni, L. P.; Rosa, E. S.; Gaspari, E. F.",Transient multiphase flow modeling and validation in a real production system with high CO2 content using the drift-flux model,Three-phase flow; Drift-flux model; Non-isothermal model; Transient; Production system,FRICTIONAL PRESSURE-DROP; GAS-LIQUID FLOW; 2-PHASE FLOW; SLUG FLOW; LONG BUBBLES; TRANSITIONS; VISCOSITY; VELOCITY; MOTION,"This study presents a transient multiphase flow simulator based on the non-isothermal Drift-Flux model that aims to reproduce oil and gas production systems. The mathematical model consists of three mass conservation equations, one equation for the momentum mixture and one equation to reproduce the energy conservation of the gas-liquid-liquid mixture, assuming mass transfer between the produced liquid and gas phases and neglecting the slip between the liquid phases. The solver utilizes the finite volume method with a semi-implicit approach making use of the upwind first order scheme with staggered grid. Liquid holdup and liquid amount between the liquid phases are evaluated explicitly whereas the coupling between velocities and pressure fields is implicit by building a global matrix. The temperature field is obtained in an uncoupled way after the volumetric fraction, mass flow rates and pressure calculus. For the sake of validation of the solver, the simulated profiles of pressure, temperature and liquid holdup along the production line are compared with those given by the reference benchmark for multiphase flow simulation in the Oil & Gas industry, OLGA (R) (OiL and GAs simulator), and real field data in the steady-state regime of an offshore oil producer well with high CO2 content. The influence of input parameters on the simulation results is investigated. A sensitivity analysis is performed on the fluid modeling, considering the Black-Oil model making use of two different R-s correlations and the compositional approach. The influence of drift parameters on the numerical solutions is also verified. Liquid holdup, pressure and temperature trends are analyzed upstream and downstream of the master valve as well as in the well bottom and on the separator regions. Finally, important production procedures such as well shutdown and start-up are analyzed. The main motivation is to verify the solver capability to reproduce the multiphase flow behavior during the oil and gas production, especially for a fluid with high GOR and high amount of CO2.",2,2,0
Pressure Drop,Horizontal Wells,"Huang, Shijun; Zhu, Yuanrui; Ding, Junwu; Li, Xingmin; Xue, Yongchao",A semi-analytical model for predicting inflow profile of long horizontal wells in super-heavy foamy oil reservoir,Super-heavy foamy oil; Horizontal well; Semi-analytical model; Formation heterogeneity; Inflow profile; Productivity prediction,RECOVERY STRATEGIES; BEHAVIOR; FLOW,"In most super-heavy oil reservoirs, depletion recovery is one of the important cold recovery methods accompanied by foamy oil production. However, the inflow profiles of horizontal wells in super-heavy foamy oil reservoirs cannot be obtained by conventional methods at present. In this study, a semi-analytical model which couples the wellbore and reservoir was established to predict the inflow profile of horizontal wells in super-heavy foamy oil reservoirs with cold production method. The coupled wellbore/reservoir model is based on the prediction of the dynamic physical property parameters of foamy oil, and employs reservoir engineering methods, such as the microelement, mirror reflection, and potential function methods. The numerical solution was obtained by applying iteration method in MATLAB. Meanwhile, the model accounts for formation heterogeneity along the horizontal well that has never been considered before and pressure drop loss along the horizontal wellbore. The model was applied to a field case, and the calculation results were compared with those predicted by using the Joshi and Furui productivity formulas. It showed that the developed model led to the smallest errors from field production data, which further verifies the accuracy of the model. Moreover, sensitivity analysis is conducted by changing the permeability distribution along the horizontal well and the length of the horizontal section based on the established model. And the results are instructive for horizontal well optimization design. In short, this model is of great significance for productivity calculations, horizontal well design optimization, and production predictions of cold production with horizontal wells in super-heavy oil reservoirs.",3,3,3
Pressure Drop,Horizontal Wells,"Omojuwa, Emmanuel; Ahmed, Ramadan",Analytical modeling of axial oscillation-supported drillstrings in high-angle wells,Axial oscillations; Directional drilling; Oscillation tools; Borehole; Friction reduction; Modeling; Displacement excitation,FRICTION-REDUCING PERFORMANCE; REDUCTION; TOOL,"Downhole vibrations generated from axial oscillation tools (AOTs) in axial oscillation-supported drillstrings (AOSDs) has become one of the efficient means of reducing friction and improving weight transfer during sliding operations in horizontal and extended-reach wells. Dynamic modeling of AOT-excited drillstrings is needed for validating the functionality of axial oscillation tools during surface tests and predicting their response under downhole conditions. An analytical model is presented in this study to predict the behavior of axial oscillation-supported drillstrings working under downhole and surface conditions. The model is useful to perform parametric studies, downhole data correlation and placement study of AOTs along the drillstring in horizontal and extended-reach wells. Unlike existing models, the nonlinear equation of motion is derived from a model damped in a viscous medium with Coulomb friction and subjected to displacement excitation. The model also accounts for the spring rate of the axial oscillation tool. The displacement excitation is obtained from the spring rate, which is a critical input to the model. The nonlinear damping is approximated with an equivalent viscous damping coefficient to obtain an analytical solution. The developed model in this study is validated with published experimental measurements obtained from field-scale drillstrings. Correlations between predicted and measured axial displacement and accelerations at different excitation frequencies, pressure drops and spring rates show an approximate average deviation of 14.5%. Also, results from this study strongly accentuates that flow rate is the most critical operating parameter for axial oscillation tools because it affects the amplitude of pressure drop, excitation force, and operating frequency of AOTs.",2,2,2
Pressure Drop,Horizontal Wells,"Tan, Yongsheng; Li, Haitao; Li, Qi; Zhou, Xiang; Jiang, Beibei; Zhang, Nan; Wang, Xiaowei",Experimental evaluation method for acid injection profiles of horizontal wells during a carbonate acidizing process,Acid injection profile; Horizontal well; Permeability-pore volume multiplier chart; Drawdown-permeability-fluid injection; volume chart; Experimental evaluation method,PEROXIDE PRESOAKING PRIOR; RESERVOIRS; MODEL,"In YB carbonate gas reservoirs, taking acidizing measures for horizontal wells is a common practice. In heterogeneous carbonate reservoirs, the acid injection profile of a horizontal well determines the acid distribution along the horizontal well. However, the present methods are not suitable for reservoirs with high temperatures and strong heterogeneity such as YB carbonate gas reservoirs. This work presents an experimental evaluation method for the acid injection profile of horizontal wells during the carbonate acidizing process. Based on the status of horizontal wells in YB carbonate gas reservoirs, an injection experimental apparatus with horizontal wells was designed and implemented. Experiments on the fluid injection profiles of horizontal wells with different formation types in an YB carbonate gas reservoir were performed, and the effects of the permeability combination, drawdown pressure, and wellbore pressure drop on the fluid injection profiles were studied. From the experimental results, a chart of the experimental drawdown-permeability-fluid injection volume was generated. By combining this chart with the creation of a permeability-pore volume multiplier chart, an experimental evaluation method was developed to evaluate horizontal well acid injection profiles. The findings in this research provide a method for acid injection evaluation and selection of target well segments for acidizing horizontal wells in YB carbonate gas reservoirs and similar oil/gas reservoirs.",1,1,1
Pressure Drop,Production Strategy,"Huang, Shijun; Zhu, Yuanrui; Ding, Junwu; Li, Xingmin; Xue, Yongchao",A semi-analytical model for predicting inflow profile of long horizontal wells in super-heavy foamy oil reservoir,Super-heavy foamy oil; Horizontal well; Semi-analytical model; Formation heterogeneity; Inflow profile; Productivity prediction,RECOVERY STRATEGIES; BEHAVIOR; FLOW,"In most super-heavy oil reservoirs, depletion recovery is one of the important cold recovery methods accompanied by foamy oil production. However, the inflow profiles of horizontal wells in super-heavy foamy oil reservoirs cannot be obtained by conventional methods at present. In this study, a semi-analytical model which couples the wellbore and reservoir was established to predict the inflow profile of horizontal wells in super-heavy foamy oil reservoirs with cold production method. The coupled wellbore/reservoir model is based on the prediction of the dynamic physical property parameters of foamy oil, and employs reservoir engineering methods, such as the microelement, mirror reflection, and potential function methods. The numerical solution was obtained by applying iteration method in MATLAB. Meanwhile, the model accounts for formation heterogeneity along the horizontal well that has never been considered before and pressure drop loss along the horizontal wellbore. The model was applied to a field case, and the calculation results were compared with those predicted by using the Joshi and Furui productivity formulas. It showed that the developed model led to the smallest errors from field production data, which further verifies the accuracy of the model. Moreover, sensitivity analysis is conducted by changing the permeability distribution along the horizontal well and the length of the horizontal section based on the established model. And the results are instructive for horizontal well optimization design. In short, this model is of great significance for productivity calculations, horizontal well design optimization, and production predictions of cold production with horizontal wells in super-heavy oil reservoirs.",3,3,3
Pressure Drop,Production Strategy,"Ghasemi, Mohammad; Al-Safran, Eissa",Integrated reservoir/wellbore production model for oil field asphaltene deposition management,Integrated modeling; Asphaltene precipitation and deposition; Micellization model; Equation-of-state; Transport mechanism,THERMODYNAMIC MICELLIZATION MODEL; EQUATION-OF-STATE; PARTICLE DEPOSITION; PRECIPITATION; FLOW; PRESSURE; SAFT,"Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity, poor understanding, and inadequate predictive tools. A literature review study on asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition taking into account the effect of their interaction on asphaltene deposition. In addition, most of the existing studies are focused on either modeling the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupling reservoir and wellbore production models, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model to ensure accurate phase behavior and volumetric calculations, and to tune the thermodynamic asphaltene precipitation model. A field case input data is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing. The proposed model predicted the location and growth of asphaltene deposition thickness with time and space in the inner production-tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop and decreasing flowrate. Sensitivity analyses to investigate several parameters such as depletion drive mechanism, asphaltene particle size, and injection of CO2 rich gas on asphaltene deposition show excellent results that are aligned with the physical and theoretical understanding of asphaltene deposition. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which affects project economics and safety.",3,3,0
Pressure Drop,Production Strategy,"Huang, Shijun; Yang, Yanwei; Yang, Lijie; Du, Mengge; Ma, Kuiqian; Guo, Shuhao; Xia, Yun",New method for evaluation of fluid interface movement in oil reservoir with gas cap and weak aquifer,Oil rim with gas cap; Gas-oil-water interface; Interface moving regular; Reasonable production strategy,,"For the development of oil rim reservoir with gas cap and weak edge water, the management of oil-gas and oil-water interface movement is extremely critical. In this paper, a new method for evaluation of fluid interface movement has been put forward, from which the law of fluid interface movement can be recognized clearly and production strategy can be designed reasonably. The new method is based on the material balance principle and the conditions of water influx, fluid expansion and oil & gas production. By analyzing the volume of gas intrusion and water influx, the rate of movement of oil-water and oil-gas interface can be obtained. Then we studied the regular of fluid interface movement and pressure variation, and gave a single reasonable production strategy and a stage reasonable production strategy. Finally, the applicability analysis was carried out. The method can be used to predict the movement speed, movement distance of fluid interface and water influx at different times and different production strategies. Meanwhile, it can be applied to analyze the influence degree of each factor, which affects the moving of fluid interface. The results indicate that: i) The rate of the oil-water interface increases with the increase of the oil production rate and injection-production ratio. The rate of the oil-gas interface increases with the increase of the injection-production ratio, while the gas production rate has less influence on it. ii) For single reasonable production strategy, when time and injection-production ratio is constant, with the increase in oil production rate, the reasonable gas production rate also increases as cubic function correspondingly; When the oil production rate is constant, with the increase in injection production ratio, the corresponding reasonable gas production rate decreases. iii) The earlier the reasonable production strategy is implemented, the slower the formation pressure drops, and the more favorable for development.",2,2,1
Pressure Drop,Porous-media,"Wan, Yizhao; Liu, Yuewu; Wu, Nengyou",Numerical pressure transient analysis for unfilled-caved carbonate reservoirs based on Stokes-Darcy coupled theory,Carbonate reservoir; Pressure transient behavior; Stokes-Darcy coupled; Flow in porous media; Numerical simulation,TARIM BASIN; BOUNDARY-CONDITION; MODEL; FLOW; VUGGY; WELL; CAVITY,"Caved carbonate reservoirs are very special because of the strong heterogeneity. The pressure transient behavior of the caved carbonate reservoirs is quite different from the conventional homogeneous or dual medium reservoirs because of the presence of large-scale cavities. There are two types of cavities: filled and unfilled, which dominated the production of the reservoirs. Fluid flow in the unfilled cavity should be described by Stokes' equation rather than Darcy's law. It is needed to better understand the role of the unfilled cavities plays in the pressure transient analysis. The objective of this work is to analyze the pressure transient behavior of the unfilled cavities. A coupled Stokes-Darcy pressure transient model is developed and the finite element method is applied in the solutions of the mathematical models. Then, the numerical pressure transient model is used in the analysis of two typical cases: a well drilled into the unfilled cavity (WIC) and a well not drilled into the unfilled cavity (WOC). The type curves of the WIC model indicate that flow in the unfilled cavity is an oscillated pressure-drop rather than a radial flow. The unfilled cavity that the well drilled into would be considered as an enlarged wellbore which is equivalent to a negative skin factor, as a consequence the wellbore storage coefficient will increase. Main characteristics of type curves for WOC model are the valley on the pressure derivative. A cavity with a larger size and smaller distance from the wellbore would give rise to a deeper valley. Comparative results indicate that unfilled cavities described by the Stokes' equation are not the limit of the filled cavities with extremely large mobility, which was predicted by previous work.",3,3,3
Pressure Drop,Porous-media,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Pressure Drop,Porous-media,"Kanimozhi, B.; Mahalingam, S.; Pranesh, Venkat; Kesavakumar, R.; Senthil, S.; Ravikumar, S.; Pradeep, Shanthi; Senthil, Sandhya; Murugan, Raji",Colloidal release in high temperature porous media with oversaturated fines during supercritical CO2 transport,Colloidal flow; Fines migration; Porous media; Pressure drop; Permeability; Temperature,CHANGE HEAT-TRANSFER; SLOW MIGRATION; IONIC-STRENGTH; OIL-RESERVOIR; FLOW BEHAVIOR; SURFACE; KAOLINITE; PARTICLES; SANDSTONE; INJECTION,"This paper presents the impacts of supercritical CO2 transport in high temperature porous media with over-saturated fines. The latter phenomenon (indicates oversaturated fines) is in which the lift force of the fine particle over pore surface is greater than the gravitational and electrostatic forces combined, where the fines are released from the pore surfaces and transport along with the permeating fluid as colloidal-suspension flow. During transport, the fines are captured in the pore-throats and thereby deteriorating the permeability and decreasing fluid recovery as well. Therefore, three sets of coreflood tests have been conducted to examine the fines mobilization in porous media during supercritical CO2 transport and the results have been compared with the results obtained from the subcritical CO2 flow. Produced suspension-colloids have been sent for microstructural analysis and its outcomes, supported the experimental results. Statistical modelling and literature data were employed and compared for model validation, which revealed high agreement.",3,3,0
Pressure Drop,Drilling Fluid,"Wan, Yizhao; Liu, Yuewu; Wu, Nengyou",Numerical pressure transient analysis for unfilled-caved carbonate reservoirs based on Stokes-Darcy coupled theory,Carbonate reservoir; Pressure transient behavior; Stokes-Darcy coupled; Flow in porous media; Numerical simulation,TARIM BASIN; BOUNDARY-CONDITION; MODEL; FLOW; VUGGY; WELL; CAVITY,"Caved carbonate reservoirs are very special because of the strong heterogeneity. The pressure transient behavior of the caved carbonate reservoirs is quite different from the conventional homogeneous or dual medium reservoirs because of the presence of large-scale cavities. There are two types of cavities: filled and unfilled, which dominated the production of the reservoirs. Fluid flow in the unfilled cavity should be described by Stokes' equation rather than Darcy's law. It is needed to better understand the role of the unfilled cavities plays in the pressure transient analysis. The objective of this work is to analyze the pressure transient behavior of the unfilled cavities. A coupled Stokes-Darcy pressure transient model is developed and the finite element method is applied in the solutions of the mathematical models. Then, the numerical pressure transient model is used in the analysis of two typical cases: a well drilled into the unfilled cavity (WIC) and a well not drilled into the unfilled cavity (WOC). The type curves of the WIC model indicate that flow in the unfilled cavity is an oscillated pressure-drop rather than a radial flow. The unfilled cavity that the well drilled into would be considered as an enlarged wellbore which is equivalent to a negative skin factor, as a consequence the wellbore storage coefficient will increase. Main characteristics of type curves for WOC model are the valley on the pressure derivative. A cavity with a larger size and smaller distance from the wellbore would give rise to a deeper valley. Comparative results indicate that unfilled cavities described by the Stokes' equation are not the limit of the filled cavities with extremely large mobility, which was predicted by previous work.",3,3,3
Pressure Drop,Drilling Fluid,"Ge, Dong; Peng, Jianming; Li, Keke; Huang, Chaoyang; Lian, Moke; Yang, Zhenglong",Influence of water-based drilling fluids on the performance of the fluidic down-the-hole hammer,Fluidic DTH hammer; Percussion drilling; Output power; Motion characteristic; Pressure drop; Water-based drilling fluids,,"Fluidic down-the-hole (DTH) hammer is a recently explored percussion drilling tool for the production of boreholes in hard rock. It has been proven efficient for exploration core drilling, geothermal drilling, and oil and gas drilling. Previous studies of this hammer have concentrated on its performance operating with clear water rather than water-based drilling fluids with additives. As the first step to filling the gap of knowledge in this area, this study was designed to explore only the performance of an SC86-H fluidic DTH hammer driven by water-based drilling fluids with various temperatures and different contents of bentonite and barite. Such performance was characterized in terms of output power, motion characteristic and operating pressure drop, and compared with that driven by water. The results showed that the output power of the SC86-H type hammer driven by drilling fluids with bentonite content <3% was better than that driven by water thanks to the lubrication effect in the fit clearance, whereas with bentonite content >= 3%, its output power was in the range or below that driven by water due to the elevation of the hydraulic losses and the frictional drag. Its operating pressure drop is only insignificantly influenced by the bentonite content. As the weighting agents in the drilling fluids, the barite particles impeded the smooth motion of the piston. However, the increased impact energy and output power can entirely offset the disadvantage mentioned above. Temperature affects the performance of the SC86-H type hammer by influencing the viscosity and density of the drilling fluids. Some optimal schemes are suggested for the rational design and application of the fluidic DTH hammer in practice. In summary, the SC86-H type hammer operated well in the drilling fluids with realistic fluid power levels. It means that the fluidic DTH hammer has good adaptation and robustness, which is favorable to practical application.",2,2,9
Pressure Drop,Emulsions,"Qing, Meiyi; Liang, Huaqing; Zhang, Jinjun; Zhan, Honglei",The mechanism of detecting water content in oil-water emulsions using impedance spectroscopy,Impedance spectroscopy; Water content; Oil-water emulsion; Distribution of droplets,DROPLET SIZE; ELECTROCHEMICAL IMPEDANCE; IN-WATER; EMULSIFICATION; DISTRIBUTIONS,"The water content of the oil-water emulsions has a significant impact on the flow pattern and pressure drop law of oil-water two-phase flow, thus more theory and methods are necessary to improve the detection of emulsion. Impedance spectroscopy was employed to detect oil-water emulsions with different water contents. The diffusion frequency extracted from impedance spectroscopy had a linear relationship with the water content of emulsions. In this study, polarization microscope was used to obtain the microstructure characteristics of oil-water emulsions. The increasing water content increased the logarithmic mean size of the droplets in a linear fashion. This led to an increase in the concentration of charged ions in the diffusion layer of the ionic double layer, which significantly influenced the time of the diffusion process. Consequently, impedance spectroscopy can be applied to detect the water content of emulsions and contribute to further understanding the characteristics of multi-phase flow in petroleum reservation and transportation industry.",3,3,5
Pressure Drop,Emulsions,"Khalid, Mozamil; Sultan, Abdullah; Noui-Mehidi, Mohamed Nabil; Al-Sarkhi, Abdelsalam; Salim, Omer",Effect of Nano-Clay Cloisite 20A on water-in-oil stable emulsion flow at different temperatures,Water-in-oil; Emulsion; Nano-Clay; Pressure drop reduction; Stable-emulsion,CRUDE-OIL; SALINITY; BEHAVIOR,"In Enhanced Oil Recovery (EOR) operations, water-in-oil emulsions are often used to ensure good sweep of the crude in the flooding process. Dispersions of 70% water in 30% oil (diesel) were extensively used to move the crude in the porous medium with good results. The present paper is concerned with a study on the influence of Cloisite 20A Nano-Clay particles particularly on the hydrodynamic performance and the stability of water-in-oil emulsions at different temperatures between 25 degrees C and 45 degrees C. The experimental results showed that the presence of Cloisite 20A stabilized the water-in-oil emulsions compared to the dispersion without Nano-Clay. It was found that the Nano-Clay concentration affects the emulsion viscosity depending on mainly the water volume fractions. In general, small quantities of the Nano-Clay reduce emulsion viscosity, while higher concentrations of the Nano-Clay resulted in a clear increase of the emulsion viscosity. The results also revealed the percentage of pressure drop reduction at different temperatures as a function of the concentration of Nano-clays, oil/water ratios and emulsion flowrates. The influence of fluid temperature on pressure drop reduction is higher than the influence of Nano-Clay concentration especially at low flowrate.",2,2,2
Pressure Drop,Control,"Wang, Shen; Li, Dongyin; Mitri, Hani; Li, Huamin",Numerical simulation of hydraulic fracture deflection influenced by slotted directional boreholes using XFEM with a modified rock fracture energy model,Directional hydraulic fracturing; XFEM; Slotted directional borehole; Hydraulic fracture morphology; Rock shear fracture energy,FINITE-ELEMENT-METHOD; PROPAGATION CONTROL; CRACK-GROWTH; PRESSURE; TECHNOLOGY; INITIATION; MECHANISM; MEDIA,"Directional hydraulic fracturing (DHF) has been used in conductivity improvement of oil, gas and geothermal energy reservoirs and hard rock roof breaking in coal mines. Although the new DHF method that integrates fracturing borehole and slotted directional borehole (SDB) has been recently introduced, the mechanism and effectiveness of SDB on hydraulic fracture guiding remain open issues. In this study, numerical simulation based on extended finite element method (XFEM) is performed to investigate the effect of SDB on hydraulic fracture deflection. A modified rock fracture energy model is proposed and performed by a user subroutine USDFLD with XFEM, which considers the hardening property of rock shear fracture energy as confining pressure increases. The effects of stress field and borehole line azimuth on hydraulic fracture deflection and bottomhole pressure are investigated. Hydraulic fracture morphologies of three kinds of multi-borehole fracturing technology are compared, the control mechanism of SDBs on hydraulic fracture is explained, and the bottomhole pressure relief effect, borehole spacing and potential application prospects are discussed. Result indicates that the modified model shows good accuracy and applicability in predicting hydraulic fracture propagation, and the hardening property of shear fracture energy should be considered when using XFEM and cohesive element method. The feature first drop and then rise ? of bottomhole pressure curve is an important sign that imply the hydraulic fracture propagates into the influence radius of SDB and can be used as an indicator to evaluate the effectiveness of DHF. Slot increases the influence radius of directional borehole and changes the local stress direction, thus allowing SDB-based DHF technique to be applied to the conditions where the stress difference ratio does not exceed one. When the stress difference ratio is greater than one, the pressurized SDB is more suitable.",3,3,15
Pressure Drop,Control,"Zaberi, Husain A.; Lee, Jason J.; Enick, Robert M.; Beckman, Eric J.; Cummings, Stephen D.; Dailey, Chris; Vasilache, Mihai",An experimental feasibility study on the use of CO2-soluble polyfluoroacrylates for CO2 mobility and conformance control applications,CO2 enhanced oil recovery; Polyfluoroacrylate; Mobility control; Conformance control; Polymer adsorption,,"High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.",2,2,1
Pressure Drop,Good Agreement,"Mazza, Ricardo A.; Suguimoto, Fabio K.",Experimental investigations of kerosene-water two-phase flow in vertical pipe,Water-oil flow; Flow patterns; Pressure drop; Oil fraction; Drift-flux correlation,LIQUID-LIQUID UPFLOW; OIL-WATER; PHASE INVERSION; PRESSURE-DROP; VELOCITY; HOLDUP; PATTERN; SUSPENSIONS; VISCOSITY; FRACTION,"Oil and water two-phase flow studies are important to the oil industries. This paper aims to determine the flow patterns, holdup, pressure losses, phase inversion, drift flux parameters and mixture properties in vertical upward kerosene and water flow. The experiment was conducted in a 26 mm i.d duct with phase velocities spanning from 0.1 to 1.0 m/s. The averaged holdup was measured using quick close valves in a 1.16 m long test section. The same test section was used to measure the pressure drop. A local impedance probe and high-speed films were used to determine the flow patterns. Six different flow patterns was identified: dispersed bubbly (DB), core annular (CA), bubbly (B), churn turbulent (CT), and elongated water drop (EWD). The kerosene holdup was highest for EWD, spanning from 0.8 to 0.9, followed by CT and CA, which spans from 0.35 to 0.75. The kerosene holdup for bubbly spans from 0.12 to 0.6, being the highest range for all patterns. The phase inversion occurs when the kerosene input fraction is beta(K) = 0.35. There is no evidence of slippage between the dispersed and continuous phases. The drift velocity is due to the misalignment of the dispersed fraction and the mixture velocity profile and the distribution parameter is C-0=1.10. The pressure loss showed a good agreement with Blasius correlation. The exception is for the bubbly and churn turbulent. The density was determined using the homogeneous model and five different mixture viscosity models were investigated. The pressure loss deviation using (Mukhaimer et al., 2015) mixture viscosity spans from 5 to 25%. The drift-flux correlation increase the predictive capability of the oil fractions in oil pipelines, which contribute to the operational security. In addition, a better pressure drop losses estimative provide in this study helps to a better oil pipeline design.",2,2,1
Pressure Drop,Good Agreement,"Andreolli, I; Azevedo, G. R.; Balino, J. L.",Application of stability solver for severe slugging considering a choking device and a tubing connected to a Wet Christmas Tree,Stability solver; Severe slugging; Petroleum production; Three-phase flow; Choking; Tubing,FLOW-RATE; SIMULATION,"This work is an improvement of a previous work (Andreolli et al. 2018) by including a tubing as a subsystem of the pipeline-riser system, a realistic choke valve model to predict the two-phase critical flow and pressure drop before the separator and boundary conditions between stretches of the geometry, in order to improve the determination of the stability boundary. The improved stability solver is applied for a three phase flow (gas, oil and water). Stability for operational points obtained from actual measurements are successfully predicted with the stability maps generated by the solver considering the tubing connected to the Wet Christmas Tree (WCT). A parametric analysis is made in order to evaluate a choke valve influence over stability maps. The stability maps are built by using field conditions at Santos and Campos basins (Brazil). The numerical results present a good agreement with numerical data and real operational conditions. The analysis to evaluate and verify the choke valve influence over stabilization shows a good agreement with the expected behavior.",1,1,3
Source Rocks,Oil Migration,"Hu, Shouzhi; Li, Shuifu; Xia, Liuwen; Lv, Qian; Cao, Jian","On the internal oil migration in shale systems and implications for shale oil accumulation: A combined petrological and geochemical investigation in the Eocene Nanxiang Basin, China",Shale oil; Internal oil migration; Primary oil migration; Bitumen fraction; Biyang sag,KIMMERIDGE SOURCE ROCKS; BRAE FIELD AREA; ORGANIC-MATTER; MOLECULAR COMPOSITION; NORTH-SEA; PETROLEUM; HYDROCARBONS; RETENTION; EXPULSION,"Internal oil migration within shale systems is of significance to shale oil accumulation as indicating the retention, expulsion, and accumulation of shale oils. However, conventional geochemical proxies to study this internal oil migration are commonly overlapped, and thus the migration is still well understood. Here we conduct a case study using the methodology of combined petrology and geochemistry, rather than the geochemistry alone in previous studies which are mostly bulk and thus cannot reveal the complex migration in different scales including macro (millimeter), micro (micron), and nano. The study area is in the lacustrine Eocene Biyang sag, Nanxiang Basin of eastern China. Results show that three types can be identified according to the petrological characteristics of the internal oil migration. Their geochemistry was further clarified. In detail, according to the correlation between residual hydrocarbons (S-1) and total organic carbon content (TOC): Type A, inward migrated oils from external sources within the shale system; Type B, weak expulsed oils to external space; and Type C, strong expulsed oils to external space. The amount of hydrocarbon expelled per unit rock mass (Q(expulsion)) for migration types A, B and C are < 0, 0-1.5 mg/g rock, and > 1.5 mg/g rock, respectively. They have good bulk and molecular geochemical responses. Typically, Type A samples have the highest saturates/aromatics and n-C-19/Sigma MP ratios, with Type C having the lowest ratios and Type B having intermediate values. Stable carbonisotope compositions indicate the level of internal oil migration too. Our data suggest that combined petrological and geochemical methods can effectively characterize internal oil migration in shale oil systems. A good combination of source and reservoir in shale systems, i.e., interbedded or juxtaposed Type A and Type C sequences is favorable for shale oil accumulation. This is universal and obviously provides useful data for regional exploration.",3,4,4
Source Rocks,Oil Migration,"Zhu, Chuanzhen; Gang, Wenzhe; Zhao, Xianzheng; Wang, Yifan; Chen, Guo; Pu, Xiugang","The preferential pathways of oil migration in the Qi-nan slope belt of Bohai Bay Basin, China: Insights from integrated analyses using geochemical and morphology tools",Oil family; Pyrrolic nitrogen compounds; Geochemical tracing of hydrocarbon migration; Preferential migration pathways; Qi-nan slope belt; Bohai Bay Basin,PYRROLIC NITROGEN-COMPOUNDS; PETROLEUM MIGRATION; HYDROCARBON MIGRATION; QIKOU SAG; BOZHONG SUBBASIN; ORDOS BASIN; CRUDE OILS; ACCUMULATION; FIELD; CONSTRAINTS,"The Qi-nan Slope belt is located in the southwestern Qikou Sag in the Bohai Bay Basin and has had relatively little oil and gas exploration. The mechanism of oil migration remains unclear due to the lack of understanding of the oil-oil relationship, the definition of oil migration pathways, and the controversy over the contributing source rocks. Based on hierarchical cluster analysis, the crude oils in the Qi-nan Slope are divided into three groups (A, B and C) with different geochemical compositions. Group A oils, including Class A(1) and Class A(2) biodegraded oils, and Group C oils are contributed by Es-1(x) and Es-3 source rocks with different organic facies, and distributions are limited to the WXZ oilfield in the western slope. Group B oils, including Class B-1 and Class B-2 biodegraded oils, mainly originated from Es-1(x) source rocks and are widely distributed in the southern slope. The significant correlation between the relative migration distance (RMD) of oils and pyrrolic nitrogen compounds, rather than the parameters related to oil maturity, indicates that the pyrrolic nitrogen compounds can effectively trace oil migration directions in the Qi-nan Slope, and 1,8-DMC/2,6-DMC is the best indicator. For oil migration conduits, no large-scale faults developed in the inner part of the slope, and the oil-gas test results from major wells on the seismic profiles suggest that oils are mostly concentrated in Es-1(x) with no obvious vertical migration in this area. Therefore, we speculate that the Es-1(x) sand body provided the migration pathway for crude oil and controlled its uneven accumulation in the slope area. The isopleth map of the 1,8-DMC/2,6-DMC ratio, the distribution characteristics of the oil test results from major wells and the morphology of the Es-1(x) transporting layer suggest that the overall migration direction of oil was dispersedly from the Qi-nan Sub-sag to the southern areas of the slope and that structural ridges provided preferential migration pathways for hydrocarbon accumulation.",2,2,2
Source Rocks,Oil Migration,"Song, Jianyang; Huo, Zhipeng; Fu, Guang; Hu, Ming; Sun, Tongwen; Liu, Zhe; Wang, Wei; Liu, Luofu","Petroleum migration and accumulation in the Liuchu area of Raoyang Sag, Bohai Bay Basin, China",Biomarkers; Migration and accumulation modeling; Migration direction; Physical characteristics of crude oil; Vertical migration,HYDROCARBON MIGRATION; MOLECULAR-PARAMETERS; DONGYING DEPRESSION; NITROGEN-COMPOUNDS; TOARCIAN SHALES; SOURCE ROCKS; PARIS BASIN; OIL-FIELD; SECONDARY; DISTRIBUTIONS,"This study focused on vertical migration of petroleum in the Liuchu area, China. The physical properties of petroleum and changes in the geochemical characteristics of the study area were also investigated. Biomarkers such as, nitrogen compounds, n-alkanes, triterpenoids, steroids, hopanes, and cholestanes were analyzed in this regard. Petro-physical characteristics, such as, density, viscosity, concentrations of wax, resin, and sulfur of oil were studied. The rNa(+)/rCl(-) ratio of Ed(2) formation water ranged from 0.25 to 5.7, oil density of Ed(2) formation ranged from 0.85 to 0.95 g/cm(3), and oil resin concentration 10-50%, oil wax content in Ed(2) formation ranged from 2 to 29% were lower than that of Es1. The rNa(+)/rCl(-) ratio and mineralization of formation water data were examined to demonstrate the migration pathways. Geochemical and crude oil physical indexes were utilized to investigate the relationship between petroleum migration and seismic data. Cholestane alpha beta beta, alpha alpha alpha cholestane, diacholestane, steroid, and low ring terpenes in the formation were utilized to trace petroleum migration. Recent studies on petroleum maturity of have focused on comparison of source rocks and have reported that the maturity effects of source rock and reservoir oil are weak while those effects are high in the Liuchu aera. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The alpha alpha alpha C-29 (20S)/(20S + 20R) and C-29 (beta beta)/alpha alpha + beta beta) ratios ranged from 0.2 to 0.35 Further, C-31 (22S)/(22S + 22R), C-32(22S)/(22S + 22R), and C-29 (20S)/(20S + 20R) ratios ranged from 0.3 to 0.8, and 0.131 and 0.81, respectively. Petroleum migrated along migration channels. This suggested that vertical migration occurred after formation of the source rock fault and lateral migration occurred along the sandbody. Reservoir sandstone content, overlying mudstone content, and thickness of caprock are likely limited lateral petroleum migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The results of this study enabled optimization of uncertain petroleum migration pathways and improved the petroleum migration and accumulation model.",2,2,1
Source Rocks,Oil Migration,"Jiang, Wenlong; Imin, Ablimit; Wang, Xueyong; Wang, Tao; Guo, Wenjian","Geochemical characterization and quantitative identification of mixed-source oils from the Baikouquan and Lower Wuerhe Formations in the eastern slope of the Mahu Sag, Junggar Basin, NW China",Mixed oil; Chemometrics; Alternating least square; Mahu sag; Junggar basin,LOWER INDUS BASIN; CRUDE OILS; PETROLEUM GEOCHEMISTRY; CRETACEOUS ROCKS; TARIM BASIN; FIELD; ORIGIN,"The quantitative identification of mixed-source oil is a popular yet difficult topic in current petroleum geochemistry research. The mixed-source oils of the Baikouquan and Lower Wuerhe formations in the eastern slope of the Mahu Sag of Junggar Basin were used as a typical example in this study. Quantitative research on mixed oils was carried out in the study area and good results were obtained using an approach combining organic geochemistry and chemometrics. The results of crude oil geochemistry research show that mixed-source crude oil is ubiquitous in the study area. After comprehensive analysis, it is likely that there are three endmembers in the current mixed-source oils. Two of the endmembers may represent mainly the contribution of the early and late source rocks of the Permian Fengcheng Formation and are dominated by late filled crude oil. However, the third endmember is quite different. Its hydrocarbons may have come from the source rocks of the Permian Lower Wuerhe Formation or the source rocks of the Fengcheng Formation under different lithofacies and sedimentary environments. The study area is dominated by hydrocarbons that accumulated from the Fengcheng Formation. Although the proportion of hydrocarbons generated in the late stage is not high, it plays a very important role in hydrocarbon migration and accumulation. This comprehensive comparative study shows that the chemometric method can play an important role in calculating the proportion of mixed-source oil and in endmember analysis.",2,2,0
Source Rocks,Oil Migration,"Han, Qiuya; Li, Meijun; Liu, Xiaoqiang; Jiang, Weidong; Shi, Shengbao; Tang, Youjun; He, Daxiang",Fractionation of alkylated carbazoles in petroleum during subsurface migration: Evidence from molecular simulation and application in sandstone reservoirs,Geo-chromatographic fractionation; Alkylcarbazole; Petroleum migration orientation; Molecular dynamics simulation; Sandstone reservoir,CHROMATOGRAPHIC SEPARATION SCHEMES; AROMATIC HETEROCYCLE FRACTIONS; PYRROLIC NITROGEN-COMPOUNDS; IN-SOURCE ROCKS; CRUDE OILS; BEIBUWAN BASIN; BENZOCARBAZOLE DISTRIBUTIONS; RAPID CHARACTERIZATION; DYNAMICS SIMULATION; ORGANIC-COMPOUNDS,"Carbazole (CA) and alkylated carbazoles are common nitrogen-containing heterocyclic aromatic compounds widely found in crude oils and sedimentary rocks extracts. Their geochemical significances in petroleum exploration have been widely investigated in previous studies. Using density functional theory (DFT) and molecular dynamics (MD) simulation, we calculated the polarity of alkylated carbazole isomers/homologues and their adsorption energy with water and alpha-quartz, respectively. The calculated results show that there are significant differences in migration fractionation effects for alkylated carbazole isomers/homologues. This study confirmed the validity of previously proposed carbazole migration indicators, i.e. 4-/1-MCA (the relative abundance of 4-methylcarbazole to 1-methylcarbazole), 2,5-/1,8-DMCA (2,5-dimethylcarbazole to 1,8-dimethylcarbazole) and 2,4-/1,8-DMCA (2,4-dimethylcarbazole to 1,8-dimethylcarbazole) on the basis of quantum chemistry and molecular simulation. All these three parameters have been successfully applied in a lacustrine sandstone reservoir in the Fushan Depression, Beibuwan Basin (South China Sea). The calculations of Gibbs free energy show that the differences in thermal stability between the isomers of alkylcarbazoles can be negligible. The source input and depositional environment have no significant effect on these indicators for oils from a same oil family. Hence, the values of these parameters are mainly controlled by subsurface petroleum migration processes. Therefore, the molecular parameters relative to alkylated carbazoles can be used as practically effective geochemical markers to trace the oil filling orientation and pathways for subsurface oil migration.",1,2,6
Source Rocks,Oil Migration,"Ashrafi, Taha; Saberi, Mohammad Hossein; ZareNezhad, Bahman","1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran",Basin modeling; Source rock evaluation; Sarchahan formation; Coastal fars; Southern Iran,FOLD-THRUST BELT; ZAGROS MOUNTAINS; PERSIAN-GULF; CONTIGUOUS OFFSHORE; LATEST ORDOVICIAN; NATURAL-GAS; ORIGIN; STRATIGRAPHY; RESERVOIRS; BASEMENT,"One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the ""hot shales"" of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m(2) since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.",1,1,2
Source Rocks,Oil Migration,"Li, Jingfei; Zhang, Zhiyao; Zhu, Guangyou; Li, Tingting; Zhao, Kun; Chi, Linxian; Yan, Huihui","The origin and accumulation of ultra-deep oil in Halahatang area, northern Tarim Basin",Giant oil accumulations; Ultra-deep strata; GCxGC-TOFMS; Halahatang area; Tarim basin,TABEI UPLIFT; NW CHINA; HYDROCARBON ACCUMULATION; DIAMONDOID HYDROCARBONS; THERMAL-CRACKING; CRATONIC REGION; TAZHONG AREA; NATURAL-GAS; CRUDE OILS; PETROLEUM,"The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000-8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.",1,2,0
Source Rocks,Shale,"Tenaglia, Max; Eberli, Gregor P.; Weger, Ralf J.; Blanco, Leticia Rodriguez; Sanchez, Laura E. Rueda; Swart, Peter K.","Total organic carbon quantification from wireline logging techniques: A case study in the Vaca Muerta Formation, Argentina",Total organic carbon; Vaca Muerta Formation; Unconventional resources; TOC prediction; Spectral gamma-ray; Source rock,NEUQUEN BASIN; SEQUENCE STRATIGRAPHY; SOURCE ROCKS; SHALES; METAMORPHISM; RESISTIVITY; RICHNESS; BOUNDARY; TIME; RAMP,"The Vaca Muerta Formation, one of the most prolific unconventional play in South America, exhibits concentrations of total organic carbon (TOC) of up to 16% with variations in TOC paralleling the general facies evolution of the prograding system. This study examines the applicability and accuracy of predicting TOC from two methods of quantifying organic-rich zones from wireline logs: the relationship of uranium from spectral gammaray to TOC, and the delta logR technique for calculating TOC. A database from extensive outcrop geochemical sampling (n = similar to 1900) was correlated to the uranium signal from a handheld spectral gamma-ray logging tool. The U/TOC relationship derived from the outcrop samples shows high variability between outcrop sections measured across the formation. The U/TOC ratio increases from proximal to distal positions within the basin. A second dataset, consisting of core samples, was also analyzed and compared to the TOC calculated using a combination of the sonic and resistivity data obtained from downhole logging. This second method of TOC prediction reliably and accurately reproduces laboratory measurements, and is the far superior choice when estimating organic richness from wireline log signatures. To further test this method of TOC prediction, a subset of sidewall plugs were analyzed for petrophysical and geochemical measurements and using the ologR technique, was able to produce TOC values that compared to discrete laboratory measurements with a correlation coefficient of R-2 = 0.83. The time-tested method of determining organic richness from wireline logs can be successfully applied in the Neuquen Basin and could be attempted in other basins once all available data has been carefully considered.",3,3,5
Source Rocks,Shale,"Hu, Shouzhi; Li, Shuifu; Xia, Liuwen; Lv, Qian; Cao, Jian","On the internal oil migration in shale systems and implications for shale oil accumulation: A combined petrological and geochemical investigation in the Eocene Nanxiang Basin, China",Shale oil; Internal oil migration; Primary oil migration; Bitumen fraction; Biyang sag,KIMMERIDGE SOURCE ROCKS; BRAE FIELD AREA; ORGANIC-MATTER; MOLECULAR COMPOSITION; NORTH-SEA; PETROLEUM; HYDROCARBONS; RETENTION; EXPULSION,"Internal oil migration within shale systems is of significance to shale oil accumulation as indicating the retention, expulsion, and accumulation of shale oils. However, conventional geochemical proxies to study this internal oil migration are commonly overlapped, and thus the migration is still well understood. Here we conduct a case study using the methodology of combined petrology and geochemistry, rather than the geochemistry alone in previous studies which are mostly bulk and thus cannot reveal the complex migration in different scales including macro (millimeter), micro (micron), and nano. The study area is in the lacustrine Eocene Biyang sag, Nanxiang Basin of eastern China. Results show that three types can be identified according to the petrological characteristics of the internal oil migration. Their geochemistry was further clarified. In detail, according to the correlation between residual hydrocarbons (S-1) and total organic carbon content (TOC): Type A, inward migrated oils from external sources within the shale system; Type B, weak expulsed oils to external space; and Type C, strong expulsed oils to external space. The amount of hydrocarbon expelled per unit rock mass (Q(expulsion)) for migration types A, B and C are < 0, 0-1.5 mg/g rock, and > 1.5 mg/g rock, respectively. They have good bulk and molecular geochemical responses. Typically, Type A samples have the highest saturates/aromatics and n-C-19/Sigma MP ratios, with Type C having the lowest ratios and Type B having intermediate values. Stable carbonisotope compositions indicate the level of internal oil migration too. Our data suggest that combined petrological and geochemical methods can effectively characterize internal oil migration in shale oil systems. A good combination of source and reservoir in shale systems, i.e., interbedded or juxtaposed Type A and Type C sequences is favorable for shale oil accumulation. This is universal and obviously provides useful data for regional exploration.",3,4,4
Source Rocks,Shale,"Zhang, Xinlei; Gao, Zhiqian; Fan, Tailiang; Xue, Jianqin; Li, Wenhuan; Zhang, Heng; Cao, Fangda","Element geochemical characteristics, provenance attributes, and paleosedimentary environment of the Paleogene strata in the Lenghu area, northwestern Qaidam Basin",Paleosedimentary environment; Provenance; Trace element geochemistry; Qaidam basin; Paleogene sedimentary period,ORDOS BASIN; DEPOSITIONAL ENVIRONMENT; NORTHERN MARGIN; BLACK SHALES; SOUTH CHINA; SEA; EVOLUTION; BEHAVIOR; PROXIES; KANSAS,"The Lenghu area is a key exploration block in the northwestern Qaidam Basin. Due to the low exploration level, the provenance and paleosedimentary environment of the Paleogene strata is not clear. Based on the major and trace element contents and the carbon and oxygen isotopes of 547 samples collected from the Paleogene strata (E-3(2), E-3(1), and E1+2), this study investigated the provenance attributes and paleosedimentary environment of the entire Paleogene period. The samples from the Paleogene strata have relatively low contents of SiO2 (39.75%-61.81%) and Al2O3 (6.23%-20.48%) and high contents of La, Sc, and Co (223.07 ppm, 273.84 ppm, and 325.45, respectively). Moreover, the La-Th-Sc, Ti/Zr-La/Sc and SiO2-K2O/Na2O discrimination diagrams suggest that the tectonic environment of the provenance is an oceanic island arc. The Co/Th-La/Sc and Zr/TiO2-(V + Ni + Cr)/Al2O3 diagrams indicate that the provenance lithology of the study area is mafic rocks with a high degree of weathering. These results imply that the source rocks of the Paleogene strata are the mafic submarine volcanic rocks of the Tanjianshan group in the Saishiteng Mountains. The Sr/Cu, Sr/Rb, and Mg/Ca indexes indicate that the paleosedimentary environment had a humid climate with a trend of slight aridity. The Sr/Ba and Rb/K ratios and the isotope coefficient Z (calculated by carbon and oxygen isotopes) indicate that the paleosalinity of the water body was predominantly fresh water with a salty trend from the Early to the Late Paleogene. The paleoredox environment during the Paleogene sedimentation was relatively oxidized with a reduction trend based on the V/(V + Ni) and V/Cr values. This combined with the trend of increasing paleosalinity suggests that there was a relatively large lake transgression in the Late Paleogene.",3,3,1
Source Rocks,Shale,"Adeoye, James A.; Akande, Samuel O.; Adekeye, Olabisi A.; Sonibare, Wasiu A.; Ondrak, Robert; Dominik, Wilhelm; Erdtmann, Bernd D.; Neeka, Jacob",Source rock maturity and petroleum generation in the Dahomey Basin SW Nigeria: Insights from geologic and geochemical modelling,,THERMAL HISTORY; BENUE TROUGH; HEAT-FLOW; MATURATION; EVOLUTION; KINETICS,"Sedimentology, foraminifera paleoecology, geochemical and petroleum system modelling studies were performed on Cretaceous shales from onshore Orimedu-1 and offshore X (at a water depth of 914 m) wells in the Dahomey Basin, southwestern Nigeria to evaluate their maturity, hydrocarbon generation potentials, and regional significance for petroleum prospectivity. Foraminifera biofacies analysis of the studied shales suggests deposition in dominantly marine environments. The average total organic carbon content (TOC, wt%) and hydrogen index (HI, mgHC/gTOC) for Cenomanian, Turonian, and Coniacian shales in X-well are 1.3, 0.9, 1.3 and 406, 560, 214 respectively. While the Cenomanian and Turonian shales in Orimedu-1 have TOC (wt%) of 1.3 and 1.9, and HI (mgHC/gTOC) of 179 and 357 respectively. Well X source rocks contain predominantly marine-derived Type II kerogen, while Orimedu-1 well contain terrigenous-derived gas prone kerogen. The integration of recently acquired kinetic data from immature source rocks further constraints the prediction of petroleum generation in the study area.1D basin modelling of X well reveals that the Cenomanian Source Rock (CSR) is the most mature bed in the basin having attained the initial 10% transformation ratio (TR) at 87 Ma, got to peak TR (similar to 50%) at 86 Ma, and reached 83% at 53.6 Ma With a present-day thermal maturity of 0.95% VRo. The Turonian source in well X also attained the initial 10% TR at 87 Ma, got to peak (similar to 50% TR) at 86 Ma and 69% TR at 50 Ma. These modelled source beds are deeper than the source with 0.62 %VRo used for kinetic study. The observed maturity trend is mostly controlled by the regional erosive events associated with the West African rift system during Santonian and Eocene times. The source rocks in Orimedu-1 are immature. The timing of the generated and expelled hydrocarbons into the Cretaceous petroleum systems of Dahomey Basin is of regional significance with the entire Gulf of Guinea basins because of the similar evolution and sedimentation history along with recent discoveries and production of hydrocarbon.",2,2,2
Source Rocks,Shale,"Song, Jianyang; Huo, Zhipeng; Fu, Guang; Hu, Ming; Sun, Tongwen; Liu, Zhe; Wang, Wei; Liu, Luofu","Petroleum migration and accumulation in the Liuchu area of Raoyang Sag, Bohai Bay Basin, China",Biomarkers; Migration and accumulation modeling; Migration direction; Physical characteristics of crude oil; Vertical migration,HYDROCARBON MIGRATION; MOLECULAR-PARAMETERS; DONGYING DEPRESSION; NITROGEN-COMPOUNDS; TOARCIAN SHALES; SOURCE ROCKS; PARIS BASIN; OIL-FIELD; SECONDARY; DISTRIBUTIONS,"This study focused on vertical migration of petroleum in the Liuchu area, China. The physical properties of petroleum and changes in the geochemical characteristics of the study area were also investigated. Biomarkers such as, nitrogen compounds, n-alkanes, triterpenoids, steroids, hopanes, and cholestanes were analyzed in this regard. Petro-physical characteristics, such as, density, viscosity, concentrations of wax, resin, and sulfur of oil were studied. The rNa(+)/rCl(-) ratio of Ed(2) formation water ranged from 0.25 to 5.7, oil density of Ed(2) formation ranged from 0.85 to 0.95 g/cm(3), and oil resin concentration 10-50%, oil wax content in Ed(2) formation ranged from 2 to 29% were lower than that of Es1. The rNa(+)/rCl(-) ratio and mineralization of formation water data were examined to demonstrate the migration pathways. Geochemical and crude oil physical indexes were utilized to investigate the relationship between petroleum migration and seismic data. Cholestane alpha beta beta, alpha alpha alpha cholestane, diacholestane, steroid, and low ring terpenes in the formation were utilized to trace petroleum migration. Recent studies on petroleum maturity of have focused on comparison of source rocks and have reported that the maturity effects of source rock and reservoir oil are weak while those effects are high in the Liuchu aera. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The alpha alpha alpha C-29 (20S)/(20S + 20R) and C-29 (beta beta)/alpha alpha + beta beta) ratios ranged from 0.2 to 0.35 Further, C-31 (22S)/(22S + 22R), C-32(22S)/(22S + 22R), and C-29 (20S)/(20S + 20R) ratios ranged from 0.3 to 0.8, and 0.131 and 0.81, respectively. Petroleum migrated along migration channels. This suggested that vertical migration occurred after formation of the source rock fault and lateral migration occurred along the sandbody. Reservoir sandstone content, overlying mudstone content, and thickness of caprock are likely limited lateral petroleum migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The results of this study enabled optimization of uncertain petroleum migration pathways and improved the petroleum migration and accumulation model.",2,2,1
Source Rocks,Shale,"Beti, Dhrupad R.; Jiang, Chunqing; Panja, Palash; Ring, Terry A.; Levey, Raymond",Hydrocarbon distributions of incremental S1 peaks corresponding to different boiling point ranges of petroleum in rock samples,Pyrolysis; S1 Peak; Incremental S1; Free petroleum; TD-GC,,"This correspondence presents an extension to the article ""A New Method of Source and Reservoir Rock Pyrolysis to Determine the Boiling Point Distribution of Petroleum in Rock Samples"" by Beti et al. (2018). Thermal desorption-gas chromatography (TD-GC) analysis of S1 peak and the sequential split of S1 into three peaks were performed on a Gothic shale sample from the Paradox Basin, Utah. The results indicate that the total area and composition of the S1 peak that includes all of the hydrocarbon molecules detected are equivalent to the sum of the three sequential peaks. The hydrocarbon distribution of the three sequential peaks was used to predict the range of hydrocarbons detected at ""Incremental S1"" temperatures.",2,2,0
Source Rocks,Shale,"Ashrafi, Taha; Saberi, Mohammad Hossein; ZareNezhad, Bahman","1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran",Basin modeling; Source rock evaluation; Sarchahan formation; Coastal fars; Southern Iran,FOLD-THRUST BELT; ZAGROS MOUNTAINS; PERSIAN-GULF; CONTIGUOUS OFFSHORE; LATEST ORDOVICIAN; NATURAL-GAS; ORIGIN; STRATIGRAPHY; RESERVOIRS; BASEMENT,"One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the ""hot shales"" of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m(2) since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.",1,1,2
Source Rocks,Shale,"Yang, Shangru; Gao, Gang; Liu, Yong; Gang, Wenzhe; Dang, Wenlong","Organic geochemistry and petrographic characteristics of the shales from the Late Miocene Zeit Formation in the Tokar area, Red Sea Basin: Implications for depositional environment and hydrocarbon potential",Geochemistry; Depositional environment; Shale; Organic petrography; Biomarker; Red sea basin,SOURCE-ROCK; PETROLEUM; MATTER,"According to the geochemistry, organic petrography, stable carbon isotopic compositions and biomarker analyses of the Late Miocene Zeit Formation shale samples in the Tokar area, Red Sea Basin, the paleoenvironment and hydrocarbon-generating potential were analyzed. The Zeit Formation shales from the Wells S. Suakin-1 and Tokar-1 contain mostly Type III kerogens with minor Type II organic matter (OM), indicating more favorable gasgenerating potential. OM of the shale samples from the Late Miocene Zeit Formation are predominantly of terrigenous higher plants. Kerogens from the Well Tokar-1 show abundant brown liptinites, indicating the mixed origin of planktonic/bacterial and terrigenous OM. The Late Miocene Zeit Formation was deposited in dysoxic/ suboxic, reducing and salt water environments. According to the results of Tmax, Ro and biomarker maturity parameters, the most shale samples from the Zeit Formation are in early mature to mature stages. The shales from the Late Miocene Zeit Formation are generally fair to good source rock. The shales from wells Suakin-2, Talla-2 and Tokar-1 have high hydrocarbon-generating potential.",1,1,1
Source Rocks,Junggar Basin,"Li, Shunming; He, Hui; Hao, Ruilin; Chen, Huanqing; Bie, Hanyu; Liu, Pengcheng","Depositional regimes and reservoir architecture characterization of alluvial fans of Karamay oilfield in Junggar basin, Western China",Junggar basin; Alluvial fan; Cohesive debris flows; Sandy debris flows; Conglomeratic reservoir architectures,PERMIAN LUCAOGOU FORMATION; GRAINED DEBRIS FLOWS; SEDIMENTARY PROCESSES; NATURAL DISTINCTION; HYDRAULIC PROCESSES; SOURCE ROCKS; FACIES; MORPHOLOGY; GEOCHEMISTRY; DELTA,"We analyzed the lithology and sedimentary structures of the lower Karamay formation alluvial fan of Karamay oilfield in Junggar basin and subdivided its lithofacies into six types. The depositional regimes of the lower Karamay formation regressive alluvial fans contain (1) cohesive debris flows, (2) sandy debris flows, (3) grain flows, (4) turbidity currents, and (5) traction currents in the light of sedimentary fabrics and lithofacies association. In terms of lithofacies association, depositional succession, boundary surface hierarchy and wireline logs, fourth-order reservoir architectures for this alluvial fan are composed of nine types: (1) trench channel conglomerates, (2) trench sandy conglomerates, (3) trench proximal sandbody, (4) trench sheetflood lithosome, (5) trench distal sandbody, (6) braided channel, (7) channel gravel bar, (8) overflow sandbody, and (9) runoff channel. On the basis of the reservoir architecture identification of all wells, we established a three-dimensional (3D) architectural element model of the lower Karamay formation with a method of sequential indicator simulation to reveal the reservoir architecture spatial distribution. Integrated three-dimensional reservoir architecture models with contemporary depositional characteristics of alluvial fans, we concluded the depositional patterns of reservoir architectures for different alluvial fan subfacies, which shows the geometric features and aspects of the reservoir architectures. This information provided a technical foundation for the remaining oil prediction, development strategy optimization, and oil recovery enhancement of the conglomeratic oil reservoirs at the high water-cut stage.",3,4,1
Source Rocks,Junggar Basin,"Zheng, Dingye; Pang, Xiongqi; Zhou, Liming; You, Xincai; Liu, Xiaohan; Guo, Fangxin; Li, Wei","Critical conditions of tight oil charging and determination of the lower limits of petrophysical properties for effective tight reservoirs: A case study from the Fengcheng Formation in the Fengcheng area, Junggar Basin",Tight oil; Effective tight reservoir; Lower limits of petrophysical properties; Dynamic mechanism; Junggar basin,TRIASSIC YANCHANG FORMATION; LUCAOGOU FORMATION; SOURCE ROCKS; JIMUSAR SAG; HYDROCARBON GENERATION; RESEARCH PROGRESS; SONGLIAO BASIN; ORDOS BASIN; CHANG 7; CHINA,"Studying the lower limits of petrophysical properties is important to evaluate the exploration and development potentials of tight oil reservoirs. At present, the evaluation criteria are based on a large number of cores and logging data, and rules are based on collections of empirical statistics and displacement pressure experiments. However, there have been few studies on the lower limits of the petrophysical properties of tight reservoirs based on force balance conditions for the hydrocarbon charging process. In this paper, the critical condition for hydrocarbon charging is determined using the oil expansion pressure as the main driving force, with the capillary pressure as the major resistance, via an analysis of the dynamic mechanism of tight oil reservoirs. A force-balance model for judging the lower limits of the petrophysical properties of tight reservoirs can be established by assuming that the oil expansion pressure is equal to the capillary force. This discriminant method is applied to calculate the critical pore-throat radius of the effective reservoirs of the Lower Permian Fengcheng Formation in the Fengcheng area, Junggar Basin, which are 0.310 mu m, 0.248 mu m, 0.208 mu m, and 0.135 mu m, when the buried depths are 2500-3000 m, 3000-3500 m, 3500-4000 m, and 4000-4500 m, respectively. The corresponding critical porosities are 6.15%, 4.84%, 3.81%, and 1.20%, respectively. The lower limits of the petrophysical properties of effective tight reservoirs gradually decrease with increasing burial depth. This method is of great significance for resource evaluations of tight oil reservoirs and the selection of exploration zones.",2,2,6
Source Rocks,Junggar Basin,"Imin, Ablimiti; Zha, Ming; Ding, Xiujian; Bian, Baoli; Liu, Yin; Zheng, Mengling; Han, Chao",Identification of a Permian foreland basin in the western Junggar Basin (NW China) and its impact on hydrocarbon accumulation,Foreland basin; Permian; Structural evolution; Hydrocarbon play; Western junggar basin,GEOCHEMICAL CHARACTERISTICS; PETROLEUM SYSTEMS; NATURAL GASES; ND; XINJIANG; MODELS; GRANITOIDS; TECTONICS; MAGMATISM; EVOLUTION,"The piedmont depression in the western Junggar Basin is a typical large-scale thrust belt rich in hydrocarbons, but there is still a debate whether its structural properties relate to a foreland basin. This controversy hinders the understanding of regional hydrocarbon plays, giving rise to this study. As a conclusion, we discovered that - it was a foreland basin in the Permian that accounted for the structural properties of the piedmont depression. The basin was generated by continuous thrusting of the Western Junggar Orogenic Belt against the Junggar-Tuha Plate. This occurred after the formation of the Western Junggar Orogenic Belt in the Carboniferous. The western basin in this study can be divided into five different zones moving from the Western Junggar Orogenic Belt to the internal plate, which are: the foreland thrust belt (the Ke-Bai and Wu-Xia thrust belts), the foreland depression (the western part of the Mahu Sag), the foreland slope (the eastern part of the Mahu Sag), the forebulge (the Dabasong Uplift), and the back-bulge basin (the Western Pen 1 Well Sag). Based on the characteristics of geological structure, and the sedimentary strata of the western Junggar Basin, the evolution of the basin was split into two distinctive stages: the Permian development stage and the Mesozoic-Cenozoic burial stage. Throughout the entire process three suites of hydrocarbon source rocks were developed, regional seal rocks, and four types of trap and reservoir assemblages. The western Junggar Basin should be considered as a typical petroliferous foreland basin.",2,2,4
Source Rocks,Junggar Basin,"Jiang, Wenlong; Imin, Ablimit; Wang, Xueyong; Wang, Tao; Guo, Wenjian","Geochemical characterization and quantitative identification of mixed-source oils from the Baikouquan and Lower Wuerhe Formations in the eastern slope of the Mahu Sag, Junggar Basin, NW China",Mixed oil; Chemometrics; Alternating least square; Mahu sag; Junggar basin,LOWER INDUS BASIN; CRUDE OILS; PETROLEUM GEOCHEMISTRY; CRETACEOUS ROCKS; TARIM BASIN; FIELD; ORIGIN,"The quantitative identification of mixed-source oil is a popular yet difficult topic in current petroleum geochemistry research. The mixed-source oils of the Baikouquan and Lower Wuerhe formations in the eastern slope of the Mahu Sag of Junggar Basin were used as a typical example in this study. Quantitative research on mixed oils was carried out in the study area and good results were obtained using an approach combining organic geochemistry and chemometrics. The results of crude oil geochemistry research show that mixed-source crude oil is ubiquitous in the study area. After comprehensive analysis, it is likely that there are three endmembers in the current mixed-source oils. Two of the endmembers may represent mainly the contribution of the early and late source rocks of the Permian Fengcheng Formation and are dominated by late filled crude oil. However, the third endmember is quite different. Its hydrocarbons may have come from the source rocks of the Permian Lower Wuerhe Formation or the source rocks of the Fengcheng Formation under different lithofacies and sedimentary environments. The study area is dominated by hydrocarbons that accumulated from the Fengcheng Formation. Although the proportion of hydrocarbons generated in the late stage is not high, it plays a very important role in hydrocarbon migration and accumulation. This comprehensive comparative study shows that the chemometric method can play an important role in calculating the proportion of mixed-source oil and in endmember analysis.",2,2,0
Source Rocks,Junggar Basin,"Ma, Ling; Zhang, Yang; Zhang, Zhihuan; Zhang, Guanlong; Wang, Shengzhu","The geochemical characteristics of the Fengcheng Formation source rocks from the Halaalate area, Junggar Basin, China",Lacustrine source rock; Biomarkers; Stable carbon isotopes; Organic geochemistry; Fengcheng Formation; Junggar Basin,LACUSTRINE SOURCE ROCKS; PERMIAN LUCAOGOU FORMATION; PHOTIC ZONE EUXINIA; BOHAI BAY BASIN; ORGANIC-MATTER; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; PETROGRAPHIC CHARACTERISTICS; DONGYING DEPRESSION; PETROLEUM SYSTEMS,"The organic-rich sediments of the Fengcheng Formation in the Halaalate area, Junggar Basin, China are important source rocks and significant tight oil exploration targets. However, their geochemical characteristics have not been well documented. The hydrocarbon generation potential, genetic type of kerogen, organic matter (OM) sources, depositional conditions, and thermal maturity have been investigated based on a sample set of 11 mudstones. These source rock samples represent good to very good hydrocarbon generation potential, and primarily contain type I to II kerogen. The major organic input sources to the Fengcheng Formation from algae and bacteria were identified using stable carbon isotopes and biomarkers. Limited higher plant input can be inferred from trace amount of terrigenous OM biomarkers and minor contents of vitrinites and inertinites. The Fengcheng sediments were deposited under hypersaline and anoxic environments. Paleoclimate was arid during the deposition of the Fengcheng Formation. The presence of evaporites, mineral-bituminous gmundmasses (MBG), alginites and microbial mats also supports these conclusions about depositional environments and biological source. The OM enrichment in the studied samples are attributed to the reducing environments, the booming of algae and the important bacterial contribution. Vitrinite reflectance and T max suggest a low thermal maturity of the studied Fengcheng sediments, in agreement with maturity-related hopane and sterane ratios and detection of hop-17(21)-enes. In a consideration of the quantity, quality and maturity of OM and their large thickness, the Fengcheng sediments have a good petroleum exploration potential.",1,1,7
Source Rocks,Junggar Basin,"Li, Shunming; Han, Rubing; Du, Yijing; Liu, Pengcheng; Bie, Hanyu","Quantitative characterization of diagenetic reservoir facies of the Karamay alluvial fan in the Junggar Basin, western China",Alluvial fan; Reservoir architecture; Diagenesis intensity; Diagenetic reservoir facies (DRFs); Quantitative prediction; Conglomeratic reservoirs,PERMIAN LUCAOGOU FORMATION; SANDSTONE RESERVOIRS; SOURCE ROCKS; QUALITY; CARBONATE; GEOCHEMISTRY; PREDICTION; FIELD; SAG; IDENTIFICATION,"The distribution of the remaining oil in developed oilfields is primarily influenced by the existing diagenetic reservoir facies (DRFs), which encompass the effects of both the sedimentary environment and the local diagenetic processes on the reservoir quality. We divided the Lower Karamay Formation reservoir samples into nine DRFs according to characteristics such as porosity, permeability, diagenetic intensity, and rock type. After applying the sequential indicator simulation methodology, we were able to create three-dimensional (3D) geological models of the DRFs. Based on these models, we can see that, during phases A and B of eodiagenesis, the prevailing DRF is a sandstone/sandy conglomerate that is moderately to weakly dissolved, moderately cemented, and characterized by moderate porosity and permeability values. The highest quality DRF, which emerged during the early stage of mesodiagenesis, is a sandstone/sandy conglomerate that is weakly compacted/cemented, moderately-to-strongly dissolved, and characterized by very high porosity and permeability values. By providing high-quality analyses of the DRFs in Block 6 of the Karamay oilfield, we provided vital information that allowed the operation to more efficiently target and extract oil from reservoir units that are already in production.",1,1,3
Source Rocks,Depositional Environment,"Zhang, Xinlei; Gao, Zhiqian; Fan, Tailiang; Xue, Jianqin; Li, Wenhuan; Zhang, Heng; Cao, Fangda","Element geochemical characteristics, provenance attributes, and paleosedimentary environment of the Paleogene strata in the Lenghu area, northwestern Qaidam Basin",Paleosedimentary environment; Provenance; Trace element geochemistry; Qaidam basin; Paleogene sedimentary period,ORDOS BASIN; DEPOSITIONAL ENVIRONMENT; NORTHERN MARGIN; BLACK SHALES; SOUTH CHINA; SEA; EVOLUTION; BEHAVIOR; PROXIES; KANSAS,"The Lenghu area is a key exploration block in the northwestern Qaidam Basin. Due to the low exploration level, the provenance and paleosedimentary environment of the Paleogene strata is not clear. Based on the major and trace element contents and the carbon and oxygen isotopes of 547 samples collected from the Paleogene strata (E-3(2), E-3(1), and E1+2), this study investigated the provenance attributes and paleosedimentary environment of the entire Paleogene period. The samples from the Paleogene strata have relatively low contents of SiO2 (39.75%-61.81%) and Al2O3 (6.23%-20.48%) and high contents of La, Sc, and Co (223.07 ppm, 273.84 ppm, and 325.45, respectively). Moreover, the La-Th-Sc, Ti/Zr-La/Sc and SiO2-K2O/Na2O discrimination diagrams suggest that the tectonic environment of the provenance is an oceanic island arc. The Co/Th-La/Sc and Zr/TiO2-(V + Ni + Cr)/Al2O3 diagrams indicate that the provenance lithology of the study area is mafic rocks with a high degree of weathering. These results imply that the source rocks of the Paleogene strata are the mafic submarine volcanic rocks of the Tanjianshan group in the Saishiteng Mountains. The Sr/Cu, Sr/Rb, and Mg/Ca indexes indicate that the paleosedimentary environment had a humid climate with a trend of slight aridity. The Sr/Ba and Rb/K ratios and the isotope coefficient Z (calculated by carbon and oxygen isotopes) indicate that the paleosalinity of the water body was predominantly fresh water with a salty trend from the Early to the Late Paleogene. The paleoredox environment during the Paleogene sedimentation was relatively oxidized with a reduction trend based on the V/(V + Ni) and V/Cr values. This combined with the trend of increasing paleosalinity suggests that there was a relatively large lake transgression in the Late Paleogene.",3,3,1
Source Rocks,Depositional Environment,"Wang, Qi; Hao, Fang; Xu, Changgui; Zou, Huayao","Paleolimnological environments and the formation of high quality source rocks in the Bohai Bay Basin: An integrated geochemical study of biomarkers, stable carbon and oxygen isotopes, and trace elements",Source rocks; Biomarkers; Carbon isotopic compositions; Bohai Bay basin (BBB),LACUSTRINE SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; SHIJIUTUO UPLIFT; ORGANIC-MATTER; EVAL PYROLYSIS; LIAODONG BAY; LAKE; PETROLEUM; EVOLUTION,"Fourteen Paleogene rock samples from the Bohai Bay Basin, including samples from the third member of the Oligocene Dongying Formation (Ed(3)) and the third member of the Eocene Shahejie Formation (Es-3), underwent total organic carbon (TOC) analysis, Rock-Eval pyrolysis, stable carbon (delta C-13(carb)) and oxygen isotope (delta O-18(carb)) analysis of carbonates, stable carbon isotope analysis of organic matter (delta C-13(om)), biomarker and trace element compositional analysis to reconstruct paleolimnological environments and investigate the factors that control the occurrence of high quality source rocks. The Rock-Eval and TOC results revealed that the source rocks meet the standard for good to excellent source rocks. The biomarker parameters and trace elements suggest that warm and humid paleolimnological conditions prevailed during the deposition of Es-3. In addition, heavier values of delta C-13(om) and light values of delta O-18(carb) indicate the existence of a hydrologically open paleolake with high primary productivity, which is supported by relatively high 4-methyl sterane index values and high barium/calcium (Ba/Ca) ratios. Ed(3) rocks formed under less reducing and more acidic conditions, which is supported by high pristane/phytane, C-27 diasteranes/C-27 regular steranes and kaolinite/illite ratios and low strontium/barium (Sr/Ba) and vanadium/chromium (V/Cr) ratios. Moreover, Ed(3) is characterized by a relatively high input of terrestrial organic matter under humid but cooler settings. A long-term positive shift of delta O-18(carb) revealed by the Ed(3) samples is associated with changes in oxygen isotopic composition of inflow water (higher precipitation) and temperature (colder). The conditions of both high productivity and enhanced preservation controlled the distribution of good source rocks in the Bohai Bay Basin (BBB). Es-3 is more likely linked with high primary productivity, which resulted in an overall positive shift in delta C-13(om), whereas Ed(3y) may be more related to favourable preservation conditions associated with relatively high sedimentation rates.",2,3,3
Source Rocks,Depositional Environment,"Adeoye, James A.; Akande, Samuel O.; Adekeye, Olabisi A.; Sonibare, Wasiu A.; Ondrak, Robert; Dominik, Wilhelm; Erdtmann, Bernd D.; Neeka, Jacob",Source rock maturity and petroleum generation in the Dahomey Basin SW Nigeria: Insights from geologic and geochemical modelling,,THERMAL HISTORY; BENUE TROUGH; HEAT-FLOW; MATURATION; EVOLUTION; KINETICS,"Sedimentology, foraminifera paleoecology, geochemical and petroleum system modelling studies were performed on Cretaceous shales from onshore Orimedu-1 and offshore X (at a water depth of 914 m) wells in the Dahomey Basin, southwestern Nigeria to evaluate their maturity, hydrocarbon generation potentials, and regional significance for petroleum prospectivity. Foraminifera biofacies analysis of the studied shales suggests deposition in dominantly marine environments. The average total organic carbon content (TOC, wt%) and hydrogen index (HI, mgHC/gTOC) for Cenomanian, Turonian, and Coniacian shales in X-well are 1.3, 0.9, 1.3 and 406, 560, 214 respectively. While the Cenomanian and Turonian shales in Orimedu-1 have TOC (wt%) of 1.3 and 1.9, and HI (mgHC/gTOC) of 179 and 357 respectively. Well X source rocks contain predominantly marine-derived Type II kerogen, while Orimedu-1 well contain terrigenous-derived gas prone kerogen. The integration of recently acquired kinetic data from immature source rocks further constraints the prediction of petroleum generation in the study area.1D basin modelling of X well reveals that the Cenomanian Source Rock (CSR) is the most mature bed in the basin having attained the initial 10% transformation ratio (TR) at 87 Ma, got to peak TR (similar to 50%) at 86 Ma, and reached 83% at 53.6 Ma With a present-day thermal maturity of 0.95% VRo. The Turonian source in well X also attained the initial 10% TR at 87 Ma, got to peak (similar to 50% TR) at 86 Ma and 69% TR at 50 Ma. These modelled source beds are deeper than the source with 0.62 %VRo used for kinetic study. The observed maturity trend is mostly controlled by the regional erosive events associated with the West African rift system during Santonian and Eocene times. The source rocks in Orimedu-1 are immature. The timing of the generated and expelled hydrocarbons into the Cretaceous petroleum systems of Dahomey Basin is of regional significance with the entire Gulf of Guinea basins because of the similar evolution and sedimentation history along with recent discoveries and production of hydrocarbon.",2,2,2
Source Rocks,Depositional Environment,"Ma, Ling; Zhang, Yang; Zhang, Zhihuan; Zhang, Guanlong; Wang, Shengzhu","The geochemical characteristics of the Fengcheng Formation source rocks from the Halaalate area, Junggar Basin, China",Lacustrine source rock; Biomarkers; Stable carbon isotopes; Organic geochemistry; Fengcheng Formation; Junggar Basin,LACUSTRINE SOURCE ROCKS; PERMIAN LUCAOGOU FORMATION; PHOTIC ZONE EUXINIA; BOHAI BAY BASIN; ORGANIC-MATTER; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; PETROGRAPHIC CHARACTERISTICS; DONGYING DEPRESSION; PETROLEUM SYSTEMS,"The organic-rich sediments of the Fengcheng Formation in the Halaalate area, Junggar Basin, China are important source rocks and significant tight oil exploration targets. However, their geochemical characteristics have not been well documented. The hydrocarbon generation potential, genetic type of kerogen, organic matter (OM) sources, depositional conditions, and thermal maturity have been investigated based on a sample set of 11 mudstones. These source rock samples represent good to very good hydrocarbon generation potential, and primarily contain type I to II kerogen. The major organic input sources to the Fengcheng Formation from algae and bacteria were identified using stable carbon isotopes and biomarkers. Limited higher plant input can be inferred from trace amount of terrigenous OM biomarkers and minor contents of vitrinites and inertinites. The Fengcheng sediments were deposited under hypersaline and anoxic environments. Paleoclimate was arid during the deposition of the Fengcheng Formation. The presence of evaporites, mineral-bituminous gmundmasses (MBG), alginites and microbial mats also supports these conclusions about depositional environments and biological source. The OM enrichment in the studied samples are attributed to the reducing environments, the booming of algae and the important bacterial contribution. Vitrinite reflectance and T max suggest a low thermal maturity of the studied Fengcheng sediments, in agreement with maturity-related hopane and sterane ratios and detection of hop-17(21)-enes. In a consideration of the quantity, quality and maturity of OM and their large thickness, the Fengcheng sediments have a good petroleum exploration potential.",1,1,7
Source Rocks,Depositional Environment,"Han, Qiuya; Li, Meijun; Liu, Xiaoqiang; Jiang, Weidong; Shi, Shengbao; Tang, Youjun; He, Daxiang",Fractionation of alkylated carbazoles in petroleum during subsurface migration: Evidence from molecular simulation and application in sandstone reservoirs,Geo-chromatographic fractionation; Alkylcarbazole; Petroleum migration orientation; Molecular dynamics simulation; Sandstone reservoir,CHROMATOGRAPHIC SEPARATION SCHEMES; AROMATIC HETEROCYCLE FRACTIONS; PYRROLIC NITROGEN-COMPOUNDS; IN-SOURCE ROCKS; CRUDE OILS; BEIBUWAN BASIN; BENZOCARBAZOLE DISTRIBUTIONS; RAPID CHARACTERIZATION; DYNAMICS SIMULATION; ORGANIC-COMPOUNDS,"Carbazole (CA) and alkylated carbazoles are common nitrogen-containing heterocyclic aromatic compounds widely found in crude oils and sedimentary rocks extracts. Their geochemical significances in petroleum exploration have been widely investigated in previous studies. Using density functional theory (DFT) and molecular dynamics (MD) simulation, we calculated the polarity of alkylated carbazole isomers/homologues and their adsorption energy with water and alpha-quartz, respectively. The calculated results show that there are significant differences in migration fractionation effects for alkylated carbazole isomers/homologues. This study confirmed the validity of previously proposed carbazole migration indicators, i.e. 4-/1-MCA (the relative abundance of 4-methylcarbazole to 1-methylcarbazole), 2,5-/1,8-DMCA (2,5-dimethylcarbazole to 1,8-dimethylcarbazole) and 2,4-/1,8-DMCA (2,4-dimethylcarbazole to 1,8-dimethylcarbazole) on the basis of quantum chemistry and molecular simulation. All these three parameters have been successfully applied in a lacustrine sandstone reservoir in the Fushan Depression, Beibuwan Basin (South China Sea). The calculations of Gibbs free energy show that the differences in thermal stability between the isomers of alkylcarbazoles can be negligible. The source input and depositional environment have no significant effect on these indicators for oils from a same oil family. Hence, the values of these parameters are mainly controlled by subsurface petroleum migration processes. Therefore, the molecular parameters relative to alkylated carbazoles can be used as practically effective geochemical markers to trace the oil filling orientation and pathways for subsurface oil migration.",1,2,6
Source Rocks,Depositional Environment,"Yang, Shangru; Gao, Gang; Liu, Yong; Gang, Wenzhe; Dang, Wenlong","Organic geochemistry and petrographic characteristics of the shales from the Late Miocene Zeit Formation in the Tokar area, Red Sea Basin: Implications for depositional environment and hydrocarbon potential",Geochemistry; Depositional environment; Shale; Organic petrography; Biomarker; Red sea basin,SOURCE-ROCK; PETROLEUM; MATTER,"According to the geochemistry, organic petrography, stable carbon isotopic compositions and biomarker analyses of the Late Miocene Zeit Formation shale samples in the Tokar area, Red Sea Basin, the paleoenvironment and hydrocarbon-generating potential were analyzed. The Zeit Formation shales from the Wells S. Suakin-1 and Tokar-1 contain mostly Type III kerogens with minor Type II organic matter (OM), indicating more favorable gasgenerating potential. OM of the shale samples from the Late Miocene Zeit Formation are predominantly of terrigenous higher plants. Kerogens from the Well Tokar-1 show abundant brown liptinites, indicating the mixed origin of planktonic/bacterial and terrigenous OM. The Late Miocene Zeit Formation was deposited in dysoxic/ suboxic, reducing and salt water environments. According to the results of Tmax, Ro and biomarker maturity parameters, the most shale samples from the Zeit Formation are in early mature to mature stages. The shales from the Late Miocene Zeit Formation are generally fair to good source rock. The shales from wells Suakin-2, Talla-2 and Tokar-1 have high hydrocarbon-generating potential.",1,1,1
Source Rocks,NW China,"Su, Long; Zhang, Dongwei; Zheng, Lunju; Liu, Xingwang; Yang, Xin; Zheng, Jianjing; Liu, Peng",Experimental study of the influences of pressure on generation and expulsion of hydrocarbons: A case study from mudstone source rocks and its geological application in the Tarim Basin,Lithostatic stress; Fluid pressure; Liquid hydrocarbon generation; Expulsion efficiencies; Pressured experiments,ORGANIC-MATTER MATURATION; THERMAL-CRACKING; NW CHINA; OIL GENERATION; PALEOZOIC OIL; KINETIC-MODEL; RETARDATION; TEMPERATURE; WATER; PYROLYSIS,"Generally, pressure, temperature, depth of organic matter/kerogen burial and organic and inorganic matter interactions can influence the hydrocarbon generation process. However, different understandings were proposed to interpret the role of pressure in hydrocarbon generation. Meanwhile, previous investigations of the influence of pressure on hydrocarbons generation are mainly focused on fluid pressure (FP), only a few work was involved in the effect of lithostatic stress (LS) due to the limitation of experimental techniques. In this study, simulation experiments were conducted to investigate the influence of pressure, including lithostatic stress (LS) and fluid pressure (FP) on yield and process of hydrocarbon generation by a modified simulation instrument. Two systematic comparative pyrolysis experiments, including pressured experiments with LP range from 27.6 to 179.4 MPa and FP range from 12.0 to 109.2 MPa, and non-pressured experiments with LP for 6.0 MPa and FP range from 2.0 to 5.0 MPa were conducted in hydrous experimental condition. The results show that the peak yields of the expelled oil and the liquid hydrocarbons in pressured experiments and non-pressured experiments are 42.48 mg/g.TOC, 52.00 mg/g.TOC, 70.14 mg/g.TOC, and 72.15 mg/g.TOC, respectively. And Ro, ratio of the expelled oil to eluted oil, the accumulated yield of the expelled oil and liquid hydrocarbons, are lower in pressured experiments than that of non-pressured experiments. However, the accumulated yields of eluted oil and residual oil are higher in pressured experiments than that of non-pressured experiments. Additionally, the expulsion efficiencies of the oil range from 20% to 25%, which are lower in pressured experiments than that of non-pressured experiments near the oil generation-window. In addition, the yields of hydrocarbon gas in pressured experiments are greater compared to the yields in non-pressured experiments at the high maturity stage. Based on the experimental results, hydrocarbon generation process can be divided into three stages. Generally, LS and FP could retard the process of mudstone maturation as well as the generation and expulsion of the liquid hydrocarbons. Hence, the residual liquid hydrocarbons in high-pressure condition can act as another source of natural gas generation in the high maturity stage. The results could help us to properly evaluate hydrocarbon generation potentials of sources rocks at petroleum-producing sedimentary basins in China and elsewhere.",2,2,7
Source Rocks,NW China,"Imin, Ablimiti; Zha, Ming; Ding, Xiujian; Bian, Baoli; Liu, Yin; Zheng, Mengling; Han, Chao",Identification of a Permian foreland basin in the western Junggar Basin (NW China) and its impact on hydrocarbon accumulation,Foreland basin; Permian; Structural evolution; Hydrocarbon play; Western junggar basin,GEOCHEMICAL CHARACTERISTICS; PETROLEUM SYSTEMS; NATURAL GASES; ND; XINJIANG; MODELS; GRANITOIDS; TECTONICS; MAGMATISM; EVOLUTION,"The piedmont depression in the western Junggar Basin is a typical large-scale thrust belt rich in hydrocarbons, but there is still a debate whether its structural properties relate to a foreland basin. This controversy hinders the understanding of regional hydrocarbon plays, giving rise to this study. As a conclusion, we discovered that - it was a foreland basin in the Permian that accounted for the structural properties of the piedmont depression. The basin was generated by continuous thrusting of the Western Junggar Orogenic Belt against the Junggar-Tuha Plate. This occurred after the formation of the Western Junggar Orogenic Belt in the Carboniferous. The western basin in this study can be divided into five different zones moving from the Western Junggar Orogenic Belt to the internal plate, which are: the foreland thrust belt (the Ke-Bai and Wu-Xia thrust belts), the foreland depression (the western part of the Mahu Sag), the foreland slope (the eastern part of the Mahu Sag), the forebulge (the Dabasong Uplift), and the back-bulge basin (the Western Pen 1 Well Sag). Based on the characteristics of geological structure, and the sedimentary strata of the western Junggar Basin, the evolution of the basin was split into two distinctive stages: the Permian development stage and the Mesozoic-Cenozoic burial stage. Throughout the entire process three suites of hydrocarbon source rocks were developed, regional seal rocks, and four types of trap and reservoir assemblages. The western Junggar Basin should be considered as a typical petroliferous foreland basin.",2,2,4
Source Rocks,NW China,"Wu, Nan; Wang, Jian; Cai, Zhongxian; Luo, Zhong; Lu, Xuesong; Ma, Xingzhi; Liu, Xianfeng","Discovery of Sinian source rocks in proterozoic in the Tarim Basin, NW China",Tarim basin; Kuruktag; Sinian source rocks; Hydrocarbon generation; Bitumen,ORGANIC-MATTER; CRUDE OILS; MATURITY PARAMETERS; THERMAL MATURITY; SICHUAN BASIN; GEOCHEMICAL CHARACTERISTICS; TRICYCLIC TERPANES; VELKERRI FORMATION; MCARTHUR BASIN; GRAND-CANYON,"As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50-60 degrees C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin.",2,2,3
Source Rocks,NW China,"Jiang, Wenlong; Imin, Ablimit; Wang, Xueyong; Wang, Tao; Guo, Wenjian","Geochemical characterization and quantitative identification of mixed-source oils from the Baikouquan and Lower Wuerhe Formations in the eastern slope of the Mahu Sag, Junggar Basin, NW China",Mixed oil; Chemometrics; Alternating least square; Mahu sag; Junggar basin,LOWER INDUS BASIN; CRUDE OILS; PETROLEUM GEOCHEMISTRY; CRETACEOUS ROCKS; TARIM BASIN; FIELD; ORIGIN,"The quantitative identification of mixed-source oil is a popular yet difficult topic in current petroleum geochemistry research. The mixed-source oils of the Baikouquan and Lower Wuerhe formations in the eastern slope of the Mahu Sag of Junggar Basin were used as a typical example in this study. Quantitative research on mixed oils was carried out in the study area and good results were obtained using an approach combining organic geochemistry and chemometrics. The results of crude oil geochemistry research show that mixed-source crude oil is ubiquitous in the study area. After comprehensive analysis, it is likely that there are three endmembers in the current mixed-source oils. Two of the endmembers may represent mainly the contribution of the early and late source rocks of the Permian Fengcheng Formation and are dominated by late filled crude oil. However, the third endmember is quite different. Its hydrocarbons may have come from the source rocks of the Permian Lower Wuerhe Formation or the source rocks of the Fengcheng Formation under different lithofacies and sedimentary environments. The study area is dominated by hydrocarbons that accumulated from the Fengcheng Formation. Although the proportion of hydrocarbons generated in the late stage is not high, it plays a very important role in hydrocarbon migration and accumulation. This comprehensive comparative study shows that the chemometric method can play an important role in calculating the proportion of mixed-source oil and in endmember analysis.",2,2,0
Source Rocks,NW China,"Li, Jingfei; Zhang, Zhiyao; Zhu, Guangyou; Li, Tingting; Zhao, Kun; Chi, Linxian; Yan, Huihui","The origin and accumulation of ultra-deep oil in Halahatang area, northern Tarim Basin",Giant oil accumulations; Ultra-deep strata; GCxGC-TOFMS; Halahatang area; Tarim basin,TABEI UPLIFT; NW CHINA; HYDROCARBON ACCUMULATION; DIAMONDOID HYDROCARBONS; THERMAL-CRACKING; CRATONIC REGION; TAZHONG AREA; NATURAL-GAS; CRUDE OILS; PETROLEUM,"The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000-8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.",1,2,0
Source Rocks,Bohai Bay Basin,"Wang, Qi; Hao, Fang; Xu, Changgui; Zou, Huayao","Paleolimnological environments and the formation of high quality source rocks in the Bohai Bay Basin: An integrated geochemical study of biomarkers, stable carbon and oxygen isotopes, and trace elements",Source rocks; Biomarkers; Carbon isotopic compositions; Bohai Bay basin (BBB),LACUSTRINE SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; SHIJIUTUO UPLIFT; ORGANIC-MATTER; EVAL PYROLYSIS; LIAODONG BAY; LAKE; PETROLEUM; EVOLUTION,"Fourteen Paleogene rock samples from the Bohai Bay Basin, including samples from the third member of the Oligocene Dongying Formation (Ed(3)) and the third member of the Eocene Shahejie Formation (Es-3), underwent total organic carbon (TOC) analysis, Rock-Eval pyrolysis, stable carbon (delta C-13(carb)) and oxygen isotope (delta O-18(carb)) analysis of carbonates, stable carbon isotope analysis of organic matter (delta C-13(om)), biomarker and trace element compositional analysis to reconstruct paleolimnological environments and investigate the factors that control the occurrence of high quality source rocks. The Rock-Eval and TOC results revealed that the source rocks meet the standard for good to excellent source rocks. The biomarker parameters and trace elements suggest that warm and humid paleolimnological conditions prevailed during the deposition of Es-3. In addition, heavier values of delta C-13(om) and light values of delta O-18(carb) indicate the existence of a hydrologically open paleolake with high primary productivity, which is supported by relatively high 4-methyl sterane index values and high barium/calcium (Ba/Ca) ratios. Ed(3) rocks formed under less reducing and more acidic conditions, which is supported by high pristane/phytane, C-27 diasteranes/C-27 regular steranes and kaolinite/illite ratios and low strontium/barium (Sr/Ba) and vanadium/chromium (V/Cr) ratios. Moreover, Ed(3) is characterized by a relatively high input of terrestrial organic matter under humid but cooler settings. A long-term positive shift of delta O-18(carb) revealed by the Ed(3) samples is associated with changes in oxygen isotopic composition of inflow water (higher precipitation) and temperature (colder). The conditions of both high productivity and enhanced preservation controlled the distribution of good source rocks in the Bohai Bay Basin (BBB). Es-3 is more likely linked with high primary productivity, which resulted in an overall positive shift in delta C-13(om), whereas Ed(3y) may be more related to favourable preservation conditions associated with relatively high sedimentation rates.",2,3,3
Source Rocks,Bohai Bay Basin,"Zhu, Chuanzhen; Gang, Wenzhe; Zhao, Xianzheng; Wang, Yifan; Chen, Guo; Pu, Xiugang","The preferential pathways of oil migration in the Qi-nan slope belt of Bohai Bay Basin, China: Insights from integrated analyses using geochemical and morphology tools",Oil family; Pyrrolic nitrogen compounds; Geochemical tracing of hydrocarbon migration; Preferential migration pathways; Qi-nan slope belt; Bohai Bay Basin,PYRROLIC NITROGEN-COMPOUNDS; PETROLEUM MIGRATION; HYDROCARBON MIGRATION; QIKOU SAG; BOZHONG SUBBASIN; ORDOS BASIN; CRUDE OILS; ACCUMULATION; FIELD; CONSTRAINTS,"The Qi-nan Slope belt is located in the southwestern Qikou Sag in the Bohai Bay Basin and has had relatively little oil and gas exploration. The mechanism of oil migration remains unclear due to the lack of understanding of the oil-oil relationship, the definition of oil migration pathways, and the controversy over the contributing source rocks. Based on hierarchical cluster analysis, the crude oils in the Qi-nan Slope are divided into three groups (A, B and C) with different geochemical compositions. Group A oils, including Class A(1) and Class A(2) biodegraded oils, and Group C oils are contributed by Es-1(x) and Es-3 source rocks with different organic facies, and distributions are limited to the WXZ oilfield in the western slope. Group B oils, including Class B-1 and Class B-2 biodegraded oils, mainly originated from Es-1(x) source rocks and are widely distributed in the southern slope. The significant correlation between the relative migration distance (RMD) of oils and pyrrolic nitrogen compounds, rather than the parameters related to oil maturity, indicates that the pyrrolic nitrogen compounds can effectively trace oil migration directions in the Qi-nan Slope, and 1,8-DMC/2,6-DMC is the best indicator. For oil migration conduits, no large-scale faults developed in the inner part of the slope, and the oil-gas test results from major wells on the seismic profiles suggest that oils are mostly concentrated in Es-1(x) with no obvious vertical migration in this area. Therefore, we speculate that the Es-1(x) sand body provided the migration pathway for crude oil and controlled its uneven accumulation in the slope area. The isopleth map of the 1,8-DMC/2,6-DMC ratio, the distribution characteristics of the oil test results from major wells and the morphology of the Es-1(x) transporting layer suggest that the overall migration direction of oil was dispersedly from the Qi-nan Sub-sag to the southern areas of the slope and that structural ridges provided preferential migration pathways for hydrocarbon accumulation.",2,2,2
Source Rocks,Bohai Bay Basin,"Song, Jianyang; Huo, Zhipeng; Fu, Guang; Hu, Ming; Sun, Tongwen; Liu, Zhe; Wang, Wei; Liu, Luofu","Petroleum migration and accumulation in the Liuchu area of Raoyang Sag, Bohai Bay Basin, China",Biomarkers; Migration and accumulation modeling; Migration direction; Physical characteristics of crude oil; Vertical migration,HYDROCARBON MIGRATION; MOLECULAR-PARAMETERS; DONGYING DEPRESSION; NITROGEN-COMPOUNDS; TOARCIAN SHALES; SOURCE ROCKS; PARIS BASIN; OIL-FIELD; SECONDARY; DISTRIBUTIONS,"This study focused on vertical migration of petroleum in the Liuchu area, China. The physical properties of petroleum and changes in the geochemical characteristics of the study area were also investigated. Biomarkers such as, nitrogen compounds, n-alkanes, triterpenoids, steroids, hopanes, and cholestanes were analyzed in this regard. Petro-physical characteristics, such as, density, viscosity, concentrations of wax, resin, and sulfur of oil were studied. The rNa(+)/rCl(-) ratio of Ed(2) formation water ranged from 0.25 to 5.7, oil density of Ed(2) formation ranged from 0.85 to 0.95 g/cm(3), and oil resin concentration 10-50%, oil wax content in Ed(2) formation ranged from 2 to 29% were lower than that of Es1. The rNa(+)/rCl(-) ratio and mineralization of formation water data were examined to demonstrate the migration pathways. Geochemical and crude oil physical indexes were utilized to investigate the relationship between petroleum migration and seismic data. Cholestane alpha beta beta, alpha alpha alpha cholestane, diacholestane, steroid, and low ring terpenes in the formation were utilized to trace petroleum migration. Recent studies on petroleum maturity of have focused on comparison of source rocks and have reported that the maturity effects of source rock and reservoir oil are weak while those effects are high in the Liuchu aera. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The alpha alpha alpha C-29 (20S)/(20S + 20R) and C-29 (beta beta)/alpha alpha + beta beta) ratios ranged from 0.2 to 0.35 Further, C-31 (22S)/(22S + 22R), C-32(22S)/(22S + 22R), and C-29 (20S)/(20S + 20R) ratios ranged from 0.3 to 0.8, and 0.131 and 0.81, respectively. Petroleum migrated along migration channels. This suggested that vertical migration occurred after formation of the source rock fault and lateral migration occurred along the sandbody. Reservoir sandstone content, overlying mudstone content, and thickness of caprock are likely limited lateral petroleum migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The results of this study enabled optimization of uncertain petroleum migration pathways and improved the petroleum migration and accumulation model.",2,2,1
Source Rocks,Bohai Bay Basin,"Ma, Ling; Zhang, Yang; Zhang, Zhihuan; Zhang, Guanlong; Wang, Shengzhu","The geochemical characteristics of the Fengcheng Formation source rocks from the Halaalate area, Junggar Basin, China",Lacustrine source rock; Biomarkers; Stable carbon isotopes; Organic geochemistry; Fengcheng Formation; Junggar Basin,LACUSTRINE SOURCE ROCKS; PERMIAN LUCAOGOU FORMATION; PHOTIC ZONE EUXINIA; BOHAI BAY BASIN; ORGANIC-MATTER; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; PETROGRAPHIC CHARACTERISTICS; DONGYING DEPRESSION; PETROLEUM SYSTEMS,"The organic-rich sediments of the Fengcheng Formation in the Halaalate area, Junggar Basin, China are important source rocks and significant tight oil exploration targets. However, their geochemical characteristics have not been well documented. The hydrocarbon generation potential, genetic type of kerogen, organic matter (OM) sources, depositional conditions, and thermal maturity have been investigated based on a sample set of 11 mudstones. These source rock samples represent good to very good hydrocarbon generation potential, and primarily contain type I to II kerogen. The major organic input sources to the Fengcheng Formation from algae and bacteria were identified using stable carbon isotopes and biomarkers. Limited higher plant input can be inferred from trace amount of terrigenous OM biomarkers and minor contents of vitrinites and inertinites. The Fengcheng sediments were deposited under hypersaline and anoxic environments. Paleoclimate was arid during the deposition of the Fengcheng Formation. The presence of evaporites, mineral-bituminous gmundmasses (MBG), alginites and microbial mats also supports these conclusions about depositional environments and biological source. The OM enrichment in the studied samples are attributed to the reducing environments, the booming of algae and the important bacterial contribution. Vitrinite reflectance and T max suggest a low thermal maturity of the studied Fengcheng sediments, in agreement with maturity-related hopane and sterane ratios and detection of hop-17(21)-enes. In a consideration of the quantity, quality and maturity of OM and their large thickness, the Fengcheng sediments have a good petroleum exploration potential.",1,1,7
Source Rocks,Experiments,"Almetwally, Ahmed G.; Jabbari, Hadi",Finite-difference simulation of coreflooding based on a reconstructed CT scan; modeling transient oscillating and pulse decay permeability experiment,Coreflooding; Static Model; Dynamic Simulation; Transient; Permeability; Image processing,ROCK SAMPLES; FLOW; PRESSURE; OIL,"Numerical simulation and experimental research of fluid flow in porous media enhance the practices of petroleum reservoirs' management. Experiments on acquired reservoir-rock samples are conducted for accurate characterization and realization of the insitu hydrocarbon reserves. Implementing precise numerical simulation of those experiments is crucial to acquire accurate conclusions from the obtained experimental results. Coreflooding experiments quantify reservoir rock's storage capacity, measure its transport connectivity, and evaluate recovery methods' effectiveness for that rock. In this paper, a reconstruction image-processing workflow of cores' CT scan is developed to build a finite difference numerical model for simulating coreflooding experiments. In a transient coreflooding experiment, a controlled pressure pulse with a known frequency and amplitude is transmitted to the rock sample. Rock permeability can be quantified by analytically solving the diffusivity flow equation for that experiment. Simulating the transient permeability experiment is very sensitive to the level of details of the pores' structure described in the numerical model. A transient permeability experiment with two different transient modes, sinusoidal oscillation, and pulse decay, was conducted on a standard Berea core sample. The Berea CT scan was image-processed to reconstruct the static porosity and permeability model in Petrel software using a 3D variogram geostatistical population. Injection and production sources were assigned to the finite gridblock, which correspond to flow nozzles of injection and production coreflooding setup's heads. Scheduled flow and controlled-pressure boundary-conditions were imposed on the dynamic model. Eclipse simulator was used to solve the dynamic model and calculate the pressure in each gridblock. The outlet pressure was calculated at each time step by three different realization approaches for porosity and permeability, i.e., from experiments, from statistical analysis for the CT scan, and by the proposed image processing workflow. The simulated outlet pressure from the prosed workflow matched ideally, with a Pearson correlation coefficient of 0.98 and 0.99, the recorded one in the two experiments compared to underestimated or overestimated outlet pressure from the other two traditional realization approaches, i.e., statistical or experimental.",3,3,2
Source Rocks,Experiments,"Su, Long; Zhang, Dongwei; Zheng, Lunju; Liu, Xingwang; Yang, Xin; Zheng, Jianjing; Liu, Peng",Experimental study of the influences of pressure on generation and expulsion of hydrocarbons: A case study from mudstone source rocks and its geological application in the Tarim Basin,Lithostatic stress; Fluid pressure; Liquid hydrocarbon generation; Expulsion efficiencies; Pressured experiments,ORGANIC-MATTER MATURATION; THERMAL-CRACKING; NW CHINA; OIL GENERATION; PALEOZOIC OIL; KINETIC-MODEL; RETARDATION; TEMPERATURE; WATER; PYROLYSIS,"Generally, pressure, temperature, depth of organic matter/kerogen burial and organic and inorganic matter interactions can influence the hydrocarbon generation process. However, different understandings were proposed to interpret the role of pressure in hydrocarbon generation. Meanwhile, previous investigations of the influence of pressure on hydrocarbons generation are mainly focused on fluid pressure (FP), only a few work was involved in the effect of lithostatic stress (LS) due to the limitation of experimental techniques. In this study, simulation experiments were conducted to investigate the influence of pressure, including lithostatic stress (LS) and fluid pressure (FP) on yield and process of hydrocarbon generation by a modified simulation instrument. Two systematic comparative pyrolysis experiments, including pressured experiments with LP range from 27.6 to 179.4 MPa and FP range from 12.0 to 109.2 MPa, and non-pressured experiments with LP for 6.0 MPa and FP range from 2.0 to 5.0 MPa were conducted in hydrous experimental condition. The results show that the peak yields of the expelled oil and the liquid hydrocarbons in pressured experiments and non-pressured experiments are 42.48 mg/g.TOC, 52.00 mg/g.TOC, 70.14 mg/g.TOC, and 72.15 mg/g.TOC, respectively. And Ro, ratio of the expelled oil to eluted oil, the accumulated yield of the expelled oil and liquid hydrocarbons, are lower in pressured experiments than that of non-pressured experiments. However, the accumulated yields of eluted oil and residual oil are higher in pressured experiments than that of non-pressured experiments. Additionally, the expulsion efficiencies of the oil range from 20% to 25%, which are lower in pressured experiments than that of non-pressured experiments near the oil generation-window. In addition, the yields of hydrocarbon gas in pressured experiments are greater compared to the yields in non-pressured experiments at the high maturity stage. Based on the experimental results, hydrocarbon generation process can be divided into three stages. Generally, LS and FP could retard the process of mudstone maturation as well as the generation and expulsion of the liquid hydrocarbons. Hence, the residual liquid hydrocarbons in high-pressure condition can act as another source of natural gas generation in the high maturity stage. The results could help us to properly evaluate hydrocarbon generation potentials of sources rocks at petroleum-producing sedimentary basins in China and elsewhere.",2,2,7
Source Rocks,Experiments,"Zheng, Dingye; Pang, Xiongqi; Zhou, Liming; You, Xincai; Liu, Xiaohan; Guo, Fangxin; Li, Wei","Critical conditions of tight oil charging and determination of the lower limits of petrophysical properties for effective tight reservoirs: A case study from the Fengcheng Formation in the Fengcheng area, Junggar Basin",Tight oil; Effective tight reservoir; Lower limits of petrophysical properties; Dynamic mechanism; Junggar basin,TRIASSIC YANCHANG FORMATION; LUCAOGOU FORMATION; SOURCE ROCKS; JIMUSAR SAG; HYDROCARBON GENERATION; RESEARCH PROGRESS; SONGLIAO BASIN; ORDOS BASIN; CHANG 7; CHINA,"Studying the lower limits of petrophysical properties is important to evaluate the exploration and development potentials of tight oil reservoirs. At present, the evaluation criteria are based on a large number of cores and logging data, and rules are based on collections of empirical statistics and displacement pressure experiments. However, there have been few studies on the lower limits of the petrophysical properties of tight reservoirs based on force balance conditions for the hydrocarbon charging process. In this paper, the critical condition for hydrocarbon charging is determined using the oil expansion pressure as the main driving force, with the capillary pressure as the major resistance, via an analysis of the dynamic mechanism of tight oil reservoirs. A force-balance model for judging the lower limits of the petrophysical properties of tight reservoirs can be established by assuming that the oil expansion pressure is equal to the capillary force. This discriminant method is applied to calculate the critical pore-throat radius of the effective reservoirs of the Lower Permian Fengcheng Formation in the Fengcheng area, Junggar Basin, which are 0.310 mu m, 0.248 mu m, 0.208 mu m, and 0.135 mu m, when the buried depths are 2500-3000 m, 3000-3500 m, 3500-4000 m, and 4000-4500 m, respectively. The corresponding critical porosities are 6.15%, 4.84%, 3.81%, and 1.20%, respectively. The lower limits of the petrophysical properties of effective tight reservoirs gradually decrease with increasing burial depth. This method is of great significance for resource evaluations of tight oil reservoirs and the selection of exploration zones.",2,2,6
Source Rocks,"Trace Element,Oxygen Isotope","Zhang, Xinlei; Gao, Zhiqian; Fan, Tailiang; Xue, Jianqin; Li, Wenhuan; Zhang, Heng; Cao, Fangda","Element geochemical characteristics, provenance attributes, and paleosedimentary environment of the Paleogene strata in the Lenghu area, northwestern Qaidam Basin",Paleosedimentary environment; Provenance; Trace element geochemistry; Qaidam basin; Paleogene sedimentary period,ORDOS BASIN; DEPOSITIONAL ENVIRONMENT; NORTHERN MARGIN; BLACK SHALES; SOUTH CHINA; SEA; EVOLUTION; BEHAVIOR; PROXIES; KANSAS,"The Lenghu area is a key exploration block in the northwestern Qaidam Basin. Due to the low exploration level, the provenance and paleosedimentary environment of the Paleogene strata is not clear. Based on the major and trace element contents and the carbon and oxygen isotopes of 547 samples collected from the Paleogene strata (E-3(2), E-3(1), and E1+2), this study investigated the provenance attributes and paleosedimentary environment of the entire Paleogene period. The samples from the Paleogene strata have relatively low contents of SiO2 (39.75%-61.81%) and Al2O3 (6.23%-20.48%) and high contents of La, Sc, and Co (223.07 ppm, 273.84 ppm, and 325.45, respectively). Moreover, the La-Th-Sc, Ti/Zr-La/Sc and SiO2-K2O/Na2O discrimination diagrams suggest that the tectonic environment of the provenance is an oceanic island arc. The Co/Th-La/Sc and Zr/TiO2-(V + Ni + Cr)/Al2O3 diagrams indicate that the provenance lithology of the study area is mafic rocks with a high degree of weathering. These results imply that the source rocks of the Paleogene strata are the mafic submarine volcanic rocks of the Tanjianshan group in the Saishiteng Mountains. The Sr/Cu, Sr/Rb, and Mg/Ca indexes indicate that the paleosedimentary environment had a humid climate with a trend of slight aridity. The Sr/Ba and Rb/K ratios and the isotope coefficient Z (calculated by carbon and oxygen isotopes) indicate that the paleosalinity of the water body was predominantly fresh water with a salty trend from the Early to the Late Paleogene. The paleoredox environment during the Paleogene sedimentation was relatively oxidized with a reduction trend based on the V/(V + Ni) and V/Cr values. This combined with the trend of increasing paleosalinity suggests that there was a relatively large lake transgression in the Late Paleogene.",3,3,1
Source Rocks,"Trace Element,Oxygen Isotope","Huo, Fei; Wang, Xingzhi; Wen, Huaguo; Xu, Wenli; Huang, Huiwen; Jiang, Huachuan; Li, Yawen; Li, Bo","Genetic mechanism and pore evolution in high quality dolomite reservoirs of the Changxing-Feixianguan Formation in the northeastern Sichuan Basin, China",Carbon oxygen isotope; Major and trace elements; Source of diagenetic fluid; Mechanism of dolomitization; Diagenesis-pore evolution,NE SICHUAN; HYDROTHERMAL DOLOMITE; ISOTOPE COMPOSITION; EASTERN SICHUAN; BURIAL DOLOMITIZATION; CARBONATE SUCCESSIONS; GAS-RESERVOIRS; JIANNAN AREA; DIAGENESIS; PLATFORM,"The marine carbonate rock in the Changxing-Feixianguan Formation of Xuanhan-Daxian area, northeastern Sichuan, the Sichuan Basin holds abundant natural gas resource, where the dolomite includes two types, the one with original texture (grain dolomite, reef dolomite) and the one without original texture (idiomorphic to anhedral-crystal dolomite, porphyritic dolomite). The analysis on the isotopes of C, O, Sr and other geochemical features shows that the dolomitizing process happened in fluid rich in Mg2+ and lean in Ca2+ and brought in Fe2+, Mn2+ and took out Sr2+; with the rise of recrystallization, the Fe2+ , Mn2+ contents tend to increase while delta O-18(PDB) and Srcontent tend to decrease. According to the variation of Sr-87/Sr-86 and other geochemical features, it is considered that the dolomitizing fluid participating in the reservoir diagenesisis the high salinity sea water later than the end of Feixianguan stage, and the dolomitization takes place mainly through the multiple thermal convective cycle effect. The micritic dolomite is of evaporative dolomitization origin with the characteristics of high Sr2+, Na+ and low Mn2+ which reflects the open environment of the surface exposed in the quasi syngenetic period, while the reef dolomite is of high Mg/Ca dolomitizing fluid origin with the characteristics of low Sr-2 , Na+ and Mn2+, whose diagenetic environment changed from near surface to shallow burial environment; crystalline dolomite is formed by metasomatism of low Mg/Ca dolomitizing fluid at deep burial depth and high temperature, with the increase of burial depth,in the high temperature and high pressure deep sealing system, its Fe2+ and Mn2+ elements increased while Sr2+ decreased. Through reconstruction of dynamic diagenesis-pore evolution, it is concluded that the low porosity of shallow beach grain dolomite is resulted from early compaction and medium-term cementation, yet the reservoir quality has been apparently improved by the later hydrocarbon dissolution; compared with shallow beach grain dolomite,the reef dolomite has smaller initial porosity, but stronger compressive capacity. The early compaction and medium-term cementation have less impact on the reef dolomite, and the later dissolution strength is slightly weaker than that of the granular dolomite, thus the change range of porosity is smaller than that of the grain dolomite; the micrite-silt dolomite mainly suffered porosity reduction caused by compaction, and the later burial dissolution and recrystallization are key to the quality improvement of this kind of dolomite reservoir.",2,3,9
Source Rocks,"Trace Element,Oxygen Isotope","Wang, Qi; Hao, Fang; Xu, Changgui; Zou, Huayao","Paleolimnological environments and the formation of high quality source rocks in the Bohai Bay Basin: An integrated geochemical study of biomarkers, stable carbon and oxygen isotopes, and trace elements",Source rocks; Biomarkers; Carbon isotopic compositions; Bohai Bay basin (BBB),LACUSTRINE SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CRUDE OILS; SHIJIUTUO UPLIFT; ORGANIC-MATTER; EVAL PYROLYSIS; LIAODONG BAY; LAKE; PETROLEUM; EVOLUTION,"Fourteen Paleogene rock samples from the Bohai Bay Basin, including samples from the third member of the Oligocene Dongying Formation (Ed(3)) and the third member of the Eocene Shahejie Formation (Es-3), underwent total organic carbon (TOC) analysis, Rock-Eval pyrolysis, stable carbon (delta C-13(carb)) and oxygen isotope (delta O-18(carb)) analysis of carbonates, stable carbon isotope analysis of organic matter (delta C-13(om)), biomarker and trace element compositional analysis to reconstruct paleolimnological environments and investigate the factors that control the occurrence of high quality source rocks. The Rock-Eval and TOC results revealed that the source rocks meet the standard for good to excellent source rocks. The biomarker parameters and trace elements suggest that warm and humid paleolimnological conditions prevailed during the deposition of Es-3. In addition, heavier values of delta C-13(om) and light values of delta O-18(carb) indicate the existence of a hydrologically open paleolake with high primary productivity, which is supported by relatively high 4-methyl sterane index values and high barium/calcium (Ba/Ca) ratios. Ed(3) rocks formed under less reducing and more acidic conditions, which is supported by high pristane/phytane, C-27 diasteranes/C-27 regular steranes and kaolinite/illite ratios and low strontium/barium (Sr/Ba) and vanadium/chromium (V/Cr) ratios. Moreover, Ed(3) is characterized by a relatively high input of terrestrial organic matter under humid but cooler settings. A long-term positive shift of delta O-18(carb) revealed by the Ed(3) samples is associated with changes in oxygen isotopic composition of inflow water (higher precipitation) and temperature (colder). The conditions of both high productivity and enhanced preservation controlled the distribution of good source rocks in the Bohai Bay Basin (BBB). Es-3 is more likely linked with high primary productivity, which resulted in an overall positive shift in delta C-13(om), whereas Ed(3y) may be more related to favourable preservation conditions associated with relatively high sedimentation rates.",2,3,3
Source Rocks,Peak,"Su, Long; Zhang, Dongwei; Zheng, Lunju; Liu, Xingwang; Yang, Xin; Zheng, Jianjing; Liu, Peng",Experimental study of the influences of pressure on generation and expulsion of hydrocarbons: A case study from mudstone source rocks and its geological application in the Tarim Basin,Lithostatic stress; Fluid pressure; Liquid hydrocarbon generation; Expulsion efficiencies; Pressured experiments,ORGANIC-MATTER MATURATION; THERMAL-CRACKING; NW CHINA; OIL GENERATION; PALEOZOIC OIL; KINETIC-MODEL; RETARDATION; TEMPERATURE; WATER; PYROLYSIS,"Generally, pressure, temperature, depth of organic matter/kerogen burial and organic and inorganic matter interactions can influence the hydrocarbon generation process. However, different understandings were proposed to interpret the role of pressure in hydrocarbon generation. Meanwhile, previous investigations of the influence of pressure on hydrocarbons generation are mainly focused on fluid pressure (FP), only a few work was involved in the effect of lithostatic stress (LS) due to the limitation of experimental techniques. In this study, simulation experiments were conducted to investigate the influence of pressure, including lithostatic stress (LS) and fluid pressure (FP) on yield and process of hydrocarbon generation by a modified simulation instrument. Two systematic comparative pyrolysis experiments, including pressured experiments with LP range from 27.6 to 179.4 MPa and FP range from 12.0 to 109.2 MPa, and non-pressured experiments with LP for 6.0 MPa and FP range from 2.0 to 5.0 MPa were conducted in hydrous experimental condition. The results show that the peak yields of the expelled oil and the liquid hydrocarbons in pressured experiments and non-pressured experiments are 42.48 mg/g.TOC, 52.00 mg/g.TOC, 70.14 mg/g.TOC, and 72.15 mg/g.TOC, respectively. And Ro, ratio of the expelled oil to eluted oil, the accumulated yield of the expelled oil and liquid hydrocarbons, are lower in pressured experiments than that of non-pressured experiments. However, the accumulated yields of eluted oil and residual oil are higher in pressured experiments than that of non-pressured experiments. Additionally, the expulsion efficiencies of the oil range from 20% to 25%, which are lower in pressured experiments than that of non-pressured experiments near the oil generation-window. In addition, the yields of hydrocarbon gas in pressured experiments are greater compared to the yields in non-pressured experiments at the high maturity stage. Based on the experimental results, hydrocarbon generation process can be divided into three stages. Generally, LS and FP could retard the process of mudstone maturation as well as the generation and expulsion of the liquid hydrocarbons. Hence, the residual liquid hydrocarbons in high-pressure condition can act as another source of natural gas generation in the high maturity stage. The results could help us to properly evaluate hydrocarbon generation potentials of sources rocks at petroleum-producing sedimentary basins in China and elsewhere.",2,2,7
Source Rocks,Peak,"Adeoye, James A.; Akande, Samuel O.; Adekeye, Olabisi A.; Sonibare, Wasiu A.; Ondrak, Robert; Dominik, Wilhelm; Erdtmann, Bernd D.; Neeka, Jacob",Source rock maturity and petroleum generation in the Dahomey Basin SW Nigeria: Insights from geologic and geochemical modelling,,THERMAL HISTORY; BENUE TROUGH; HEAT-FLOW; MATURATION; EVOLUTION; KINETICS,"Sedimentology, foraminifera paleoecology, geochemical and petroleum system modelling studies were performed on Cretaceous shales from onshore Orimedu-1 and offshore X (at a water depth of 914 m) wells in the Dahomey Basin, southwestern Nigeria to evaluate their maturity, hydrocarbon generation potentials, and regional significance for petroleum prospectivity. Foraminifera biofacies analysis of the studied shales suggests deposition in dominantly marine environments. The average total organic carbon content (TOC, wt%) and hydrogen index (HI, mgHC/gTOC) for Cenomanian, Turonian, and Coniacian shales in X-well are 1.3, 0.9, 1.3 and 406, 560, 214 respectively. While the Cenomanian and Turonian shales in Orimedu-1 have TOC (wt%) of 1.3 and 1.9, and HI (mgHC/gTOC) of 179 and 357 respectively. Well X source rocks contain predominantly marine-derived Type II kerogen, while Orimedu-1 well contain terrigenous-derived gas prone kerogen. The integration of recently acquired kinetic data from immature source rocks further constraints the prediction of petroleum generation in the study area.1D basin modelling of X well reveals that the Cenomanian Source Rock (CSR) is the most mature bed in the basin having attained the initial 10% transformation ratio (TR) at 87 Ma, got to peak TR (similar to 50%) at 86 Ma, and reached 83% at 53.6 Ma With a present-day thermal maturity of 0.95% VRo. The Turonian source in well X also attained the initial 10% TR at 87 Ma, got to peak (similar to 50% TR) at 86 Ma and 69% TR at 50 Ma. These modelled source beds are deeper than the source with 0.62 %VRo used for kinetic study. The observed maturity trend is mostly controlled by the regional erosive events associated with the West African rift system during Santonian and Eocene times. The source rocks in Orimedu-1 are immature. The timing of the generated and expelled hydrocarbons into the Cretaceous petroleum systems of Dahomey Basin is of regional significance with the entire Gulf of Guinea basins because of the similar evolution and sedimentation history along with recent discoveries and production of hydrocarbon.",2,2,2
Source Rocks,Peak,"Beti, Dhrupad R.; Jiang, Chunqing; Panja, Palash; Ring, Terry A.; Levey, Raymond",Hydrocarbon distributions of incremental S1 peaks corresponding to different boiling point ranges of petroleum in rock samples,Pyrolysis; S1 Peak; Incremental S1; Free petroleum; TD-GC,,"This correspondence presents an extension to the article ""A New Method of Source and Reservoir Rock Pyrolysis to Determine the Boiling Point Distribution of Petroleum in Rock Samples"" by Beti et al. (2018). Thermal desorption-gas chromatography (TD-GC) analysis of S1 peak and the sequential split of S1 into three peaks were performed on a Gothic shale sample from the Paradox Basin, Utah. The results indicate that the total area and composition of the S1 peak that includes all of the hydrocarbon molecules detected are equivalent to the sum of the three sequential peaks. The hydrocarbon distribution of the three sequential peaks was used to predict the range of hydrocarbons detected at ""Incremental S1"" temperatures.",2,2,0
Source Rocks,Alluvial Fan,"Li, Shunming; He, Hui; Hao, Ruilin; Chen, Huanqing; Bie, Hanyu; Liu, Pengcheng","Depositional regimes and reservoir architecture characterization of alluvial fans of Karamay oilfield in Junggar basin, Western China",Junggar basin; Alluvial fan; Cohesive debris flows; Sandy debris flows; Conglomeratic reservoir architectures,PERMIAN LUCAOGOU FORMATION; GRAINED DEBRIS FLOWS; SEDIMENTARY PROCESSES; NATURAL DISTINCTION; HYDRAULIC PROCESSES; SOURCE ROCKS; FACIES; MORPHOLOGY; GEOCHEMISTRY; DELTA,"We analyzed the lithology and sedimentary structures of the lower Karamay formation alluvial fan of Karamay oilfield in Junggar basin and subdivided its lithofacies into six types. The depositional regimes of the lower Karamay formation regressive alluvial fans contain (1) cohesive debris flows, (2) sandy debris flows, (3) grain flows, (4) turbidity currents, and (5) traction currents in the light of sedimentary fabrics and lithofacies association. In terms of lithofacies association, depositional succession, boundary surface hierarchy and wireline logs, fourth-order reservoir architectures for this alluvial fan are composed of nine types: (1) trench channel conglomerates, (2) trench sandy conglomerates, (3) trench proximal sandbody, (4) trench sheetflood lithosome, (5) trench distal sandbody, (6) braided channel, (7) channel gravel bar, (8) overflow sandbody, and (9) runoff channel. On the basis of the reservoir architecture identification of all wells, we established a three-dimensional (3D) architectural element model of the lower Karamay formation with a method of sequential indicator simulation to reveal the reservoir architecture spatial distribution. Integrated three-dimensional reservoir architecture models with contemporary depositional characteristics of alluvial fans, we concluded the depositional patterns of reservoir architectures for different alluvial fan subfacies, which shows the geometric features and aspects of the reservoir architectures. This information provided a technical foundation for the remaining oil prediction, development strategy optimization, and oil recovery enhancement of the conglomeratic oil reservoirs at the high water-cut stage.",3,4,1
Source Rocks,Alluvial Fan,"Li, Shunming; Han, Rubing; Du, Yijing; Liu, Pengcheng; Bie, Hanyu","Quantitative characterization of diagenetic reservoir facies of the Karamay alluvial fan in the Junggar Basin, western China",Alluvial fan; Reservoir architecture; Diagenesis intensity; Diagenetic reservoir facies (DRFs); Quantitative prediction; Conglomeratic reservoirs,PERMIAN LUCAOGOU FORMATION; SANDSTONE RESERVOIRS; SOURCE ROCKS; QUALITY; CARBONATE; GEOCHEMISTRY; PREDICTION; FIELD; SAG; IDENTIFICATION,"The distribution of the remaining oil in developed oilfields is primarily influenced by the existing diagenetic reservoir facies (DRFs), which encompass the effects of both the sedimentary environment and the local diagenetic processes on the reservoir quality. We divided the Lower Karamay Formation reservoir samples into nine DRFs according to characteristics such as porosity, permeability, diagenetic intensity, and rock type. After applying the sequential indicator simulation methodology, we were able to create three-dimensional (3D) geological models of the DRFs. Based on these models, we can see that, during phases A and B of eodiagenesis, the prevailing DRF is a sandstone/sandy conglomerate that is moderately to weakly dissolved, moderately cemented, and characterized by moderate porosity and permeability values. The highest quality DRF, which emerged during the early stage of mesodiagenesis, is a sandstone/sandy conglomerate that is weakly compacted/cemented, moderately-to-strongly dissolved, and characterized by very high porosity and permeability values. By providing high-quality analyses of the DRFs in Block 6 of the Karamay oilfield, we provided vital information that allowed the operation to more efficiently target and extract oil from reservoir units that are already in production.",1,1,3
Source Rocks,Gas Resource,"Huo, Fei; Wang, Xingzhi; Wen, Huaguo; Xu, Wenli; Huang, Huiwen; Jiang, Huachuan; Li, Yawen; Li, Bo","Genetic mechanism and pore evolution in high quality dolomite reservoirs of the Changxing-Feixianguan Formation in the northeastern Sichuan Basin, China",Carbon oxygen isotope; Major and trace elements; Source of diagenetic fluid; Mechanism of dolomitization; Diagenesis-pore evolution,NE SICHUAN; HYDROTHERMAL DOLOMITE; ISOTOPE COMPOSITION; EASTERN SICHUAN; BURIAL DOLOMITIZATION; CARBONATE SUCCESSIONS; GAS-RESERVOIRS; JIANNAN AREA; DIAGENESIS; PLATFORM,"The marine carbonate rock in the Changxing-Feixianguan Formation of Xuanhan-Daxian area, northeastern Sichuan, the Sichuan Basin holds abundant natural gas resource, where the dolomite includes two types, the one with original texture (grain dolomite, reef dolomite) and the one without original texture (idiomorphic to anhedral-crystal dolomite, porphyritic dolomite). The analysis on the isotopes of C, O, Sr and other geochemical features shows that the dolomitizing process happened in fluid rich in Mg2+ and lean in Ca2+ and brought in Fe2+, Mn2+ and took out Sr2+; with the rise of recrystallization, the Fe2+ , Mn2+ contents tend to increase while delta O-18(PDB) and Srcontent tend to decrease. According to the variation of Sr-87/Sr-86 and other geochemical features, it is considered that the dolomitizing fluid participating in the reservoir diagenesisis the high salinity sea water later than the end of Feixianguan stage, and the dolomitization takes place mainly through the multiple thermal convective cycle effect. The micritic dolomite is of evaporative dolomitization origin with the characteristics of high Sr2+, Na+ and low Mn2+ which reflects the open environment of the surface exposed in the quasi syngenetic period, while the reef dolomite is of high Mg/Ca dolomitizing fluid origin with the characteristics of low Sr-2 , Na+ and Mn2+, whose diagenetic environment changed from near surface to shallow burial environment; crystalline dolomite is formed by metasomatism of low Mg/Ca dolomitizing fluid at deep burial depth and high temperature, with the increase of burial depth,in the high temperature and high pressure deep sealing system, its Fe2+ and Mn2+ elements increased while Sr2+ decreased. Through reconstruction of dynamic diagenesis-pore evolution, it is concluded that the low porosity of shallow beach grain dolomite is resulted from early compaction and medium-term cementation, yet the reservoir quality has been apparently improved by the later hydrocarbon dissolution; compared with shallow beach grain dolomite,the reef dolomite has smaller initial porosity, but stronger compressive capacity. The early compaction and medium-term cementation have less impact on the reef dolomite, and the later dissolution strength is slightly weaker than that of the granular dolomite, thus the change range of porosity is smaller than that of the grain dolomite; the micrite-silt dolomite mainly suffered porosity reduction caused by compaction, and the later burial dissolution and recrystallization are key to the quality improvement of this kind of dolomite reservoir.",2,3,9
Source Rocks,Gas Resource,"Wu, Nan; Wang, Jian; Cai, Zhongxian; Luo, Zhong; Lu, Xuesong; Ma, Xingzhi; Liu, Xianfeng","Discovery of Sinian source rocks in proterozoic in the Tarim Basin, NW China",Tarim basin; Kuruktag; Sinian source rocks; Hydrocarbon generation; Bitumen,ORGANIC-MATTER; CRUDE OILS; MATURITY PARAMETERS; THERMAL MATURITY; SICHUAN BASIN; GEOCHEMICAL CHARACTERISTICS; TRICYCLIC TERPANES; VELKERRI FORMATION; MCARTHUR BASIN; GRAND-CANYON,"As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50-60 degrees C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin.",2,2,3
Source Rocks,Wireline Logs,"Tenaglia, Max; Eberli, Gregor P.; Weger, Ralf J.; Blanco, Leticia Rodriguez; Sanchez, Laura E. Rueda; Swart, Peter K.","Total organic carbon quantification from wireline logging techniques: A case study in the Vaca Muerta Formation, Argentina",Total organic carbon; Vaca Muerta Formation; Unconventional resources; TOC prediction; Spectral gamma-ray; Source rock,NEUQUEN BASIN; SEQUENCE STRATIGRAPHY; SOURCE ROCKS; SHALES; METAMORPHISM; RESISTIVITY; RICHNESS; BOUNDARY; TIME; RAMP,"The Vaca Muerta Formation, one of the most prolific unconventional play in South America, exhibits concentrations of total organic carbon (TOC) of up to 16% with variations in TOC paralleling the general facies evolution of the prograding system. This study examines the applicability and accuracy of predicting TOC from two methods of quantifying organic-rich zones from wireline logs: the relationship of uranium from spectral gammaray to TOC, and the delta logR technique for calculating TOC. A database from extensive outcrop geochemical sampling (n = similar to 1900) was correlated to the uranium signal from a handheld spectral gamma-ray logging tool. The U/TOC relationship derived from the outcrop samples shows high variability between outcrop sections measured across the formation. The U/TOC ratio increases from proximal to distal positions within the basin. A second dataset, consisting of core samples, was also analyzed and compared to the TOC calculated using a combination of the sonic and resistivity data obtained from downhole logging. This second method of TOC prediction reliably and accurately reproduces laboratory measurements, and is the far superior choice when estimating organic richness from wireline log signatures. To further test this method of TOC prediction, a subset of sidewall plugs were analyzed for petrophysical and geochemical measurements and using the ologR technique, was able to produce TOC values that compared to discrete laboratory measurements with a correlation coefficient of R-2 = 0.83. The time-tested method of determining organic richness from wireline logs can be successfully applied in the Neuquen Basin and could be attempted in other basins once all available data has been carefully considered.",3,3,5
Source Rocks,Wireline Logs,"Li, Shunming; He, Hui; Hao, Ruilin; Chen, Huanqing; Bie, Hanyu; Liu, Pengcheng","Depositional regimes and reservoir architecture characterization of alluvial fans of Karamay oilfield in Junggar basin, Western China",Junggar basin; Alluvial fan; Cohesive debris flows; Sandy debris flows; Conglomeratic reservoir architectures,PERMIAN LUCAOGOU FORMATION; GRAINED DEBRIS FLOWS; SEDIMENTARY PROCESSES; NATURAL DISTINCTION; HYDRAULIC PROCESSES; SOURCE ROCKS; FACIES; MORPHOLOGY; GEOCHEMISTRY; DELTA,"We analyzed the lithology and sedimentary structures of the lower Karamay formation alluvial fan of Karamay oilfield in Junggar basin and subdivided its lithofacies into six types. The depositional regimes of the lower Karamay formation regressive alluvial fans contain (1) cohesive debris flows, (2) sandy debris flows, (3) grain flows, (4) turbidity currents, and (5) traction currents in the light of sedimentary fabrics and lithofacies association. In terms of lithofacies association, depositional succession, boundary surface hierarchy and wireline logs, fourth-order reservoir architectures for this alluvial fan are composed of nine types: (1) trench channel conglomerates, (2) trench sandy conglomerates, (3) trench proximal sandbody, (4) trench sheetflood lithosome, (5) trench distal sandbody, (6) braided channel, (7) channel gravel bar, (8) overflow sandbody, and (9) runoff channel. On the basis of the reservoir architecture identification of all wells, we established a three-dimensional (3D) architectural element model of the lower Karamay formation with a method of sequential indicator simulation to reveal the reservoir architecture spatial distribution. Integrated three-dimensional reservoir architecture models with contemporary depositional characteristics of alluvial fans, we concluded the depositional patterns of reservoir architectures for different alluvial fan subfacies, which shows the geometric features and aspects of the reservoir architectures. This information provided a technical foundation for the remaining oil prediction, development strategy optimization, and oil recovery enhancement of the conglomeratic oil reservoirs at the high water-cut stage.",3,4,1
Two-phase Flow,Pressure Gradient,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Two-phase Flow,Pressure Gradient,"Santos, M. P. P. C.; Carvalho, M. S.",Pore network model for retrograde gas flow in porous media,Pore-network models; Gas-condensate; Capillary condensation; Compositional reservoir simulation,CONDENSATE; VISCOSITY,"Gas well deliverability in retrograde gas reservoirs is affected by the appearance of a liquid phase near the wellbore when the bottom-hole pressure is below the dew point. At low enough pressure gradients, the liquid phase may bridge the pore throats, blocking the gas phase flow, leading to what is known as condensate blockage. If the pressure gradient is above a critical value, the capillary forces cannot block the gas flow and the condensate bridges are displaced. Gas production can be estimated using reservoir-scale simulation of the retrograde gas flow near producing wells using relative permeability curves that take into account the different physical phenomena and their dependence on local pressure, temperature and pressure gradient (capillary number). Pore-scale simulators can be used to model retrograde gas flow through porous media and to determine the gas and liquid phases relative permeability curves as a function of different flow parameters. Here, a fully-implicit isothermal compositional pore-scale network model is presented for retrograde gas flow in porous media at high capillary number, at which capillary forces are neglected. The flow pattern in each capillary changes from a single-phase gas flow to a two-phase core-annular flow regime when the pressure and the fluid composition reach a critical condition based on the thermodynamics of the fluid mixture. Newton's method is used to solve the non-linear flow and thermodynamics equations to calculate the pressure distribution and the flow rate of each component through the network. The model was used to predict gas-liquid relative permeability at high capillary number from a depletion process in a 2D network. The results show the evolution of the condensate saturation at different conditions and how the gas permeability falls abruptly at a certain condensate saturation.",3,3,0
Two-phase Flow,Pressure Gradient,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Two-phase Flow,Pressure Gradient,"Kim, Tea-Woo; Kim, Sungil; Lim, Jung-Tek",Modeling and prediction of slug characteristics utilizing data-driven machine-learning methodology,Liquid-gas two-phase slug flow; Horizontal and near-horizontal slug flow; Slug flow parameters; Slug liquid holdup; Translational velocity; Slug length,LIQUID SLUG; 2-PHASE FLOW; HOLDUP; FRACTION,"Slug liquid holdup, translational velocity, and slug length are representative slug characteristics. The precise prediction of these parameters is essential for the accurate calculation of the average liquid holdup and pressure gradient in pipes. Nevertheless, existing correlations have mainly been developed by an empirical approach. Each correlation can only be applied to a restricted fluid property and geometrical condition, preventing people from selecting a suitable one without professional knowledge. In this study, slug characteristics were predicted by several machine learning methodologies with 2590 experimental data to overcome the limitation of selecting the proper model or correlation. The experimental dataset includes -10 degrees <= theta (pipe inclination angle) <= 10 degrees, 0.0258 m <= I.D. (pipe inner diameter) <= 0.0780 m, 0.01 m/s <= vSL (superficial liquid velocity) <= 3.4 m/s, 0.03 m/s <= vSg (superficial gas velocity) <= 20 m/s, 769 kg/m(3) <= rho(L) <= 998 kg/m(3), 1.12 kg/m(3) <= rho(G) <= 7.36 kg/m(3), 0.001 Pa s <= mu(L) <= 4.65 Pa s, and 6 <= Re-M (mixture Reynolds number) <= 863,920. The existing dataset has been preprocessed to pursue better machine learning performance. The random forest results reveal a better training performance and prediction than that of a deep neural network and present a competitive prediction compared with the existing correlations, indicating a great potential of utilizing the data-driven machine learning methodology.",2,2,0
Two-phase Flow,Pressure Gradient,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Two-phase Flow,Water Content,"Qing, Meiyi; Liang, Huaqing; Zhang, Jinjun; Zhan, Honglei",The mechanism of detecting water content in oil-water emulsions using impedance spectroscopy,Impedance spectroscopy; Water content; Oil-water emulsion; Distribution of droplets,DROPLET SIZE; ELECTROCHEMICAL IMPEDANCE; IN-WATER; EMULSIFICATION; DISTRIBUTIONS,"The water content of the oil-water emulsions has a significant impact on the flow pattern and pressure drop law of oil-water two-phase flow, thus more theory and methods are necessary to improve the detection of emulsion. Impedance spectroscopy was employed to detect oil-water emulsions with different water contents. The diffusion frequency extracted from impedance spectroscopy had a linear relationship with the water content of emulsions. In this study, polarization microscope was used to obtain the microstructure characteristics of oil-water emulsions. The increasing water content increased the logarithmic mean size of the droplets in a linear fashion. This led to an increase in the concentration of charged ions in the diffusion layer of the ionic double layer, which significantly influenced the time of the diffusion process. Consequently, impedance spectroscopy can be applied to detect the water content of emulsions and contribute to further understanding the characteristics of multi-phase flow in petroleum reservation and transportation industry.",3,3,5
Two-phase Flow,Water Content,"Zhang, Dailu; Zhang, Hongbing; Rui, Jianwen; Pan, Yixin; Liu, Xingbin; Shang, Zuoping",Prediction model for the transition between oil-water two-phase separation and dispersed flows in horizontal and inclined pipes,Stratified flow; Annular flow; Dispersed flow; Mixed froude number; Prediction model of transition,DROPLET ENTRAINMENT,"There are two important flow patterns associated with horizontal and deviated wells: separation flows, which include stratified and annular flows, and dispersed flows. Because various types of flow patterns often exchange with each other under certain conditions, it is of great significance for improving the efficiency of oil transportation to develop prediction models describing the transition between oil-water stratified and annular or dispersed flows. Owing to the variable flow rate, water content, and pipeline inclination, the transition characteristics and prediction models for the transition from stratified to annular or dispersed flows are not clear. Therefore, in this study, relevant experiments were carried out and the transition characteristics were investigated to establish a new prediction model. In the transition from a stratified to annular flow, the prediction model for the transition boundaries and criteria is based on mixed Froude numbers. In contrast to previous studies, it was found in these experiments that the mixed Froude number is not constant when conversion between stratified flow and annular flow occurs. Instead, the mixed Froude number is related to the inlet water content and the pipeline inclination. The transition boundaries predicted by the proposed model are in good agreement with the experimental results. Based on the existing two-dimensional interfacial wave shearing mechanism, the three-dimensional interfacial wave shear deformation mechanism is elucidated. In the transition from stratified to dispersed flows, the external force on the flow direction of the interfacial wave, which includes the drag force, interfacial tension, gravity, and buoyancy, is theoretically derived by analysing the force situation before and after deformation of the two-phase interfacial wave. A prediction model for the deformation of the interfacial wave is developed, and the relationships between the external force and wave amplitude or wavelength are analysed with the prediction model. The results indicate that deformation is more likely to occur as the inclination angle of the well increases, the interfacial wave becomes unstable with increasing amplitude, and droplet formation occurs with long waves.",3,3,4
Two-phase Flow,Water Content,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Two-phase Flow,Water Content,"Qin, Hao; Dai, Jiacai; Liu, Xiangjun; Yang, Guofeng; Pei, Yang; Gou, Shunchao; Chen, Meng",Slip behaviours and evaluation of interpretative model of oil/water two-phase flow in a large-diameter pipe,Production logging; Oil/water flow; Slip behaviour; Interpretative model; Water holdup,OIL-WATER 2-PHASE; SLUG-LIQUID-HOLDUP; DRIFT-FLUX MODEL; MECHANISTIC MODEL; PRESSURE-DROP; VERTICAL PIPE; VELOCITY; PATTERNS; BUBBLES,"Mixtures of oil and water are common in oil-producing wells. When the oilfield has a mid-late exploitation status, the production of oil and water gradually decreases and the comprehensive water content sharply increases with time. An accurate evaluation of the volumetric flow rate of each phase in the pipe is of importance for diagnosing production problems, developing an engineering design, and guiding reservoir management activities. In this study, the slip behaviours we investigated based on the high-quality experimental data obtained from a multi-phase flow loop with a large-diameter (inner diameter: 5.5 inch) vertical pipe with low flow rates (<30 m(3)/d). Furthermore, the interpretation accuracies of five interpretative models of vertical oil/water flow ware comprehensively evaluated. The results show that the slip trends to increase with decreasing flow rates. However, it was found that, when the flow rate is less than 7 m3/d, the flow rate minimally affects the slip. Additionally, the variation tendency of the slip velocity as a function of the water holdup is not stable, hence, a reasonable interpretative model should be selected according to the water holdup. The slip velocity gradually increased, and was found to be nearly linear, and the slip model proposed by Hasan and Kabir (1999) demonstrated the best adaptability under the conditions of the tested data and a water holdup of less than 0.9. The slip velocity exponentially increased with increasing water holdup and the modified drift-flux model proposed by Wu et al. (1992) was found to be more appropriate under the condition that the water holdup exceeds 0.9. Overall (i.e. for all of the test data), the Hasan model (1999) yielded better processing results for the vertical oil/water flow system under the condition of low flow rates. The analysis in this study provides better insight into the slip between the oil and water phases in a two-phase flow system with a low flow rate. In addition, the interpretative model with the best predictive capability is highlighted in this paper.",1,1,3
Two-phase Flow,Multiphase Flow,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Two-phase Flow,Multiphase Flow,"Pugliese, Victor; Panacharoensawad, Ekarit; Ettehadtavakkol, Amin",Numerical study of the motion of a single elongated bubble in high viscosity stagnant liquids along pipelines,Multiphase flow; Drift flux model; Taylor bubble; High-viscosity oil; Drift velocity; Inclined pipes,DRIFT-FLUX MODEL; SLUG FLOW; MULTIPHASE FLOW; LONG BUBBLES; 2-PHASE FLOW; VELOCITY; CLOSURE; SIMULATION; EQUATIONS,"Multiphase flow models involve more variables than available equations, thus closure relationships are required to solve the system of partial differential equations. In the Drift Flux Model, the mean drift velocity of the gas phase is estimate using the drift velocity closure relationship. This study investigates the motion of a single elongated bubble in high viscosity stagnant liquids in order to propose a comprehensive closure relationship for the bubble drift velocity. Different cases were run with inclination angles varying from 0 degrees (horizontal direction) to 90 degrees (vertical upward). OpenFOAM, an open source Computation Fluid Dynamics software, was used to numerically solve the two-phase incompressible flow problem. Drift velocities based on the movement of the bubble tip and the void fraction weighted averaged were compared to clarify the ambiguity in the drift velocity calculation and measurement. For horizontal pipe cases, the deformation of the bubble caused the drift velocity to be higher at the tip of the bubble than the drift velocity inside the bubble. For inclination angles more than 0 degrees, the drift velocity at the tip is the same as inside the bubble. The closure relationship proposed is validated against experimental data in the literature. The results indicate that the closure relationship has a maximum 10% absolute average relative error for the viscosity range of 0.14-1.120 Pa.s, pipe size up to 0.152 m and pipe inclinations from 0 degrees to 90 degrees. The limitations of the closure relationship and potential enhancements for future studies are discussed.",2,2,2
Two-phase Flow,Multiphase Flow,"Wu, Yuqi; Tahmasebi, Pejman; Lin, Chengyan; Ren, Lihua; Zhang, Yimin",Quantitative characterization of non-wetting phase in water-wet porous media based on multiphase flow experiment and numerical simulation,Multiphase fluid flow; Residual oil; Fluid physics; Pore-scale modeling; Pore occupancy,PORE-SCALE; RESIDUAL OIL; RELATIVE-PERMEABILITY; 2-PHASE FLOW; RECOVERY; SHALE; TECHNOLOGIES; MULTISCALE; SALINITY; SIZE,"It is of great significance to analyze the distribution characteristics of the non-wetting phase during the multiphase flow and identify the positions of the oil ganglia since it can guide us to design the schemes for improving oil recovery. In this paper, the two-phase (brine and oil) flow experiment and simulation are performed on a water-wet sandstone. A comprehensive analysis of the distribution of the non-wetting (oil) phase in 3D pore space and individual pores are presented. To calculate the pore occupancy of the non-wetting ganglia in every single pore from 3D CT experimental data, we proposed a technique, called the Axis-aligned Bounding Box (AABB) algorithm, to determine which oil blobs exist in a unique pore. The pore-by-pore distribution characteristics of the residual phase are then analyzed based on the experimental and numerical data. The results reveal the large oil clusters are separated into small blobs during the imbibition process, which results in increasing the number of non-wetting ganglia, dropping its connectivity, and increasing the smoothness. Moreover, the larger the volume of one pore, the larger the volume and saturation of residual oil ganglia in the pore are. Furthermore, our analysis based on the experimental and numerical results indicates that most of the non-wetting ganglia reside in the median-size pores. Hence, the finding provides us a piece of significant evidence to better target the pore-spaces for the purpose of increasing the recovery.",2,2,2
Two-phase Flow,Multiphase Flow,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Two-phase Flow,Evaluation,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Two-phase Flow,Evaluation,"Galindez-Ramirez, G.; Contreras, F. R. L.; Carvalho, D. K. E.; Lyra, P. R. M.",Numerical simulation of two-phase flows in 2-D petroleum reservoirs using a very high-order CPR method coupled to the MPFA-D finite volume scheme,Oil-water displacements; Anisotropic and heterogeneous petroleum reservoirs; High-order approximations; Multipoint Flux Approximation with Diamond Stencil (MPFA-D); Correction Procedure via Reconstruction (CPR); Multidimensional Limiting Process (MLP),DISCONTINUOUS GALERKIN METHODS; POROUS-MEDIA; ELEMENT-METHOD; RECONSTRUCTION; ACCURACY; IMPLICIT; APPROXIMATIONS; FORMULATION; VELOCITY; MESHES,"The focus of the present work is to model the two-phase flow of oil and water in 2-D anisotropic petroleum reservoirs using a novel appropriate combination of a non-orthodox cell-centered Multipoint Flux Approximation with a Diamond Stencil (MPFA-D) finite volume method to discretize the pressure equation coupled to the very high-resolution Correction Procedure via Reconstruction (CPR) scheme for the discretization of the saturation equation. To suppress numerical oscillations (under/overshoots) near shocks, that are typical in higher-order schemes, and to deliver high accuracy in smooth regions of the solution, a hierarchical Multidimensional Limiting Process (MLP) is used in the reconstruction stage. The integration in time is carried out using a third-order Runge-Kutta method. The coupling of the pressure-saturation set of equations is carried out using a classical Implicit Pressure Explicit Saturation (IMPES) procedure. To properly couple the MPFA-D method with the CPR formulation, it is necessary to obtain an adequate velocity reconstruction throughout the control volumes of the mesh. Because the cell-centered finite volume method naturally delivers fluxes across control surfaces of the primal grid, then, we use a reconstruction operator based on the lowest order Raviart-Thomas interpolation functions and the Piola transformation, to get the complete knowledge of the velocity field throughout the domain. Finally, some representative problems were solved to evaluate the accuracy, efficiency, and shock-capturing capabilities of our new numerical methodology.",3,3,0
Two-phase Flow,Evaluation,"Andreolli, I; Azevedo, G. R.; Balino, J. L.",Application of stability solver for severe slugging considering a choking device and a tubing connected to a Wet Christmas Tree,Stability solver; Severe slugging; Petroleum production; Three-phase flow; Choking; Tubing,FLOW-RATE; SIMULATION,"This work is an improvement of a previous work (Andreolli et al. 2018) by including a tubing as a subsystem of the pipeline-riser system, a realistic choke valve model to predict the two-phase critical flow and pressure drop before the separator and boundary conditions between stretches of the geometry, in order to improve the determination of the stability boundary. The improved stability solver is applied for a three phase flow (gas, oil and water). Stability for operational points obtained from actual measurements are successfully predicted with the stability maps generated by the solver considering the tubing connected to the Wet Christmas Tree (WCT). A parametric analysis is made in order to evaluate a choke valve influence over stability maps. The stability maps are built by using field conditions at Santos and Campos basins (Brazil). The numerical results present a good agreement with numerical data and real operational conditions. The analysis to evaluate and verify the choke valve influence over stabilization shows a good agreement with the expected behavior.",1,1,3
Two-phase Flow,Evaluation,"Qin, Hao; Dai, Jiacai; Liu, Xiangjun; Yang, Guofeng; Pei, Yang; Gou, Shunchao; Chen, Meng",Slip behaviours and evaluation of interpretative model of oil/water two-phase flow in a large-diameter pipe,Production logging; Oil/water flow; Slip behaviour; Interpretative model; Water holdup,OIL-WATER 2-PHASE; SLUG-LIQUID-HOLDUP; DRIFT-FLUX MODEL; MECHANISTIC MODEL; PRESSURE-DROP; VERTICAL PIPE; VELOCITY; PATTERNS; BUBBLES,"Mixtures of oil and water are common in oil-producing wells. When the oilfield has a mid-late exploitation status, the production of oil and water gradually decreases and the comprehensive water content sharply increases with time. An accurate evaluation of the volumetric flow rate of each phase in the pipe is of importance for diagnosing production problems, developing an engineering design, and guiding reservoir management activities. In this study, the slip behaviours we investigated based on the high-quality experimental data obtained from a multi-phase flow loop with a large-diameter (inner diameter: 5.5 inch) vertical pipe with low flow rates (<30 m(3)/d). Furthermore, the interpretation accuracies of five interpretative models of vertical oil/water flow ware comprehensively evaluated. The results show that the slip trends to increase with decreasing flow rates. However, it was found that, when the flow rate is less than 7 m3/d, the flow rate minimally affects the slip. Additionally, the variation tendency of the slip velocity as a function of the water holdup is not stable, hence, a reasonable interpretative model should be selected according to the water holdup. The slip velocity gradually increased, and was found to be nearly linear, and the slip model proposed by Hasan and Kabir (1999) demonstrated the best adaptability under the conditions of the tested data and a water holdup of less than 0.9. The slip velocity exponentially increased with increasing water holdup and the modified drift-flux model proposed by Wu et al. (1992) was found to be more appropriate under the condition that the water holdup exceeds 0.9. Overall (i.e. for all of the test data), the Hasan model (1999) yielded better processing results for the vertical oil/water flow system under the condition of low flow rates. The analysis in this study provides better insight into the slip between the oil and water phases in a two-phase flow system with a low flow rate. In addition, the interpretative model with the best predictive capability is highlighted in this paper.",1,1,3
Two-phase Flow,Drift Velocity,"Liu, Yaxin; Tong, Tran A.; Ozbayoglu, Evren; Yu, Mengjiao; Upchurch, Eric",An improved drift-flux correlation for gas-liquid two-phase flow in horizontal and vertical upward inclined wells,Drift-flux model; Distribution coefficient; Drift velocity; Two-phase flow; Void fraction,MODEL; PREDICTION; HOLDUPS; MOTION; PHASE; SLUG,"Drift-flux model has been diffusely applied to characterize two-phase flow in pipes and wellbores owing to its accuracy and simplicity. The constitutive correlations used in the drift-flux model specifying the relative motion between the phases have been extensively investigated leading to the development of multitudinous correlations. However, previous studies reveal that most of the correlations can either be proper for limited two-phase flow conditions or the applicability is extended by increasing the complexity of the correlation. This study attempts to propose an improved drift-flux correlation concerning the distribution coefficient and drift velocity applying for a wide range of fluid properties, pipe orientations, and flow patterns without complicating the correlation. In this study, the drift velocity is defined in terms of pipe diameter, inclination angle, and void fraction while the distribution coefficient is correlated as a function of mixture Reynolds number and a Yield-Power-Law correlation in terms of void fraction. A comprehensive experimental database consisted of 1865 datarecords collected from 13 distinct sources is used for correlation parameterization and performance estimation. The proposed correlation shows comparable or even better performance in comparison to the other three well-established drift-flux correlations for predicting void fraction. The proposed correlation has also demonstrated outstanding performance in case where high liquid viscosity is involved.",3,3,1
Two-phase Flow,Drift Velocity,"Pugliese, Victor; Panacharoensawad, Ekarit; Ettehadtavakkol, Amin",Numerical study of the motion of a single elongated bubble in high viscosity stagnant liquids along pipelines,Multiphase flow; Drift flux model; Taylor bubble; High-viscosity oil; Drift velocity; Inclined pipes,DRIFT-FLUX MODEL; SLUG FLOW; MULTIPHASE FLOW; LONG BUBBLES; 2-PHASE FLOW; VELOCITY; CLOSURE; SIMULATION; EQUATIONS,"Multiphase flow models involve more variables than available equations, thus closure relationships are required to solve the system of partial differential equations. In the Drift Flux Model, the mean drift velocity of the gas phase is estimate using the drift velocity closure relationship. This study investigates the motion of a single elongated bubble in high viscosity stagnant liquids in order to propose a comprehensive closure relationship for the bubble drift velocity. Different cases were run with inclination angles varying from 0 degrees (horizontal direction) to 90 degrees (vertical upward). OpenFOAM, an open source Computation Fluid Dynamics software, was used to numerically solve the two-phase incompressible flow problem. Drift velocities based on the movement of the bubble tip and the void fraction weighted averaged were compared to clarify the ambiguity in the drift velocity calculation and measurement. For horizontal pipe cases, the deformation of the bubble caused the drift velocity to be higher at the tip of the bubble than the drift velocity inside the bubble. For inclination angles more than 0 degrees, the drift velocity at the tip is the same as inside the bubble. The closure relationship proposed is validated against experimental data in the literature. The results indicate that the closure relationship has a maximum 10% absolute average relative error for the viscosity range of 0.14-1.120 Pa.s, pipe size up to 0.152 m and pipe inclinations from 0 degrees to 90 degrees. The limitations of the closure relationship and potential enhancements for future studies are discussed.",2,2,2
Two-phase Flow,Drift Velocity,"Mazza, Ricardo A.; Suguimoto, Fabio K.",Experimental investigations of kerosene-water two-phase flow in vertical pipe,Water-oil flow; Flow patterns; Pressure drop; Oil fraction; Drift-flux correlation,LIQUID-LIQUID UPFLOW; OIL-WATER; PHASE INVERSION; PRESSURE-DROP; VELOCITY; HOLDUP; PATTERN; SUSPENSIONS; VISCOSITY; FRACTION,"Oil and water two-phase flow studies are important to the oil industries. This paper aims to determine the flow patterns, holdup, pressure losses, phase inversion, drift flux parameters and mixture properties in vertical upward kerosene and water flow. The experiment was conducted in a 26 mm i.d duct with phase velocities spanning from 0.1 to 1.0 m/s. The averaged holdup was measured using quick close valves in a 1.16 m long test section. The same test section was used to measure the pressure drop. A local impedance probe and high-speed films were used to determine the flow patterns. Six different flow patterns was identified: dispersed bubbly (DB), core annular (CA), bubbly (B), churn turbulent (CT), and elongated water drop (EWD). The kerosene holdup was highest for EWD, spanning from 0.8 to 0.9, followed by CT and CA, which spans from 0.35 to 0.75. The kerosene holdup for bubbly spans from 0.12 to 0.6, being the highest range for all patterns. The phase inversion occurs when the kerosene input fraction is beta(K) = 0.35. There is no evidence of slippage between the dispersed and continuous phases. The drift velocity is due to the misalignment of the dispersed fraction and the mixture velocity profile and the distribution parameter is C-0=1.10. The pressure loss showed a good agreement with Blasius correlation. The exception is for the bubbly and churn turbulent. The density was determined using the homogeneous model and five different mixture viscosity models were investigated. The pressure loss deviation using (Mukhaimer et al., 2015) mixture viscosity spans from 5 to 25%. The drift-flux correlation increase the predictive capability of the oil fractions in oil pipelines, which contribute to the operational security. In addition, a better pressure drop losses estimative provide in this study helps to a better oil pipeline design.",2,2,1
Two-phase Flow,Flow Behavior,"Zaidani, Mouna; Hasan, Amena; Al-musharfy, Mohamed; Sassi, Mohamed",Numerical investigation of surface wettability on gas - Liquid flow hydrodynamics in microchannel: Application to trickle bed reactors,Two-phase flow; Microchannel; Surface wettability; Flow characterization; Trickle bed reactor (TBR),VERTICAL 2-PHASE FLOW; REGIME TRANSITIONS; CONTACT-ANGLE; HEAT-TRANSFER; DIAMETER; PATTERN; SIMULATION; MICROFLUIDICS,"Two-phase gas-liquid flows are very important in trickle bed catalytic reactors. To investigate the effect of catalyst wettability on the two-phase flow hydrodynamics in the bed, microchannels are considered in order to simulate the pore scale phenomena. Since the surface area to volume ratio is a key factor at the microscale, the role of surface interaction becomes dominant. In this work, the channel hydrophobicity is varied in order to study the effect of the wetting properties of a rectangular horizontal micro-channel on the gas-liquid two-phase flow behavior. Air and water are injected through a Y junction microchannel where water is injected in the middle and air from side inlets, to investigate the air/water two-phase flow behavior in the straight section. The surface wettability of two types of catalysts is experimentally measured and used as input to the numerical computational model. The microchannel is of 300 mu m, 100 mu m and 1 cm in width, height and length, respectively. The CFD simulation is done on COMSOL Multiphysics, using the Level Set method. The level-set technique is used to represent a discrete fluid interface between the two phases. Navier Stokes equations and conservation of mass, coupled to the level set method keep track of the interface between the air and water in the flow field, including the interfacial interactions with the microchannel walls. The developed numerical model is used to characterize the hydrodynamics of cocurrent gas-liquid flow through the microchannel. The model was validated against published experimental data and good agreements are obtained. The prediction results demonstrate that the wetting properties of the microchannel affect drastically the two-phase flow hydrodynamic behaviors. We identified eight different flow patterns in the hydrophobic microchannel, whereas, in the case of hydrophilic microchannel, only two flow patterns were observed. All of these results were in good agreement with published experimental ones. The developed numerical model was thus used to predict trickle bed flow hydrodynamics at the microscale.",2,2,5
Two-phase Flow,Flow Behavior,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Two-phase Flow,Flow Behavior,"Gholamzadeh, Younes; Sharifi, Mohammad; Karkevandi-Talkhooncheh, Abdorreza; Moraveji, Mostafa Keshavarz",A new physical modeling for two-phase wellbore storage due to phase redistribution,Well testing; Phase redistribution; Build-up test; Gas dissolution; Non-ideal wellbore storage; Modeling; Pressure hump,PRESSURE BUILDUP ANALYSIS; FLOW,"Pressure transient analysis is one of the main dynamic sources for reservoir characterization. The main task in well test interpretation is to understand the reservoir properties using the bottom-hole pressure behavior. Unfortunately, one of the main factors that can affect this task is wellbore storage effects, especially in cases that we have a non-ideal one. In pressure build-up test if pressure is below the bubble point or if gas enters into the wellbore, the phase redistribution can happen during the shut-in period. This phenomenon causes pressure anomalies. Besides, due to pressure increase or existence of under-saturated liquid in the wellbore, the gas starts to dissolve, and it is led to pressure decrease. So the pressure build-up test is dominated by three main factors: firstly, the pressure increase resulted from build-up test. Secondly, the pressure increase due to phase redistribution. Finally, the pressure decrease due to gas dissolution. These effects are known as non-ideal wellbore storage. Most of the studies focused on non-ideal wellbore storage try to propose an empirical equation to simulate the pressure curve more accurately instead of proposing an analytical model, because of the large number of effective parameters in an actual case. This paper is proposing a new analytical model for changing wellbore storage and analysis of gas phase segregation during the pressure build-up test in the existence of the under-saturated liquid. This model is further modified for two-phase flow when pressure falls below the bubble point in the wellhead. When the well is shut in at the start of build-up test, gas bubbles travel upward because of the buoyancy force. This model is presented for the case of dissolving gas pockets while rising in the wellbore. The novelty of this paper in comparison to previous researches is in developing a new physical model for two-phase wellbore storage done by modeling pressure increase due to gas bubbles rise while modeling gas dissolution against time. In this study, first, the basic assumptions for simplifying the model are described and the basic theory behind the proposed model is explained. Then a simple model without gas dissolution, using Laplace transformation, is introduced. Next, the modified model considering gas dissolution effect is proposed. A synthetic case is considered and the corresponding well test type curves are generated using the proposed method. Finally, the comparison between the proposed model and a real build-up case is made. The result is consistent with the typical non-ideal wellbore storage that is seen in the literature.",2,2,0
Two-phase Flow,Flow Behavior,"Andreolli, I; Azevedo, G. R.; Balino, J. L.",Application of stability solver for severe slugging considering a choking device and a tubing connected to a Wet Christmas Tree,Stability solver; Severe slugging; Petroleum production; Three-phase flow; Choking; Tubing,FLOW-RATE; SIMULATION,"This work is an improvement of a previous work (Andreolli et al. 2018) by including a tubing as a subsystem of the pipeline-riser system, a realistic choke valve model to predict the two-phase critical flow and pressure drop before the separator and boundary conditions between stretches of the geometry, in order to improve the determination of the stability boundary. The improved stability solver is applied for a three phase flow (gas, oil and water). Stability for operational points obtained from actual measurements are successfully predicted with the stability maps generated by the solver considering the tubing connected to the Wet Christmas Tree (WCT). A parametric analysis is made in order to evaluate a choke valve influence over stability maps. The stability maps are built by using field conditions at Santos and Campos basins (Brazil). The numerical results present a good agreement with numerical data and real operational conditions. The analysis to evaluate and verify the choke valve influence over stabilization shows a good agreement with the expected behavior.",1,1,3
Two-phase Flow,Boundary,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Two-phase Flow,Boundary,"Zhang, Dailu; Zhang, Hongbing; Rui, Jianwen; Pan, Yixin; Liu, Xingbin; Shang, Zuoping",Prediction model for the transition between oil-water two-phase separation and dispersed flows in horizontal and inclined pipes,Stratified flow; Annular flow; Dispersed flow; Mixed froude number; Prediction model of transition,DROPLET ENTRAINMENT,"There are two important flow patterns associated with horizontal and deviated wells: separation flows, which include stratified and annular flows, and dispersed flows. Because various types of flow patterns often exchange with each other under certain conditions, it is of great significance for improving the efficiency of oil transportation to develop prediction models describing the transition between oil-water stratified and annular or dispersed flows. Owing to the variable flow rate, water content, and pipeline inclination, the transition characteristics and prediction models for the transition from stratified to annular or dispersed flows are not clear. Therefore, in this study, relevant experiments were carried out and the transition characteristics were investigated to establish a new prediction model. In the transition from a stratified to annular flow, the prediction model for the transition boundaries and criteria is based on mixed Froude numbers. In contrast to previous studies, it was found in these experiments that the mixed Froude number is not constant when conversion between stratified flow and annular flow occurs. Instead, the mixed Froude number is related to the inlet water content and the pipeline inclination. The transition boundaries predicted by the proposed model are in good agreement with the experimental results. Based on the existing two-dimensional interfacial wave shearing mechanism, the three-dimensional interfacial wave shear deformation mechanism is elucidated. In the transition from stratified to dispersed flows, the external force on the flow direction of the interfacial wave, which includes the drag force, interfacial tension, gravity, and buoyancy, is theoretically derived by analysing the force situation before and after deformation of the two-phase interfacial wave. A prediction model for the deformation of the interfacial wave is developed, and the relationships between the external force and wave amplitude or wavelength are analysed with the prediction model. The results indicate that deformation is more likely to occur as the inclination angle of the well increases, the interfacial wave becomes unstable with increasing amplitude, and droplet formation occurs with long waves.",3,3,4
Two-phase Flow,Boundary,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Two-phase Flow,Boundary,"Andreolli, I; Azevedo, G. R.; Balino, J. L.",Application of stability solver for severe slugging considering a choking device and a tubing connected to a Wet Christmas Tree,Stability solver; Severe slugging; Petroleum production; Three-phase flow; Choking; Tubing,FLOW-RATE; SIMULATION,"This work is an improvement of a previous work (Andreolli et al. 2018) by including a tubing as a subsystem of the pipeline-riser system, a realistic choke valve model to predict the two-phase critical flow and pressure drop before the separator and boundary conditions between stretches of the geometry, in order to improve the determination of the stability boundary. The improved stability solver is applied for a three phase flow (gas, oil and water). Stability for operational points obtained from actual measurements are successfully predicted with the stability maps generated by the solver considering the tubing connected to the Wet Christmas Tree (WCT). A parametric analysis is made in order to evaluate a choke valve influence over stability maps. The stability maps are built by using field conditions at Santos and Campos basins (Brazil). The numerical results present a good agreement with numerical data and real operational conditions. The analysis to evaluate and verify the choke valve influence over stabilization shows a good agreement with the expected behavior.",1,1,3
Two-phase Flow,Contact Angle,"Khodadadi, Behayeen; Siddiqui, Mohammed Abdul Qadeer; Pirzada, Muhammad Asad; Le-Hussain, Furqan; Iglauer, Stefan; Roshan, Hamid",Direct observation of two-phase flow in deformable fractures of shales: A Utica shale example,Shale; Fracture; Microfluidic; Two-phase flow; Wettability; Utica; Deformation,DYNAMIC CONTACT-ANGLE; SURFACE WETTABILITY; CAPILLARY RISE; ROUGHNESS; ROCK; IMBIBITION; DEPENDENCE; INSIGHTS; WATER,"Despite the success of hydrocarbon production from unconventional shale reservoirs, the physical processes controlling the production are not yet fully understood. The wettability controlling the two-phase flow in deformable natural fractures of shale is among the processes that still need special attention. With the advances of optical technologies, microfluidics can now be used to observe, measure, and analyse the dynamic changes of flow in fractured systems. However, mimicking the natural wall roughness of the fractures with high precision and having flexibility to allow fracture deformation has remained challenging. We have therefore developed a new microfluidic technique to create tensile fractures in shale with subsurface representative random geometries and roughness, and then observed two-phase flow in these deformable fractures at a high resolution for Utica shale. During the two-phase flow, dynamic contact angles of water-oil in the fractures with varying apertures of 60-100 mu m were measured and analysed. Significant contact angle hysteresis was observed when oil displaced water out of the fracture and vice versa. Interestingly, water completely displaced the oil out of the fracture through spontaneous imbibition, although its contact angle in the fracture varied from 20 degrees to 90 degrees. The water velocity in the fracture was found to be correlated to the observed contact angles during the spontaneous imbibition test. The large change in the contact angle was further investigated using fluorescence tracking where patches of oil were observed to remain on the fracture wall despite its water wetness. It was then shown through further investigations that the formation of these oil patches was primarily controlled by mineral heterogeneity than wall roughness.",3,3,4
Two-phase Flow,Contact Angle,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Two-phase Flow,Contact Angle,"Zaidani, Mouna; Hasan, Amena; Al-musharfy, Mohamed; Sassi, Mohamed",Numerical investigation of surface wettability on gas - Liquid flow hydrodynamics in microchannel: Application to trickle bed reactors,Two-phase flow; Microchannel; Surface wettability; Flow characterization; Trickle bed reactor (TBR),VERTICAL 2-PHASE FLOW; REGIME TRANSITIONS; CONTACT-ANGLE; HEAT-TRANSFER; DIAMETER; PATTERN; SIMULATION; MICROFLUIDICS,"Two-phase gas-liquid flows are very important in trickle bed catalytic reactors. To investigate the effect of catalyst wettability on the two-phase flow hydrodynamics in the bed, microchannels are considered in order to simulate the pore scale phenomena. Since the surface area to volume ratio is a key factor at the microscale, the role of surface interaction becomes dominant. In this work, the channel hydrophobicity is varied in order to study the effect of the wetting properties of a rectangular horizontal micro-channel on the gas-liquid two-phase flow behavior. Air and water are injected through a Y junction microchannel where water is injected in the middle and air from side inlets, to investigate the air/water two-phase flow behavior in the straight section. The surface wettability of two types of catalysts is experimentally measured and used as input to the numerical computational model. The microchannel is of 300 mu m, 100 mu m and 1 cm in width, height and length, respectively. The CFD simulation is done on COMSOL Multiphysics, using the Level Set method. The level-set technique is used to represent a discrete fluid interface between the two phases. Navier Stokes equations and conservation of mass, coupled to the level set method keep track of the interface between the air and water in the flow field, including the interfacial interactions with the microchannel walls. The developed numerical model is used to characterize the hydrodynamics of cocurrent gas-liquid flow through the microchannel. The model was validated against published experimental data and good agreements are obtained. The prediction results demonstrate that the wetting properties of the microchannel affect drastically the two-phase flow hydrodynamic behaviors. We identified eight different flow patterns in the hydrophobic microchannel, whereas, in the case of hydrophilic microchannel, only two flow patterns were observed. All of these results were in good agreement with published experimental ones. The developed numerical model was thus used to predict trickle bed flow hydrodynamics at the microscale.",2,2,5
Two-phase Flow,Drift Flux,"Pugliese, Victor; Panacharoensawad, Ekarit; Ettehadtavakkol, Amin",Numerical study of the motion of a single elongated bubble in high viscosity stagnant liquids along pipelines,Multiphase flow; Drift flux model; Taylor bubble; High-viscosity oil; Drift velocity; Inclined pipes,DRIFT-FLUX MODEL; SLUG FLOW; MULTIPHASE FLOW; LONG BUBBLES; 2-PHASE FLOW; VELOCITY; CLOSURE; SIMULATION; EQUATIONS,"Multiphase flow models involve more variables than available equations, thus closure relationships are required to solve the system of partial differential equations. In the Drift Flux Model, the mean drift velocity of the gas phase is estimate using the drift velocity closure relationship. This study investigates the motion of a single elongated bubble in high viscosity stagnant liquids in order to propose a comprehensive closure relationship for the bubble drift velocity. Different cases were run with inclination angles varying from 0 degrees (horizontal direction) to 90 degrees (vertical upward). OpenFOAM, an open source Computation Fluid Dynamics software, was used to numerically solve the two-phase incompressible flow problem. Drift velocities based on the movement of the bubble tip and the void fraction weighted averaged were compared to clarify the ambiguity in the drift velocity calculation and measurement. For horizontal pipe cases, the deformation of the bubble caused the drift velocity to be higher at the tip of the bubble than the drift velocity inside the bubble. For inclination angles more than 0 degrees, the drift velocity at the tip is the same as inside the bubble. The closure relationship proposed is validated against experimental data in the literature. The results indicate that the closure relationship has a maximum 10% absolute average relative error for the viscosity range of 0.14-1.120 Pa.s, pipe size up to 0.152 m and pipe inclinations from 0 degrees to 90 degrees. The limitations of the closure relationship and potential enhancements for future studies are discussed.",2,2,2
Two-phase Flow,Drift Flux,"Mazza, Ricardo A.; Suguimoto, Fabio K.",Experimental investigations of kerosene-water two-phase flow in vertical pipe,Water-oil flow; Flow patterns; Pressure drop; Oil fraction; Drift-flux correlation,LIQUID-LIQUID UPFLOW; OIL-WATER; PHASE INVERSION; PRESSURE-DROP; VELOCITY; HOLDUP; PATTERN; SUSPENSIONS; VISCOSITY; FRACTION,"Oil and water two-phase flow studies are important to the oil industries. This paper aims to determine the flow patterns, holdup, pressure losses, phase inversion, drift flux parameters and mixture properties in vertical upward kerosene and water flow. The experiment was conducted in a 26 mm i.d duct with phase velocities spanning from 0.1 to 1.0 m/s. The averaged holdup was measured using quick close valves in a 1.16 m long test section. The same test section was used to measure the pressure drop. A local impedance probe and high-speed films were used to determine the flow patterns. Six different flow patterns was identified: dispersed bubbly (DB), core annular (CA), bubbly (B), churn turbulent (CT), and elongated water drop (EWD). The kerosene holdup was highest for EWD, spanning from 0.8 to 0.9, followed by CT and CA, which spans from 0.35 to 0.75. The kerosene holdup for bubbly spans from 0.12 to 0.6, being the highest range for all patterns. The phase inversion occurs when the kerosene input fraction is beta(K) = 0.35. There is no evidence of slippage between the dispersed and continuous phases. The drift velocity is due to the misalignment of the dispersed fraction and the mixture velocity profile and the distribution parameter is C-0=1.10. The pressure loss showed a good agreement with Blasius correlation. The exception is for the bubbly and churn turbulent. The density was determined using the homogeneous model and five different mixture viscosity models were investigated. The pressure loss deviation using (Mukhaimer et al., 2015) mixture viscosity spans from 5 to 25%. The drift-flux correlation increase the predictive capability of the oil fractions in oil pipelines, which contribute to the operational security. In addition, a better pressure drop losses estimative provide in this study helps to a better oil pipeline design.",2,2,1
Two-phase Flow,Stability,"Jing, Jiaqiang; Du, Mingjun; Yin, Ran; Wang, Yahui; Teng, Yu",Numerical study on two-phase flow characteristics of heavy oil-water ring transport boundary layer,Heavy oil; Drag reduction; Boundary layer; Oil-water two-phase; Microscopic characteristics,CFD SIMULATION; VISCOSITY,"Studying the characteristics of two-phase flow of heavy oil-water ring transportation is of great significance for determining the structure of heavy oil flow in the bottom layer and the core area of the boundary layer, and establishing an optimal drag reduction model. Based on experimental research, the effects of key factors such as density difference, viscosity difference, velocity difference, and interfacial tension difference between oil and water on the stability and pressure drop of water ring are numerically analyzed. The result shows that there is basically no velocity gradient in the core area of heavy oil during heavy oil-water ring transportation, which can be approximated as the elastic solid, and the water phase friction has a greater impact on the pipe pressure drop. Only the difference in oil-water density will affect the formation of an eccentric water ring, and when only considering the effect of density, the eccentric water ring pressure drop is reduced to the concentric water ring pressure drop. When analyzing the effect of heavy oil viscosity, it is concluded that the oil-water viscosity difference is kept within a certain range, which can maintain stable flow, and the pressure drop of the pipe decreases slightly with the decrease of the viscosity of the heavy oil. By studying the oil-water two-phase velocity difference, it is found that no matter whether oil and water are at the same velocity, or the oil is faster or slower than water, there must be an optimal flow rate to make the heavy oil-water ring transportation stable and efficient. And the velocity is the most critical factor affecting eccentricity. In addition, appropriately increasing the oil-water interfacial tension can reduce the eccentricity and improve water ring stability.",3,3,5
Two-phase Flow,Stability,"Andreolli, I; Azevedo, G. R.; Balino, J. L.",Application of stability solver for severe slugging considering a choking device and a tubing connected to a Wet Christmas Tree,Stability solver; Severe slugging; Petroleum production; Three-phase flow; Choking; Tubing,FLOW-RATE; SIMULATION,"This work is an improvement of a previous work (Andreolli et al. 2018) by including a tubing as a subsystem of the pipeline-riser system, a realistic choke valve model to predict the two-phase critical flow and pressure drop before the separator and boundary conditions between stretches of the geometry, in order to improve the determination of the stability boundary. The improved stability solver is applied for a three phase flow (gas, oil and water). Stability for operational points obtained from actual measurements are successfully predicted with the stability maps generated by the solver considering the tubing connected to the Wet Christmas Tree (WCT). A parametric analysis is made in order to evaluate a choke valve influence over stability maps. The stability maps are built by using field conditions at Santos and Campos basins (Brazil). The numerical results present a good agreement with numerical data and real operational conditions. The analysis to evaluate and verify the choke valve influence over stabilization shows a good agreement with the expected behavior.",1,1,3
Two-phase Flow,Finite Volume Method,"Galindez-Ramirez, G.; Contreras, F. R. L.; Carvalho, D. K. E.; Lyra, P. R. M.",Numerical simulation of two-phase flows in 2-D petroleum reservoirs using a very high-order CPR method coupled to the MPFA-D finite volume scheme,Oil-water displacements; Anisotropic and heterogeneous petroleum reservoirs; High-order approximations; Multipoint Flux Approximation with Diamond Stencil (MPFA-D); Correction Procedure via Reconstruction (CPR); Multidimensional Limiting Process (MLP),DISCONTINUOUS GALERKIN METHODS; POROUS-MEDIA; ELEMENT-METHOD; RECONSTRUCTION; ACCURACY; IMPLICIT; APPROXIMATIONS; FORMULATION; VELOCITY; MESHES,"The focus of the present work is to model the two-phase flow of oil and water in 2-D anisotropic petroleum reservoirs using a novel appropriate combination of a non-orthodox cell-centered Multipoint Flux Approximation with a Diamond Stencil (MPFA-D) finite volume method to discretize the pressure equation coupled to the very high-resolution Correction Procedure via Reconstruction (CPR) scheme for the discretization of the saturation equation. To suppress numerical oscillations (under/overshoots) near shocks, that are typical in higher-order schemes, and to deliver high accuracy in smooth regions of the solution, a hierarchical Multidimensional Limiting Process (MLP) is used in the reconstruction stage. The integration in time is carried out using a third-order Runge-Kutta method. The coupling of the pressure-saturation set of equations is carried out using a classical Implicit Pressure Explicit Saturation (IMPES) procedure. To properly couple the MPFA-D method with the CPR formulation, it is necessary to obtain an adequate velocity reconstruction throughout the control volumes of the mesh. Because the cell-centered finite volume method naturally delivers fluxes across control surfaces of the primal grid, then, we use a reconstruction operator based on the lowest order Raviart-Thomas interpolation functions and the Piola transformation, to get the complete knowledge of the velocity field throughout the domain. Finally, some representative problems were solved to evaluate the accuracy, efficiency, and shock-capturing capabilities of our new numerical methodology.",3,3,0
Two-phase Flow,Finite Volume Method,"Garmroodi, M. R. Daneshvar; Ahmadpour, A.",Numerical simulation of stratified waxy crude oil and water flows across horizontal pipes in the presence of wall heating,Waxy crude oil-water flow; Viscoplastic fluids; Stratified flow; Volume of fluid (VOF); Wall heating,2-PHASE TURBULENT-FLOW; PRESSURE-GRADIENT; LIQUID FLOW; PIPELINES; PATTERNS; PREDICTION; INTERFACE; RESTART; LAMINAR,"In the present work, a 3D numerical study was carried out to investigate the stratified flow of waxy crude oil-water through a horizontal pipe with a contraction-expansion placed in its midsection. Moreover, a uniform heat flux was applied to the pipeline wall to investigate its effect on the overall pressure drop across the pipeline and the two-phase flow pattern. Waxy crude oils are highly viscous fluids, and they exhibit non-Newtonian viscoplastic flow behavior. The governing equations of such non-Newtonian multiphase flows were discretized and solved using the finite volume method on a structured numerical grid. The volume of fluid (VOF) method was utilized to capture the oil-water interface. Waxy crude oil flowed in the laminar regime while a turbulent water flow field was assumed, and it was modeled using the well-known SST k-omega turbulence model. The effect of several parameters, such as heat flux, wax content of the crude oil, and oil inlet velocity, have been studied comprehensively. The results revealed that the overall pressure drop was extremely sensitive to the wax content. Moreover, the simulation results indicated that using a relatively low uniform heat flux can reduce the pressure drop, up to 25%. Finally, it is shown that by increasing oil velocity at the inlet, pressure drop monotonically increased.",2,2,3
Two-phase Flow,Flow Hydrodynamics,"Zaidani, Mouna; Hasan, Amena; Al-musharfy, Mohamed; Sassi, Mohamed",Numerical investigation of surface wettability on gas - Liquid flow hydrodynamics in microchannel: Application to trickle bed reactors,Two-phase flow; Microchannel; Surface wettability; Flow characterization; Trickle bed reactor (TBR),VERTICAL 2-PHASE FLOW; REGIME TRANSITIONS; CONTACT-ANGLE; HEAT-TRANSFER; DIAMETER; PATTERN; SIMULATION; MICROFLUIDICS,"Two-phase gas-liquid flows are very important in trickle bed catalytic reactors. To investigate the effect of catalyst wettability on the two-phase flow hydrodynamics in the bed, microchannels are considered in order to simulate the pore scale phenomena. Since the surface area to volume ratio is a key factor at the microscale, the role of surface interaction becomes dominant. In this work, the channel hydrophobicity is varied in order to study the effect of the wetting properties of a rectangular horizontal micro-channel on the gas-liquid two-phase flow behavior. Air and water are injected through a Y junction microchannel where water is injected in the middle and air from side inlets, to investigate the air/water two-phase flow behavior in the straight section. The surface wettability of two types of catalysts is experimentally measured and used as input to the numerical computational model. The microchannel is of 300 mu m, 100 mu m and 1 cm in width, height and length, respectively. The CFD simulation is done on COMSOL Multiphysics, using the Level Set method. The level-set technique is used to represent a discrete fluid interface between the two phases. Navier Stokes equations and conservation of mass, coupled to the level set method keep track of the interface between the air and water in the flow field, including the interfacial interactions with the microchannel walls. The developed numerical model is used to characterize the hydrodynamics of cocurrent gas-liquid flow through the microchannel. The model was validated against published experimental data and good agreements are obtained. The prediction results demonstrate that the wetting properties of the microchannel affect drastically the two-phase flow hydrodynamic behaviors. We identified eight different flow patterns in the hydrophobic microchannel, whereas, in the case of hydrophilic microchannel, only two flow patterns were observed. All of these results were in good agreement with published experimental ones. The developed numerical model was thus used to predict trickle bed flow hydrodynamics at the microscale.",2,2,5
Two-phase Flow,Flow Hydrodynamics,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Two-phase Flow,Shock Waves,"Apolinario, Felipe de O.; de Paula, Analia S.; Pires, Adolfo P.",Injection of water slug containing two polymers in porous media: Analytical solution for two-phase flow accounting for adsorption effects,Enhanced oil recovery; Chemical enhanced oil recovery; Polymer flooding; Conservation laws; Hyperbolic systems of partial differential equations,MULTICOMPONENT FLOW; HYPERBOLIC SYSTEM; OIL DISPLACEMENT; RIEMANN PROBLEM,"Polymer flooding is the most applied chemical method of enhanced oil recovery (EOR). Usually this process consists of injecting a slug containing dissolved chemicals displaced by water. This technique is modeled by a system of conservation laws with constant initial condition and not constant boundary conditions. In this paper we extend the two solute one-dimensional chromatography problem solution (Rhee et al., 2001) for a two-phase environment. The exact solution for the injection of a slug containing two dissolved polymers driven by water in an oil reservoir is developed. It is considered that both polymers may adsorb in porous media following Langmuir' s adsorption isotherm. The solution is built splitting the original system into a purely chromatographic problem (auxiliary system), and a lifting equation that considers the hydrodynamics properties of the system. Due to the chase water drive, interactions between waves arise along the space-time plane and change the path of the characteristics at the rear of the slug. The presented solution is composed by rarefaction and shock waves, and constant states. Moreover, a complete chromatography cycle develops in the porous media (complete separation of the chemical components).",2,2,0
Two-phase Flow,Shock Waves,"Kiran, Raj; Elgaddafi, Rida; Ahmed, Ramadan; Salehi, Saeed; Griffith, Craig A.; Fajemidupe, Taye",Wellbore fluid sonic conditions during blowouts,Worst-case discharge; Two-phase flow; Pressure drop; Sonic condition; Nodal analysis,LIQUID 2-PHASE FLOW; DIAMETER; SPEED; SOUND; MODEL; OIL; AIR,"The understanding of high-velocity two-phase flow is critical for predicting worst-case discharge scenarios. During a blowout, the fluid discharge rate can be very high, and its velocity may reach the sonic speed at the surface. Therefore, it is crucial to understand the fluid dynamics and flow characteristics of multiphase flow in the high-velocity range. In this investigation, two-phase (air-water) flow experiments were conducted to study the flow evolution in extreme high-velocities occurring during worst-case discharge. The experiments were performed in a vertical pipe section with a diameter of 83 mm and a length of 5.5 m. A fully transparent viewport was installed on the test section to monitor the flow pattern. The superficial gas velocities were ranging approximately from 8 to 160 m/s. During the test, the pressure gradient was monitored while increasing the gas rate at a constant liquid rate. Under subsonic conditions, the pressure gradient increase with superficial gas velocity indicating the establishment of friction dominated flow regime. However, the pressure-gradient trend changed when shock waves formed in the test section. With increasing the superficial gas velocity at a given liquid rate, the pressure gradient attained its maximum when flow transition occurred and shock waves formed in the test section, which were observed through the viewport. Under sonic conditions, increasing the superficial gas velocity a constant liquid flow rate reduced the pressure-gradient. After examining various two-phase flow sonic velocity models and measurements, a new correlation has been developed to predict sonic conditions during worst-case discharge. Experimental results are compared with predictions of existing wave propagation models and demonstrated reasonable agreement. Subsequently, a computational tool has been developed to estimate fluid flow rates for worst-case discharge scenarios involving sonic flow conditions. The new correlation has been implemented in the computational tool to forecast the establishment of sonic flow conditions in the wellbore. The computational tool shows a reasonable agreement with commercial packages for basic worst-case discharge circumstances. A sensitivity analysis performed using the computational model suggests that the discharge rate varies with the in-situ parameters such as skin factor, pay-zone height, and reservoir permeability.",1,1,1
Sand,Sand Production,"Zhang, Yang; Lu, Fengming; Cai, Mingjun; Yang, Yongqiang; Li, Ji; Guo, Zhiqiao; Wang, Rui; Zheng, Rongji",Physical simulation experiments of remaining oil distribution and production in alluvial fans controlled by dynamic and static factors,Alluvial fan; Dynamic and static factors; Physical simulation experiment for water flooding; Remaining oil distribution and production; Cangdong sag,DEBRIS-FLOW; BASIN; FIELD; INTERCALATION; SEDIMENTATION; PERFORATION; RESERVOIRS; SATURATION; EVOLUTION; VALLEY,"In order to study the remaining oil distribution and production in alluvial fans controlled by both static geologic factors and dynamic development factors, 2D and 3D macroscopic physical models have been constructed for the alluvial fan reservoirs in the eastern part of Cangdong sag, Bohai Bay Basin, China. Through considering static reservoir architecture and dynamic displacement rate, perforation position, well type, and well pattern, 7 water flooding physical simulation experiments have been finished, and the remaining oil distribution and production in oilfields with ultra-high water cut controlled by both dynamic and static factors were revealed. The study shows that without considering the economic benefits, drilling horizontal well, drilling infilled vertical well, increasing displacement rate, and plugging off water flooded layers at the initial stage of ultra-high water cut exhibited decreased performance in remaining oil production. After the dynamic factors adjustment, the remaining oil distribution and production is mainly controlled by the interlayer position, reservoir rhythm and the combination relationship between dynamic and static factors. When more injector-producer groups are located in the same single sand body, and the oil wells are uniformly drilled in single sand of different types, the oil recovery efficiency will be higher, and the distribution of the remaining oil will be more uniform. According to the experimental results, the remaining oil controlled by braided sand island and braided river channel could be divided into three types, and the corresponding measures to tap the potential were proposed.",3,3,2
Sand,Sand Production,"Haftani, Mohammad; Kotb, Omar; Phuong Hoang Nguyen; Wang, Chenxi; Salimi, Mahmood; Nouri, Alireza",A Novel sand control testing facility to evaluate the impact of radial flow regime on screen performance and its verification,Sand retention testing; Full-scale completion testing facility; Sand control; Radial flow; SAGD,,"Optimum design of the sand control devices in oil sand reservoirs plays a vital role in minimizing the sand production and increasing the reservoir productivity in Steam-Assisted Gravity Drainage (SAGD) operations. Various sand control testing facilities have been developed to evaluate the performance of sand control screens, such as the pre-packed Sand Retention Test (SRT). Current testing apparatuses are based on the linear flow regime. However, fluid flow around SAGD production wells is radial flow, not linear. This study introduces a Full-scale Completion Test (FCT) facility to emulate the radial-flow condition in SAGD wells. Instead of using a disk-shaped screen coupon, this facility utilizes a cylindrical-shaped screen. A couple of tests were carried out to determine the flow uniformity inside the cell and identify the test repeatability. Test results show that flow is distributed uniformly inside the cell, and experiments are repeatable in terms of differential pressures, fines production, and sanding levels. Therefore, this innovative FCT experimental setup and procedure allows a more realistic evaluation of the liner performance by emulating the real SAGD flow regime around the liner. Testing results obtained from the FCT can be used to complement and validate the current testing procedures. These tools can be adopted for an objective custom-design and selection of standalone screens in SAGD.",3,3,1
Sand,Sand Production,"Garolera, Daniel; Carol, Ignacio; Papanastasiou, Panos",Application of zero-thickness interface elements to sanding prediction analysis,Sand production prediction; Sanding; Zero-thickness interfaces; Micromechanics; Localization; Cracking,MICROMECHANICAL ANALYSIS; BOREHOLE; FRACTURE; MODEL; LOCALIZATION; CRACKING,"A computational micromechanical analysis based on zero thickness interface elements for modelling solid prediction in hydrocarbon reservoir sandstones is presented. The model is capable of modelling localization of deformation, disintegration and cracking of cemented rock formation that leads to initiation and continuous sand production during hydrocarbon production and reservoir depletion. Using only few physical parameters, the model is calibrated at the macroscale by reproducing the typical behaviour of geomaterials in compression element tests that is characterized by transition from brittle dilatant to ductile compactant behaviour with increasing confining stress. In the presented application presented, the model was calibrated first using the results of two triaxial tests performed on samples that were recovered from a deep well and then a sand production analysis was carried out. The model predictions are compared well with the experimental results of thick wall cylinder tests. The proposed methodology is very promising as it can predict not only the initiation of sanding, but also the continuous produced sand volumes under geometry changing conditions which is still a challenging research problem.",3,3,1
Sand,Sand Production,"Yuan, Hemin; Han, De-hua; Li, Hui; Zhao, Luanxiao; Zhang, Weimin",The effect of rock frame on elastic properties of bitumen sands,Bitumen sands; Frame effect; Bitumen effect; Acoustic velocity,HEAVY; VELOCITIES; ORIGIN; ATTENUATION; RESERVOIRS; POROSITY,"Elastic properties of bitumen reservoir change dramatically during thermal production, due to varying temperature and pressure conditions, which affect both the pore fluid and the rock frame. The effect of bitumen on the elastic properties of bitumen sands is widely studied, while the frame effect is commonly ignored. The influence of frame under different pressure and temperature conditions is investigated through laboratory measurements. Natural and artificial samples are compared to investigate the role of rock frame in their elastic properties. Samples with the same bitumen but different porosities are also compared, which reveals that the distinctions between the samples vary with temperature. Theoretical models are also applied to inspect the influence of rock frame, indicating the weak frame. In the end, two samples from Alaska and Alberta are compared, justifying the roles of bitumen and rock frame during the heating process. Our results reveal that rock frame of bitumen sands is quite loose, which may even damage during the heating process; and its influence on the rock elastic property is temperature dependent: at low temperature, its influence is insignificant, while at high temperature, its contribution is more important. These results suggest that for seismic monitoring of bitumen reservoir production, we should emphasize the temperature effect at the early stage and pay more attention to the pressure effect at the later stage of thermal production.",3,3,0
Sand,Sand Production,"Murphy, A.; Soga, K.; Yamamoto, K.",Experimental investigation into sand production from turbidite strata,Sand production; Gas hydrates; Turbidites; Sediment transport; High pressure plane-strain apparatus; Particle image velocimetry (PIV),HYDRATE-BEARING SEDIMENT; EASTERN NANKAI TROUGH; PRODUCTION TEST-SITE; DAINI-ATSUMI KNOLL; DEFORMATION MEASUREMENT; STABILITY; MODEL; CORE; SIZE; FLOW,"This study investigates whether the heterogeneity of deepwater turbidite strata, particularly the layering and grainsize, could be contributing to catastrophic sand production during extraction of fluid from the subsurface through a wellbore. This type of sand production was seen from the producing interval over turbidite strata during the 2013 gas hydrate trial at the Daini-Atsumi Knoll, Nankai Trough, offshore Japan. To investigate this sand production, an apparatus was designed to simulate a plane-strain case of sand production in the openhole gravel packed hydrate production well. Two scenarios of turbidite strata grainsize and layering were tested in the apparatus. The results of these sand production experiments suggest that the layering and grain size variations of the turbidites encourages sanding. The sand production preferentially came from specific layers in the turbidite sequence. This behaviour was explained by the development of shear induced negative excess pore pressure in the silt layer in undrained conditions which created a slab effect and encouraged the creation of a high permeability zone below the layer. The increase in permeability and fluid flow velocity in this zone increased the carrying capacity of the fluid flow. Modified versions of surface sediment transport theories are able to describe the conservative estimate of this erosion and transport of sand.",3,4,0
Sand,Sand Production,"Gao, Xiaoyang; He, Wenxiang; Hu, Yong",Modeling of meandering river deltas based on the conditional generative adversarial network,Reservoir modeling; Meandering river delta; Artificial intelligence; Deep learning; Convolution neural network; Conditional generative adversarial network,SIMULATION,"Because the structure of delta reservoirs is too complex, the traditional modeling method cannot describe the delta reservoir model well, and the delta reservoir model cannot be directly applied to oilfield production. At present, the generative adversarial network (GAN) has been gradually applied to the field of reservoir modeling and has made some achievements, and the conditional generative adversarial network (CGAN) has been shown to provide a theoretical basis for solving the problem of the generated reservoir model being too free. Based on CGAN theory, a new reservoir modeling scheme of the meandering river delta is proposed in this study, taking the meandering river delta sedimentary area in the western slope zone of the Xihu Depression as an example. Because the reservoir model generated by the traditional CGAN theory encounters difficulty in achieving the expected effect, a new improvement scheme based on the traditional CGAN is proposed: The delta model obtained from CGAN process and the original real delta reservoir model are recombined into a new data set. The CGAN training process is repeated again, and a more accurate and complete delta reservoir model is generated by iterating many times. The results show that this modeling method overcomes the shortcomings of the traditional delta modeling method and improves the accuracy of the generated model, which provides a new idea for the delta reservoir sand body modeling.",2,2,6
Sand,Sand Production,"Kozhagulova, Ashirgul; Nguyen Hop Minh; Zhao, Yong; Fok, Sai Cheong",Experimental and Analytical Investigation of Sand Production in Weak formations for Multiple Well Shut-Ins,Weak formation; Sand production; Experimental testing; Analytical prediction; Well shut-in; Ustyurt-Buzachi,ROCK FAILURE; MODEL; PRESSURE; CRITERIA; ONSET,"Sand production is a severe problem in oilfields and is majorly associated with weak and unconsolidated formations. Therefore, identifying the expected amount and rate of sand has been approached by different analytical and numerical prediction methods. Within them the former requires less computational time and therefore being widely used. However, despite some of the analytical models proved to be fairly predictive for sand production during steady-state flow, they cannot be used directly for the wells with complex production profiles. The current study focuses on the experimental investigation of the sand production pattern during well production and shut-in periods. The laboratory work was conducted on artificial sandstone replicating weak Cretaceous formations in Kazakhstan using customized High Pressure Consolidation System (HPCS) for sand production experiments. HPCS accommodates a sandstone sample of a large diameter to diminish boundary effect when the fluid is injected. The tests were conducted at different overburden stresses as well as pressure drawdowns in several well shut-in runs. The paper presents a modification of the classical steady-state flow analytical solution incorporating field and fluid conditions as well as the dependence on the well shut-in runs. The model showed good convergence with the experimental and well data.",2,2,1
Sand,Sand Production,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Sand,Remaining Oil,"Zhang, Yang; Lu, Fengming; Cai, Mingjun; Yang, Yongqiang; Li, Ji; Guo, Zhiqiao; Wang, Rui; Zheng, Rongji",Physical simulation experiments of remaining oil distribution and production in alluvial fans controlled by dynamic and static factors,Alluvial fan; Dynamic and static factors; Physical simulation experiment for water flooding; Remaining oil distribution and production; Cangdong sag,DEBRIS-FLOW; BASIN; FIELD; INTERCALATION; SEDIMENTATION; PERFORATION; RESERVOIRS; SATURATION; EVOLUTION; VALLEY,"In order to study the remaining oil distribution and production in alluvial fans controlled by both static geologic factors and dynamic development factors, 2D and 3D macroscopic physical models have been constructed for the alluvial fan reservoirs in the eastern part of Cangdong sag, Bohai Bay Basin, China. Through considering static reservoir architecture and dynamic displacement rate, perforation position, well type, and well pattern, 7 water flooding physical simulation experiments have been finished, and the remaining oil distribution and production in oilfields with ultra-high water cut controlled by both dynamic and static factors were revealed. The study shows that without considering the economic benefits, drilling horizontal well, drilling infilled vertical well, increasing displacement rate, and plugging off water flooded layers at the initial stage of ultra-high water cut exhibited decreased performance in remaining oil production. After the dynamic factors adjustment, the remaining oil distribution and production is mainly controlled by the interlayer position, reservoir rhythm and the combination relationship between dynamic and static factors. When more injector-producer groups are located in the same single sand body, and the oil wells are uniformly drilled in single sand of different types, the oil recovery efficiency will be higher, and the distribution of the remaining oil will be more uniform. According to the experimental results, the remaining oil controlled by braided sand island and braided river channel could be divided into three types, and the corresponding measures to tap the potential were proposed.",3,3,2
Sand,Remaining Oil,"Feng, Xianhua; Stewart, Sean; Sartori, Larry; Hodges, Katherine",Understanding the effect of skim oil recycle on the water/oil separation in steam assisted gravity drainage operations,Demulsification; Demulsifiers; Water treatment; Dynamic optical fluid imaging; Particle size distribution; Steam assisted gravity drainage,INTERFACIAL BEHAVIOR; EMULSION; ASPHALTENES; DEMULSIFIER; SANDS,"In steam assisted gravity drainage (SAGD) operations, skim oil recycled to a free water knockout (FWKO) often results in poor water quality and rag formation at the oil/water interface. To improve water quality and demulsification efficiency in the presence of skim oil recycle, it is necessary to understand the status of oil and solids in the produced water throughout the process. In this paper, the effect of skim oil on the water/oil separation in SAGD operations was studied. Dynamic optical fluid imaging (DOFI) technology was used to characterize oil and solids concentrations, oil droplet sizes, and the associated size distributions in the produced water collected from various vessels in a SAGD process. The DOFI analyses show that skim oil recycle caused more oil and solids to be sent to the FWKO, treater and induced gas flotation (IGF) outlet waters and finally to oil removal filters (ORF). The increased oil in water led to more oil droplets, especially more numerous small oil droplets remaining in the produced water. These small oil droplets are more challenging to remove than larger oil droplets, resulting in deteriorated water quality. Skim oil recycle decreased the oil removal efficiency of the IGF vessel and increased fouling of ORF filters by oil and solids. Fourier transform infrared spectroscopy analysis of the solids collected from the produced water in the presence of skim oil recycle indicated that the solids are bitumen-coated fine quartz and clays. Demulsification studies show that application of dual reverse emulsion breakers could help improve water quality and alleviate the negative effects due to the solids from skim oil addition.",2,2,4
Sand,Remaining Oil,"Zhu, Chuanzhen; Gang, Wenzhe; Zhao, Xianzheng; Wang, Yifan; Chen, Guo; Pu, Xiugang","The preferential pathways of oil migration in the Qi-nan slope belt of Bohai Bay Basin, China: Insights from integrated analyses using geochemical and morphology tools",Oil family; Pyrrolic nitrogen compounds; Geochemical tracing of hydrocarbon migration; Preferential migration pathways; Qi-nan slope belt; Bohai Bay Basin,PYRROLIC NITROGEN-COMPOUNDS; PETROLEUM MIGRATION; HYDROCARBON MIGRATION; QIKOU SAG; BOZHONG SUBBASIN; ORDOS BASIN; CRUDE OILS; ACCUMULATION; FIELD; CONSTRAINTS,"The Qi-nan Slope belt is located in the southwestern Qikou Sag in the Bohai Bay Basin and has had relatively little oil and gas exploration. The mechanism of oil migration remains unclear due to the lack of understanding of the oil-oil relationship, the definition of oil migration pathways, and the controversy over the contributing source rocks. Based on hierarchical cluster analysis, the crude oils in the Qi-nan Slope are divided into three groups (A, B and C) with different geochemical compositions. Group A oils, including Class A(1) and Class A(2) biodegraded oils, and Group C oils are contributed by Es-1(x) and Es-3 source rocks with different organic facies, and distributions are limited to the WXZ oilfield in the western slope. Group B oils, including Class B-1 and Class B-2 biodegraded oils, mainly originated from Es-1(x) source rocks and are widely distributed in the southern slope. The significant correlation between the relative migration distance (RMD) of oils and pyrrolic nitrogen compounds, rather than the parameters related to oil maturity, indicates that the pyrrolic nitrogen compounds can effectively trace oil migration directions in the Qi-nan Slope, and 1,8-DMC/2,6-DMC is the best indicator. For oil migration conduits, no large-scale faults developed in the inner part of the slope, and the oil-gas test results from major wells on the seismic profiles suggest that oils are mostly concentrated in Es-1(x) with no obvious vertical migration in this area. Therefore, we speculate that the Es-1(x) sand body provided the migration pathway for crude oil and controlled its uneven accumulation in the slope area. The isopleth map of the 1,8-DMC/2,6-DMC ratio, the distribution characteristics of the oil test results from major wells and the morphology of the Es-1(x) transporting layer suggest that the overall migration direction of oil was dispersedly from the Qi-nan Sub-sag to the southern areas of the slope and that structural ridges provided preferential migration pathways for hydrocarbon accumulation.",2,2,2
Sand,Remaining Oil,Sun Zhifeng; Lin Chengyan; Du Dongxing; Bi Haisheng; Ren Huaiqiang,Application of seismic architecture interpretation in enhancing oil recovery in late development Stage-Taking meandering river reservoir in Dongying depression as an example,Meander belt; Sand body geometry; Coaxial morphology; Seismic architecture; Remaining oil distribution,BASIN; BELT; EVOLUTION; FAN,"Taking typical meandering river deposits of Ng(52+3) in the west 7th block of Gudong Oilfield as an example, the influence of point-bar-sandstone superposition structure on flooding law and remaining oil distribution is studied by means of seismic architecture interpretation under the guidance of point-bar geometry. Meanwhile, the influence of morphological parameters and lithology of lateral accretionary surfaces on remaining oil and development characteristics is discussed. The seismic waveform and amplitude of point-bar boundary sandstones are obvious when they overlap with each other. The connectivity of superimposed zones between boundary sand-bodies of point-bars is poor. The remaining oil near the superimposed zones is enriched when base-of-channel sandstone that infills abandonment (PI) and the earliest sandstone at the beginning of migration of the point bars (PI) superimposed with each other. Remaining oil is relatively not enriched when PI sandstones of point-bars are superimposed in superimposed zone. Remaining oil is relatively enriched in the upper point-bar sandstone at the superimposed zone. The effective shielding area effective distance to obstruct fluid flow of mudstone section of lateral accretionary surfaces is 50-80 m along the lateral direction of lateral-accretion surfaces, and the remaining oil is not enriched in the same point bar within the range of 50-80 m around oil and water wells. The physical property section of lateral-accretion surfaces in the middle and lower part of the surfaces has a certain blocking effect on flow and can obviously reduce the recovery degree. Seismic architectural interpretation plays an important role in predicting remaining oil enriched areas and prolonging oil field life in order to improve oil recovery.",1,1,4
Sand,Remaining Oil,"Chen, Tong; Leung, Juliana Y.; Bryan, Jonathan L.; Kantzas, Apostolos",Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes,Post-CHOPS; Solvent; Foamy oil; Heavy oil; Numerical simulation,SOLUTION-GAS DRIVE; HEAVY-OIL; RECOVERY; DEPLETION; MODEL; EQUATION; STATE,"Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency. First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow. The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties. Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.",1,1,2
Sand,Gravity Drainage,"Haftani, Mohammad; Kotb, Omar; Phuong Hoang Nguyen; Wang, Chenxi; Salimi, Mahmood; Nouri, Alireza",A Novel sand control testing facility to evaluate the impact of radial flow regime on screen performance and its verification,Sand retention testing; Full-scale completion testing facility; Sand control; Radial flow; SAGD,,"Optimum design of the sand control devices in oil sand reservoirs plays a vital role in minimizing the sand production and increasing the reservoir productivity in Steam-Assisted Gravity Drainage (SAGD) operations. Various sand control testing facilities have been developed to evaluate the performance of sand control screens, such as the pre-packed Sand Retention Test (SRT). Current testing apparatuses are based on the linear flow regime. However, fluid flow around SAGD production wells is radial flow, not linear. This study introduces a Full-scale Completion Test (FCT) facility to emulate the radial-flow condition in SAGD wells. Instead of using a disk-shaped screen coupon, this facility utilizes a cylindrical-shaped screen. A couple of tests were carried out to determine the flow uniformity inside the cell and identify the test repeatability. Test results show that flow is distributed uniformly inside the cell, and experiments are repeatable in terms of differential pressures, fines production, and sanding levels. Therefore, this innovative FCT experimental setup and procedure allows a more realistic evaluation of the liner performance by emulating the real SAGD flow regime around the liner. Testing results obtained from the FCT can be used to complement and validate the current testing procedures. These tools can be adopted for an objective custom-design and selection of standalone screens in SAGD.",3,3,1
Sand,Gravity Drainage,"Kim, Min; Shin, Hyundon",Numerical simulation of undulating shale breaking with steam-assisted gravity drainage (UB-SAGD) for the oil sands reservoir with a shale barrier,Shale barrier; Undulating shale breaking with steam-assisted; gravity drainage (UB-SAGD); Undulating drilling; Rotary-steerable system (RSS); Maximum NPV (M_NPV),OVER-SOLVENT INJECTION; HEAVY-OIL; RECOVERY; PERFORMANCE; PARAMETERS; WATER; INTEGRATION; BITUMEN; VAPEX; WELL,"A thick oil sands reservoir separated into two thin oil sands reservoirs by a shale barrier, particularly when the separated reservoir thickness is less than 10 m, is inefficient for economic steam-assisted gravity drainage (SAGD) applications. This paper proposes undulating shale breaking with SAGD (UB-SAGD) to develop this type of reservoir, and the trajectory of undulating drilling to break the shale was designed. In addition, sensitivity analysis was performed to evaluate the effects of the area and permeability of a breaking zone and steam injection pressure. The UB-SAGD is a novel in-situ recovery method that applies undulating drilling to break the shale in the parallel direction and the above SAGD well pairs. In addition, it adds an extra injector to facilitate thermal communication between the upper and lower parts of the shale barrier, and the steam chamber can be expanded into the upper the oil sands layer along a flow path. As the area and permeability of the breaking zone were increased, the recovery factor (RF) and maximum NPV (M_NPV) increased, and the cumulative steam-oil ratio (CSOR) decreased. A comparison of the low and high steam injection pressures revealed the M_NPV of high steam injection pressure to be higher than that of low steam injection pressure because a high injection pressure facilitates flow in a smaller area of the breaking zone. The RF and CSOR of best result were improved by 24.65% and 10.21%, respectively, compared to two well-pairs of SAGD without undulating drilling. In addition, the M_NPV of this result was $3.05 MM higher than that of two well-pairs. The UB-SAGD will be very useful for the economic development of shale interbedded oil sands reservoirs using conventional SAGD.",3,3,1
Sand,Gravity Drainage,"Feng, Xianhua; Stewart, Sean; Sartori, Larry; Hodges, Katherine",Understanding the effect of skim oil recycle on the water/oil separation in steam assisted gravity drainage operations,Demulsification; Demulsifiers; Water treatment; Dynamic optical fluid imaging; Particle size distribution; Steam assisted gravity drainage,INTERFACIAL BEHAVIOR; EMULSION; ASPHALTENES; DEMULSIFIER; SANDS,"In steam assisted gravity drainage (SAGD) operations, skim oil recycled to a free water knockout (FWKO) often results in poor water quality and rag formation at the oil/water interface. To improve water quality and demulsification efficiency in the presence of skim oil recycle, it is necessary to understand the status of oil and solids in the produced water throughout the process. In this paper, the effect of skim oil on the water/oil separation in SAGD operations was studied. Dynamic optical fluid imaging (DOFI) technology was used to characterize oil and solids concentrations, oil droplet sizes, and the associated size distributions in the produced water collected from various vessels in a SAGD process. The DOFI analyses show that skim oil recycle caused more oil and solids to be sent to the FWKO, treater and induced gas flotation (IGF) outlet waters and finally to oil removal filters (ORF). The increased oil in water led to more oil droplets, especially more numerous small oil droplets remaining in the produced water. These small oil droplets are more challenging to remove than larger oil droplets, resulting in deteriorated water quality. Skim oil recycle decreased the oil removal efficiency of the IGF vessel and increased fouling of ORF filters by oil and solids. Fourier transform infrared spectroscopy analysis of the solids collected from the produced water in the presence of skim oil recycle indicated that the solids are bitumen-coated fine quartz and clays. Demulsification studies show that application of dual reverse emulsion breakers could help improve water quality and alleviate the negative effects due to the solids from skim oil addition.",2,2,4
Sand,Gravity Drainage,"Wei, Yi-Ming; Qiao, Lu; Jiang, Shou-Ming; Lv, Xin",A decision-making approach considering technology progress for investment in oil sands projects: An empirical analysis in Canada,Oil sands; Investment evaluation; L-shaped NPV model,ASSISTED GRAVITY DRAINAGE; GREENHOUSE-GAS EMISSIONS; TECHNOECONOMIC ASSESSMENT; HYDROGEN-PRODUCTION; WESTERN CANADA; BITUMEN; ENERGY; MODEL; SCENARIO; EVALUATE,"This study presents a new decision-making approach for international oil firms to evaluate oil sands projects in Canada and examine the effects of technical progress on investment valuations. The results reveal that the linear net present value model in previous studies dramatically underestimates economic profits and the breakeven price estimated by the proposed approach (L-shaped NPV model) will be lower than US$50 per barrel for oil sands projects. This work also finds that some oil enterprises with advanced technology could reduce their oil sands exploration costs to approximately $32.73 per barrel. Furthermore, this study indicates that the profits from extraction cost reduction can cover the losses caused by some risk factors, such as exchange rates, inflation, and natural gas prices. The main contribution of this paper is to offer a flexible investment evaluation model that can assist oil companies in evaluating their own oil sands projects with different firm-specific technical progress characteristics.",1,1,1
Sand,Image,Yin Yanshu; Hu Xun; Huang Jixin; Feng Wenjie; Wang Linxin; Duan Taizhong; Zhao Lei; Zhang Wenbiao,"A three-dimensional model of deep-water turbidity channel in Plutonio oilfield, Angola: From training image generation, optimization to multi-point geostatistical modelling",Multi-point geostatistics; Training image; Alluvsim; Optimization method; The Plutonio oilfield in Angola,SIMULATION; RESERVOIRS; DISTANCE,"The deep-water turbidity channel system in the Oligocene O73 sand layer in the Plutonio oilfield in Angola of west Africa has good oil and gas reservoir capability. As the well spacing is large due to operation cost, and the seismic resolution of the target layer is relatively low, identification of turbidity channel boundary was difficult. To establishes a fine model is a problem faced by the modelers. In this paper, a complete multi-point geostatistical modeling flowchart is presented for the construction of fine deep-water turbidity channel model. According to the investigation of seismic, well logging, drilling data and references in the study area, the genesis, reservoir scale, lithofacies type, morphological characteristics and evolution of the deep-water turbidity channel of the target layer were obtained. The improved Alluvsim algorithm was utilized to generate a set of adaptive deep-water turbidity channel training images with specified curvatures. Net-to-gross, variogram and a high-order statistics method based on the single data event were compared to evaluate and sort the training images. Then, the Snesim method was utilized to construct the models using the sorted compatible training images with a same set of parameters. At last, the quality of different models was compared based on the seismic attribute slices and a composite correlation coefficient optimization method based on seismic data. The results suggest that the improved Alluvsim algorithm can reproduce the channel morphology and stacking patterns better. Compared with the first-order and second-order statistics comparison method, the method using higher-order statistics of single data event taken spatial patterns into consideration and sorted training images better. The reservoir model was established using the optimal selected training image which has a high correlation with seismic attributes, and the model is more consistent with the characteristics of subsurface reservoirs. At the same time, this paper also provides a complete research program for the application of multi-point geostatistical modeling method which is from training image generation, optimal training image selection and multi-point geostatistics modeling to realizations selection for practical subsurface reservoir modelling.",3,3,2
Sand,Image,"Murphy, A.; Soga, K.; Yamamoto, K.",Experimental investigation into sand production from turbidite strata,Sand production; Gas hydrates; Turbidites; Sediment transport; High pressure plane-strain apparatus; Particle image velocimetry (PIV),HYDRATE-BEARING SEDIMENT; EASTERN NANKAI TROUGH; PRODUCTION TEST-SITE; DAINI-ATSUMI KNOLL; DEFORMATION MEASUREMENT; STABILITY; MODEL; CORE; SIZE; FLOW,"This study investigates whether the heterogeneity of deepwater turbidite strata, particularly the layering and grainsize, could be contributing to catastrophic sand production during extraction of fluid from the subsurface through a wellbore. This type of sand production was seen from the producing interval over turbidite strata during the 2013 gas hydrate trial at the Daini-Atsumi Knoll, Nankai Trough, offshore Japan. To investigate this sand production, an apparatus was designed to simulate a plane-strain case of sand production in the openhole gravel packed hydrate production well. Two scenarios of turbidite strata grainsize and layering were tested in the apparatus. The results of these sand production experiments suggest that the layering and grain size variations of the turbidites encourages sanding. The sand production preferentially came from specific layers in the turbidite sequence. This behaviour was explained by the development of shear induced negative excess pore pressure in the silt layer in undrained conditions which created a slab effect and encouraged the creation of a high permeability zone below the layer. The increase in permeability and fluid flow velocity in this zone increased the carrying capacity of the fluid flow. Modified versions of surface sediment transport theories are able to describe the conservative estimate of this erosion and transport of sand.",3,4,0
Sand,Image,"Feng, Xianhua; Stewart, Sean; Sartori, Larry; Hodges, Katherine",Understanding the effect of skim oil recycle on the water/oil separation in steam assisted gravity drainage operations,Demulsification; Demulsifiers; Water treatment; Dynamic optical fluid imaging; Particle size distribution; Steam assisted gravity drainage,INTERFACIAL BEHAVIOR; EMULSION; ASPHALTENES; DEMULSIFIER; SANDS,"In steam assisted gravity drainage (SAGD) operations, skim oil recycled to a free water knockout (FWKO) often results in poor water quality and rag formation at the oil/water interface. To improve water quality and demulsification efficiency in the presence of skim oil recycle, it is necessary to understand the status of oil and solids in the produced water throughout the process. In this paper, the effect of skim oil on the water/oil separation in SAGD operations was studied. Dynamic optical fluid imaging (DOFI) technology was used to characterize oil and solids concentrations, oil droplet sizes, and the associated size distributions in the produced water collected from various vessels in a SAGD process. The DOFI analyses show that skim oil recycle caused more oil and solids to be sent to the FWKO, treater and induced gas flotation (IGF) outlet waters and finally to oil removal filters (ORF). The increased oil in water led to more oil droplets, especially more numerous small oil droplets remaining in the produced water. These small oil droplets are more challenging to remove than larger oil droplets, resulting in deteriorated water quality. Skim oil recycle decreased the oil removal efficiency of the IGF vessel and increased fouling of ORF filters by oil and solids. Fourier transform infrared spectroscopy analysis of the solids collected from the produced water in the presence of skim oil recycle indicated that the solids are bitumen-coated fine quartz and clays. Demulsification studies show that application of dual reverse emulsion breakers could help improve water quality and alleviate the negative effects due to the solids from skim oil addition.",2,2,4
Sand,Image,"Buckman, Jim; Chudi, Obinna; Lewis, Helen; Couples, Gary; Huang, Tianshen; Jiang, Zeyun","Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",Pore occlusion; Pore network model; Digital rock model; Quartz cementation; Permeability,,"Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36-51%, and the earlier Miocene samples have a porosity of around 18-35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234-1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",2,2,1
Sand,ORDOS Basin,"Duan, Yi; Wu, Yingzhong","Distribution and formation of Mesozoic low permeability underpressured oil reservoirs in the Ordos Basin, China",Ordos Basin; Mesozoic; Underpressured reservoirs; Formation,GROUNDWATER-FLOW; FLUID PRESSURES; ALBERTA; EVOLUTION; FIELD; SHALE,"The stratum pressure characteristics of Mesozoic reservoirs in the Ordos Basin were first studied. It was found that the Mesozoic reservoirs were mainly ultra-underpressured reservoirs with an average stratum pressure coefficient of 0.63-0.86 and the differences in the abnormal underpressure between the different regions and layers were distinct. The results showed that with increases in the eroded stratum thickness and temperature decrease in the reservoirs, the stratum pressure coefficients showed a decreasing trend. The pore water volume contraction in the Yanchang Formation was from 0.82% to 1.94% after tectonic uplift and stratum temperature reduction. It was proposed that because of the strong uplift of the basin for a long time at the end of the Cretaceous, the function of stratum erosion and paleotemperature reduction resulted in the formation of underpressured reservoirs. It is considered that this underpressured closed system of the Mesozoic in the Ordos Basin was advantageous for reservoir preservation and might have played an important role in adjustment, reenrichment of hydrocarbons by migration, and oil and water distribution in reservoirs. The formation of underpressured anhydrous sand lens reservoirs in the Chang 7 subsection could be related to the distribution of such an underpressured closed system.",2,2,2
Sand,ORDOS Basin,"Zhu, Chuanzhen; Gang, Wenzhe; Zhao, Xianzheng; Wang, Yifan; Chen, Guo; Pu, Xiugang","The preferential pathways of oil migration in the Qi-nan slope belt of Bohai Bay Basin, China: Insights from integrated analyses using geochemical and morphology tools",Oil family; Pyrrolic nitrogen compounds; Geochemical tracing of hydrocarbon migration; Preferential migration pathways; Qi-nan slope belt; Bohai Bay Basin,PYRROLIC NITROGEN-COMPOUNDS; PETROLEUM MIGRATION; HYDROCARBON MIGRATION; QIKOU SAG; BOZHONG SUBBASIN; ORDOS BASIN; CRUDE OILS; ACCUMULATION; FIELD; CONSTRAINTS,"The Qi-nan Slope belt is located in the southwestern Qikou Sag in the Bohai Bay Basin and has had relatively little oil and gas exploration. The mechanism of oil migration remains unclear due to the lack of understanding of the oil-oil relationship, the definition of oil migration pathways, and the controversy over the contributing source rocks. Based on hierarchical cluster analysis, the crude oils in the Qi-nan Slope are divided into three groups (A, B and C) with different geochemical compositions. Group A oils, including Class A(1) and Class A(2) biodegraded oils, and Group C oils are contributed by Es-1(x) and Es-3 source rocks with different organic facies, and distributions are limited to the WXZ oilfield in the western slope. Group B oils, including Class B-1 and Class B-2 biodegraded oils, mainly originated from Es-1(x) source rocks and are widely distributed in the southern slope. The significant correlation between the relative migration distance (RMD) of oils and pyrrolic nitrogen compounds, rather than the parameters related to oil maturity, indicates that the pyrrolic nitrogen compounds can effectively trace oil migration directions in the Qi-nan Slope, and 1,8-DMC/2,6-DMC is the best indicator. For oil migration conduits, no large-scale faults developed in the inner part of the slope, and the oil-gas test results from major wells on the seismic profiles suggest that oils are mostly concentrated in Es-1(x) with no obvious vertical migration in this area. Therefore, we speculate that the Es-1(x) sand body provided the migration pathway for crude oil and controlled its uneven accumulation in the slope area. The isopleth map of the 1,8-DMC/2,6-DMC ratio, the distribution characteristics of the oil test results from major wells and the morphology of the Es-1(x) transporting layer suggest that the overall migration direction of oil was dispersedly from the Qi-nan Sub-sag to the southern areas of the slope and that structural ridges provided preferential migration pathways for hydrocarbon accumulation.",2,2,2
Sand,ORDOS Basin,"Chai, Yibo; Lu, Jun; Chen, Benchi; Zhang, Tieqiang",Elastic parameter inversion of a sand body based on the exact reflection coefficient,AVA inversion; Jacobian matrix; Oil-gas exploration; Elastic parameter; Gas-bearing sandstone,AVO INVERSION; LEAST-SQUARES; SEISMIC DATA; WAVE; APPROXIMATIONS; ALGORITHM; EQUATIONS; GAS; PP,"Prestack seismic inversion is an important technology for oil and gas exploration that can provide accurate lithology and pore fluid information on underground media. Prestack inversion is theoretically based on the Zoeppritz equations, which establish the relationship between the seismic reflection coefficients of different offsets and elastic parameter contrasts between the interface of two lithologies. However, these are fourth-order matrix equations with a complex form and are difficult to be directly applied to inversion. Approximate analytical solutions have been used to establish a linear relationship between the seismic reflection coefficients and elastic parameters. And the approximations are based on the assumptions of a small angle and weak contrast, they cannot be applied to layers of high contrast, such as gas-bearing sandstones and coal seams. In this paper, we present an accurate prestack seismic inversion method that can be applied to a wider range of geological models. First, we derive the partial derivatives of the exact reflection coefficients of PP waves based on the Zoeppritz equations with respect to the elastic parameters and establish the exact Jacobian and Hessian matrices. Then, we use the least-squares algorithm to construct objective functions for the simultaneous inversion of three elastic parameters: The P-wave velocity, S-wave velocity, and density. Examples show that our inversion method is more accurate for strata with strong reflection interfaces than the approximate prestack inversion methods and stable under noisy conditions. The inversion method was applied in channel sand depositions of the Lower Permian Shanxi and Shihezi Formation of the Ordos Basin, and it was efficient to identify the gas-bearing sand layers and determine the range of potentially favorable areas.",1,1,1
Sand,Cement,"Garolera, Daniel; Carol, Ignacio; Papanastasiou, Panos",Application of zero-thickness interface elements to sanding prediction analysis,Sand production prediction; Sanding; Zero-thickness interfaces; Micromechanics; Localization; Cracking,MICROMECHANICAL ANALYSIS; BOREHOLE; FRACTURE; MODEL; LOCALIZATION; CRACKING,"A computational micromechanical analysis based on zero thickness interface elements for modelling solid prediction in hydrocarbon reservoir sandstones is presented. The model is capable of modelling localization of deformation, disintegration and cracking of cemented rock formation that leads to initiation and continuous sand production during hydrocarbon production and reservoir depletion. Using only few physical parameters, the model is calibrated at the macroscale by reproducing the typical behaviour of geomaterials in compression element tests that is characterized by transition from brittle dilatant to ductile compactant behaviour with increasing confining stress. In the presented application presented, the model was calibrated first using the results of two triaxial tests performed on samples that were recovered from a deep well and then a sand production analysis was carried out. The model predictions are compared well with the experimental results of thick wall cylinder tests. The proposed methodology is very promising as it can predict not only the initiation of sanding, but also the continuous produced sand volumes under geometry changing conditions which is still a challenging research problem.",3,3,1
Sand,Cement,"Liu, Chao; Sun, Lidong; Lu, Jiamin; Sun, Youhai; Xu, Yan; Lu, Mingxu; Li, Jijun","Characteristics of the newly found oil-bearing sandstone in the Denglouku formation of the northern Songliao Basin, China",Denlouku Formation; Oil; Reservoir; Controlling factors; Shuangcheng area; Songliao Basin,RESERVOIR QUALITY PREDICTION; TARANAKI BASIN; DIAGENESIS; POROSITY; PERMEABILITY; EVOLUTION; GAS; PRESSURE,"Over the past 50 years, exploration in the northern Songliao Basin has revealed that the sandstone in the Denglouku Formation is a tight gas reservoir. Oil-bearing reservoirs with good physical properties have only recently been discovered and have become the new focus of petroleum exploration. We carried out thin section observation, X-ray diffraction analysis, particle size analysis, mercury intrusion test, and stratigraphic burial history based on 377 core samples collected from the Denglouku Formation in the Shuangcheng area, where oil exploration has made a significant breakthrough. The results revealed the reservoir rock to be feldspathic sandstone and lithic feldspar sandstone, with the dominating interstitial materials of carbonates and mud matrix. The grain size ranged from silty sand to coarse sand. The pore types were primary intergranular pores and partial secondary dissolution pores. The porosity was generally 5%-20%, and the permeability was in a wide range of 0.1 mD to 2000 mD. Tectonic uplift prevented the sandstone from being deeply buried, which is an important reason for the good quality of the reservoir. Hydrocarbon filling improved the reservoir quality not only by forming dissolved pores but also by inhibiting carbonate cementation. The mud matrix and the carbonate cement decreased the reservoir quality, causing heterogeneity of the reservoir. This study indicated that the displacement pressure was effective in the classification of reservoirs that were characterized by good physical property and strong heterogeneity. The Denglouku reservoirs were divided into three classes. Favorable reservoirs (Class I and Class II) showed low displacement pressure because of the low mud matrix and carbonate cement and well-developed primary pores.",2,2,3
Sand,Cement,"Buckman, Jim; Chudi, Obinna; Lewis, Helen; Couples, Gary; Huang, Tianshen; Jiang, Zeyun","Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",Pore occlusion; Pore network model; Digital rock model; Quartz cementation; Permeability,,"Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36-51%, and the earlier Miocene samples have a porosity of around 18-35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234-1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",2,2,1
Sand,Porosity,"Yuan, Hemin; Han, De-hua; Li, Hui; Zhao, Luanxiao; Zhang, Weimin",The effect of rock frame on elastic properties of bitumen sands,Bitumen sands; Frame effect; Bitumen effect; Acoustic velocity,HEAVY; VELOCITIES; ORIGIN; ATTENUATION; RESERVOIRS; POROSITY,"Elastic properties of bitumen reservoir change dramatically during thermal production, due to varying temperature and pressure conditions, which affect both the pore fluid and the rock frame. The effect of bitumen on the elastic properties of bitumen sands is widely studied, while the frame effect is commonly ignored. The influence of frame under different pressure and temperature conditions is investigated through laboratory measurements. Natural and artificial samples are compared to investigate the role of rock frame in their elastic properties. Samples with the same bitumen but different porosities are also compared, which reveals that the distinctions between the samples vary with temperature. Theoretical models are also applied to inspect the influence of rock frame, indicating the weak frame. In the end, two samples from Alaska and Alberta are compared, justifying the roles of bitumen and rock frame during the heating process. Our results reveal that rock frame of bitumen sands is quite loose, which may even damage during the heating process; and its influence on the rock elastic property is temperature dependent: at low temperature, its influence is insignificant, while at high temperature, its contribution is more important. These results suggest that for seismic monitoring of bitumen reservoir production, we should emphasize the temperature effect at the early stage and pay more attention to the pressure effect at the later stage of thermal production.",3,3,0
Sand,Porosity,"Liu, Chao; Sun, Lidong; Lu, Jiamin; Sun, Youhai; Xu, Yan; Lu, Mingxu; Li, Jijun","Characteristics of the newly found oil-bearing sandstone in the Denglouku formation of the northern Songliao Basin, China",Denlouku Formation; Oil; Reservoir; Controlling factors; Shuangcheng area; Songliao Basin,RESERVOIR QUALITY PREDICTION; TARANAKI BASIN; DIAGENESIS; POROSITY; PERMEABILITY; EVOLUTION; GAS; PRESSURE,"Over the past 50 years, exploration in the northern Songliao Basin has revealed that the sandstone in the Denglouku Formation is a tight gas reservoir. Oil-bearing reservoirs with good physical properties have only recently been discovered and have become the new focus of petroleum exploration. We carried out thin section observation, X-ray diffraction analysis, particle size analysis, mercury intrusion test, and stratigraphic burial history based on 377 core samples collected from the Denglouku Formation in the Shuangcheng area, where oil exploration has made a significant breakthrough. The results revealed the reservoir rock to be feldspathic sandstone and lithic feldspar sandstone, with the dominating interstitial materials of carbonates and mud matrix. The grain size ranged from silty sand to coarse sand. The pore types were primary intergranular pores and partial secondary dissolution pores. The porosity was generally 5%-20%, and the permeability was in a wide range of 0.1 mD to 2000 mD. Tectonic uplift prevented the sandstone from being deeply buried, which is an important reason for the good quality of the reservoir. Hydrocarbon filling improved the reservoir quality not only by forming dissolved pores but also by inhibiting carbonate cementation. The mud matrix and the carbonate cement decreased the reservoir quality, causing heterogeneity of the reservoir. This study indicated that the displacement pressure was effective in the classification of reservoirs that were characterized by good physical property and strong heterogeneity. The Denglouku reservoirs were divided into three classes. Favorable reservoirs (Class I and Class II) showed low displacement pressure because of the low mud matrix and carbonate cement and well-developed primary pores.",2,2,3
Sand,Porosity,"Buckman, Jim; Chudi, Obinna; Lewis, Helen; Couples, Gary; Huang, Tianshen; Jiang, Zeyun","Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",Pore occlusion; Pore network model; Digital rock model; Quartz cementation; Permeability,,"Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36-51%, and the earlier Miocene samples have a porosity of around 18-35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234-1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",2,2,1
Sand,Inversion,"Zhang, Ji; Yuan, Han; Cheng, Liang; Mei, Ning",Inverse estimation of the sand concentration for sand-oil flow in a horizontal pipeline based on the Eulerian-Eulerian model,Sand-oil flow; Sand estimation; Volume fraction distribution; Eulerian-Eulerian model; Inverse heat transfer problem,HEAT-TRANSFER COEFFICIENTS; TRANSPORT CHARACTERISTICS; VELOCITY; LIQUID; IDENTIFICATION; SIMULATION; PARTICLES; SUSPENSIONS; LIMIT; FLUX,"A method that predicts the sand concentration and volume fraction distribution of sand-oil flow in a horizontal pipeline was proposed based on the inverse heat transfer problem theory. The forward problem of the convective heat transfer process for the sand-oil flow was investigated using a computational fluid dynamics (CFD) simulation based on the Eulerian-Eulerian model. The inverse problem of sand concentration estimation was solved using the temperature distributions at different measurement locations. The sand volume fraction was controlled by an inverse problem algorithm and optimized by inputting the external experiment temperature. Experiments with different sand concentrations were carried out to verify the accuracy of the inverse problem approach. Due to the inherent error between the simulation results and the actual experimental measurements, appropriate modifications in the inverse procedure were made in the input information to ensure that the CFD calculation was more consistent with the actual concentration data. The relative error of the sand concentration estimations could be controlled within 6.0% when the modified measurements were considered the input information of the inverse problem. The volume fraction distributions were also investigated in this study. The important variables that can impact flow temperatures, such as flow velocities and sand diameters, were investigated, and the results showed the inverse method is feasible for estimating the sand concentration of sand-oil flow.",1,2,5
Sand,Inversion,"Chai, Yibo; Lu, Jun; Chen, Benchi; Zhang, Tieqiang",Elastic parameter inversion of a sand body based on the exact reflection coefficient,AVA inversion; Jacobian matrix; Oil-gas exploration; Elastic parameter; Gas-bearing sandstone,AVO INVERSION; LEAST-SQUARES; SEISMIC DATA; WAVE; APPROXIMATIONS; ALGORITHM; EQUATIONS; GAS; PP,"Prestack seismic inversion is an important technology for oil and gas exploration that can provide accurate lithology and pore fluid information on underground media. Prestack inversion is theoretically based on the Zoeppritz equations, which establish the relationship between the seismic reflection coefficients of different offsets and elastic parameter contrasts between the interface of two lithologies. However, these are fourth-order matrix equations with a complex form and are difficult to be directly applied to inversion. Approximate analytical solutions have been used to establish a linear relationship between the seismic reflection coefficients and elastic parameters. And the approximations are based on the assumptions of a small angle and weak contrast, they cannot be applied to layers of high contrast, such as gas-bearing sandstones and coal seams. In this paper, we present an accurate prestack seismic inversion method that can be applied to a wider range of geological models. First, we derive the partial derivatives of the exact reflection coefficients of PP waves based on the Zoeppritz equations with respect to the elastic parameters and establish the exact Jacobian and Hessian matrices. Then, we use the least-squares algorithm to construct objective functions for the simultaneous inversion of three elastic parameters: The P-wave velocity, S-wave velocity, and density. Examples show that our inversion method is more accurate for strata with strong reflection interfaces than the approximate prestack inversion methods and stable under noisy conditions. The inversion method was applied in channel sand depositions of the Lower Permian Shanxi and Shihezi Formation of the Ordos Basin, and it was efficient to identify the gas-bearing sand layers and determine the range of potentially favorable areas.",1,1,1
Sand,Delta,"Gao, Xiaoyang; He, Wenxiang; Hu, Yong",Modeling of meandering river deltas based on the conditional generative adversarial network,Reservoir modeling; Meandering river delta; Artificial intelligence; Deep learning; Convolution neural network; Conditional generative adversarial network,SIMULATION,"Because the structure of delta reservoirs is too complex, the traditional modeling method cannot describe the delta reservoir model well, and the delta reservoir model cannot be directly applied to oilfield production. At present, the generative adversarial network (GAN) has been gradually applied to the field of reservoir modeling and has made some achievements, and the conditional generative adversarial network (CGAN) has been shown to provide a theoretical basis for solving the problem of the generated reservoir model being too free. Based on CGAN theory, a new reservoir modeling scheme of the meandering river delta is proposed in this study, taking the meandering river delta sedimentary area in the western slope zone of the Xihu Depression as an example. Because the reservoir model generated by the traditional CGAN theory encounters difficulty in achieving the expected effect, a new improvement scheme based on the traditional CGAN is proposed: The delta model obtained from CGAN process and the original real delta reservoir model are recombined into a new data set. The CGAN training process is repeated again, and a more accurate and complete delta reservoir model is generated by iterating many times. The results show that this modeling method overcomes the shortcomings of the traditional delta modeling method and improves the accuracy of the generated model, which provides a new idea for the delta reservoir sand body modeling.",2,2,6
Sand,Delta,"Buckman, Jim; Chudi, Obinna; Lewis, Helen; Couples, Gary; Huang, Tianshen; Jiang, Zeyun","Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",Pore occlusion; Pore network model; Digital rock model; Quartz cementation; Permeability,,"Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36-51%, and the earlier Miocene samples have a porosity of around 18-35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234-1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",2,2,1
Sand,Generation,Yin Yanshu; Hu Xun; Huang Jixin; Feng Wenjie; Wang Linxin; Duan Taizhong; Zhao Lei; Zhang Wenbiao,"A three-dimensional model of deep-water turbidity channel in Plutonio oilfield, Angola: From training image generation, optimization to multi-point geostatistical modelling",Multi-point geostatistics; Training image; Alluvsim; Optimization method; The Plutonio oilfield in Angola,SIMULATION; RESERVOIRS; DISTANCE,"The deep-water turbidity channel system in the Oligocene O73 sand layer in the Plutonio oilfield in Angola of west Africa has good oil and gas reservoir capability. As the well spacing is large due to operation cost, and the seismic resolution of the target layer is relatively low, identification of turbidity channel boundary was difficult. To establishes a fine model is a problem faced by the modelers. In this paper, a complete multi-point geostatistical modeling flowchart is presented for the construction of fine deep-water turbidity channel model. According to the investigation of seismic, well logging, drilling data and references in the study area, the genesis, reservoir scale, lithofacies type, morphological characteristics and evolution of the deep-water turbidity channel of the target layer were obtained. The improved Alluvsim algorithm was utilized to generate a set of adaptive deep-water turbidity channel training images with specified curvatures. Net-to-gross, variogram and a high-order statistics method based on the single data event were compared to evaluate and sort the training images. Then, the Snesim method was utilized to construct the models using the sorted compatible training images with a same set of parameters. At last, the quality of different models was compared based on the seismic attribute slices and a composite correlation coefficient optimization method based on seismic data. The results suggest that the improved Alluvsim algorithm can reproduce the channel morphology and stacking patterns better. Compared with the first-order and second-order statistics comparison method, the method using higher-order statistics of single data event taken spatial patterns into consideration and sorted training images better. The reservoir model was established using the optimal selected training image which has a high correlation with seismic attributes, and the model is more consistent with the characteristics of subsurface reservoirs. At the same time, this paper also provides a complete research program for the application of multi-point geostatistical modeling method which is from training image generation, optimal training image selection and multi-point geostatistics modeling to realizations selection for practical subsurface reservoir modelling.",3,3,2
Sand,Generation,"Gao, Xiaoyang; He, Wenxiang; Hu, Yong",Modeling of meandering river deltas based on the conditional generative adversarial network,Reservoir modeling; Meandering river delta; Artificial intelligence; Deep learning; Convolution neural network; Conditional generative adversarial network,SIMULATION,"Because the structure of delta reservoirs is too complex, the traditional modeling method cannot describe the delta reservoir model well, and the delta reservoir model cannot be directly applied to oilfield production. At present, the generative adversarial network (GAN) has been gradually applied to the field of reservoir modeling and has made some achievements, and the conditional generative adversarial network (CGAN) has been shown to provide a theoretical basis for solving the problem of the generated reservoir model being too free. Based on CGAN theory, a new reservoir modeling scheme of the meandering river delta is proposed in this study, taking the meandering river delta sedimentary area in the western slope zone of the Xihu Depression as an example. Because the reservoir model generated by the traditional CGAN theory encounters difficulty in achieving the expected effect, a new improvement scheme based on the traditional CGAN is proposed: The delta model obtained from CGAN process and the original real delta reservoir model are recombined into a new data set. The CGAN training process is repeated again, and a more accurate and complete delta reservoir model is generated by iterating many times. The results show that this modeling method overcomes the shortcomings of the traditional delta modeling method and improves the accuracy of the generated model, which provides a new idea for the delta reservoir sand body modeling.",2,2,6
Sand,Physical Properties,"Liu, Chao; Sun, Lidong; Lu, Jiamin; Sun, Youhai; Xu, Yan; Lu, Mingxu; Li, Jijun","Characteristics of the newly found oil-bearing sandstone in the Denglouku formation of the northern Songliao Basin, China",Denlouku Formation; Oil; Reservoir; Controlling factors; Shuangcheng area; Songliao Basin,RESERVOIR QUALITY PREDICTION; TARANAKI BASIN; DIAGENESIS; POROSITY; PERMEABILITY; EVOLUTION; GAS; PRESSURE,"Over the past 50 years, exploration in the northern Songliao Basin has revealed that the sandstone in the Denglouku Formation is a tight gas reservoir. Oil-bearing reservoirs with good physical properties have only recently been discovered and have become the new focus of petroleum exploration. We carried out thin section observation, X-ray diffraction analysis, particle size analysis, mercury intrusion test, and stratigraphic burial history based on 377 core samples collected from the Denglouku Formation in the Shuangcheng area, where oil exploration has made a significant breakthrough. The results revealed the reservoir rock to be feldspathic sandstone and lithic feldspar sandstone, with the dominating interstitial materials of carbonates and mud matrix. The grain size ranged from silty sand to coarse sand. The pore types were primary intergranular pores and partial secondary dissolution pores. The porosity was generally 5%-20%, and the permeability was in a wide range of 0.1 mD to 2000 mD. Tectonic uplift prevented the sandstone from being deeply buried, which is an important reason for the good quality of the reservoir. Hydrocarbon filling improved the reservoir quality not only by forming dissolved pores but also by inhibiting carbonate cementation. The mud matrix and the carbonate cement decreased the reservoir quality, causing heterogeneity of the reservoir. This study indicated that the displacement pressure was effective in the classification of reservoirs that were characterized by good physical property and strong heterogeneity. The Denglouku reservoirs were divided into three classes. Favorable reservoirs (Class I and Class II) showed low displacement pressure because of the low mud matrix and carbonate cement and well-developed primary pores.",2,2,3
Sand,Physical Properties,Sun Zhifeng; Lin Chengyan; Du Dongxing; Bi Haisheng; Ren Huaiqiang,Application of seismic architecture interpretation in enhancing oil recovery in late development Stage-Taking meandering river reservoir in Dongying depression as an example,Meander belt; Sand body geometry; Coaxial morphology; Seismic architecture; Remaining oil distribution,BASIN; BELT; EVOLUTION; FAN,"Taking typical meandering river deposits of Ng(52+3) in the west 7th block of Gudong Oilfield as an example, the influence of point-bar-sandstone superposition structure on flooding law and remaining oil distribution is studied by means of seismic architecture interpretation under the guidance of point-bar geometry. Meanwhile, the influence of morphological parameters and lithology of lateral accretionary surfaces on remaining oil and development characteristics is discussed. The seismic waveform and amplitude of point-bar boundary sandstones are obvious when they overlap with each other. The connectivity of superimposed zones between boundary sand-bodies of point-bars is poor. The remaining oil near the superimposed zones is enriched when base-of-channel sandstone that infills abandonment (PI) and the earliest sandstone at the beginning of migration of the point bars (PI) superimposed with each other. Remaining oil is relatively not enriched when PI sandstones of point-bars are superimposed in superimposed zone. Remaining oil is relatively enriched in the upper point-bar sandstone at the superimposed zone. The effective shielding area effective distance to obstruct fluid flow of mudstone section of lateral accretionary surfaces is 50-80 m along the lateral direction of lateral-accretion surfaces, and the remaining oil is not enriched in the same point bar within the range of 50-80 m around oil and water wells. The physical property section of lateral-accretion surfaces in the middle and lower part of the surfaces has a certain blocking effect on flow and can obviously reduce the recovery degree. Seismic architectural interpretation plays an important role in predicting remaining oil enriched areas and prolonging oil field life in order to improve oil recovery.",1,1,4
Tarim Basin,Fault,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Tarim Basin,Fault,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Tarim Basin,Fault,"Chen, Junqing; Ma, Kuiyou; Pang, Xiongqi; Yang, Haijun","Secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin",Tarim basin; Lunnan area; Ordovician carbonate; Hydrocarbon secondary migration,PALEOZOIC MARINE PETROLEUM; LOWER INDUS BASIN; TABEI UPLIFT; CRUDE OILS; NW CHINA; GEOCHEMICAL CHARACTERIZATION; TAZHONG UPLIFT; ORIGIN; ACCUMULATION; GAS,"The study on the secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area has been a challenge caused by limited geologic records as direct physical evidence, and physical simulations are difficult to conduct since the parameters of realistic geologic conditions are rare. Based on the analysis of the regional structure, and by integrating the study on the fluid properties and benzocarbazole nitrogen compounds parameters, the secondary hydrocarbon migration in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin, were investigated. The results indicated oil density show gradually increasing trends from Lungudong Fault to the Middle Slope in eastern Lunnan Uplift; while the trend is converse from southwest of Lunxi and Sangtamu Faults to the Middle Slope in western area. The benzocarbazole nitrogen compounds contents of Ordovician reservoir oil exhibit gradually increasing trends from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope. The wax contents, gas dryness coefficients and gas/oil ratios show decreasing trends from east to west and away from the Lungudong Fault and Sangtamu Fault. The crude oil generated at the late Hercynian stage (about 290 Ma ago) in the Lunnan area migrated along the directions from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope; the gas formed at the late Himalayan stage (about 208 Ma ago) migrated from the east to west laterally, and along the natural gas invasion faults Lungudong Fault and Sangtamu Fault upwards vertically.",1,1,4
Tarim Basin,Fault,"Li, Jingfei; Zhang, Zhiyao; Zhu, Guangyou; Li, Tingting; Zhao, Kun; Chi, Linxian; Yan, Huihui","The origin and accumulation of ultra-deep oil in Halahatang area, northern Tarim Basin",Giant oil accumulations; Ultra-deep strata; GCxGC-TOFMS; Halahatang area; Tarim basin,TABEI UPLIFT; NW CHINA; HYDROCARBON ACCUMULATION; DIAMONDOID HYDROCARBONS; THERMAL-CRACKING; CRATONIC REGION; TAZHONG AREA; NATURAL-GAS; CRUDE OILS; PETROLEUM,"The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000-8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.",1,2,0
Tarim Basin,Zone,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Tarim Basin,Zone,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Tarim Basin,Zone,"Shi, Pingzhou; Tang, Hongming; Wang, Zhenyu; Sha, Xuguang; Wei, Huadong; Liu, Chao","Carbonate diagenesis in fourth-order sequences: A case study of yingshan formation (Lower Ordovician) from the yubei area -Tarim Basin, NW China",Carbonate diagenesis; High-frequency sequence; Yingshan formation; Lower ordovician; Yubei area; Tarim basin,SEA-LEVEL CHANGES; PLATFORM; FACIES; EVOLUTION; DOLOMITIZATION; SIGNATURE; RESERVOIR; EXAMPLE; RAMP,"The Yingshan Formation in Lower Ordovician is an important hydrocarbon reservoir of the Tarim Basin, northwest China; however, the factors controlling reservoir development in the formation are not fully understood. Data from thin-section observations, scanning electron microscopy, and gamma-ray logging were applied to produce a fourth-order sequence stratigraphic framework for the Yingshan Formation in the Yubei area of the Tarim Basin. The framework was assessed in terms of the carbonate diagenesis of the reservoir rock. The influence of diagenesis on reservoir porosity, the factors restricting reservoir quality, and the significance of the results for exploration are discussed. Diagenesis, dolomitization, and cementation by atmospheric fresh water occurred in the lowstand systems tracts. The sediments in the transgressive systems tract were consolidated by seawater, or dolomitization occurred in the landward mixed zone, or the sediments quickly entered the shallow burial marine diagenetic environment and became compacted. The highstand systems tract experienced significant diagenesis, with seafloor cementation, atmospheric water dissolution and dolomitization. These factors were related to sea-level fluctuation and sedimentary features. The porosity of some high-frequency sequences in the lower part of the Yingshan Formation was improved significantly. In the Yubei area, cementation of the middle part of the fourth-order sequence during burial reduced the porosity and permeability of the reservoir. This was the main cause of reservoir deterioration. During oil and gas exploration, attention should be paid to the higher degree of dissolution in the middle part of the fourth-order sequence and the superposition of atmospheric fresh-water dissolution in the upper part of the sequence.",2,2,2
Tarim Basin,Zone,"Li, Jingfei; Zhang, Zhiyao; Zhu, Guangyou; Li, Tingting; Zhao, Kun; Chi, Linxian; Yan, Huihui","The origin and accumulation of ultra-deep oil in Halahatang area, northern Tarim Basin",Giant oil accumulations; Ultra-deep strata; GCxGC-TOFMS; Halahatang area; Tarim basin,TABEI UPLIFT; NW CHINA; HYDROCARBON ACCUMULATION; DIAMONDOID HYDROCARBONS; THERMAL-CRACKING; CRATONIC REGION; TAZHONG AREA; NATURAL-GAS; CRUDE OILS; PETROLEUM,"The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000-8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.",1,2,0
Tarim Basin,Sources,"Su, Long; Zhang, Dongwei; Zheng, Lunju; Liu, Xingwang; Yang, Xin; Zheng, Jianjing; Liu, Peng",Experimental study of the influences of pressure on generation and expulsion of hydrocarbons: A case study from mudstone source rocks and its geological application in the Tarim Basin,Lithostatic stress; Fluid pressure; Liquid hydrocarbon generation; Expulsion efficiencies; Pressured experiments,ORGANIC-MATTER MATURATION; THERMAL-CRACKING; NW CHINA; OIL GENERATION; PALEOZOIC OIL; KINETIC-MODEL; RETARDATION; TEMPERATURE; WATER; PYROLYSIS,"Generally, pressure, temperature, depth of organic matter/kerogen burial and organic and inorganic matter interactions can influence the hydrocarbon generation process. However, different understandings were proposed to interpret the role of pressure in hydrocarbon generation. Meanwhile, previous investigations of the influence of pressure on hydrocarbons generation are mainly focused on fluid pressure (FP), only a few work was involved in the effect of lithostatic stress (LS) due to the limitation of experimental techniques. In this study, simulation experiments were conducted to investigate the influence of pressure, including lithostatic stress (LS) and fluid pressure (FP) on yield and process of hydrocarbon generation by a modified simulation instrument. Two systematic comparative pyrolysis experiments, including pressured experiments with LP range from 27.6 to 179.4 MPa and FP range from 12.0 to 109.2 MPa, and non-pressured experiments with LP for 6.0 MPa and FP range from 2.0 to 5.0 MPa were conducted in hydrous experimental condition. The results show that the peak yields of the expelled oil and the liquid hydrocarbons in pressured experiments and non-pressured experiments are 42.48 mg/g.TOC, 52.00 mg/g.TOC, 70.14 mg/g.TOC, and 72.15 mg/g.TOC, respectively. And Ro, ratio of the expelled oil to eluted oil, the accumulated yield of the expelled oil and liquid hydrocarbons, are lower in pressured experiments than that of non-pressured experiments. However, the accumulated yields of eluted oil and residual oil are higher in pressured experiments than that of non-pressured experiments. Additionally, the expulsion efficiencies of the oil range from 20% to 25%, which are lower in pressured experiments than that of non-pressured experiments near the oil generation-window. In addition, the yields of hydrocarbon gas in pressured experiments are greater compared to the yields in non-pressured experiments at the high maturity stage. Based on the experimental results, hydrocarbon generation process can be divided into three stages. Generally, LS and FP could retard the process of mudstone maturation as well as the generation and expulsion of the liquid hydrocarbons. Hence, the residual liquid hydrocarbons in high-pressure condition can act as another source of natural gas generation in the high maturity stage. The results could help us to properly evaluate hydrocarbon generation potentials of sources rocks at petroleum-producing sedimentary basins in China and elsewhere.",2,2,7
Tarim Basin,Sources,"Wu, Nan; Wang, Jian; Cai, Zhongxian; Luo, Zhong; Lu, Xuesong; Ma, Xingzhi; Liu, Xianfeng","Discovery of Sinian source rocks in proterozoic in the Tarim Basin, NW China",Tarim basin; Kuruktag; Sinian source rocks; Hydrocarbon generation; Bitumen,ORGANIC-MATTER; CRUDE OILS; MATURITY PARAMETERS; THERMAL MATURITY; SICHUAN BASIN; GEOCHEMICAL CHARACTERISTICS; TRICYCLIC TERPANES; VELKERRI FORMATION; MCARTHUR BASIN; GRAND-CANYON,"As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50-60 degrees C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin.",2,2,3
Tarim Basin,Sources,"Jiang, Wenlong; Imin, Ablimit; Wang, Xueyong; Wang, Tao; Guo, Wenjian","Geochemical characterization and quantitative identification of mixed-source oils from the Baikouquan and Lower Wuerhe Formations in the eastern slope of the Mahu Sag, Junggar Basin, NW China",Mixed oil; Chemometrics; Alternating least square; Mahu sag; Junggar basin,LOWER INDUS BASIN; CRUDE OILS; PETROLEUM GEOCHEMISTRY; CRETACEOUS ROCKS; TARIM BASIN; FIELD; ORIGIN,"The quantitative identification of mixed-source oil is a popular yet difficult topic in current petroleum geochemistry research. The mixed-source oils of the Baikouquan and Lower Wuerhe formations in the eastern slope of the Mahu Sag of Junggar Basin were used as a typical example in this study. Quantitative research on mixed oils was carried out in the study area and good results were obtained using an approach combining organic geochemistry and chemometrics. The results of crude oil geochemistry research show that mixed-source crude oil is ubiquitous in the study area. After comprehensive analysis, it is likely that there are three endmembers in the current mixed-source oils. Two of the endmembers may represent mainly the contribution of the early and late source rocks of the Permian Fengcheng Formation and are dominated by late filled crude oil. However, the third endmember is quite different. Its hydrocarbons may have come from the source rocks of the Permian Lower Wuerhe Formation or the source rocks of the Fengcheng Formation under different lithofacies and sedimentary environments. The study area is dominated by hydrocarbons that accumulated from the Fengcheng Formation. Although the proportion of hydrocarbons generated in the late stage is not high, it plays a very important role in hydrocarbon migration and accumulation. This comprehensive comparative study shows that the chemometric method can play an important role in calculating the proportion of mixed-source oil and in endmember analysis.",2,2,0
Tarim Basin,Sources,"Li, Jingfei; Zhang, Zhiyao; Zhu, Guangyou; Li, Tingting; Zhao, Kun; Chi, Linxian; Yan, Huihui","The origin and accumulation of ultra-deep oil in Halahatang area, northern Tarim Basin",Giant oil accumulations; Ultra-deep strata; GCxGC-TOFMS; Halahatang area; Tarim basin,TABEI UPLIFT; NW CHINA; HYDROCARBON ACCUMULATION; DIAMONDOID HYDROCARBONS; THERMAL-CRACKING; CRATONIC REGION; TAZHONG AREA; NATURAL-GAS; CRUDE OILS; PETROLEUM,"The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000-8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.",1,2,0
Tarim Basin,Northern Tarim Basin,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Tarim Basin,Northern Tarim Basin,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Tarim Basin,Northern Tarim Basin,"Li, Jingfei; Zhang, Zhiyao; Zhu, Guangyou; Li, Tingting; Zhao, Kun; Chi, Linxian; Yan, Huihui","The origin and accumulation of ultra-deep oil in Halahatang area, northern Tarim Basin",Giant oil accumulations; Ultra-deep strata; GCxGC-TOFMS; Halahatang area; Tarim basin,TABEI UPLIFT; NW CHINA; HYDROCARBON ACCUMULATION; DIAMONDOID HYDROCARBONS; THERMAL-CRACKING; CRATONIC REGION; TAZHONG AREA; NATURAL-GAS; CRUDE OILS; PETROLEUM,"The giant Ordovician petroleum accumulations in the Halahatang area, northern Tarim Basin, China with burial depths of 7000-8000m are the deepest paleo marine carbonate oilfield ever discovered so far. By conducting comprehensive molecular geochemical analyses on 12 Halahatang oil samples, we suggested these oils and their associated gases are likely from the Cambrian source rock at mature stage; however, the oil maturity shows slight variation, it increases with the burial depth. Reservoir studies reveal that lateral fluid migration was hindered as a result of strong lateral reservoir heterogeneities, contrarily, vertical fluid migration was favorable due to developed fault system. Fluid inclusion and basin modeling analyses indicate a main oil and gas charge event during the late Hercynian period. Therefore, the formation of the giant Halahatang oilfields is attributed to abundant hydrocarbon generated from deep-buried source rocks, favorable vertical migration conduits related to fault system, and high-quality fracture-vuggy reservoirs in Ordovician strata. It is further proposed that Halahatang oilfields were formed in three evolution stages, including the reservoir formation during the Caledonian (after Silurian), the hydrocarbon accumulation during the late Hercynian (Permian), and continuous deep buried after the late Hercynian (since Triassic). Due to the low geothermal gradient and rapid burial in the late stage, oils in the Halahatang area did not reach the cracking threshold, resulting in abundant liquid oil accumulations preserved in the deep strata near the fault zone. The great exploration potential in the deep buried zones can be speculated based on this study.",1,2,0
Tarim Basin,Well Log,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Tarim Basin,Well Log,"Sun, Panke; Fang, Huijing; Xu, Zhaohui; Wang, Chao; Xu, Huaimin; Lu, Man","Siliciclastic depositional model within a subsurface coastal parasequence based on barriers and baffles - An application to the Donghe Sandstone Member in the Hudson Oilfield, Tarim Basin, NW China",Barrier; Baffle; Dipmeter data; Sea-level; Donghe sandstone; Depositional model,SEQUENCE STRATIGRAPHY; FACIES; HIERARCHY; OUTCROP; ORIGIN,"Detailed analyses of a siliciclastic coastal reservoir highlights the need for an enhanced knowledge of their depositional model. At the scale of the bed sets, however, it is difficult to determine the depositional model, largely due to a limit in vertical resolution of seismic data and conventional wireline logs. Barriers and baffles, following either surfaces of bed sets or beds, act as isochronous boundaries, therefore, holding a key to reveal the sedimentary evolution of subsurface reservoirs at small scales. Calcareous and argillaceous barriers and baffles of the Donghe Sandstone Member in the Hudson Oilfield have obvious low conductivity responses in dipmeter data, therefore, they are interpreted and correlated by integration of conventional logs and dipmeter data. Barriers separate the Donghe Sandstone Member into three retrogradational bed sets (i.e., B1 similar to B3) and two progradational bed sets (i.e., B4 similar to B5), of which beds are constrained by baffles with larger dip angles than barriers in the current structure pattern as well as the period of deposition. The stacking patterns indicate relative sea-level rise within B1 similar to B3 and fall within B4 similar to B5. The relative sea-level changes control the baffle frequency, thickness and length of barriers and baffles. Vertically, the variation of frequency and maximum thickness of both argillaceous and calcareous baffles increase during the transgression yet reduce during regression. Horizontally, the length of barriers and baffles positively correlates with their maximum thickness along the paleoshoreline, as it does the direction perpendicular to the paleoshoreline. Therefore, a depositional model of early retrogradation followed by progradation is built for the Donghe Sandstone Member, a siliciclastic coastal parasequence with upper-shoreface and lower-shoreface facies, based on barriers and baffles. This depositional model is embodied with certain principles of reservoir architecture and behavior.",3,3,1
Tarim Basin,Well Log,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Tarim Basin,Cavity,"Wan, Yizhao; Liu, Yuewu; Wu, Nengyou",Numerical pressure transient analysis for unfilled-caved carbonate reservoirs based on Stokes-Darcy coupled theory,Carbonate reservoir; Pressure transient behavior; Stokes-Darcy coupled; Flow in porous media; Numerical simulation,TARIM BASIN; BOUNDARY-CONDITION; MODEL; FLOW; VUGGY; WELL; CAVITY,"Caved carbonate reservoirs are very special because of the strong heterogeneity. The pressure transient behavior of the caved carbonate reservoirs is quite different from the conventional homogeneous or dual medium reservoirs because of the presence of large-scale cavities. There are two types of cavities: filled and unfilled, which dominated the production of the reservoirs. Fluid flow in the unfilled cavity should be described by Stokes' equation rather than Darcy's law. It is needed to better understand the role of the unfilled cavities plays in the pressure transient analysis. The objective of this work is to analyze the pressure transient behavior of the unfilled cavities. A coupled Stokes-Darcy pressure transient model is developed and the finite element method is applied in the solutions of the mathematical models. Then, the numerical pressure transient model is used in the analysis of two typical cases: a well drilled into the unfilled cavity (WIC) and a well not drilled into the unfilled cavity (WOC). The type curves of the WIC model indicate that flow in the unfilled cavity is an oscillated pressure-drop rather than a radial flow. The unfilled cavity that the well drilled into would be considered as an enlarged wellbore which is equivalent to a negative skin factor, as a consequence the wellbore storage coefficient will increase. Main characteristics of type curves for WOC model are the valley on the pressure derivative. A cavity with a larger size and smaller distance from the wellbore would give rise to a deeper valley. Comparative results indicate that unfilled cavities described by the Stokes' equation are not the limit of the filled cavities with extremely large mobility, which was predicted by previous work.",3,3,3
Tarim Basin,Cavity,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Du, He","Design and construction of the knowledge base system for geological outfield cavities classifications: An example of the fracture-cavity reservoir outfield in Tarim basin, NW China",UAV scanning; 3D digital model; Multiple linear regression; Discriminant classification; Fracture-cavity reservoir,VUGGY CARBONATE RESERVOIRS; OIL-FIELD; NETWORK; SIMULATION; PREDICTION; CAVE; GAS,"Tahe oilfield, located in NW Tarim Basin, is one of the largest and most difficult fracture cavity reservoirs in the world. Different fracture cavities, different generated mechanisms, and different oil production capacities. In order to study the significant parameters that can characterize the categories of facture-cavity. This research adopted outfield manual measurement, 3D digital modeling technique to obtain characterization parameters. According to experienced geological survey, typical outcrops were selected, then scanned by UAV (Unmanned aerial vehicle). Consequently, 3D digital models, including real coordinates and parameter information, were established by Agisoft Photoscan. Through geological testing results, various combination characteristic patterns of relative categories were analyzed. By using digital measure tool, combined with manually measured data, the parameters were extracted from the 3D digital model (DM). Then an initial geological database was established. For furtherly analyzing the database, the mathematic statistics methods of multiple linear regression (MLR), neural network technique (NNT) and discriminative classification technique (DCT) were applied. Using software of SPSS statistics 17.0, more than 200 groups of geological data (various categories of fracture-cavity) were optimally processed. Consequently, the significant characteristic parameters were interpreted to determine diverse categories. The results showed that: (1) cavity width, height, fracture length and cavity aspect ratio were significant parameters to classify runoff cavity categories. (2) Fault-controlled cavities could be accurately classified by fracture length and fracture density. (3) The main cavity categories could be distinguished by cavity width, cavity height and fracture density. Performances of the approach have been examined with 10 percentages of the samples, and a good agreement performed in the simulated results, and anastomosis rate was more than 80%. The researched results have critical guiding significance to evaluate types of fracture-cavity, develop and explore of fracture-cavity reservoirs. The construction technique of knowledge base can be applied for diverse fracture-cavity reservoirs in the various formations in different areas in the world.",3,3,2
Tarim Basin,Calcite,"Wei, Duan; Gao, Zhiqian; Fan, Tailiang; Zhang, Chi; Tsau, Jyun-Syung",The rock-fabric/petrophysical characteristics and classification of the micropores hosted between the calcite and dolomite crystals,,NUCLEAR-MAGNETIC-RESONANCE; CARBONATE RESERVOIRS; PORE STRUCTURE; TARIM BASIN; RELAXATION; PERMEABILITY; POROSITY; AREA; MICROCRYSTALS; ORDOVICIAN,,2,3,2
Tarim Basin,Calcite,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Li, Mengping; Du, He",Mineral filling mechanism in complex carbonate reservoir fracture system : Enlightenment from numerical simulation of water-rock interaction,Fracture filling characteristics; Differential filling and dissolution; Numerical simulation of water-rock interaction; Complex fracture system,NATURAL FRACTURES; MODEL; BASIN; DISSOLUTION; FIELD,"The Tahe oilfield, located in the northern Tarim Basin, is characterized by complex fracture-cavity system and various mineral fillings. To reveal the mineral filling mechanism in this complex fracture system, this manuscript conducted a numerical simulation of water-rock interaction on basis of outcrop observation, cast thin section, electron scanning imaging and geochemical testing. Considering the influence of fracture dip angle, aperture, combination pattern, depth and temperature, 12 geological models were constructed in PetraSim software. The simulated results showed as followings: (1) The larger the dip angle, the faster the precipitation rate of calcite in faults. A larger amount of precipitation accelerated the reduction rate of calcium ions. (2) Dissolution and precipitation occurred more easily in faults with larger aperture. The larger the aperture, the faster the water flow. It contributed to the injection and flow of CO2 and facilitated calcite precipitation. (3) Multiple sets of faults with numerous intersection areas resulted in more complex distributions of mineral filling and precipitation. The calcium ion loss and precipitation rates in fault intersection areas were faster than that in a single fault. (4) In the intersection areas of faults with different apertures, dissolution and precipitation were prone to develop in the fault with larger aperture. (5) As a consequence of the upwelling of hydrothermal fluids, calcite precipitates transferred from relatively shallow parts to deeper parts. The amount of calcite precipitation in faults was larger than that in strata. (6) As temperature increased, the precipitation rate of calcite in faults and adjacent areas increased. Deeper faults with larger apertures had more abundant calcite precipitation.",1,1,4
Tarim Basin,Porosity,"Shi, Pingzhou; Tang, Hongming; Wang, Zhenyu; Sha, Xuguang; Wei, Huadong; Liu, Chao","Carbonate diagenesis in fourth-order sequences: A case study of yingshan formation (Lower Ordovician) from the yubei area -Tarim Basin, NW China",Carbonate diagenesis; High-frequency sequence; Yingshan formation; Lower ordovician; Yubei area; Tarim basin,SEA-LEVEL CHANGES; PLATFORM; FACIES; EVOLUTION; DOLOMITIZATION; SIGNATURE; RESERVOIR; EXAMPLE; RAMP,"The Yingshan Formation in Lower Ordovician is an important hydrocarbon reservoir of the Tarim Basin, northwest China; however, the factors controlling reservoir development in the formation are not fully understood. Data from thin-section observations, scanning electron microscopy, and gamma-ray logging were applied to produce a fourth-order sequence stratigraphic framework for the Yingshan Formation in the Yubei area of the Tarim Basin. The framework was assessed in terms of the carbonate diagenesis of the reservoir rock. The influence of diagenesis on reservoir porosity, the factors restricting reservoir quality, and the significance of the results for exploration are discussed. Diagenesis, dolomitization, and cementation by atmospheric fresh water occurred in the lowstand systems tracts. The sediments in the transgressive systems tract were consolidated by seawater, or dolomitization occurred in the landward mixed zone, or the sediments quickly entered the shallow burial marine diagenetic environment and became compacted. The highstand systems tract experienced significant diagenesis, with seafloor cementation, atmospheric water dissolution and dolomitization. These factors were related to sea-level fluctuation and sedimentary features. The porosity of some high-frequency sequences in the lower part of the Yingshan Formation was improved significantly. In the Yubei area, cementation of the middle part of the fourth-order sequence during burial reduced the porosity and permeability of the reservoir. This was the main cause of reservoir deterioration. During oil and gas exploration, attention should be paid to the higher degree of dissolution in the middle part of the fourth-order sequence and the superposition of atmospheric fresh-water dissolution in the upper part of the sequence.",2,2,2
Tarim Basin,Porosity,"Wei, Duan; Gao, Zhiqian; Fan, Tailiang; Zhang, Chi; Tsau, Jyun-Syung",The rock-fabric/petrophysical characteristics and classification of the micropores hosted between the calcite and dolomite crystals,,NUCLEAR-MAGNETIC-RESONANCE; CARBONATE RESERVOIRS; PORE STRUCTURE; TARIM BASIN; RELAXATION; PERMEABILITY; POROSITY; AREA; MICROCRYSTALS; ORDOVICIAN,,2,3,2
Tarim Basin,Classification,"Ren, Qiqiang; Jin, Qiang; Feng, Jianwei; Du, He","Design and construction of the knowledge base system for geological outfield cavities classifications: An example of the fracture-cavity reservoir outfield in Tarim basin, NW China",UAV scanning; 3D digital model; Multiple linear regression; Discriminant classification; Fracture-cavity reservoir,VUGGY CARBONATE RESERVOIRS; OIL-FIELD; NETWORK; SIMULATION; PREDICTION; CAVE; GAS,"Tahe oilfield, located in NW Tarim Basin, is one of the largest and most difficult fracture cavity reservoirs in the world. Different fracture cavities, different generated mechanisms, and different oil production capacities. In order to study the significant parameters that can characterize the categories of facture-cavity. This research adopted outfield manual measurement, 3D digital modeling technique to obtain characterization parameters. According to experienced geological survey, typical outcrops were selected, then scanned by UAV (Unmanned aerial vehicle). Consequently, 3D digital models, including real coordinates and parameter information, were established by Agisoft Photoscan. Through geological testing results, various combination characteristic patterns of relative categories were analyzed. By using digital measure tool, combined with manually measured data, the parameters were extracted from the 3D digital model (DM). Then an initial geological database was established. For furtherly analyzing the database, the mathematic statistics methods of multiple linear regression (MLR), neural network technique (NNT) and discriminative classification technique (DCT) were applied. Using software of SPSS statistics 17.0, more than 200 groups of geological data (various categories of fracture-cavity) were optimally processed. Consequently, the significant characteristic parameters were interpreted to determine diverse categories. The results showed that: (1) cavity width, height, fracture length and cavity aspect ratio were significant parameters to classify runoff cavity categories. (2) Fault-controlled cavities could be accurately classified by fracture length and fracture density. (3) The main cavity categories could be distinguished by cavity width, cavity height and fracture density. Performances of the approach have been examined with 10 percentages of the samples, and a good agreement performed in the simulated results, and anastomosis rate was more than 80%. The researched results have critical guiding significance to evaluate types of fracture-cavity, develop and explore of fracture-cavity reservoirs. The construction technique of knowledge base can be applied for diverse fracture-cavity reservoirs in the various formations in different areas in the world.",3,3,2
Tarim Basin,Classification,"Wei, Duan; Gao, Zhiqian; Fan, Tailiang; Zhang, Chi; Tsau, Jyun-Syung",The rock-fabric/petrophysical characteristics and classification of the micropores hosted between the calcite and dolomite crystals,,NUCLEAR-MAGNETIC-RESONANCE; CARBONATE RESERVOIRS; PORE STRUCTURE; TARIM BASIN; RELAXATION; PERMEABILITY; POROSITY; AREA; MICROCRYSTALS; ORDOVICIAN,,2,3,2
Tarim Basin,Dolomite Reservoir,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Tarim Basin,Dolomite Reservoir,"Wei, Duan; Gao, Zhiqian; Fan, Tailiang; Zhang, Chi; Tsau, Jyun-Syung",The rock-fabric/petrophysical characteristics and classification of the micropores hosted between the calcite and dolomite crystals,,NUCLEAR-MAGNETIC-RESONANCE; CARBONATE RESERVOIRS; PORE STRUCTURE; TARIM BASIN; RELAXATION; PERMEABILITY; POROSITY; AREA; MICROCRYSTALS; ORDOVICIAN,,2,3,2
Tarim Basin,Structure,"Li, Hui; Lin, Chengyan; Ren, Lihua; Dong, Chunmei; Ma, Cunfei; Li, Shitao; Liang, Shuyi",An Integrated quantitative modeling approach for fault-related fractures in tight sandstone reservoirs,Geological conceptual model; 3D heterogeneity geomechanical model; Stress field simulation; Natural fracture model; BP neural Network; Stochastic modeling method,TRIASSIC YANCHANG FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; NIUTITANG FORMATION; CENGONG BLOCK; STRESS-FIELDS; ORDOS BASIN; TARIM BASIN; PREDICTION; NETWORK,"Fault-related fractures widely exist in tight sandstone reservoirs, which greatly improve the heterogeneity of reservoir. Unraveling the spatial distribution of fractures is most important for enhancing oil and gas recovery. In this study, an integrated quantitative modeling approach is proposed and applied to the Boxing sag in Jiyang Depression, Bohai Basin, China. From observations of drilled cores and well log interpretations we construct the internal structure of the fault damage zone and establish its geological conceptual model. A single well rock mechanics model is built by applying BP neural network method on rock mechanics experimental data. With the sedimentary facies guided lithofacies model, a three-dimensional heterogeneous rock mechanics model is constructed by integrating three geostatistical methods (i.e. sequential Gaussian simulation method, probability volume modeling method and trend modeling method). This workflow assigns the geological concept and rock mechanics characteristics to the geological volume. Based on the energy conservation principle, the relationship between fracture density and strain energy is derived using different fracture criteria. Based on simulation and calculation results, the fracture density model is established by deterministic modeling. Finally, these properties are incorporated into a DFN model. The model results show that, at the regions near the faults, the fracture development is mainly controlled by faulting. The induced fracture zone is a fracture-intensive area. However, there are few fractures within the fault core zone. The regions far from the faults are mainly controlled by the rock mechanics properties of geological materials, which show zonal characteristics. This model is validated by data from five wells in this region, which shows a strong correlation between predicted fracture density and water cut in produced fluid.",3,3,4
Tarim Basin,Structure,"Sun, Panke; Fang, Huijing; Xu, Zhaohui; Wang, Chao; Xu, Huaimin; Lu, Man","Siliciclastic depositional model within a subsurface coastal parasequence based on barriers and baffles - An application to the Donghe Sandstone Member in the Hudson Oilfield, Tarim Basin, NW China",Barrier; Baffle; Dipmeter data; Sea-level; Donghe sandstone; Depositional model,SEQUENCE STRATIGRAPHY; FACIES; HIERARCHY; OUTCROP; ORIGIN,"Detailed analyses of a siliciclastic coastal reservoir highlights the need for an enhanced knowledge of their depositional model. At the scale of the bed sets, however, it is difficult to determine the depositional model, largely due to a limit in vertical resolution of seismic data and conventional wireline logs. Barriers and baffles, following either surfaces of bed sets or beds, act as isochronous boundaries, therefore, holding a key to reveal the sedimentary evolution of subsurface reservoirs at small scales. Calcareous and argillaceous barriers and baffles of the Donghe Sandstone Member in the Hudson Oilfield have obvious low conductivity responses in dipmeter data, therefore, they are interpreted and correlated by integration of conventional logs and dipmeter data. Barriers separate the Donghe Sandstone Member into three retrogradational bed sets (i.e., B1 similar to B3) and two progradational bed sets (i.e., B4 similar to B5), of which beds are constrained by baffles with larger dip angles than barriers in the current structure pattern as well as the period of deposition. The stacking patterns indicate relative sea-level rise within B1 similar to B3 and fall within B4 similar to B5. The relative sea-level changes control the baffle frequency, thickness and length of barriers and baffles. Vertically, the variation of frequency and maximum thickness of both argillaceous and calcareous baffles increase during the transgression yet reduce during regression. Horizontally, the length of barriers and baffles positively correlates with their maximum thickness along the paleoshoreline, as it does the direction perpendicular to the paleoshoreline. Therefore, a depositional model of early retrogradation followed by progradation is built for the Donghe Sandstone Member, a siliciclastic coastal parasequence with upper-shoreface and lower-shoreface facies, based on barriers and baffles. This depositional model is embodied with certain principles of reservoir architecture and behavior.",3,3,1
Tarim Basin,Structure,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Tarim Basin,Structure,"Wei, Duan; Gao, Zhiqian; Fan, Tailiang; Zhang, Chi; Tsau, Jyun-Syung",The rock-fabric/petrophysical characteristics and classification of the micropores hosted between the calcite and dolomite crystals,,NUCLEAR-MAGNETIC-RESONANCE; CARBONATE RESERVOIRS; PORE STRUCTURE; TARIM BASIN; RELAXATION; PERMEABILITY; POROSITY; AREA; MICROCRYSTALS; ORDOVICIAN,,2,3,2
Tarim Basin,Structure,"Chen, Junqing; Ma, Kuiyou; Pang, Xiongqi; Yang, Haijun","Secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin",Tarim basin; Lunnan area; Ordovician carbonate; Hydrocarbon secondary migration,PALEOZOIC MARINE PETROLEUM; LOWER INDUS BASIN; TABEI UPLIFT; CRUDE OILS; NW CHINA; GEOCHEMICAL CHARACTERIZATION; TAZHONG UPLIFT; ORIGIN; ACCUMULATION; GAS,"The study on the secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area has been a challenge caused by limited geologic records as direct physical evidence, and physical simulations are difficult to conduct since the parameters of realistic geologic conditions are rare. Based on the analysis of the regional structure, and by integrating the study on the fluid properties and benzocarbazole nitrogen compounds parameters, the secondary hydrocarbon migration in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin, were investigated. The results indicated oil density show gradually increasing trends from Lungudong Fault to the Middle Slope in eastern Lunnan Uplift; while the trend is converse from southwest of Lunxi and Sangtamu Faults to the Middle Slope in western area. The benzocarbazole nitrogen compounds contents of Ordovician reservoir oil exhibit gradually increasing trends from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope. The wax contents, gas dryness coefficients and gas/oil ratios show decreasing trends from east to west and away from the Lungudong Fault and Sangtamu Fault. The crude oil generated at the late Hercynian stage (about 290 Ma ago) in the Lunnan area migrated along the directions from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope; the gas formed at the late Himalayan stage (about 208 Ma ago) migrated from the east to west laterally, and along the natural gas invasion faults Lungudong Fault and Sangtamu Fault upwards vertically.",1,1,4
Capillary Pressure,Water,"Neshat, Sajjad S.; Okuno, Ryosuke; Pope, Gary A.",Simulation of solvent treatments for fluid blockage removal in tight formations using coupled three-phase flash and capillary pressure models,Unconventional EOR; Solvent; Shale gas; Solvent.; Capillary pressure; Phase behavior,STABILITY ANALYSIS; PHASE-BEHAVIOR; CONDENSATE; MIXTURES; WATER; RESERVOIR,"Water and condensate blockage near production wells in unconventional reservoirs can significantly reduce oil and gas production rates. This paper presents a new approach for more accurate modeling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. A cubic equation of state is used to model mixtures of solvent, hydrocarbons and water that form up to three phases. The three-phase flash model is coupled with a three-phase capillary pressure model to account for the effect of capillary pressure in confined space. The capillary pressure function includes the impact of several important petrophysical properties such as pore size distribution and wettability. A compositional simulator is used to demonstrate the importance of the new phase behavior model. Single- and multi-cycle processes of methanol, dimethyl ether or CO2 injection are simulated to remove liquid blockage and increase production rate in tight oil/gas reservoirs. Simulation results show that DME is more efficient than methanol and CO2 for removal of liquid blockage in tight oil/gas reservoirs because DME is miscible with both oil and water under the simulated reservoir conditions.",3,3,1
Capillary Pressure,Water,"Naeem, Mohammad Hossein Towfighi; Dehaghani, Amir Hossein Saeedi",Evaluation of the performance of oil as a membrane during low-salinity water injection; focusing on type and concentration of salts,Smart water; Low-salinity water; Semi-permeable membrane; Osmotic pressure gradient,WETTABILITY; EOR; SANDSTONE,"Injection of low-salinity or smart water into the reservoir is one of the most common EOR techniques. This technique leads to more oil recovery in comparison to reservoir water and seawater injection. Several mechanisms explain the reasons for this increased recovery level, the most important of which is the wettability alteration towards water-wet conditions. However, in recent years, further mechanisms have been added to the previous ones as the main or complementary mechanism. One of these newly added mechanisms is the performance of oil as a semi-permeable membrane between connate and low-salinity waters. According to this mechanism, water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure (difference in chemical potential), which works as the driving force, until the system moves toward equilibrium in concentration. Introducing water molecules into connate water causes the swelling of connate water, and eventually moves the oil towards the pore throats. In this study, experiments have been performed on capillary tubes, while ignoring the effect of fluid-rock interactions to investigate the proposed theory. Experimental results confirmed the role of osmotic theory. Furthermore, a decrease in the salinity of the low-salinity water causes the oil-droplets' displacement to increase, whereas further reductions in the salinity of the injected water cause lower displacements. Therefore, there is an optimum value of low-salinity water concentration to obtain the highest possible oil drop displacement. The optimum values for the tested samples in this study were about 5000-10000 ppm. Additionally, it was found that among all of the essential seawater salts, potassium chloride leads to the highest oil drop displacement; and among oil samples, heptane showed better membrane-like performance in comparison to toluene and crude oil.",3,3,0
Capillary Pressure,Water,"Bouquet, Sarah; Douarche, Frederic; Roggero, Frederic; Bourbiaux, Bernard",Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization,Enhanced oil recovery; Naturally fractured reservoir; Oil-wet; Foam; Multiphase flow; Capillary pressure; Interfacial tension; Reservoir simulation; Mobility reduction; Dual-medium; Viscous forces,SIMULATION,"In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction. Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale. This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals. This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ""low-IFT"" effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.",3,3,0
Capillary Pressure,Water,"Salimi, Hamidreza; Bruining, Johannes; Joekar-Niasar, Vahid",Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities,Percolation theory; Effective-medium approximation; Relative permeability; Pore-network theory; Primary and secondary drainage; Noncircular pore throats,2-PHASE FLOW; POROUS-MEDIA; PERCOLATION THEORY; WETTING LIQUID; LAMINAR-FLOW; IMBIBITION; CORNERS,"Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation-at which there is no infinite cluster of completely filled water pores-but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 x 301 x 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).",2,2,2
Capillary Pressure,Petrophysical Properties,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Capillary Pressure,Petrophysical Properties,"Neshat, Sajjad S.; Okuno, Ryosuke; Pope, Gary A.",Simulation of solvent treatments for fluid blockage removal in tight formations using coupled three-phase flash and capillary pressure models,Unconventional EOR; Solvent; Shale gas; Solvent.; Capillary pressure; Phase behavior,STABILITY ANALYSIS; PHASE-BEHAVIOR; CONDENSATE; MIXTURES; WATER; RESERVOIR,"Water and condensate blockage near production wells in unconventional reservoirs can significantly reduce oil and gas production rates. This paper presents a new approach for more accurate modeling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. A cubic equation of state is used to model mixtures of solvent, hydrocarbons and water that form up to three phases. The three-phase flash model is coupled with a three-phase capillary pressure model to account for the effect of capillary pressure in confined space. The capillary pressure function includes the impact of several important petrophysical properties such as pore size distribution and wettability. A compositional simulator is used to demonstrate the importance of the new phase behavior model. Single- and multi-cycle processes of methanol, dimethyl ether or CO2 injection are simulated to remove liquid blockage and increase production rate in tight oil/gas reservoirs. Simulation results show that DME is more efficient than methanol and CO2 for removal of liquid blockage in tight oil/gas reservoirs because DME is miscible with both oil and water under the simulated reservoir conditions.",3,3,1
Capillary Pressure,Petrophysical Properties,"Zheng, Dingye; Pang, Xiongqi; Zhou, Liming; You, Xincai; Liu, Xiaohan; Guo, Fangxin; Li, Wei","Critical conditions of tight oil charging and determination of the lower limits of petrophysical properties for effective tight reservoirs: A case study from the Fengcheng Formation in the Fengcheng area, Junggar Basin",Tight oil; Effective tight reservoir; Lower limits of petrophysical properties; Dynamic mechanism; Junggar basin,TRIASSIC YANCHANG FORMATION; LUCAOGOU FORMATION; SOURCE ROCKS; JIMUSAR SAG; HYDROCARBON GENERATION; RESEARCH PROGRESS; SONGLIAO BASIN; ORDOS BASIN; CHANG 7; CHINA,"Studying the lower limits of petrophysical properties is important to evaluate the exploration and development potentials of tight oil reservoirs. At present, the evaluation criteria are based on a large number of cores and logging data, and rules are based on collections of empirical statistics and displacement pressure experiments. However, there have been few studies on the lower limits of the petrophysical properties of tight reservoirs based on force balance conditions for the hydrocarbon charging process. In this paper, the critical condition for hydrocarbon charging is determined using the oil expansion pressure as the main driving force, with the capillary pressure as the major resistance, via an analysis of the dynamic mechanism of tight oil reservoirs. A force-balance model for judging the lower limits of the petrophysical properties of tight reservoirs can be established by assuming that the oil expansion pressure is equal to the capillary force. This discriminant method is applied to calculate the critical pore-throat radius of the effective reservoirs of the Lower Permian Fengcheng Formation in the Fengcheng area, Junggar Basin, which are 0.310 mu m, 0.248 mu m, 0.208 mu m, and 0.135 mu m, when the buried depths are 2500-3000 m, 3000-3500 m, 3500-4000 m, and 4000-4500 m, respectively. The corresponding critical porosities are 6.15%, 4.84%, 3.81%, and 1.20%, respectively. The lower limits of the petrophysical properties of effective tight reservoirs gradually decrease with increasing burial depth. This method is of great significance for resource evaluations of tight oil reservoirs and the selection of exploration zones.",2,2,6
Capillary Pressure,Ones,"He, Jie; Wang, Hua; Tang, Jianrong; Shangguan, Yunfei; Yang, Xiangrong; Gong, Yin; Zhao, Rui; Zhou, Xuefeng","Evaluation of lacustrine mudstone top sealing capacity in the Lenghu-5 area, Qaidam Basin, Tibetan Plateau",Sealing capacity; Nitrogen adsorption; Mercury injection capillary pressure; Diagenesis; Overpressure; Brittleness index,PORE-SIZE DISTRIBUTION; FRACTAL CHARACTERISTICS; NORTHERN MARGIN; GAS-ADSORPTION; CAP-ROCK; MECHANICAL-PROPERTIES; THRESHOLD PRESSURE; REGIONAL TECTONICS; SURFACE-AREA; NATURAL-GAS,"Top seal capacity is one of the fundamental geological factors that must be considered during petroleum exploration. Based on thin section, low-pressure N-2 adsorption, bulk mineralogy, X-ray diffraction (XRD), mercury injection experiment and pressure data, the sealing capacity, lithofacies, petrophysics, diagenesis, capillary breakthrough pressure, overpressure, and brittleness index characteristics of a lacustrine mudstone top seal from the Lenghu-5 area, Qaidam Basin, Tibetan Plateau was investigated. The bulk rock composition of the top seal was dominated by clay minerals with carbonate cements and has a gross mudstone to sandy mudstone lithofacies. The isotherms from low-pressure nitrogen adsorption tests which presents as reversed S-shaped, belong to type B and the characteristics of hysteresis loops indicating the silt-like pores in the samples. The pores of the mudstone top seals are predominantly mesopores according to the N-2 adsorption and mercury injection experiment results. The cumulative mudstone thickness varies from 100 to 1400 m. The overpressured mudstone top seal in the Lenghu-5 area has three potential hydrocarbon preservation implications: overpressure cannot seal oil and gas, overpressure seals oil and gas directly, and overpressure seals oil and gas indirectly. The brittleness index (BI) values calculated by four methods based on the mineralogical composition of the mudstone top seals and the BI is higher at the top and bottom of the studied interval than in the middle mudstone layer. Based on the mud content, pore diameter, thickness, diagenetic stage, capillary breakthrough pressure, overpressure coefficient and brittleness index of the lacustrine mudstone, the top seal in the Lenghu-5 area is classified into four types: type I, II, III and IV, representing good to poor sealing capacities. The method for evaluation of the sealing capacity in this study can not only provide useful guidance for hydrocarbon exploration in Lenghu-5 area, Qaidam Basin, but also can be used in basins around the world by selecting the main influencing factors of sealing capacity in the basin.",3,3,6
Capillary Pressure,Ones,"Naeem, Mohammad Hossein Towfighi; Dehaghani, Amir Hossein Saeedi",Evaluation of the performance of oil as a membrane during low-salinity water injection; focusing on type and concentration of salts,Smart water; Low-salinity water; Semi-permeable membrane; Osmotic pressure gradient,WETTABILITY; EOR; SANDSTONE,"Injection of low-salinity or smart water into the reservoir is one of the most common EOR techniques. This technique leads to more oil recovery in comparison to reservoir water and seawater injection. Several mechanisms explain the reasons for this increased recovery level, the most important of which is the wettability alteration towards water-wet conditions. However, in recent years, further mechanisms have been added to the previous ones as the main or complementary mechanism. One of these newly added mechanisms is the performance of oil as a semi-permeable membrane between connate and low-salinity waters. According to this mechanism, water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure (difference in chemical potential), which works as the driving force, until the system moves toward equilibrium in concentration. Introducing water molecules into connate water causes the swelling of connate water, and eventually moves the oil towards the pore throats. In this study, experiments have been performed on capillary tubes, while ignoring the effect of fluid-rock interactions to investigate the proposed theory. Experimental results confirmed the role of osmotic theory. Furthermore, a decrease in the salinity of the low-salinity water causes the oil-droplets' displacement to increase, whereas further reductions in the salinity of the injected water cause lower displacements. Therefore, there is an optimum value of low-salinity water concentration to obtain the highest possible oil drop displacement. The optimum values for the tested samples in this study were about 5000-10000 ppm. Additionally, it was found that among all of the essential seawater salts, potassium chloride leads to the highest oil drop displacement; and among oil samples, heptane showed better membrane-like performance in comparison to toluene and crude oil.",3,3,0
Capillary Pressure,Ones,"Salimi, Hamidreza; Bruining, Johannes; Joekar-Niasar, Vahid",Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities,Percolation theory; Effective-medium approximation; Relative permeability; Pore-network theory; Primary and secondary drainage; Noncircular pore throats,2-PHASE FLOW; POROUS-MEDIA; PERCOLATION THEORY; WETTING LIQUID; LAMINAR-FLOW; IMBIBITION; CORNERS,"Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation-at which there is no infinite cluster of completely filled water pores-but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 x 301 x 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).",2,2,2
Capillary Pressure,Ones,"Dakhelpour-Ghoveifel, Jalal; Shahverdi, Hamidreza",Prediction of gas-oil capillary pressure of carbonate rock using pore network modeling,Pore network modelling; Pore network history match; Capillary pressure prediction; Pore size distribution,POROUS-MEDIA; FINITE-ELEMENT; 2-PHASE FLOW; RELATIVE PERMEABILITY; MULTIPHASE FLOW; RECONSTRUCTION; SIMULATIONS; SANDSTONE; IMAGES,"This study suggests a frame work to predict the capillary pressure curve of the carbonate rocks using a pore network simulation. A novel pore network manipulation algorithm is introduced to match three curves and predict only one curve (air-oil). This implies that the matching process is much more complicated. In return, more valid results are obtained and the problem of non-uniqueness of statistical PNM approach is mitigated. Finally, a collection of the most significant parameters governing capillary pressure are tabulated. Two plugs with air-mercury, air-oil and water-oil drainage and water-oil imbibition capillary pressure tests are used. Water-oil drainage and imbibition and air-mercury drainage are matched with the same pore network. The pore network is constructed based on a statistical distribution of the network elements. Then, properties of air and oil are input to the pore network to estimate air-oil capillary pressure. Matching three capillary pressure curves using a network is a complicated task to do, especially when no 3D image of the plugs is available. On the other hand, it is evident by the acceptable results that the error of prediction is moderated using the suggested method. This estimation technic is a new application of pore network modeling that can be used for reservoirs with no 3D image of plugs and limited SCAL data.",1,1,1
Capillary Pressure,Mu M,"Purswani, Prakash; Karpyn, Zuleima T.; Enab, Khaled; Xue, Yuan; Huang, Xiaolei",Evaluation of image segmentation techniques for image-based rock property estimation,X-ray imaging; Porous media; Image segmentation; Machine learning; WEKA segmentation; MIA clustering,X-RAY MICROTOMOGRAPHY; POROUS-MEDIA; RELATIVE PERMEABILITY; INTERFACIAL AREA; CAPILLARY-PRESSURE; MULTIPHASE FLOW; 2-PHASE FLOW; AIR-WATER; HYSTERESIS; FLUID,"Accurate characterization of rock and fluid properties in porous media using X-ray imaging techniques depends on reliable identification and segmentation of the involved phases. Segmentation is critical for the estimation of porosity, fluid saturations, fluid and rock topology, and pore connectivity, among other pore-scale properties. Therefore, the purpose of this study is to compare the effectiveness of different image segmentation techniques when applied to image data analysis in porous media. Two machine learning based segmentation techniques - a supervised ML technique called Fast Random Forest, and an unsupervised method combining k-means and fuzzy c-means clustering algorithms - were compared using an experimental data set. Comparisons are also presented against traditional thresholding segmentation. In addition, we discuss the potential and limitations of applying deep learning based segmentation algorithms. The performance of the segmentation techniques were compared on estimates of porosity, saturation, and surface area, as well as pore-scale estimates such as fluid-fluid interfacial areas, and Euler characteristic. X-ray micro-computed tomography images for a sintered glass frit, saturated with two-phases (air and brine), were acquired at two different voxel resolutions. The high-resolution images (6 mu m) were used as the benchmark case, while the low-resolution images (18 mu m) were segmented by three segmentation techniques: Fast Random Forest, clustering, and thresholding. The results for porosity and phase saturation from thresholding and from the supervised ML method (i.e. Fast Random Forest) were found to be close to the benchmark case. Segmentation results from the unsupervised ML method (i.e. clustering) were largely unsatisfactory, except for total surface area measurements. The supervised ML segmentation results provided better measurements for air-brine interfacial areas by capturing three-phase interfacial regions. Also, all segmentation techniques resulted in similar measurements for air-phase Euler characteristic confirming poor connectivity of the trapped air phase, although the closest results were obtained by the supervised ML method. Finally, despite the supervised ML segmentation technique being more computationally intensive, it was found to require less user intervention and its implementation was more straightforward. In summary, this work provides insights into different segmentation techniques, their implementation, as well as advantages and limitations with regards to quantitative analysis of pore-scale properties in saturated porous media.",3,3,1
Capillary Pressure,Mu M,"Zheng, Dingye; Pang, Xiongqi; Zhou, Liming; You, Xincai; Liu, Xiaohan; Guo, Fangxin; Li, Wei","Critical conditions of tight oil charging and determination of the lower limits of petrophysical properties for effective tight reservoirs: A case study from the Fengcheng Formation in the Fengcheng area, Junggar Basin",Tight oil; Effective tight reservoir; Lower limits of petrophysical properties; Dynamic mechanism; Junggar basin,TRIASSIC YANCHANG FORMATION; LUCAOGOU FORMATION; SOURCE ROCKS; JIMUSAR SAG; HYDROCARBON GENERATION; RESEARCH PROGRESS; SONGLIAO BASIN; ORDOS BASIN; CHANG 7; CHINA,"Studying the lower limits of petrophysical properties is important to evaluate the exploration and development potentials of tight oil reservoirs. At present, the evaluation criteria are based on a large number of cores and logging data, and rules are based on collections of empirical statistics and displacement pressure experiments. However, there have been few studies on the lower limits of the petrophysical properties of tight reservoirs based on force balance conditions for the hydrocarbon charging process. In this paper, the critical condition for hydrocarbon charging is determined using the oil expansion pressure as the main driving force, with the capillary pressure as the major resistance, via an analysis of the dynamic mechanism of tight oil reservoirs. A force-balance model for judging the lower limits of the petrophysical properties of tight reservoirs can be established by assuming that the oil expansion pressure is equal to the capillary force. This discriminant method is applied to calculate the critical pore-throat radius of the effective reservoirs of the Lower Permian Fengcheng Formation in the Fengcheng area, Junggar Basin, which are 0.310 mu m, 0.248 mu m, 0.208 mu m, and 0.135 mu m, when the buried depths are 2500-3000 m, 3000-3500 m, 3500-4000 m, and 4000-4500 m, respectively. The corresponding critical porosities are 6.15%, 4.84%, 3.81%, and 1.20%, respectively. The lower limits of the petrophysical properties of effective tight reservoirs gradually decrease with increasing burial depth. This method is of great significance for resource evaluations of tight oil reservoirs and the selection of exploration zones.",2,2,6
Capillary Pressure,Mu M,"Li, Ying; Cui, Xiaojiang; Li, Haitao; Chen, Shengnan; Zhang, Qihui",An in-situ capillary pressure measurement method to characterize pore structure of tight formation,Capillary pressure; In-situ; Pore structure; Tight formation; Confining pressure,PERMEABILITY; FLOW; SCALE,"Tight sandstones usually contain pore throats ranging from nano-scale to micro-scale with poor connectivity. Few existing capillary pressure obtainment methods are capable of providing accurate in-situ capillary pressures for tight formations. This work has developed and verified a method (SMD) to measure the in-situ capillary pressure specially for tight formations under high pressure, high temperature and confining pressure with native formation fluids. The capillary pressures converted from the porous plate method (PP), the mercury intrusion method (MICP) and the self-developed method under ambient temperature (SDM-A) were compared with the in-situ capillary pressures to examine errors of the converted capillary pressures. Furthermore, the in-situ capillary pressures and the pore structure of a target tight formation were investigated through the SDM. Results show that the relative errors of the SDM are lower than 20% with an average value of 7.8%. Average relative errors are around 29.5%, 12% and 6% for the converted capillary pressures from the MICP, PP and SDM-A, respectively. This indicates that it is better to measure the in-situ capillary pressure directly through the easy and reliable SDM than to convert from other capillary pressures. The median in-situ capillary pressures of the target tight rock samples range from 0.1 MPa to 0.8 MPa. The pore throat radiuses are mainly from 0.1 mu m to 1.0 mu m, and the movable oil saturation is between 11.72% and 66.21% with an average value of 34.92%. This paper provides a new method to accurately characterize the in-situ pore structure and can provide guidance for oil-gas field development.",1,1,2
Capillary Pressure,Pressure Gradient,"Andersen, Pal O.; Zhou, Yingfang",Steady state relative permeability experiments with capillary end effects: Analytical solutions including derivation of the intercept method,Capillary end effects; SCAL; Steady state experiment; Generalized capillary number; Analytical solutions; Intercept method,,"Steady state relative permeability experiments are performed by coinjection of two (or more) immiscible fluids. The relative permeabilities can be calculated directly from the stabilized pressure drop and saturation of the core if capillary end effects and transient effects are negligible. In most cases such conditions are difficult to obtain. This work presents an analytical solution in form of explicit expressions for the spatial profiles of pressure gradients and saturation, average saturation and pressure drop for a core being injected simultaneously with two phases at steady state when capillary end effects are significant. When arbitrary saturation functions are applied, such parameters and distributions can only by obtained by numerical integration. By assumption of simplified saturation function correlations the differential equation describing steady state can be integrated. A new dimensionless capillary number N is obtained which contains the fluid and rock parameters, but also the saturation function parameters (relative permeability and capillary pressure), fluid viscosities, injected flow fraction, total flow rate and more. It is shown that when this number is of magnitude 1, end effects cover parts of the core, but parts of the core are also unaffected. For N > 10 the end effects are negligible, while for N < 10 end effects are dominant. This paper gives the first formal proof of the intercept method from basic assumptions. It is shown that when the inlet saturation is sufficiently close to that of a no capillary pressure situation; the average saturation changes linearly with the inverse of total rate towards the saturation corresponding to no capillary forces; also, the pressure drop divided by the pressure drop of a no end effect situation goes linearly towards 1 with the inverse of total rate.",3,3,3
Capillary Pressure,Pressure Gradient,"Naeem, Mohammad Hossein Towfighi; Dehaghani, Amir Hossein Saeedi",Evaluation of the performance of oil as a membrane during low-salinity water injection; focusing on type and concentration of salts,Smart water; Low-salinity water; Semi-permeable membrane; Osmotic pressure gradient,WETTABILITY; EOR; SANDSTONE,"Injection of low-salinity or smart water into the reservoir is one of the most common EOR techniques. This technique leads to more oil recovery in comparison to reservoir water and seawater injection. Several mechanisms explain the reasons for this increased recovery level, the most important of which is the wettability alteration towards water-wet conditions. However, in recent years, further mechanisms have been added to the previous ones as the main or complementary mechanism. One of these newly added mechanisms is the performance of oil as a semi-permeable membrane between connate and low-salinity waters. According to this mechanism, water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure (difference in chemical potential), which works as the driving force, until the system moves toward equilibrium in concentration. Introducing water molecules into connate water causes the swelling of connate water, and eventually moves the oil towards the pore throats. In this study, experiments have been performed on capillary tubes, while ignoring the effect of fluid-rock interactions to investigate the proposed theory. Experimental results confirmed the role of osmotic theory. Furthermore, a decrease in the salinity of the low-salinity water causes the oil-droplets' displacement to increase, whereas further reductions in the salinity of the injected water cause lower displacements. Therefore, there is an optimum value of low-salinity water concentration to obtain the highest possible oil drop displacement. The optimum values for the tested samples in this study were about 5000-10000 ppm. Additionally, it was found that among all of the essential seawater salts, potassium chloride leads to the highest oil drop displacement; and among oil samples, heptane showed better membrane-like performance in comparison to toluene and crude oil.",3,3,0
Capillary Pressure,Pressure Gradient,"Santos, M. P. P. C.; Carvalho, M. S.",Pore network model for retrograde gas flow in porous media,Pore-network models; Gas-condensate; Capillary condensation; Compositional reservoir simulation,CONDENSATE; VISCOSITY,"Gas well deliverability in retrograde gas reservoirs is affected by the appearance of a liquid phase near the wellbore when the bottom-hole pressure is below the dew point. At low enough pressure gradients, the liquid phase may bridge the pore throats, blocking the gas phase flow, leading to what is known as condensate blockage. If the pressure gradient is above a critical value, the capillary forces cannot block the gas flow and the condensate bridges are displaced. Gas production can be estimated using reservoir-scale simulation of the retrograde gas flow near producing wells using relative permeability curves that take into account the different physical phenomena and their dependence on local pressure, temperature and pressure gradient (capillary number). Pore-scale simulators can be used to model retrograde gas flow through porous media and to determine the gas and liquid phases relative permeability curves as a function of different flow parameters. Here, a fully-implicit isothermal compositional pore-scale network model is presented for retrograde gas flow in porous media at high capillary number, at which capillary forces are neglected. The flow pattern in each capillary changes from a single-phase gas flow to a two-phase core-annular flow regime when the pressure and the fluid composition reach a critical condition based on the thermodynamics of the fluid mixture. Newton's method is used to solve the non-linear flow and thermodynamics equations to calculate the pressure distribution and the flow rate of each component through the network. The model was used to predict gas-liquid relative permeability at high capillary number from a depletion process in a 2D network. The results show the evolution of the condensate saturation at different conditions and how the gas permeability falls abruptly at a certain condensate saturation.",3,3,0
Capillary Pressure,Interfacial Tension,"Francisco Perez-Sanchez, Josue; Palacio-Perez, Arturo; Jonathan Suarez-Dominguez, Edgardo; Patricia Diaz-Zavala, Nancy; Izquierdo-Kulich, Elena",Evaluation of surface tension modifiers for crude oil transport through porous media,Porous media pressure drop; Two-phase flow in porous beds; Oil/water interfacial tension; Biodiesel-based products,PEROXIDE PRESOAKING PRIOR; CAPILLARY NUMBER; WETTABILITY; HEAVY; PERMEABILITY; RESERVOIRS; RECOVERY; MOBILITY; ENERGY; PHASE,"The high viscosity and low surface tension of heavy crude oils, combined with the low relative permeability of the medium, cause their entrapment in the porous reservoir nets, affecting the oil production. In this work, the effect of two biodiesel-based flow improvers, and a non-ionic surfactant was evaluated on surface tension modification and fluid flow through porous media. A mathematical model was obtained, whose simplicity in the application makes it useful for the preliminary evaluation of EOR chemical products. The model determines the pressure drop in porous media through the correlation of contact angle, surface tension, and viscosity, as well as the fractal characterization of the surface. It was found that the biodiesel-based improvers reduce the surface tension and the pressure drop in the transport through porous media by up to 20%.",3,3,1
Capillary Pressure,Interfacial Tension,"Bouquet, Sarah; Douarche, Frederic; Roggero, Frederic; Bourbiaux, Bernard",Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization,Enhanced oil recovery; Naturally fractured reservoir; Oil-wet; Foam; Multiphase flow; Capillary pressure; Interfacial tension; Reservoir simulation; Mobility reduction; Dual-medium; Viscous forces,SIMULATION,"In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction. Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale. This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals. This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ""low-IFT"" effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.",3,3,0
Capillary Pressure,Image,"Purswani, Prakash; Karpyn, Zuleima T.; Enab, Khaled; Xue, Yuan; Huang, Xiaolei",Evaluation of image segmentation techniques for image-based rock property estimation,X-ray imaging; Porous media; Image segmentation; Machine learning; WEKA segmentation; MIA clustering,X-RAY MICROTOMOGRAPHY; POROUS-MEDIA; RELATIVE PERMEABILITY; INTERFACIAL AREA; CAPILLARY-PRESSURE; MULTIPHASE FLOW; 2-PHASE FLOW; AIR-WATER; HYSTERESIS; FLUID,"Accurate characterization of rock and fluid properties in porous media using X-ray imaging techniques depends on reliable identification and segmentation of the involved phases. Segmentation is critical for the estimation of porosity, fluid saturations, fluid and rock topology, and pore connectivity, among other pore-scale properties. Therefore, the purpose of this study is to compare the effectiveness of different image segmentation techniques when applied to image data analysis in porous media. Two machine learning based segmentation techniques - a supervised ML technique called Fast Random Forest, and an unsupervised method combining k-means and fuzzy c-means clustering algorithms - were compared using an experimental data set. Comparisons are also presented against traditional thresholding segmentation. In addition, we discuss the potential and limitations of applying deep learning based segmentation algorithms. The performance of the segmentation techniques were compared on estimates of porosity, saturation, and surface area, as well as pore-scale estimates such as fluid-fluid interfacial areas, and Euler characteristic. X-ray micro-computed tomography images for a sintered glass frit, saturated with two-phases (air and brine), were acquired at two different voxel resolutions. The high-resolution images (6 mu m) were used as the benchmark case, while the low-resolution images (18 mu m) were segmented by three segmentation techniques: Fast Random Forest, clustering, and thresholding. The results for porosity and phase saturation from thresholding and from the supervised ML method (i.e. Fast Random Forest) were found to be close to the benchmark case. Segmentation results from the unsupervised ML method (i.e. clustering) were largely unsatisfactory, except for total surface area measurements. The supervised ML segmentation results provided better measurements for air-brine interfacial areas by capturing three-phase interfacial regions. Also, all segmentation techniques resulted in similar measurements for air-phase Euler characteristic confirming poor connectivity of the trapped air phase, although the closest results were obtained by the supervised ML method. Finally, despite the supervised ML segmentation technique being more computationally intensive, it was found to require less user intervention and its implementation was more straightforward. In summary, this work provides insights into different segmentation techniques, their implementation, as well as advantages and limitations with regards to quantitative analysis of pore-scale properties in saturated porous media.",3,3,1
Capillary Pressure,Image,"Dakhelpour-Ghoveifel, Jalal; Shahverdi, Hamidreza",Prediction of gas-oil capillary pressure of carbonate rock using pore network modeling,Pore network modelling; Pore network history match; Capillary pressure prediction; Pore size distribution,POROUS-MEDIA; FINITE-ELEMENT; 2-PHASE FLOW; RELATIVE PERMEABILITY; MULTIPHASE FLOW; RECONSTRUCTION; SIMULATIONS; SANDSTONE; IMAGES,"This study suggests a frame work to predict the capillary pressure curve of the carbonate rocks using a pore network simulation. A novel pore network manipulation algorithm is introduced to match three curves and predict only one curve (air-oil). This implies that the matching process is much more complicated. In return, more valid results are obtained and the problem of non-uniqueness of statistical PNM approach is mitigated. Finally, a collection of the most significant parameters governing capillary pressure are tabulated. Two plugs with air-mercury, air-oil and water-oil drainage and water-oil imbibition capillary pressure tests are used. Water-oil drainage and imbibition and air-mercury drainage are matched with the same pore network. The pore network is constructed based on a statistical distribution of the network elements. Then, properties of air and oil are input to the pore network to estimate air-oil capillary pressure. Matching three capillary pressure curves using a network is a complicated task to do, especially when no 3D image of the plugs is available. On the other hand, it is evident by the acceptable results that the error of prediction is moderated using the suggested method. This estimation technic is a new application of pore network modeling that can be used for reservoirs with no 3D image of plugs and limited SCAL data.",1,1,1
Capillary Pressure,Clay,"He, Jie; Wang, Hua; Tang, Jianrong; Shangguan, Yunfei; Yang, Xiangrong; Gong, Yin; Zhao, Rui; Zhou, Xuefeng","Evaluation of lacustrine mudstone top sealing capacity in the Lenghu-5 area, Qaidam Basin, Tibetan Plateau",Sealing capacity; Nitrogen adsorption; Mercury injection capillary pressure; Diagenesis; Overpressure; Brittleness index,PORE-SIZE DISTRIBUTION; FRACTAL CHARACTERISTICS; NORTHERN MARGIN; GAS-ADSORPTION; CAP-ROCK; MECHANICAL-PROPERTIES; THRESHOLD PRESSURE; REGIONAL TECTONICS; SURFACE-AREA; NATURAL-GAS,"Top seal capacity is one of the fundamental geological factors that must be considered during petroleum exploration. Based on thin section, low-pressure N-2 adsorption, bulk mineralogy, X-ray diffraction (XRD), mercury injection experiment and pressure data, the sealing capacity, lithofacies, petrophysics, diagenesis, capillary breakthrough pressure, overpressure, and brittleness index characteristics of a lacustrine mudstone top seal from the Lenghu-5 area, Qaidam Basin, Tibetan Plateau was investigated. The bulk rock composition of the top seal was dominated by clay minerals with carbonate cements and has a gross mudstone to sandy mudstone lithofacies. The isotherms from low-pressure nitrogen adsorption tests which presents as reversed S-shaped, belong to type B and the characteristics of hysteresis loops indicating the silt-like pores in the samples. The pores of the mudstone top seals are predominantly mesopores according to the N-2 adsorption and mercury injection experiment results. The cumulative mudstone thickness varies from 100 to 1400 m. The overpressured mudstone top seal in the Lenghu-5 area has three potential hydrocarbon preservation implications: overpressure cannot seal oil and gas, overpressure seals oil and gas directly, and overpressure seals oil and gas indirectly. The brittleness index (BI) values calculated by four methods based on the mineralogical composition of the mudstone top seals and the BI is higher at the top and bottom of the studied interval than in the middle mudstone layer. Based on the mud content, pore diameter, thickness, diagenetic stage, capillary breakthrough pressure, overpressure coefficient and brittleness index of the lacustrine mudstone, the top seal in the Lenghu-5 area is classified into four types: type I, II, III and IV, representing good to poor sealing capacities. The method for evaluation of the sealing capacity in this study can not only provide useful guidance for hydrocarbon exploration in Lenghu-5 area, Qaidam Basin, but also can be used in basins around the world by selecting the main influencing factors of sealing capacity in the basin.",3,3,6
Capillary Pressure,Clay,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Capillary Pressure,Surface Area,"He, Jie; Wang, Hua; Tang, Jianrong; Shangguan, Yunfei; Yang, Xiangrong; Gong, Yin; Zhao, Rui; Zhou, Xuefeng","Evaluation of lacustrine mudstone top sealing capacity in the Lenghu-5 area, Qaidam Basin, Tibetan Plateau",Sealing capacity; Nitrogen adsorption; Mercury injection capillary pressure; Diagenesis; Overpressure; Brittleness index,PORE-SIZE DISTRIBUTION; FRACTAL CHARACTERISTICS; NORTHERN MARGIN; GAS-ADSORPTION; CAP-ROCK; MECHANICAL-PROPERTIES; THRESHOLD PRESSURE; REGIONAL TECTONICS; SURFACE-AREA; NATURAL-GAS,"Top seal capacity is one of the fundamental geological factors that must be considered during petroleum exploration. Based on thin section, low-pressure N-2 adsorption, bulk mineralogy, X-ray diffraction (XRD), mercury injection experiment and pressure data, the sealing capacity, lithofacies, petrophysics, diagenesis, capillary breakthrough pressure, overpressure, and brittleness index characteristics of a lacustrine mudstone top seal from the Lenghu-5 area, Qaidam Basin, Tibetan Plateau was investigated. The bulk rock composition of the top seal was dominated by clay minerals with carbonate cements and has a gross mudstone to sandy mudstone lithofacies. The isotherms from low-pressure nitrogen adsorption tests which presents as reversed S-shaped, belong to type B and the characteristics of hysteresis loops indicating the silt-like pores in the samples. The pores of the mudstone top seals are predominantly mesopores according to the N-2 adsorption and mercury injection experiment results. The cumulative mudstone thickness varies from 100 to 1400 m. The overpressured mudstone top seal in the Lenghu-5 area has three potential hydrocarbon preservation implications: overpressure cannot seal oil and gas, overpressure seals oil and gas directly, and overpressure seals oil and gas indirectly. The brittleness index (BI) values calculated by four methods based on the mineralogical composition of the mudstone top seals and the BI is higher at the top and bottom of the studied interval than in the middle mudstone layer. Based on the mud content, pore diameter, thickness, diagenetic stage, capillary breakthrough pressure, overpressure coefficient and brittleness index of the lacustrine mudstone, the top seal in the Lenghu-5 area is classified into four types: type I, II, III and IV, representing good to poor sealing capacities. The method for evaluation of the sealing capacity in this study can not only provide useful guidance for hydrocarbon exploration in Lenghu-5 area, Qaidam Basin, but also can be used in basins around the world by selecting the main influencing factors of sealing capacity in the basin.",3,3,6
Capillary Pressure,Surface Area,"Purswani, Prakash; Karpyn, Zuleima T.; Enab, Khaled; Xue, Yuan; Huang, Xiaolei",Evaluation of image segmentation techniques for image-based rock property estimation,X-ray imaging; Porous media; Image segmentation; Machine learning; WEKA segmentation; MIA clustering,X-RAY MICROTOMOGRAPHY; POROUS-MEDIA; RELATIVE PERMEABILITY; INTERFACIAL AREA; CAPILLARY-PRESSURE; MULTIPHASE FLOW; 2-PHASE FLOW; AIR-WATER; HYSTERESIS; FLUID,"Accurate characterization of rock and fluid properties in porous media using X-ray imaging techniques depends on reliable identification and segmentation of the involved phases. Segmentation is critical for the estimation of porosity, fluid saturations, fluid and rock topology, and pore connectivity, among other pore-scale properties. Therefore, the purpose of this study is to compare the effectiveness of different image segmentation techniques when applied to image data analysis in porous media. Two machine learning based segmentation techniques - a supervised ML technique called Fast Random Forest, and an unsupervised method combining k-means and fuzzy c-means clustering algorithms - were compared using an experimental data set. Comparisons are also presented against traditional thresholding segmentation. In addition, we discuss the potential and limitations of applying deep learning based segmentation algorithms. The performance of the segmentation techniques were compared on estimates of porosity, saturation, and surface area, as well as pore-scale estimates such as fluid-fluid interfacial areas, and Euler characteristic. X-ray micro-computed tomography images for a sintered glass frit, saturated with two-phases (air and brine), were acquired at two different voxel resolutions. The high-resolution images (6 mu m) were used as the benchmark case, while the low-resolution images (18 mu m) were segmented by three segmentation techniques: Fast Random Forest, clustering, and thresholding. The results for porosity and phase saturation from thresholding and from the supervised ML method (i.e. Fast Random Forest) were found to be close to the benchmark case. Segmentation results from the unsupervised ML method (i.e. clustering) were largely unsatisfactory, except for total surface area measurements. The supervised ML segmentation results provided better measurements for air-brine interfacial areas by capturing three-phase interfacial regions. Also, all segmentation techniques resulted in similar measurements for air-phase Euler characteristic confirming poor connectivity of the trapped air phase, although the closest results were obtained by the supervised ML method. Finally, despite the supervised ML segmentation technique being more computationally intensive, it was found to require less user intervention and its implementation was more straightforward. In summary, this work provides insights into different segmentation techniques, their implementation, as well as advantages and limitations with regards to quantitative analysis of pore-scale properties in saturated porous media.",3,3,1
Capillary Pressure,Adsorption,"He, Jie; Wang, Hua; Tang, Jianrong; Shangguan, Yunfei; Yang, Xiangrong; Gong, Yin; Zhao, Rui; Zhou, Xuefeng","Evaluation of lacustrine mudstone top sealing capacity in the Lenghu-5 area, Qaidam Basin, Tibetan Plateau",Sealing capacity; Nitrogen adsorption; Mercury injection capillary pressure; Diagenesis; Overpressure; Brittleness index,PORE-SIZE DISTRIBUTION; FRACTAL CHARACTERISTICS; NORTHERN MARGIN; GAS-ADSORPTION; CAP-ROCK; MECHANICAL-PROPERTIES; THRESHOLD PRESSURE; REGIONAL TECTONICS; SURFACE-AREA; NATURAL-GAS,"Top seal capacity is one of the fundamental geological factors that must be considered during petroleum exploration. Based on thin section, low-pressure N-2 adsorption, bulk mineralogy, X-ray diffraction (XRD), mercury injection experiment and pressure data, the sealing capacity, lithofacies, petrophysics, diagenesis, capillary breakthrough pressure, overpressure, and brittleness index characteristics of a lacustrine mudstone top seal from the Lenghu-5 area, Qaidam Basin, Tibetan Plateau was investigated. The bulk rock composition of the top seal was dominated by clay minerals with carbonate cements and has a gross mudstone to sandy mudstone lithofacies. The isotherms from low-pressure nitrogen adsorption tests which presents as reversed S-shaped, belong to type B and the characteristics of hysteresis loops indicating the silt-like pores in the samples. The pores of the mudstone top seals are predominantly mesopores according to the N-2 adsorption and mercury injection experiment results. The cumulative mudstone thickness varies from 100 to 1400 m. The overpressured mudstone top seal in the Lenghu-5 area has three potential hydrocarbon preservation implications: overpressure cannot seal oil and gas, overpressure seals oil and gas directly, and overpressure seals oil and gas indirectly. The brittleness index (BI) values calculated by four methods based on the mineralogical composition of the mudstone top seals and the BI is higher at the top and bottom of the studied interval than in the middle mudstone layer. Based on the mud content, pore diameter, thickness, diagenetic stage, capillary breakthrough pressure, overpressure coefficient and brittleness index of the lacustrine mudstone, the top seal in the Lenghu-5 area is classified into four types: type I, II, III and IV, representing good to poor sealing capacities. The method for evaluation of the sealing capacity in this study can not only provide useful guidance for hydrocarbon exploration in Lenghu-5 area, Qaidam Basin, but also can be used in basins around the world by selecting the main influencing factors of sealing capacity in the basin.",3,3,6
Capillary Pressure,Adsorption,"Bouquet, Sarah; Douarche, Frederic; Roggero, Frederic; Bourbiaux, Bernard",Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization,Enhanced oil recovery; Naturally fractured reservoir; Oil-wet; Foam; Multiphase flow; Capillary pressure; Interfacial tension; Reservoir simulation; Mobility reduction; Dual-medium; Viscous forces,SIMULATION,"In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction. Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale. This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals. This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ""low-IFT"" effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.",3,3,0
Capillary Pressure,Size Distribution,"Neshat, Sajjad S.; Okuno, Ryosuke; Pope, Gary A.",Simulation of solvent treatments for fluid blockage removal in tight formations using coupled three-phase flash and capillary pressure models,Unconventional EOR; Solvent; Shale gas; Solvent.; Capillary pressure; Phase behavior,STABILITY ANALYSIS; PHASE-BEHAVIOR; CONDENSATE; MIXTURES; WATER; RESERVOIR,"Water and condensate blockage near production wells in unconventional reservoirs can significantly reduce oil and gas production rates. This paper presents a new approach for more accurate modeling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. A cubic equation of state is used to model mixtures of solvent, hydrocarbons and water that form up to three phases. The three-phase flash model is coupled with a three-phase capillary pressure model to account for the effect of capillary pressure in confined space. The capillary pressure function includes the impact of several important petrophysical properties such as pore size distribution and wettability. A compositional simulator is used to demonstrate the importance of the new phase behavior model. Single- and multi-cycle processes of methanol, dimethyl ether or CO2 injection are simulated to remove liquid blockage and increase production rate in tight oil/gas reservoirs. Simulation results show that DME is more efficient than methanol and CO2 for removal of liquid blockage in tight oil/gas reservoirs because DME is miscible with both oil and water under the simulated reservoir conditions.",3,3,1
Capillary Pressure,Size Distribution,"Dakhelpour-Ghoveifel, Jalal; Shahverdi, Hamidreza",Prediction of gas-oil capillary pressure of carbonate rock using pore network modeling,Pore network modelling; Pore network history match; Capillary pressure prediction; Pore size distribution,POROUS-MEDIA; FINITE-ELEMENT; 2-PHASE FLOW; RELATIVE PERMEABILITY; MULTIPHASE FLOW; RECONSTRUCTION; SIMULATIONS; SANDSTONE; IMAGES,"This study suggests a frame work to predict the capillary pressure curve of the carbonate rocks using a pore network simulation. A novel pore network manipulation algorithm is introduced to match three curves and predict only one curve (air-oil). This implies that the matching process is much more complicated. In return, more valid results are obtained and the problem of non-uniqueness of statistical PNM approach is mitigated. Finally, a collection of the most significant parameters governing capillary pressure are tabulated. Two plugs with air-mercury, air-oil and water-oil drainage and water-oil imbibition capillary pressure tests are used. Water-oil drainage and imbibition and air-mercury drainage are matched with the same pore network. The pore network is constructed based on a statistical distribution of the network elements. Then, properties of air and oil are input to the pore network to estimate air-oil capillary pressure. Matching three capillary pressure curves using a network is a complicated task to do, especially when no 3D image of the plugs is available. On the other hand, it is evident by the acceptable results that the error of prediction is moderated using the suggested method. This estimation technic is a new application of pore network modeling that can be used for reservoirs with no 3D image of plugs and limited SCAL data.",1,1,1
Seismic Data,Inversion,"Li, Yue; Cao, Danping; Jin, Chao",Joint inversion of quality factor based on upgoing and downgoing waves,Quality factor; Upgoing wave; Downgoing wave; Amplitude spectrum,SEISMIC ATTENUATION; ZERO-OFFSET; FREQUENCY; PEAK,"Quality factor Q is a key parameter describing seismic wave attenuation. Estimating Q accurately is important to seismic data processing and reservoir characterization. Downgoing and upgoing waves are coming from above and below the receiver containing the strata information, respectively. Downgoing wave has always been the key in Q inversion, while the upgoing wave is seldom used. Thus, the information contained in the upgoing wave is not fully utilized, leading to problems of multi-solution and low accuracy. To fix these problems, this study proposes a joint inversion method of Q, which uses both upgoing and downgoing waves. The nonlinear relation among the upgoing wave, downgoing wave, and Q value is jointly used to construct an objective function, which measures the energy difference between the actual and calculated amplitude spectra. As the energy between upgoing and downgoing waves is not balanced, to balance the weight of the two kinds of waves in Q inversion, a weight coefficient is used to adaptively control the weight of them. The optimal Q can be estimated by minimizing the objective function. Numerical simulation results indicate that the proposed method can reduce the effect of frequency band selection, and provide more accurate results. The application on field data demonstrates that good results can be achieved, and the estimated Q has great potential in reservoir characterization.",2,2,2
Seismic Data,Inversion,"Van Huong Le; Diaz-Viera, Martin A.; Vazquez-Ramirez, Daniel; Del Valle-Garcia, Raul; Erdely, Arturo; Grana, Dario",Bernstein copula -based spatial cosimulation for petrophysical property prediction conditioned to elastic attributes,,SEISMIC DATA; NONPARAMETRIC-ESTIMATION; POROSITY; INVERSION; INTEGRATION; SIMULATION; MODEL; PERMEABILITY; FACIES,,2,2,1
Seismic Data,Inversion,"Abd-Allah, Ali M. A.; Abd El-Naby, Ahmed; Aal, Mohamed H. Abdel","Tectonic and basin evolution of South Eastern Mediterranean for hydrocarbon potentiality in North Sinai, Egypt",Inversion tectonics; Sinai; Eastern mediterranean basin; African continental margin; Basin evolution,MESSINIAN SALINITY CRISIS; CONTINENTAL-MARGIN; LEVANT BASIN; ERATOSTHENES SEAMOUNT; NORTHEASTERN AFRICA; CRUSTAL STRUCTURE; REGION; INVERSION; ORIGIN; HISTORY,"South Eastern Mediterranean margin has expressed two Jurassic-Recent tectonic cycles that related to the opening and closure of the Neotethys Ocean. Structural and sedimentological complications related to these cycles and the basin evolution are selected to be the main targets of the present study in North Sinai. 2D seismic, boreholes, and outcrop data are used to achieve these targets. The development of the margin began by the formation of the NE and E-W oriented normal faults during the Jurassic-Early Cretaceous rifting. Two Albian uplifting phases occurred by the end of this rifting and followed by the Cenomanian-Oligocene positive inversion that was interrupted by a tectonic loading subsidence phase allowed the deposition of the pelagic Campanian-Maastrichtian chalk on the shallow Upper Cretaceous carbonate. Shortening related to this inversion inverted completely the normal-slip on some rift-related faults into reverse faults and related folds or partially inverted by decreasing of the normal slip on the others. Inversion was ended by the post-Oligocene extensional-subsidence event that is related to north-sinking of the northern part of the African margin under the European plate. The three-tectonic regimes in association with the sediments supplies, sea level changes, total basin subsidence, basin extension, uplifting, and erosion resulted in complex sedimentary packages that are interrupted by many un-conformities and exhibited dramatic lateral facies and thickness changes. Considerable depositional environments were transited northward, from the reefal and subtidal to shelf and then to the deep marine, where the facies formation was controlled by mix effects of the sediment supplies, north-tilting continental margin, tectonic activities, sediment load and subsidence. Offshore part of Sinai preserves good conditions favorable for hydrocarbon accumulation and requires more intensive exploration.",2,2,0
Seismic Data,Inversion,"Pan, Xinpeng; Li, Lin; Zhang, Guangzhi",Multiscale frequency-domain seismic inversion for fracture weakness,Multiscale frequency-domain inversion; AVOAz inversion; Bayesian inversion; Fracture weaknesses; Fourier operator,WAVE-FORM INVERSION; AVO INVERSION; MODEL; COEFFICIENTS; ANISOTROPY; AMPLITUDE; AZIMUTH; PHASE; ANGLE,"Amplitude variation with offset and azimuth (AVOAz) inversion is an effective tool to invert the azimuthal seismic reflection data for fracture weaknesses, which play an important role in seismic characterization of fractures. Conventional AVOAz inversion is implemented in the time domain, which simultaneously uses full-frequency components of the seismic data causing an unstable and inaccurate inversion result in the case of noisy seismic data. Here we propose a novel multiscale frequency-domain seismic inversion approach to improve resolution and accuracy of fracture weakness estimates. Based on new derived frequency-domain expression of azimuthal seismic amplitude difference for a horizontal transversely isotropic (HTI) medium, we build the kernel function incorporated with the Fourier operator, which avoids the Fourier inverse transform in the frequency-domain inversion. Low frequency information in seismic data is often missing or contaminated with noises, thus we establish an inversion objective function combining low frequency regularization term and Cauchy sparse regularization term in the Bayesian framework. We adopt the multiscale strategy and perform inversion successively from low to high frequency group utilizing a limited number of frequency components with a high signal-to-noise (S/N) ratio. In addition, we compare the multiscale frequency-domain inversion approach, the frequency-domain simultaneous inversion approach, and the time-domain inversion approach using synthetic data and field data. Synthetic example demonstrates that the cross-correlation coefficients (CCs) between the true fracture weaknesses and the inversion results obtained by multiscale frequency-domain inversion approach are above 0.83 even with a S/N of 2. Compared to the time-domain inversion approach and the frequencydomain simultaneous inversion approach, the inversion results with multiscale frequency-domain inversion approach have higher resolution and accuracy. Field data example further validates the feasibility and superiority of the proposed multiscale frequency-domain inversion approach.",2,2,0
Seismic Data,Inversion,"Chai, Yibo; Lu, Jun; Chen, Benchi; Zhang, Tieqiang",Elastic parameter inversion of a sand body based on the exact reflection coefficient,AVA inversion; Jacobian matrix; Oil-gas exploration; Elastic parameter; Gas-bearing sandstone,AVO INVERSION; LEAST-SQUARES; SEISMIC DATA; WAVE; APPROXIMATIONS; ALGORITHM; EQUATIONS; GAS; PP,"Prestack seismic inversion is an important technology for oil and gas exploration that can provide accurate lithology and pore fluid information on underground media. Prestack inversion is theoretically based on the Zoeppritz equations, which establish the relationship between the seismic reflection coefficients of different offsets and elastic parameter contrasts between the interface of two lithologies. However, these are fourth-order matrix equations with a complex form and are difficult to be directly applied to inversion. Approximate analytical solutions have been used to establish a linear relationship between the seismic reflection coefficients and elastic parameters. And the approximations are based on the assumptions of a small angle and weak contrast, they cannot be applied to layers of high contrast, such as gas-bearing sandstones and coal seams. In this paper, we present an accurate prestack seismic inversion method that can be applied to a wider range of geological models. First, we derive the partial derivatives of the exact reflection coefficients of PP waves based on the Zoeppritz equations with respect to the elastic parameters and establish the exact Jacobian and Hessian matrices. Then, we use the least-squares algorithm to construct objective functions for the simultaneous inversion of three elastic parameters: The P-wave velocity, S-wave velocity, and density. Examples show that our inversion method is more accurate for strata with strong reflection interfaces than the approximate prestack inversion methods and stable under noisy conditions. The inversion method was applied in channel sand depositions of the Lower Permian Shanxi and Shihezi Formation of the Ordos Basin, and it was efficient to identify the gas-bearing sand layers and determine the range of potentially favorable areas.",1,1,1
Seismic Data,Oil Field,"Han, Changcheng; Tian, Jijun; Hu, Chenlin; Liu, Hailei; Wang, Wenfeng; Huan, Zhipeng; Feng, Shuo","Lithofacies characteristics and their controlling effects on reservoirs in buried hills of metamorphic rocks: A case study of late Paleozoic units in the Aryskum depression, South Turgay Basin, Kazakhstan",Metamorphic rocks; Lithofacies characters; Reservoir properties; Aryskum depression,KARATAU FAULT; PETROGEOCHEMICAL CHARACTERISTICS; TECTONIC IMPLICATIONS; CARBONATE RESERVOIRS; VOLCANIC-ROCKS; LIAOHE BASIN; CORE COMPLEX; OIL-FIELD; EVOLUTION; BELT,"Metamorphic rock reservoirs are special reservoirs that are quite different from traditional sedimentary rock reservoirs and contain rich hydrocarbon reserves. However, their lithofacies characteristics and reservoir properties are relatively underexplored, and the key factor in reservoirs is lithofacies. Based on core samples, thin sections, whole-rock analysis and well-log and seismic data, we evaluated the lithologies, petrological characteristics and reservoir properties of metamorphic rocks and then explored the main factors controlling reservoir formation and metamorphic rock quality in the Aryskum depression, South Turgay Basin, Kazakhstan. In this area, four types of lithofacies are identified: granitic gneiss (high DEN and CN, low GR), leptite (high GR and CN), gabbro (low GR and CN) and granite (high GR and low CN); among these rocks, granitic gneiss is widely distributed. The reservoir spaces of metamorphic rocks are divided into fractures and pores produced via metamorphism and structural movements. Fractures can be subdivided into structural fractures (SFs), dissolution fractures (DFs), cleavage microfissures (CMfs) and microfissures (Mfs), and pores include dissolved intergranular pores (DInterPs), dissolved intragranular pores (DIntrPs) and vugs (Vgs). Numerous SFs and DFs provide the main reservoir spaces for hydrocarbons. The reservoir quality of metamorphic rocks is primarily controlled by faults, fractures, lithofacies, minerals, dissolution and paleogeomorphology. Lithofacies and minerals are the internal factors that control dissolution and fragmentation, while paleogeomorphology and faults are the external factors that control fracture development. Leptite and granitic gneiss are high-quality reservoir lithofacies, and high paleogeomorphology areas and fault zones are the optimal locations for fractures and pores. Reservoir spaces undergo a series of repeated changes from formation to development, filling and reformation, and a comprehensive reservoir evolution model is proposed to illustrate the distribution of high-quality reservoirs. This study has scientific significance for investigating the reservoir-forming mechanisms of metamorphic rocks and practical applications for exploring and developing oil and gas fields in areas with metamorphic rocks.",3,3,4
Seismic Data,Oil Field,Yin Yanshu; Hu Xun; Huang Jixin; Feng Wenjie; Wang Linxin; Duan Taizhong; Zhao Lei; Zhang Wenbiao,"A three-dimensional model of deep-water turbidity channel in Plutonio oilfield, Angola: From training image generation, optimization to multi-point geostatistical modelling",Multi-point geostatistics; Training image; Alluvsim; Optimization method; The Plutonio oilfield in Angola,SIMULATION; RESERVOIRS; DISTANCE,"The deep-water turbidity channel system in the Oligocene O73 sand layer in the Plutonio oilfield in Angola of west Africa has good oil and gas reservoir capability. As the well spacing is large due to operation cost, and the seismic resolution of the target layer is relatively low, identification of turbidity channel boundary was difficult. To establishes a fine model is a problem faced by the modelers. In this paper, a complete multi-point geostatistical modeling flowchart is presented for the construction of fine deep-water turbidity channel model. According to the investigation of seismic, well logging, drilling data and references in the study area, the genesis, reservoir scale, lithofacies type, morphological characteristics and evolution of the deep-water turbidity channel of the target layer were obtained. The improved Alluvsim algorithm was utilized to generate a set of adaptive deep-water turbidity channel training images with specified curvatures. Net-to-gross, variogram and a high-order statistics method based on the single data event were compared to evaluate and sort the training images. Then, the Snesim method was utilized to construct the models using the sorted compatible training images with a same set of parameters. At last, the quality of different models was compared based on the seismic attribute slices and a composite correlation coefficient optimization method based on seismic data. The results suggest that the improved Alluvsim algorithm can reproduce the channel morphology and stacking patterns better. Compared with the first-order and second-order statistics comparison method, the method using higher-order statistics of single data event taken spatial patterns into consideration and sorted training images better. The reservoir model was established using the optimal selected training image which has a high correlation with seismic attributes, and the model is more consistent with the characteristics of subsurface reservoirs. At the same time, this paper also provides a complete research program for the application of multi-point geostatistical modeling method which is from training image generation, optimal training image selection and multi-point geostatistics modeling to realizations selection for practical subsurface reservoir modelling.",3,3,2
Seismic Data,Oil Field,"Sun, Panke; Fang, Huijing; Xu, Zhaohui; Wang, Chao; Xu, Huaimin; Lu, Man","Siliciclastic depositional model within a subsurface coastal parasequence based on barriers and baffles - An application to the Donghe Sandstone Member in the Hudson Oilfield, Tarim Basin, NW China",Barrier; Baffle; Dipmeter data; Sea-level; Donghe sandstone; Depositional model,SEQUENCE STRATIGRAPHY; FACIES; HIERARCHY; OUTCROP; ORIGIN,"Detailed analyses of a siliciclastic coastal reservoir highlights the need for an enhanced knowledge of their depositional model. At the scale of the bed sets, however, it is difficult to determine the depositional model, largely due to a limit in vertical resolution of seismic data and conventional wireline logs. Barriers and baffles, following either surfaces of bed sets or beds, act as isochronous boundaries, therefore, holding a key to reveal the sedimentary evolution of subsurface reservoirs at small scales. Calcareous and argillaceous barriers and baffles of the Donghe Sandstone Member in the Hudson Oilfield have obvious low conductivity responses in dipmeter data, therefore, they are interpreted and correlated by integration of conventional logs and dipmeter data. Barriers separate the Donghe Sandstone Member into three retrogradational bed sets (i.e., B1 similar to B3) and two progradational bed sets (i.e., B4 similar to B5), of which beds are constrained by baffles with larger dip angles than barriers in the current structure pattern as well as the period of deposition. The stacking patterns indicate relative sea-level rise within B1 similar to B3 and fall within B4 similar to B5. The relative sea-level changes control the baffle frequency, thickness and length of barriers and baffles. Vertically, the variation of frequency and maximum thickness of both argillaceous and calcareous baffles increase during the transgression yet reduce during regression. Horizontally, the length of barriers and baffles positively correlates with their maximum thickness along the paleoshoreline, as it does the direction perpendicular to the paleoshoreline. Therefore, a depositional model of early retrogradation followed by progradation is built for the Donghe Sandstone Member, a siliciclastic coastal parasequence with upper-shoreface and lower-shoreface facies, based on barriers and baffles. This depositional model is embodied with certain principles of reservoir architecture and behavior.",3,3,1
Seismic Data,Oil Field,"Song, Jianyang; Huo, Zhipeng; Fu, Guang; Hu, Ming; Sun, Tongwen; Liu, Zhe; Wang, Wei; Liu, Luofu","Petroleum migration and accumulation in the Liuchu area of Raoyang Sag, Bohai Bay Basin, China",Biomarkers; Migration and accumulation modeling; Migration direction; Physical characteristics of crude oil; Vertical migration,HYDROCARBON MIGRATION; MOLECULAR-PARAMETERS; DONGYING DEPRESSION; NITROGEN-COMPOUNDS; TOARCIAN SHALES; SOURCE ROCKS; PARIS BASIN; OIL-FIELD; SECONDARY; DISTRIBUTIONS,"This study focused on vertical migration of petroleum in the Liuchu area, China. The physical properties of petroleum and changes in the geochemical characteristics of the study area were also investigated. Biomarkers such as, nitrogen compounds, n-alkanes, triterpenoids, steroids, hopanes, and cholestanes were analyzed in this regard. Petro-physical characteristics, such as, density, viscosity, concentrations of wax, resin, and sulfur of oil were studied. The rNa(+)/rCl(-) ratio of Ed(2) formation water ranged from 0.25 to 5.7, oil density of Ed(2) formation ranged from 0.85 to 0.95 g/cm(3), and oil resin concentration 10-50%, oil wax content in Ed(2) formation ranged from 2 to 29% were lower than that of Es1. The rNa(+)/rCl(-) ratio and mineralization of formation water data were examined to demonstrate the migration pathways. Geochemical and crude oil physical indexes were utilized to investigate the relationship between petroleum migration and seismic data. Cholestane alpha beta beta, alpha alpha alpha cholestane, diacholestane, steroid, and low ring terpenes in the formation were utilized to trace petroleum migration. Recent studies on petroleum maturity of have focused on comparison of source rocks and have reported that the maturity effects of source rock and reservoir oil are weak while those effects are high in the Liuchu aera. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The alpha alpha alpha C-29 (20S)/(20S + 20R) and C-29 (beta beta)/alpha alpha + beta beta) ratios ranged from 0.2 to 0.35 Further, C-31 (22S)/(22S + 22R), C-32(22S)/(22S + 22R), and C-29 (20S)/(20S + 20R) ratios ranged from 0.3 to 0.8, and 0.131 and 0.81, respectively. Petroleum migrated along migration channels. This suggested that vertical migration occurred after formation of the source rock fault and lateral migration occurred along the sandbody. Reservoir sandstone content, overlying mudstone content, and thickness of caprock are likely limited lateral petroleum migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The results of this study enabled optimization of uncertain petroleum migration pathways and improved the petroleum migration and accumulation model.",2,2,1
Seismic Data,Approach,"Asghar, Saleem; Choi, Junhwan; Yoon, Daeung; Byun, Joongmoo",Spatial pseudo-labeling for semi-supervised facies classification,Facies classification; Deep learning; Pseudo-labeling; Reservoir characterization,NEURAL-NETWORKS; ROCK TYPES; PREDICTION; LITHOLOGY; LOGS,"For the Quantitative classification of facies is crucial to link seismic data with its corresponding lithology for the evaluation of reservoir properties. During the past decade, seismic volumes have increased to the degree that it is perplexing for the geoscientists and seismic interpreters to examine every single seismic section to carry out facies classification. This has triggered and inspired the need and development of machine learning approaches to efficiently predict seismic facies. However, classified data or labeled data (i.e., well log data) are limited by various restraints and needs huge amount of time and cost to obtain, whereas unlabeled data (seismic data) are in abundance and relatively easy to obtain. Geoscientists are tasked with interpreting large amounts of unlabeled data using very little labeled data. In this paper, we adopt a semi-supervised machine learning approach utilizing pseudo-labeling technique to predict seismic facies and to account for the scarcity of training data by taking advantage of unlabeled data. In each iteration, a small amount of unlabeled data is labeled in spatial manner and the most confident labels (labels that are within 95% confidence interval) are added back to the training data set, starting from labeling the unlabeled data adjacent to the well and spatially moving away in small steps (few traces in each step). The labels obtained from the unlabeled data near the well (pseudo-labels) are added to the labeled data to retrain the deep learning model (classifier) in each iteration. This addition of spatial pseudo-labels adds invariance and diversity to the classifier which in turn helps classifier capitalize on known input variance, which might act as a helpful prior knowledge for next prediction. In other words, the proposed workflow accounts for spatial change in lithology that occurs while moving away from the well. Using our proposed workflow, we observed that, the classification accuracy of a machine learning model trained on a small amount of training data can be enhanced considerably. Pseudo-labels also helped improve lateral continuity of facies. Furthermore, the proposed method outperformed conventional methods, achieving a test accuracy of 96.7% and logarithmic loss as low as 0.15 compared to 91% and 0.6, respectively for supervised baseline. Whereas, for training and validation; the training accuracy, validation accuracy and loss were 98.9%, 99.09% and 0.029 respectively.",3,3,4
Seismic Data,Approach,"Silva Neto, Gilson M.; Rios, Victor de Souza; Davolio, Alessandra; Schiozer, Denis J.",Improving fluid modeling representation for seismic data assimilation in compositional reservoir simulation,Speed of sound; Cubic equation of state; Hydrocarbon fluid; Petroelastic model,SOUND-VELOCITY,"There is a growing interest in applying quantitative methods to adjust reservoir flow models using time-lapse seismic data. The most common approach relies on a petroelastic model to convert the flow simulator outputs into acoustic impedance. The comparison of this simulated data with the observed time-lapse seismic anomalies enables the computation of changes in the reservoir models' parameters, reducing the uncertainty, and improving the reservoir characterization. Among other properties, the petroelastic model requires fluid models capable of forecasting the speed of sound. This fact becomes more challenging when the oil is volatile and contains a significant amount of CO2, which is the case in some reservoirs in the Brazilian pre-salt region. In this situation, some classical models fail to predict the speed of sound in the oil phase within reasonable accuracy. Other models require testing for specific fluids or are not conveniently build to the integration with actual compositional reservoir simulators. Therefore, we propose the application of a calibrated cubic equation of state to represent the fluid behavior for both reservoir flow and petroelastic simulations. For this purpose, we describe a methodology in which the fluid model is progressively adjusted using reservoir engineering and speed of sound experimental data, depending on the available information. We applied this methodology using the well-known Peng-Robinson equation, but similar results could be obtained with other models of this class. We show that the match to the conventional pressure-volume-temperature data, a common practice in reservoir engineering, can be enough to generate fluid models capable of forecasting the speed of sound. Furthermore, the speed of sound experimental data can improve the fluid characterization without jeopardizing the previous fitted experiments. We tested our methodology with experimental data of a fluid of one reservoir in the Brazilian pre-salt region. Moreover, we compared the results obtained in the equation of state with other published correlations and simplified models. Synthetic reservoir models with different production strategies were applied in these comparisons.",2,2,0
Seismic Data,Approach,"Pan, Xinpeng; Li, Lin; Zhang, Guangzhi",Multiscale frequency-domain seismic inversion for fracture weakness,Multiscale frequency-domain inversion; AVOAz inversion; Bayesian inversion; Fracture weaknesses; Fourier operator,WAVE-FORM INVERSION; AVO INVERSION; MODEL; COEFFICIENTS; ANISOTROPY; AMPLITUDE; AZIMUTH; PHASE; ANGLE,"Amplitude variation with offset and azimuth (AVOAz) inversion is an effective tool to invert the azimuthal seismic reflection data for fracture weaknesses, which play an important role in seismic characterization of fractures. Conventional AVOAz inversion is implemented in the time domain, which simultaneously uses full-frequency components of the seismic data causing an unstable and inaccurate inversion result in the case of noisy seismic data. Here we propose a novel multiscale frequency-domain seismic inversion approach to improve resolution and accuracy of fracture weakness estimates. Based on new derived frequency-domain expression of azimuthal seismic amplitude difference for a horizontal transversely isotropic (HTI) medium, we build the kernel function incorporated with the Fourier operator, which avoids the Fourier inverse transform in the frequency-domain inversion. Low frequency information in seismic data is often missing or contaminated with noises, thus we establish an inversion objective function combining low frequency regularization term and Cauchy sparse regularization term in the Bayesian framework. We adopt the multiscale strategy and perform inversion successively from low to high frequency group utilizing a limited number of frequency components with a high signal-to-noise (S/N) ratio. In addition, we compare the multiscale frequency-domain inversion approach, the frequency-domain simultaneous inversion approach, and the time-domain inversion approach using synthetic data and field data. Synthetic example demonstrates that the cross-correlation coefficients (CCs) between the true fracture weaknesses and the inversion results obtained by multiscale frequency-domain inversion approach are above 0.83 even with a S/N of 2. Compared to the time-domain inversion approach and the frequencydomain simultaneous inversion approach, the inversion results with multiscale frequency-domain inversion approach have higher resolution and accuracy. Field data example further validates the feasibility and superiority of the proposed multiscale frequency-domain inversion approach.",2,2,0
Seismic Data,Approach,"Azamifard, Arash; Ahmadi, Mohammad; Rashidi, Fariborz; Pourfard, Mohammadreza; Dabir, Bahram",QuiltEdge: Novel geostatistical workflow for heterogeneous reservoirs with an innovative combination of multi-variable image quilting and edge property concept to model heterogeneity and flow barriers,Edge property; Permeability texture; Geostatistic; Image quilting; Reservoir heterogeneity; Multiple point statistics,MULTIPLE-POINT GEOSTATISTICS; SEISMIC DATA; SIMULATION; CONDUCTIVITY; ENVIRONMENT; MEDIA; BASIN,"Detailed and accurate techniques which plays a vital role in providing more reliable predictions of reservoir performance are needed for spatial modeling of reservoirs with complex heterogeneity. Additional auxiliary parameters are usually defined to emulate the reservoir complex geometry and high degree of heterogeneity. Edge property concept can be used to model the effect of large-scale flow barriers or highly conductive channels such as sealing or conductive fault planes. In this study, the edge properties are overlaid on a grid of extremely heterogeneous permeability to examine the predictability of the reservoir model. Image quilting is applied to simultaneously build the cell-wise and edge properties of the reservoir model. Image quilting in this study utilizes a multivariable approach for simultaneous cell-wise and edge property modeling. Our proposed approach has been successfully examined on modified SPE 10 benchmark model, where the permeability spatial variation was modified and edge properties were added to represent the large-scale sealing or conductive faults. Several realizations were generated using image quilting technique based on training images. The geological patterns of permeability variation and the large scale barriers or conduits are conveyed properly from training images into reservoir model, even in this extremely heterogeneous studied reservoir. The difference of gas breakthrough time between inferred value of model realizations and the reference model is almost 12 days for minor modifications of famous SPE10 benchmark. Moreover, maximum oil production rate is predicted with more reliability as a consequence of proposed approach. The slope of oil production rate is identical to the reference case for the times after breakthrough. In addition, breakthrough time is estimated efficiently. With this approach (derived from permeability texture concept), the modelled properties become more and more realistic (geologically-consistent realizations) and the reservoir simulation outputs are become more reliable. This approach constrains the variability of geological properties and consequently the uncertainty with reservoir forecast is substantially reduced.",1,1,1
Seismic Data,Deposition,"Sun, Panke; Fang, Huijing; Xu, Zhaohui; Wang, Chao; Xu, Huaimin; Lu, Man","Siliciclastic depositional model within a subsurface coastal parasequence based on barriers and baffles - An application to the Donghe Sandstone Member in the Hudson Oilfield, Tarim Basin, NW China",Barrier; Baffle; Dipmeter data; Sea-level; Donghe sandstone; Depositional model,SEQUENCE STRATIGRAPHY; FACIES; HIERARCHY; OUTCROP; ORIGIN,"Detailed analyses of a siliciclastic coastal reservoir highlights the need for an enhanced knowledge of their depositional model. At the scale of the bed sets, however, it is difficult to determine the depositional model, largely due to a limit in vertical resolution of seismic data and conventional wireline logs. Barriers and baffles, following either surfaces of bed sets or beds, act as isochronous boundaries, therefore, holding a key to reveal the sedimentary evolution of subsurface reservoirs at small scales. Calcareous and argillaceous barriers and baffles of the Donghe Sandstone Member in the Hudson Oilfield have obvious low conductivity responses in dipmeter data, therefore, they are interpreted and correlated by integration of conventional logs and dipmeter data. Barriers separate the Donghe Sandstone Member into three retrogradational bed sets (i.e., B1 similar to B3) and two progradational bed sets (i.e., B4 similar to B5), of which beds are constrained by baffles with larger dip angles than barriers in the current structure pattern as well as the period of deposition. The stacking patterns indicate relative sea-level rise within B1 similar to B3 and fall within B4 similar to B5. The relative sea-level changes control the baffle frequency, thickness and length of barriers and baffles. Vertically, the variation of frequency and maximum thickness of both argillaceous and calcareous baffles increase during the transgression yet reduce during regression. Horizontally, the length of barriers and baffles positively correlates with their maximum thickness along the paleoshoreline, as it does the direction perpendicular to the paleoshoreline. Therefore, a depositional model of early retrogradation followed by progradation is built for the Donghe Sandstone Member, a siliciclastic coastal parasequence with upper-shoreface and lower-shoreface facies, based on barriers and baffles. This depositional model is embodied with certain principles of reservoir architecture and behavior.",3,3,1
Seismic Data,Deposition,"Fu, Sheng; Liu, Zhen; Ge, Jiawang; Tian, Ning; Wang, Xin; Wang, Huilai; Liu, Hui; Yin, Kewei; Han, Qi","Tectono-stratigraphy characteristics of the Lower Cretaceous Saihantala Sag in the Erlian Basin, China: Normal faulting and controls on the depositional variability",Fault system; Tectonic evolution; Depositional systems; Basin filling pattern; Saihantala sag,LACUSTRINE RIFT BASINS; SEQUENCE STRATIGRAPHY; NE CHINA; TECTONOSTRATIGRAPHIC EVOLUTION; SEDIMENTOLOGY; SEDIMENTATION; DEPRESSION; CLIMATE; SYSTEMS; RECORD,"Tectonism is one of the most important factors controlling the formation of sedimentary stratigraphy in lacustrine rift basins, but the controlling effects need to be further clarified. Based on 2D and 3D seismic data, well logs, logging data, and core data from the Saihantala Sag, our study aimed to analyse the fault system of the sag, determine its tectonic evolution process, establish the faulting pattern of the sag, recognise its depositional systems, and finally discuss the relationships between the tectonic factors and the basin evolution and sediment filling process. Four types of depositional systems including fan-delta, braided-delta, near-shore subaqueous fan and lacustrine deposits were recognized in the Saihantala Sag based on an integrated analysis of the well logs, cores and seismic data. The results indicated that 1) The Xilin fault is the eastern boundary fault of the Saihantala Sag, and its subsections and connections controlled the stratigraphic pattern of the sag. 2) tectonic evolution controlled the evolution of the lake basin and depositional systems in the Saihantala Sag, especially the deposition of near-shore subaqueous fan and the connection and retrogradation of braided-delta and fan-delta systems. 3) The tectonic evolution also controlled the filling pattern of the Saihantala Sag, which features two sets of braided-delta deposits in its gentle slope belt and one set of fan-delta deposits and two sets of near-shore sub-lacustrine fan deposits in its steep slope belt. 4) All three tectonic belts (Zhabu, Yihe and Saisi) mainly experienced a middle-late activated single-cycle faulting pattern, which controlled the distribution of braided-delta front deposits and lenticular sandy bodies.",2,2,2
Seismic Data,Deposition,"Abd-Allah, Ali M. A.; Abd El-Naby, Ahmed; Aal, Mohamed H. Abdel","Tectonic and basin evolution of South Eastern Mediterranean for hydrocarbon potentiality in North Sinai, Egypt",Inversion tectonics; Sinai; Eastern mediterranean basin; African continental margin; Basin evolution,MESSINIAN SALINITY CRISIS; CONTINENTAL-MARGIN; LEVANT BASIN; ERATOSTHENES SEAMOUNT; NORTHEASTERN AFRICA; CRUSTAL STRUCTURE; REGION; INVERSION; ORIGIN; HISTORY,"South Eastern Mediterranean margin has expressed two Jurassic-Recent tectonic cycles that related to the opening and closure of the Neotethys Ocean. Structural and sedimentological complications related to these cycles and the basin evolution are selected to be the main targets of the present study in North Sinai. 2D seismic, boreholes, and outcrop data are used to achieve these targets. The development of the margin began by the formation of the NE and E-W oriented normal faults during the Jurassic-Early Cretaceous rifting. Two Albian uplifting phases occurred by the end of this rifting and followed by the Cenomanian-Oligocene positive inversion that was interrupted by a tectonic loading subsidence phase allowed the deposition of the pelagic Campanian-Maastrichtian chalk on the shallow Upper Cretaceous carbonate. Shortening related to this inversion inverted completely the normal-slip on some rift-related faults into reverse faults and related folds or partially inverted by decreasing of the normal slip on the others. Inversion was ended by the post-Oligocene extensional-subsidence event that is related to north-sinking of the northern part of the African margin under the European plate. The three-tectonic regimes in association with the sediments supplies, sea level changes, total basin subsidence, basin extension, uplifting, and erosion resulted in complex sedimentary packages that are interrupted by many un-conformities and exhibited dramatic lateral facies and thickness changes. Considerable depositional environments were transited northward, from the reefal and subtidal to shelf and then to the deep marine, where the facies formation was controlled by mix effects of the sediment supplies, north-tilting continental margin, tectonic activities, sediment load and subsidence. Offshore part of Sinai preserves good conditions favorable for hydrocarbon accumulation and requires more intensive exploration.",2,2,0
Seismic Data,Training Images,Yin Yanshu; Hu Xun; Huang Jixin; Feng Wenjie; Wang Linxin; Duan Taizhong; Zhao Lei; Zhang Wenbiao,"A three-dimensional model of deep-water turbidity channel in Plutonio oilfield, Angola: From training image generation, optimization to multi-point geostatistical modelling",Multi-point geostatistics; Training image; Alluvsim; Optimization method; The Plutonio oilfield in Angola,SIMULATION; RESERVOIRS; DISTANCE,"The deep-water turbidity channel system in the Oligocene O73 sand layer in the Plutonio oilfield in Angola of west Africa has good oil and gas reservoir capability. As the well spacing is large due to operation cost, and the seismic resolution of the target layer is relatively low, identification of turbidity channel boundary was difficult. To establishes a fine model is a problem faced by the modelers. In this paper, a complete multi-point geostatistical modeling flowchart is presented for the construction of fine deep-water turbidity channel model. According to the investigation of seismic, well logging, drilling data and references in the study area, the genesis, reservoir scale, lithofacies type, morphological characteristics and evolution of the deep-water turbidity channel of the target layer were obtained. The improved Alluvsim algorithm was utilized to generate a set of adaptive deep-water turbidity channel training images with specified curvatures. Net-to-gross, variogram and a high-order statistics method based on the single data event were compared to evaluate and sort the training images. Then, the Snesim method was utilized to construct the models using the sorted compatible training images with a same set of parameters. At last, the quality of different models was compared based on the seismic attribute slices and a composite correlation coefficient optimization method based on seismic data. The results suggest that the improved Alluvsim algorithm can reproduce the channel morphology and stacking patterns better. Compared with the first-order and second-order statistics comparison method, the method using higher-order statistics of single data event taken spatial patterns into consideration and sorted training images better. The reservoir model was established using the optimal selected training image which has a high correlation with seismic attributes, and the model is more consistent with the characteristics of subsurface reservoirs. At the same time, this paper also provides a complete research program for the application of multi-point geostatistical modeling method which is from training image generation, optimal training image selection and multi-point geostatistics modeling to realizations selection for practical subsurface reservoir modelling.",3,3,2
Seismic Data,Training Images,"Azamifard, Arash; Ahmadi, Mohammad; Rashidi, Fariborz; Pourfard, Mohammadreza; Dabir, Bahram",QuiltEdge: Novel geostatistical workflow for heterogeneous reservoirs with an innovative combination of multi-variable image quilting and edge property concept to model heterogeneity and flow barriers,Edge property; Permeability texture; Geostatistic; Image quilting; Reservoir heterogeneity; Multiple point statistics,MULTIPLE-POINT GEOSTATISTICS; SEISMIC DATA; SIMULATION; CONDUCTIVITY; ENVIRONMENT; MEDIA; BASIN,"Detailed and accurate techniques which plays a vital role in providing more reliable predictions of reservoir performance are needed for spatial modeling of reservoirs with complex heterogeneity. Additional auxiliary parameters are usually defined to emulate the reservoir complex geometry and high degree of heterogeneity. Edge property concept can be used to model the effect of large-scale flow barriers or highly conductive channels such as sealing or conductive fault planes. In this study, the edge properties are overlaid on a grid of extremely heterogeneous permeability to examine the predictability of the reservoir model. Image quilting is applied to simultaneously build the cell-wise and edge properties of the reservoir model. Image quilting in this study utilizes a multivariable approach for simultaneous cell-wise and edge property modeling. Our proposed approach has been successfully examined on modified SPE 10 benchmark model, where the permeability spatial variation was modified and edge properties were added to represent the large-scale sealing or conductive faults. Several realizations were generated using image quilting technique based on training images. The geological patterns of permeability variation and the large scale barriers or conduits are conveyed properly from training images into reservoir model, even in this extremely heterogeneous studied reservoir. The difference of gas breakthrough time between inferred value of model realizations and the reference model is almost 12 days for minor modifications of famous SPE10 benchmark. Moreover, maximum oil production rate is predicted with more reliability as a consequence of proposed approach. The slope of oil production rate is identical to the reference case for the times after breakthrough. In addition, breakthrough time is estimated efficiently. With this approach (derived from permeability texture concept), the modelled properties become more and more realistic (geologically-consistent realizations) and the reservoir simulation outputs are become more reliable. This approach constrains the variability of geological properties and consequently the uncertainty with reservoir forecast is substantially reduced.",1,1,1
Seismic Data,Training Images,"Noori, Maryam; Hassani, Hossein; Javaherian, Abdolrahim; Amindavar, Hamidreza","3D seismic fault detection using the Gaussian process regression, a study on synthetic and real 3D seismic data",Unsupervised Gaussian process; Global anomaly; Fault detection; Morphological reconstruction; Structural similarity index,COHERENCE,"Faults are natural tectonic events as planar features along which rock units are moved. The patterns of these planes on seismic sections include linear or curvilinear features that are called edge in image processing, where amplitudes sharply change. In seismic data, these edge features made by fault traces are usually detected by seismic attributes, which need complex mathematical calculation such as a dip-steered cube. In this study, we introduce faults as global anomalies which disturb the normal interaction of seismic reflectors. Here, the normal interaction means the absence of intensive changes in reflectors trend in seismic sections. Fault detection as a global anomaly is done by the Gaussian process regression model (GPR), which is a nonparametric probabilistic model based on Bayesian statistics supporting noisy (Gaussian noise) and sparse features in data. In data mining, anomaly detection identifies items or events that do not match an expected pattern in a dataset. Global anomalies are sparse and affect a wide range of normal trends of data which are also held by fault features in seismic data. In this study, the GPR-based anomaly detection algorithm was implemented on the 3D seismic data of the Gulf of Mexico containing normal growth faults and a salt dome to detect salt boundary and fault traces in seismic data. In this respect, the reflections from rock units and fault features were taken into account as normal interactions and global anomalies, respectively, because faults disrupted the normal trend of reflectors in seismic sections. To detect fault locations, the location of a voxel in voxel grid where it is a part of fault in seismic data, after smoothing the seismic data, a Gaussian process (GP) model was trained on seismic data, attempting to describe the seismic amplitude data as a multivariate Gaussian model. However, GP regression fails to describe the seismic data at fault locations. Thus, the failure of the GP in the regression step was analyzed to separate the probable fault points, highlighted by calculating the variance of the GPR results. Finally, the detected probable fault points were improved and separated from background results by implementing a consistent reconstruction morphological algorithm. The results were validated using a similar structural index method, mean square error, and power signal to noise ratio indices in comparison with interpreted faults, implying the superiority of the proposed method in comparison with seismic attributes. The faults detected by the proposed method have the most structural similarity to faults interpreted. This similarity has improved by 22% compared to used attributes.",1,1,1
Sichuan Basin,Oil and Gas,"Wu, Nan; Wang, Jian; Cai, Zhongxian; Luo, Zhong; Lu, Xuesong; Ma, Xingzhi; Liu, Xianfeng","Discovery of Sinian source rocks in proterozoic in the Tarim Basin, NW China",Tarim basin; Kuruktag; Sinian source rocks; Hydrocarbon generation; Bitumen,ORGANIC-MATTER; CRUDE OILS; MATURITY PARAMETERS; THERMAL MATURITY; SICHUAN BASIN; GEOCHEMICAL CHARACTERISTICS; TRICYCLIC TERPANES; VELKERRI FORMATION; MCARTHUR BASIN; GRAND-CANYON,"As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50-60 degrees C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin.",2,2,3
Sichuan Basin,Oil and Gas,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Sichuan Basin,Oil and Gas,"Fan, Xiaojie; Mao, Xiaoping; Liu, Zhongrong; Geng, Tao; Wang, Haochen","Organic geochemical characteristics and hydrocarbon generation potential of Jurassic shales and mudstones in Qixiang Co area southern Qiangtang Basin, Tibet",Shale; Organic geochemical characteristics; Sedimentary environment; Resource potential; Qiangtang basin,LUCAOGOU FORMATION; LONGTAN FORMATION; SICHUAN BASIN; BLACK SHALES; OIL-FIELDS; MARINE; MATTER; ACCUMULATION; INDICATORS; SEDIMENTS,"The Qixiang Co area is located in the South Qiangtang Depression Zone. Jurassic shales and mudstones with large thicknesses are widely developed in this area. The Jurassic was a potential exploration horizon in the Qiangtang Basin; however, few detailed analyses have been conducted on the geochemical characteristics of mudstones and shales in this area. In this paper, the hydrocarbon generation potential and sedimentary environment of shales and mudstones are analyzed using organic geochemical data. The results show that the abundance of organic matter is low, as indicated by the low TOC value (averaging 0.70%) and hydrocarbon potential (S-1+S-2) (0.13 mg/g). The main macerals of kemgen are exinites with an average value of 82%, and they are mainly type II2 kerogen. A summary of the results is presented: the thermal maturity of organic matter is high; the average Ro value is more than 1.2%; n-alkanes are dominated by a high carbon number and have no obvious odd-even advantage; the average value of Pr/Ph is 0.74; the distribution of C-23 triterpenoids satisfies C-20 < C-21 < C-23; the content of the gammacerane index is moderate (0.21) the variation range is small; and the C-27 content in regular steranes is dominant. It can be concluded that the organic matter precursors in this area were a mix of higher plants and marine phytoplankton. Organic matter was deposited under a reductive environment with stable water and slightly high salinity. The hydrocarbon generation potential of the Jurassic shale and mudstone in this area is poor, which is unfavorable to oil and gas exploration.",2,2,2
Sichuan Basin,Oil and Gas,"Tang, Wei; Li, Meng",Scalable double regularization for 3D Nano-CT reconstruction,Shale; Nano-CT; Image reconstruction; Regularization; Scalable algorithm,CONVOLUTIONAL NEURAL-NETWORK; X-RAY CT; IMAGE-RECONSTRUCTION; ALGORITHMS; QUALITY; SHALE; ART,"Nano-CT (computerized tomography) has emerged as a non-destructive high-resolution cross-sectional imaging technique to effectively study the sub-mu m pore structure of shale, which is of fundamental importance to the evaluation and development of shale oil and gas. Nano-CT poses unique challenges to the inverse problem of reconstructing the 3D structure due to the lower signal-to-noise ratio (than Micro-CT) at the nano-scale, increased sensitivity to the misaligned geometry caused by the movement of object manipulator, limited sample size, and a larger volume of data at higher resolution. We propose a scalable double regularization (SDR) method to utilize the entire dataset for simultaneous 3D structural reconstruction across slices through total variation regularization within slices and L-1 regularization between adjacent slices. SDR allows information borrowing both within and between slices, contrasting with the traditional methods that usually build on slice by slice reconstruction. We develop a scalable and memory-efficient algorithm by exploiting the systematic sparsity and consistent geometry induced by such Nano-CT data. We illustrate the proposed method using synthetic data and two Nano-CT imaging datasets of Jiulaodong (JLD) shale and Longmaxi (LMX) shale acquired in the Sichuan Basin. These numerical experiments show that the proposed method substantially outperforms selected alternatives both visually and quantitatively.",1,1,8
Sichuan Basin,Casing,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Sichuan Basin,Casing,"Shi, Wenyang; Yao, Yuedong; Cheng, Shiqing; Shi, Zhiliang; Wang, Yang; Zhang, Jia; Zhang, Chengwei; Gao, Min","Pressure transient behavior and flow regimes characteristics of vertical commingled well with vertical combined boundary: A field case in XC gas field of northwest Sichuan Basin, China",Layered reservoir; Vertical commingled well; Vertical heterogeneity; Combined boundary; Pressure transient behavior; Flow regimes characteristics,CHANGQING OIL-FIELD; RESERVOIR; UNCERTAINTY; WATERFLOOD,"The multilayered deposition is the main feature of the XC gas reservoir in the northwestern Sichuan Basin. The boundaries among layers of the XC gas reservoir is different. In this paper, we propose an extended pressure transient analysis model for vertical commingle well, considering different boundary radii and boundary types, to capture the Vertical Combined Boundary (VCB) effect on the pressure transient behavior and flow regime characteristics. The analytical solution is yielded by the Laplace transform, Bessel functions, Duhamel's superposition principle, and Stehfest inversion algorithm, and new flow regimes under different boundary combinations are identified by the pressure derivative curve. Taking the dual-layer VCB model as a type example, nine combinations of boundaries are analyzed. Compared with the current vertical commingled well model with the same boundary radii or single boundary types, this model has novel flow regimes controlled by the VCB. The research results indicate that the pressure derivative type curve during the novel flow regimes stage can diagnosis the VCB type. On the one hand, there are quantitative linear relationships between the pressure derivative feature value and interlayer heterogeneity of the VCB model with the same boundary radii. These linear relationships provide a new perspective to quickly capture interlay heterogeneity through the of the pressure derivative feature value. One the other hand, the pressure behavior and flow regimes of the VCB model with different boundary radii obey the successive superposition rule. This rule provides a method to recognize the VCB type with different boundary radii based on that of the VCB with the same boundary radii. Finally, a field case from the northwestern Sichuan Basin gas reservoir is discussed in detail to exhibit the workflow of our model application and validate the capability of our model.",2,2,1
Sichuan Basin,Casing,"Long, Shengxiang; You, Yuchun; Jiang, Shu; Liu, Guoping; Feng, Qiong; Gao, Yang; Niu, Xiaofang","Integrated characterization of ultradeep reef-shoal reservoir architecture: A case study of the Upper Permian Changxing Formation in the giant Yuanba gas field, Sichuan Basin, China",Reef; Shoal; Reservoir architecture; Integrated characterization; Pseudo-acoustic inversion,SPECTRAL DECOMPOSITION; CARBONATE RESERVOIR; ACOUSTIC PROPERTIES; PARIS BASIN; SEDIMENTOLOGY; DISCOVERY; POROSITY; RAMP,"The Yuanba giant gas field in the Sichuan Basin produces from Upper Permian Changxing heterogeneous reef-shoal reservoirs. It is an ultradeep tight gas reservoir with burial depth of 7000 m. This paper proposes an integrated methodology incorporating the reservoir geology description, petrophysics characterization, seismic response analysis, forward seismic modeling, pseudo-acoustic inversion, and reservoir architecture imaging to identify the geologically complex reef-shoal reservoirs and predict the distribution of the producible reservoirs. The facies of reef cap, reef core, reef base and shoal are first identified based on observations and interpretations of cores, thin sections, mud logging, wireline logs, and formation microscanner images (FMIs). High-energy shoals, reef cores, and reef caps are the most favorable reservoir microfacies. Seismic responses of reef-shoal reservoirs are then investigated through forward modeling and well-seismic calibration. Four reef belts are identified based on seismic reflections and edge detection by seismic paleogeomorphologic features. Reservoir distribution and quantitative properties are predicted using the facies-controlled postattack seismic inversion technique through the correlation between reservoir properties and seismic attributes, which is aided by pseudogamma acoustic inversion to exclude the shale-bearing non-reservoir and pseudo-neutron acoustic inversion based on its good relationship with porosity. The reef reservoir thicknesses range from 10 m to 130 m, and the thickest reservoir is located in the northwestern Yuanba gas field. Finally, 3-D visualization is used to characterize the spatial variation of the interior architecture, connectivity, and distribution of a good reservoir in the reef system. The accuracy rate of prediction for reservoirs and non-reservoirs reaches 88% using this method. The technique has also been successfully used for the deployment of development wells and well trajectory optimization, and the rate of encountering the predicted reservoirs is 100%. This study provides a practical approach to identify and predict the tight carbonate gas reservoir with similar petrophysical responses of density and acoustic to non-reservoirs in the complex carbonate system.",1,1,4
Sichuan Basin,Dolomite,"Huo, Fei; Wang, Xingzhi; Wen, Huaguo; Xu, Wenli; Huang, Huiwen; Jiang, Huachuan; Li, Yawen; Li, Bo","Genetic mechanism and pore evolution in high quality dolomite reservoirs of the Changxing-Feixianguan Formation in the northeastern Sichuan Basin, China",Carbon oxygen isotope; Major and trace elements; Source of diagenetic fluid; Mechanism of dolomitization; Diagenesis-pore evolution,NE SICHUAN; HYDROTHERMAL DOLOMITE; ISOTOPE COMPOSITION; EASTERN SICHUAN; BURIAL DOLOMITIZATION; CARBONATE SUCCESSIONS; GAS-RESERVOIRS; JIANNAN AREA; DIAGENESIS; PLATFORM,"The marine carbonate rock in the Changxing-Feixianguan Formation of Xuanhan-Daxian area, northeastern Sichuan, the Sichuan Basin holds abundant natural gas resource, where the dolomite includes two types, the one with original texture (grain dolomite, reef dolomite) and the one without original texture (idiomorphic to anhedral-crystal dolomite, porphyritic dolomite). The analysis on the isotopes of C, O, Sr and other geochemical features shows that the dolomitizing process happened in fluid rich in Mg2+ and lean in Ca2+ and brought in Fe2+, Mn2+ and took out Sr2+; with the rise of recrystallization, the Fe2+ , Mn2+ contents tend to increase while delta O-18(PDB) and Srcontent tend to decrease. According to the variation of Sr-87/Sr-86 and other geochemical features, it is considered that the dolomitizing fluid participating in the reservoir diagenesisis the high salinity sea water later than the end of Feixianguan stage, and the dolomitization takes place mainly through the multiple thermal convective cycle effect. The micritic dolomite is of evaporative dolomitization origin with the characteristics of high Sr2+, Na+ and low Mn2+ which reflects the open environment of the surface exposed in the quasi syngenetic period, while the reef dolomite is of high Mg/Ca dolomitizing fluid origin with the characteristics of low Sr-2 , Na+ and Mn2+, whose diagenetic environment changed from near surface to shallow burial environment; crystalline dolomite is formed by metasomatism of low Mg/Ca dolomitizing fluid at deep burial depth and high temperature, with the increase of burial depth,in the high temperature and high pressure deep sealing system, its Fe2+ and Mn2+ elements increased while Sr2+ decreased. Through reconstruction of dynamic diagenesis-pore evolution, it is concluded that the low porosity of shallow beach grain dolomite is resulted from early compaction and medium-term cementation, yet the reservoir quality has been apparently improved by the later hydrocarbon dissolution; compared with shallow beach grain dolomite,the reef dolomite has smaller initial porosity, but stronger compressive capacity. The early compaction and medium-term cementation have less impact on the reef dolomite, and the later dissolution strength is slightly weaker than that of the granular dolomite, thus the change range of porosity is smaller than that of the grain dolomite; the micrite-silt dolomite mainly suffered porosity reduction caused by compaction, and the later burial dissolution and recrystallization are key to the quality improvement of this kind of dolomite reservoir.",2,3,9
Sichuan Basin,Dolomite,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Sichuan Basin,Zone,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Sichuan Basin,Zone,"Fan, Xiaojie; Mao, Xiaoping; Liu, Zhongrong; Geng, Tao; Wang, Haochen","Organic geochemical characteristics and hydrocarbon generation potential of Jurassic shales and mudstones in Qixiang Co area southern Qiangtang Basin, Tibet",Shale; Organic geochemical characteristics; Sedimentary environment; Resource potential; Qiangtang basin,LUCAOGOU FORMATION; LONGTAN FORMATION; SICHUAN BASIN; BLACK SHALES; OIL-FIELDS; MARINE; MATTER; ACCUMULATION; INDICATORS; SEDIMENTS,"The Qixiang Co area is located in the South Qiangtang Depression Zone. Jurassic shales and mudstones with large thicknesses are widely developed in this area. The Jurassic was a potential exploration horizon in the Qiangtang Basin; however, few detailed analyses have been conducted on the geochemical characteristics of mudstones and shales in this area. In this paper, the hydrocarbon generation potential and sedimentary environment of shales and mudstones are analyzed using organic geochemical data. The results show that the abundance of organic matter is low, as indicated by the low TOC value (averaging 0.70%) and hydrocarbon potential (S-1+S-2) (0.13 mg/g). The main macerals of kemgen are exinites with an average value of 82%, and they are mainly type II2 kerogen. A summary of the results is presented: the thermal maturity of organic matter is high; the average Ro value is more than 1.2%; n-alkanes are dominated by a high carbon number and have no obvious odd-even advantage; the average value of Pr/Ph is 0.74; the distribution of C-23 triterpenoids satisfies C-20 < C-21 < C-23; the content of the gammacerane index is moderate (0.21) the variation range is small; and the C-27 content in regular steranes is dominant. It can be concluded that the organic matter precursors in this area were a mix of higher plants and marine phytoplankton. Organic matter was deposited under a reductive environment with stable water and slightly high salinity. The hydrocarbon generation potential of the Jurassic shale and mudstone in this area is poor, which is unfavorable to oil and gas exploration.",2,2,2
Sichuan Basin,Hydraulic Fracture,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Sichuan Basin,Hydraulic Fracture,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Sichuan Basin,Organic Matter,"Wu, Nan; Wang, Jian; Cai, Zhongxian; Luo, Zhong; Lu, Xuesong; Ma, Xingzhi; Liu, Xianfeng","Discovery of Sinian source rocks in proterozoic in the Tarim Basin, NW China",Tarim basin; Kuruktag; Sinian source rocks; Hydrocarbon generation; Bitumen,ORGANIC-MATTER; CRUDE OILS; MATURITY PARAMETERS; THERMAL MATURITY; SICHUAN BASIN; GEOCHEMICAL CHARACTERISTICS; TRICYCLIC TERPANES; VELKERRI FORMATION; MCARTHUR BASIN; GRAND-CANYON,"As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50-60 degrees C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin.",2,2,3
Sichuan Basin,Organic Matter,"Fan, Xiaojie; Mao, Xiaoping; Liu, Zhongrong; Geng, Tao; Wang, Haochen","Organic geochemical characteristics and hydrocarbon generation potential of Jurassic shales and mudstones in Qixiang Co area southern Qiangtang Basin, Tibet",Shale; Organic geochemical characteristics; Sedimentary environment; Resource potential; Qiangtang basin,LUCAOGOU FORMATION; LONGTAN FORMATION; SICHUAN BASIN; BLACK SHALES; OIL-FIELDS; MARINE; MATTER; ACCUMULATION; INDICATORS; SEDIMENTS,"The Qixiang Co area is located in the South Qiangtang Depression Zone. Jurassic shales and mudstones with large thicknesses are widely developed in this area. The Jurassic was a potential exploration horizon in the Qiangtang Basin; however, few detailed analyses have been conducted on the geochemical characteristics of mudstones and shales in this area. In this paper, the hydrocarbon generation potential and sedimentary environment of shales and mudstones are analyzed using organic geochemical data. The results show that the abundance of organic matter is low, as indicated by the low TOC value (averaging 0.70%) and hydrocarbon potential (S-1+S-2) (0.13 mg/g). The main macerals of kemgen are exinites with an average value of 82%, and they are mainly type II2 kerogen. A summary of the results is presented: the thermal maturity of organic matter is high; the average Ro value is more than 1.2%; n-alkanes are dominated by a high carbon number and have no obvious odd-even advantage; the average value of Pr/Ph is 0.74; the distribution of C-23 triterpenoids satisfies C-20 < C-21 < C-23; the content of the gammacerane index is moderate (0.21) the variation range is small; and the C-27 content in regular steranes is dominant. It can be concluded that the organic matter precursors in this area were a mix of higher plants and marine phytoplankton. Organic matter was deposited under a reductive environment with stable water and slightly high salinity. The hydrocarbon generation potential of the Jurassic shale and mudstone in this area is poor, which is unfavorable to oil and gas exploration.",2,2,2
Sichuan Basin,Deformation,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Sichuan Basin,Deformation,"Wang, Y.; Liu, D. Q.; Zhao, Z. H.; Wang, H. J.",Investigation on the effect of confining pressure on the geomechanical and ultrasonic properties of black shale using ultrasonic transmission and post-test CT visualization,Velocity anisotropy; Confining pressure; CT imaging; Crack pattern,LONGMAXI FORMATION SHALE; ELASTIC-WAVE VELOCITIES; X-RAY CT; MECHANICAL-PROPERTIES; ANISOTROPY; DEFORMATION; BEHAVIOR; ROCKS,"Knowledge of the influence of confining pressure on the geomechanical and ultrasonic characteristics is essential to exploration and development of gas shale reservoirs. In contrast to the extensive studies on the physical and mechanical properties of shale, the velocities of P-wave and S-wave during continuous deformation are not thoroughly understood. In this study, a suite of triaxial compression tests were done on the shale samples collected from the Sichuan Basin and were cored with horizontal bedding structure under various confining pressure. In-situ ultrasonic transmission technique combined with post-test CT imaging analysis was used to reveal the velocity-pressure characteristics and crack patterns. The experimental results indicate that strength, elastic parameter, P- and S-wave velocities, and failure pattern are influenced by the applied confining pressure. At the pre-peak stage on the stress-strain curve, the P-wave velocity increases with elevated stress; however, the S-wave velocity first increases and then decreases, which is related to the crack damage evolution. The mesostructural changes during deformation are considered to be the main factor controlling the pressure sensitivity of the velocities. Under compression, the relatively soft pores, micro-cracks and minerals were compacted gradually, and it is the primary reason leading to the increment of velocities. Based on the CT scanning technique, the crack pattern was obtained after triaxial testing, the crack pattern analysis suggests that the fractal dimension of fracture distribution almost increases with confining pressure. What is more, the stimulated fracture density increases with increasing confining pressure. It suggests that, for the Longmaxi black shale, a high confining pressure condition is beneficial to form a complex fracture network.",2,2,4
Sichuan Basin,Characterization,"Wang, Ziyi; Chen, Lei; Chen, Dongxia; Lai, Jin; Deng, Gaoshan; Liu, Ziyi; Wang, Chao",Characterization and evaluation of shale lithofacies within the lowermost Longmaxi-Wufeng Formation in the Southeast Sichuan Basin,,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; MARINE SHALE; GAS; AREA,,3,3,6
Sichuan Basin,Characterization,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Sichuan Basin,Characterization,"Long, Shengxiang; You, Yuchun; Jiang, Shu; Liu, Guoping; Feng, Qiong; Gao, Yang; Niu, Xiaofang","Integrated characterization of ultradeep reef-shoal reservoir architecture: A case study of the Upper Permian Changxing Formation in the giant Yuanba gas field, Sichuan Basin, China",Reef; Shoal; Reservoir architecture; Integrated characterization; Pseudo-acoustic inversion,SPECTRAL DECOMPOSITION; CARBONATE RESERVOIR; ACOUSTIC PROPERTIES; PARIS BASIN; SEDIMENTOLOGY; DISCOVERY; POROSITY; RAMP,"The Yuanba giant gas field in the Sichuan Basin produces from Upper Permian Changxing heterogeneous reef-shoal reservoirs. It is an ultradeep tight gas reservoir with burial depth of 7000 m. This paper proposes an integrated methodology incorporating the reservoir geology description, petrophysics characterization, seismic response analysis, forward seismic modeling, pseudo-acoustic inversion, and reservoir architecture imaging to identify the geologically complex reef-shoal reservoirs and predict the distribution of the producible reservoirs. The facies of reef cap, reef core, reef base and shoal are first identified based on observations and interpretations of cores, thin sections, mud logging, wireline logs, and formation microscanner images (FMIs). High-energy shoals, reef cores, and reef caps are the most favorable reservoir microfacies. Seismic responses of reef-shoal reservoirs are then investigated through forward modeling and well-seismic calibration. Four reef belts are identified based on seismic reflections and edge detection by seismic paleogeomorphologic features. Reservoir distribution and quantitative properties are predicted using the facies-controlled postattack seismic inversion technique through the correlation between reservoir properties and seismic attributes, which is aided by pseudogamma acoustic inversion to exclude the shale-bearing non-reservoir and pseudo-neutron acoustic inversion based on its good relationship with porosity. The reef reservoir thicknesses range from 10 m to 130 m, and the thickest reservoir is located in the northwestern Yuanba gas field. Finally, 3-D visualization is used to characterize the spatial variation of the interior architecture, connectivity, and distribution of a good reservoir in the reef system. The accuracy rate of prediction for reservoirs and non-reservoirs reaches 88% using this method. The technique has also been successfully used for the deployment of development wells and well trajectory optimization, and the rate of encountering the predicted reservoirs is 100%. This study provides a practical approach to identify and predict the tight carbonate gas reservoir with similar petrophysical responses of density and acoustic to non-reservoirs in the complex carbonate system.",1,1,4
Sichuan Basin,Evaluation,"Wang, Ziyi; Chen, Lei; Chen, Dongxia; Lai, Jin; Deng, Gaoshan; Liu, Ziyi; Wang, Chao",Characterization and evaluation of shale lithofacies within the lowermost Longmaxi-Wufeng Formation in the Southeast Sichuan Basin,,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; MARINE SHALE; GAS; AREA,,3,3,6
Sichuan Basin,Evaluation,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Sichuan Basin,Evaluation,"Tang, Wei; Li, Meng",Scalable double regularization for 3D Nano-CT reconstruction,Shale; Nano-CT; Image reconstruction; Regularization; Scalable algorithm,CONVOLUTIONAL NEURAL-NETWORK; X-RAY CT; IMAGE-RECONSTRUCTION; ALGORITHMS; QUALITY; SHALE; ART,"Nano-CT (computerized tomography) has emerged as a non-destructive high-resolution cross-sectional imaging technique to effectively study the sub-mu m pore structure of shale, which is of fundamental importance to the evaluation and development of shale oil and gas. Nano-CT poses unique challenges to the inverse problem of reconstructing the 3D structure due to the lower signal-to-noise ratio (than Micro-CT) at the nano-scale, increased sensitivity to the misaligned geometry caused by the movement of object manipulator, limited sample size, and a larger volume of data at higher resolution. We propose a scalable double regularization (SDR) method to utilize the entire dataset for simultaneous 3D structural reconstruction across slices through total variation regularization within slices and L-1 regularization between adjacent slices. SDR allows information borrowing both within and between slices, contrasting with the traditional methods that usually build on slice by slice reconstruction. We develop a scalable and memory-efficient algorithm by exploiting the systematic sparsity and consistent geometry induced by such Nano-CT data. We illustrate the proposed method using synthetic data and two Nano-CT imaging datasets of Jiulaodong (JLD) shale and Longmaxi (LMX) shale acquired in the Sichuan Basin. These numerical experiments show that the proposed method substantially outperforms selected alternatives both visually and quantitatively.",1,1,8
Sichuan Basin,Formation Shale,"Wang, Ziyi; Chen, Lei; Chen, Dongxia; Lai, Jin; Deng, Gaoshan; Liu, Ziyi; Wang, Chao",Characterization and evaluation of shale lithofacies within the lowermost Longmaxi-Wufeng Formation in the Southeast Sichuan Basin,,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; MARINE SHALE; GAS; AREA,,3,3,6
Sichuan Basin,Formation Shale,"Wang, Y.; Liu, D. Q.; Zhao, Z. H.; Wang, H. J.",Investigation on the effect of confining pressure on the geomechanical and ultrasonic properties of black shale using ultrasonic transmission and post-test CT visualization,Velocity anisotropy; Confining pressure; CT imaging; Crack pattern,LONGMAXI FORMATION SHALE; ELASTIC-WAVE VELOCITIES; X-RAY CT; MECHANICAL-PROPERTIES; ANISOTROPY; DEFORMATION; BEHAVIOR; ROCKS,"Knowledge of the influence of confining pressure on the geomechanical and ultrasonic characteristics is essential to exploration and development of gas shale reservoirs. In contrast to the extensive studies on the physical and mechanical properties of shale, the velocities of P-wave and S-wave during continuous deformation are not thoroughly understood. In this study, a suite of triaxial compression tests were done on the shale samples collected from the Sichuan Basin and were cored with horizontal bedding structure under various confining pressure. In-situ ultrasonic transmission technique combined with post-test CT imaging analysis was used to reveal the velocity-pressure characteristics and crack patterns. The experimental results indicate that strength, elastic parameter, P- and S-wave velocities, and failure pattern are influenced by the applied confining pressure. At the pre-peak stage on the stress-strain curve, the P-wave velocity increases with elevated stress; however, the S-wave velocity first increases and then decreases, which is related to the crack damage evolution. The mesostructural changes during deformation are considered to be the main factor controlling the pressure sensitivity of the velocities. Under compression, the relatively soft pores, micro-cracks and minerals were compacted gradually, and it is the primary reason leading to the increment of velocities. Based on the CT scanning technique, the crack pattern was obtained after triaxial testing, the crack pattern analysis suggests that the fractal dimension of fracture distribution almost increases with confining pressure. What is more, the stimulated fracture density increases with increasing confining pressure. It suggests that, for the Longmaxi black shale, a high confining pressure condition is beneficial to form a complex fracture network.",2,2,4
Sichuan Basin,Formation Shale,"Fan, Xiaojie; Mao, Xiaoping; Liu, Zhongrong; Geng, Tao; Wang, Haochen","Organic geochemical characteristics and hydrocarbon generation potential of Jurassic shales and mudstones in Qixiang Co area southern Qiangtang Basin, Tibet",Shale; Organic geochemical characteristics; Sedimentary environment; Resource potential; Qiangtang basin,LUCAOGOU FORMATION; LONGTAN FORMATION; SICHUAN BASIN; BLACK SHALES; OIL-FIELDS; MARINE; MATTER; ACCUMULATION; INDICATORS; SEDIMENTS,"The Qixiang Co area is located in the South Qiangtang Depression Zone. Jurassic shales and mudstones with large thicknesses are widely developed in this area. The Jurassic was a potential exploration horizon in the Qiangtang Basin; however, few detailed analyses have been conducted on the geochemical characteristics of mudstones and shales in this area. In this paper, the hydrocarbon generation potential and sedimentary environment of shales and mudstones are analyzed using organic geochemical data. The results show that the abundance of organic matter is low, as indicated by the low TOC value (averaging 0.70%) and hydrocarbon potential (S-1+S-2) (0.13 mg/g). The main macerals of kemgen are exinites with an average value of 82%, and they are mainly type II2 kerogen. A summary of the results is presented: the thermal maturity of organic matter is high; the average Ro value is more than 1.2%; n-alkanes are dominated by a high carbon number and have no obvious odd-even advantage; the average value of Pr/Ph is 0.74; the distribution of C-23 triterpenoids satisfies C-20 < C-21 < C-23; the content of the gammacerane index is moderate (0.21) the variation range is small; and the C-27 content in regular steranes is dominant. It can be concluded that the organic matter precursors in this area were a mix of higher plants and marine phytoplankton. Organic matter was deposited under a reductive environment with stable water and slightly high salinity. The hydrocarbon generation potential of the Jurassic shale and mudstone in this area is poor, which is unfavorable to oil and gas exploration.",2,2,2
Sichuan Basin,Shale Gas,"Wang, Ziyi; Chen, Lei; Chen, Dongxia; Lai, Jin; Deng, Gaoshan; Liu, Ziyi; Wang, Chao",Characterization and evaluation of shale lithofacies within the lowermost Longmaxi-Wufeng Formation in the Southeast Sichuan Basin,,MISSISSIPPIAN BARNETT SHALE; FORT-WORTH BASIN; MARINE SHALE; GAS; AREA,,3,3,6
Sichuan Basin,Shale Gas,"Zhang, Fengshou; Jiang, Zhenyuan; Chen, Zhaowei; Yin, Zirui; Tang, Jizhou",Hydraulic fracturing induced fault slip and casing shear in Sichuan Basin: A multi-scale numerical investigation,Fault slip; Casing deformation; Hydraulic fracturing; Mitigation; Natural fractures,SHALE GAS; NATURAL FRACTURES; DEFORMATION; RESERVOIR; FAILURE; CHALLENGES; COMPACTION; SIMULATION; VOLUME; MODEL,"A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured.",2,2,6
Sichuan Basin,Shale Gas,"Wang, Y.; Liu, D. Q.; Zhao, Z. H.; Wang, H. J.",Investigation on the effect of confining pressure on the geomechanical and ultrasonic properties of black shale using ultrasonic transmission and post-test CT visualization,Velocity anisotropy; Confining pressure; CT imaging; Crack pattern,LONGMAXI FORMATION SHALE; ELASTIC-WAVE VELOCITIES; X-RAY CT; MECHANICAL-PROPERTIES; ANISOTROPY; DEFORMATION; BEHAVIOR; ROCKS,"Knowledge of the influence of confining pressure on the geomechanical and ultrasonic characteristics is essential to exploration and development of gas shale reservoirs. In contrast to the extensive studies on the physical and mechanical properties of shale, the velocities of P-wave and S-wave during continuous deformation are not thoroughly understood. In this study, a suite of triaxial compression tests were done on the shale samples collected from the Sichuan Basin and were cored with horizontal bedding structure under various confining pressure. In-situ ultrasonic transmission technique combined with post-test CT imaging analysis was used to reveal the velocity-pressure characteristics and crack patterns. The experimental results indicate that strength, elastic parameter, P- and S-wave velocities, and failure pattern are influenced by the applied confining pressure. At the pre-peak stage on the stress-strain curve, the P-wave velocity increases with elevated stress; however, the S-wave velocity first increases and then decreases, which is related to the crack damage evolution. The mesostructural changes during deformation are considered to be the main factor controlling the pressure sensitivity of the velocities. Under compression, the relatively soft pores, micro-cracks and minerals were compacted gradually, and it is the primary reason leading to the increment of velocities. Based on the CT scanning technique, the crack pattern was obtained after triaxial testing, the crack pattern analysis suggests that the fractal dimension of fracture distribution almost increases with confining pressure. What is more, the stimulated fracture density increases with increasing confining pressure. It suggests that, for the Longmaxi black shale, a high confining pressure condition is beneficial to form a complex fracture network.",2,2,4
Sichuan Basin,Shale Gas,"Fan, Xiaojie; Mao, Xiaoping; Liu, Zhongrong; Geng, Tao; Wang, Haochen","Organic geochemical characteristics and hydrocarbon generation potential of Jurassic shales and mudstones in Qixiang Co area southern Qiangtang Basin, Tibet",Shale; Organic geochemical characteristics; Sedimentary environment; Resource potential; Qiangtang basin,LUCAOGOU FORMATION; LONGTAN FORMATION; SICHUAN BASIN; BLACK SHALES; OIL-FIELDS; MARINE; MATTER; ACCUMULATION; INDICATORS; SEDIMENTS,"The Qixiang Co area is located in the South Qiangtang Depression Zone. Jurassic shales and mudstones with large thicknesses are widely developed in this area. The Jurassic was a potential exploration horizon in the Qiangtang Basin; however, few detailed analyses have been conducted on the geochemical characteristics of mudstones and shales in this area. In this paper, the hydrocarbon generation potential and sedimentary environment of shales and mudstones are analyzed using organic geochemical data. The results show that the abundance of organic matter is low, as indicated by the low TOC value (averaging 0.70%) and hydrocarbon potential (S-1+S-2) (0.13 mg/g). The main macerals of kemgen are exinites with an average value of 82%, and they are mainly type II2 kerogen. A summary of the results is presented: the thermal maturity of organic matter is high; the average Ro value is more than 1.2%; n-alkanes are dominated by a high carbon number and have no obvious odd-even advantage; the average value of Pr/Ph is 0.74; the distribution of C-23 triterpenoids satisfies C-20 < C-21 < C-23; the content of the gammacerane index is moderate (0.21) the variation range is small; and the C-27 content in regular steranes is dominant. It can be concluded that the organic matter precursors in this area were a mix of higher plants and marine phytoplankton. Organic matter was deposited under a reductive environment with stable water and slightly high salinity. The hydrocarbon generation potential of the Jurassic shale and mudstone in this area is poor, which is unfavorable to oil and gas exploration.",2,2,2
Sichuan Basin,Shale Gas,"Tang, Wei; Li, Meng",Scalable double regularization for 3D Nano-CT reconstruction,Shale; Nano-CT; Image reconstruction; Regularization; Scalable algorithm,CONVOLUTIONAL NEURAL-NETWORK; X-RAY CT; IMAGE-RECONSTRUCTION; ALGORITHMS; QUALITY; SHALE; ART,"Nano-CT (computerized tomography) has emerged as a non-destructive high-resolution cross-sectional imaging technique to effectively study the sub-mu m pore structure of shale, which is of fundamental importance to the evaluation and development of shale oil and gas. Nano-CT poses unique challenges to the inverse problem of reconstructing the 3D structure due to the lower signal-to-noise ratio (than Micro-CT) at the nano-scale, increased sensitivity to the misaligned geometry caused by the movement of object manipulator, limited sample size, and a larger volume of data at higher resolution. We propose a scalable double regularization (SDR) method to utilize the entire dataset for simultaneous 3D structural reconstruction across slices through total variation regularization within slices and L-1 regularization between adjacent slices. SDR allows information borrowing both within and between slices, contrasting with the traditional methods that usually build on slice by slice reconstruction. We develop a scalable and memory-efficient algorithm by exploiting the systematic sparsity and consistent geometry induced by such Nano-CT data. We illustrate the proposed method using synthetic data and two Nano-CT imaging datasets of Jiulaodong (JLD) shale and Longmaxi (LMX) shale acquired in the Sichuan Basin. These numerical experiments show that the proposed method substantially outperforms selected alternatives both visually and quantitatively.",1,1,8
Image Logs,,Yin Yanshu; Hu Xun; Huang Jixin; Feng Wenjie; Wang Linxin; Duan Taizhong; Zhao Lei; Zhang Wenbiao,"A three-dimensional model of deep-water turbidity channel in Plutonio oilfield, Angola: From training image generation, optimization to multi-point geostatistical modelling",Multi-point geostatistics; Training image; Alluvsim; Optimization method; The Plutonio oilfield in Angola,SIMULATION; RESERVOIRS; DISTANCE,"The deep-water turbidity channel system in the Oligocene O73 sand layer in the Plutonio oilfield in Angola of west Africa has good oil and gas reservoir capability. As the well spacing is large due to operation cost, and the seismic resolution of the target layer is relatively low, identification of turbidity channel boundary was difficult. To establishes a fine model is a problem faced by the modelers. In this paper, a complete multi-point geostatistical modeling flowchart is presented for the construction of fine deep-water turbidity channel model. According to the investigation of seismic, well logging, drilling data and references in the study area, the genesis, reservoir scale, lithofacies type, morphological characteristics and evolution of the deep-water turbidity channel of the target layer were obtained. The improved Alluvsim algorithm was utilized to generate a set of adaptive deep-water turbidity channel training images with specified curvatures. Net-to-gross, variogram and a high-order statistics method based on the single data event were compared to evaluate and sort the training images. Then, the Snesim method was utilized to construct the models using the sorted compatible training images with a same set of parameters. At last, the quality of different models was compared based on the seismic attribute slices and a composite correlation coefficient optimization method based on seismic data. The results suggest that the improved Alluvsim algorithm can reproduce the channel morphology and stacking patterns better. Compared with the first-order and second-order statistics comparison method, the method using higher-order statistics of single data event taken spatial patterns into consideration and sorted training images better. The reservoir model was established using the optimal selected training image which has a high correlation with seismic attributes, and the model is more consistent with the characteristics of subsurface reservoirs. At the same time, this paper also provides a complete research program for the application of multi-point geostatistical modeling method which is from training image generation, optimal training image selection and multi-point geostatistics modeling to realizations selection for practical subsurface reservoir modelling.",3,3,2
Image Logs,,"Alpak, Faruk O.; Jennings, James W.",Adjoint method acceleration protocols for model maturation to update static models with time-lapse reservoir surveillance data,,ALGORITHM; QUANTIFICATION,"We develop an ensemble model-maturation method that is based on the Randomized Maximum Likelihood (RML) technique and adjoint-based computation of objective function gradients. The new approach is especially relevant for rich data sets with time-lapse information content. The inversion method that solves the model-maturation problem takes advantage of the adjoint-based computation of objective function gradients for a very large number of model parameters at the cost of a forward and a backward (adjoint) simulation. The inversion algorithm calibrates model parameters to arbitrary types of production data including time-lapse reservoir-pressure traces by use of a weighted and regularized objective function. We have also developed a new and effective multigrid preconditioning protocol for accelerated iterative linear solutions of the adjoint-simulation step for models with multiple levels of local grid refinement. The protocol is based on a geometric multigrid (GMG) preconditioning technique. Within the model-maturation workflow, a deep-learning technique is applied to establish links between the mesh-based inversion results (e.g., permeability-multiplier fields) and geologic modeling parameters inside a static model (e.g., object dimensions, etc.). Our workflow integrates the ""earnings from inversion back into the static model, and thereby, ensures the geologic consistency of the static model while improving the quality of the ensuing dynamic model in terms of honoring production and time-lapse data, and reducing forecast uncertainty. This use of deep learning (DL) to post-process the model-maturation outcome effectively converts the conventional continuous-parameter history-matching result into a discrete tomographic inversion result constrained to geological rules encoded in training images. We demonstrate the practical utilization of the adjoint-based model-maturation method on a large time-lapse reservoir-pressure data set using an ensemble of full-field models from a reservoir case study. The model-maturation technique effectively identifies the permeability modification zones that are consistent with alternative geological interpretations and proposes updates to the static model. Upon these updates, the model not only agrees better with the time-lapse reservoir-pressure data but also better honors the tubing-head pressure as well as production logging data. We also provide computational performance indicators that demonstrate the accelerated convergence characteristics of the new iterative linear solver for adjoint equations.",3,3,1
Image Logs,,"Wang, Song; Wang, Guiwen; Lai, Jin; Li, Dong; Liu, Shichen; Chen, Xu; Yang, Kefu; Song, Lianteng","Logging identification and evaluation of vertical zonation of buried hill in Cambrian dolomite reservoir: A study of Yingmai-Yaha buried hill structural belt, northern Tarim basin",Dolostones; Paleokarst; Image log; Cambrian; Tarim basin,CARBONATE RESERVOIR; SICHUAN BASIN; IMAGE LOGS; ORDOS BASIN; OIL-FIELD; KARST; AREA; PALEOGEOMORPHOLOGY; PREDICTION; FRACTURE,"Buried hill reservoir is indispensable part of karst reservoirs in northern Tarim basin, China, which is resulted from the long-term exposure of Cambrian carbonate rock due to meteoric freshwater. Four types of zones could be divided in the buried hill of Upper Cambrian Xiaqiulitage Formation in Yingmai-Yaha structure, including surface karst zone, vertical vadose zone, horizontal underflow zone and deep slow flow zone from up to bottom. Firstly, the conventional and image log response characteristics of different types of vertical karst zonation were summarized through cores, thin section and well log-calibration. The surface karst zone is close to the weathering crust, showing breccia and residual characteristics, and is recognized as bright spots appearances on the image logs. Due to the vertical movement of atmospheric fresh water, a large number of high-angle fractures and dissolution caves are developed in the vertical vadose zone, and the vertical vadose zones are characterized by high-angle sine curve appearances on the image logs. The horizontal under flow zone has a horizontally connected caves or vugs due to the horizontal movement of groundwater, and the image logs are recognized as dark bands. The conventional logs also show the decrease of resistivity and the increase of gamma ray (GR). The deep slow flow zone is less affected by karstification, and there are fewer dissolution caves and fractures, but there is also a certain weak dissolution and may contain small vugs. The image logs show isolated dark spots. The Vertical zonation of buried hill can be divided using well logs by calibrating cores, and thin sections. Finally, the core analysis, and the oil test data are used to determine the zoning of the high-quality reservoir. The results show that the four zones of the buried hills have obvious well log response characteristics. The karst zoning can be well divided by the image logs and conventional well logs when calibrated with cores. The data of core analysis and oil testing show that although the reservoir quality in the horizontal underflow zone is the best, the study area is a bottom-water reservoir, and the reservoirs in the horizontal underflow zone are mainly water-producing. On the contrary, in the vertical vadose zone, a large number of high-angle fractures communicated with small pores, which not only improved the quality of the reservoir, but also the oil test data proves that the reservoir is mainly producing oil and gas. Therefore, compared with the horizontal underflow zone and deep slow flow zone, the vertical vadose zone is favorable to the enrichment and preservation of oil and gas. The research results will provide important insights in the hydrocarbon exploration and exploitation in dolostone reservoirs of Tarim Basin.",2,3,3
Image Logs,,"Aghli, Ghasem; Moussavi-Harami, Reza; Tokhmechi, Behzad","Integration of sonic and resistivity conventional logs for identification of fracture parameters in the carbonate reservoirs (A case study, Carbonate Asmari Formation, Zagros Basin, SW Iran)",Fractures; Image logs; Sonic logs; Reservoir parameters; Resistivity logs,SITU STRESS DIRECTION; FOLD-THRUST BELT; IMAGE LOGS; OIL-FIELD; POROSITY; DENSITY; CORE,"Between all available methods for fractures evaluation, core and image logs are prime methods. However, both of these data are very expensive and practically available in less than 10% of drilled wells. Therefore, a less expensive and quick method would be very helpful for fracture analysis. The main aim of this study is to identify the fracture parameters in the carbonate reservoirs, i.e. fracture density and fracture aperture, using a combination of sonic, resistivity and other conventional logs which commonly available in all wells. For this aim, fractures and their parameters were precisely determined on the image logs in 6 wells from carbonate Asmari Formation as a typical fractured reservoir in the world. Then, the effect of fracture parameters on the sonic and resistivity logs were used to identify fracture parameters in the wells with no core and image logs. Results indicate that the zones with high fracture density and aperture are easily detectable by conventional logs. On the other hand, the behavior of these logs is a function of fracture parameters in the fractured intervals, especially in the zones with high fracture aperture. Separation between shallow (RLA2) and deep (RLA5) resistivity logs along with their cross plot are very reliable indicators for fractured intervals. Sonic transit time rapidly increases where fractures density or aperture increased as well. In this study, a combination of sonic and neutron porosity logs have also been used to determine the effect of fracture aperture, as the main effective factor on the reservoir properties. Furthermore, full waveforms in some studied wells combined with sonic transit time to improve the results of fractures evaluation. Using sonic and resistivity along with neutron porosity and gamma ray logs provides a reliable method for describing the fracture parameters which shows high correlation with image logs results. Due to the high impact of fracture aperture on both reservoir quality and conventional log responses, determination of this parameter is more crucial than other fracture parameters. This method is also applicable for OBM (Oil Base Mud) image tools which conventionally cannot detect fracture aperture.",2,2,3
Image Logs,,"Zuo, Chengji; Qiao, Wenxiao; Che, Xiaohua; Yang, Shubo",Evaluation of azimuth cement bond quality based on the arcuate phased array acoustic receiver station,Phased array; Azimuth resolution; Numerical simulation; Physical experiment; Cement bond quality,NUMERICAL-SIMULATION; ARC ARRAY; FINITE-DIFFERENCE; WELLBORE STABILITY; 2-PHASE FLOW; FIELD; GAS; INTERFACE; WAVE; OIL,"Cement bond quality is a crucial parameter in oil production, and acoustic logging is among the main methods of evaluating this property. By analyzing the characteristics of casing and formation waves, the cement bond quality of the casing-cement interface (interface I) and cement-formation interface (interface II) can be evaluated. However, the use of both monopole sources and receivers render the evaluation of the azimuth and angle range of cement channeling difficult using conventional acoustic logging tools. Herein, we developed an improved azimuthally acoustic bond tool (AABT 2.0) comprising a monopole acoustic radiator and arcuate phased array (APA) acoustic receiver stations with enhanced azimuth resolution capability. AABT 2.0 can determine the azimuth and angle range of cement channeling and improve the resolution of azimuth measurement. We studied these factors through numerical simulation and physical experiments. Numerical simulation results show that the azimuth of cement channeling can be determined by measuring the amplitude of the casing wave's head wave in multiple azimuths received by the APA acoustic receiver stations in a casing well. Compared with individualreception mode, APA acoustic receiver stations with the scanning-reception mode can both determine the azimuth of cement channeling more accurately and confirm the angle range of cement channeling. Data processing results from experimental wells show that AABT 2.0 can evaluate the cement bond quality of interface I with a high azimuth resolution in the circumferential and axial directions, through the amplitude imaging display of the casing wave's head wave. The reliability of AABT 2.0 and the accuracy of our measurement results are verified through comparison with results from an ultrasonic imaging logging tool and information concerning the well condition.",2,2,2
Image Logs,,"Buckman, Jim; Chudi, Obinna; Lewis, Helen; Couples, Gary; Huang, Tianshen; Jiang, Zeyun","Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",Pore occlusion; Pore network model; Digital rock model; Quartz cementation; Permeability,,"Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36-51%, and the earlier Miocene samples have a porosity of around 18-35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234-1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",2,2,1
Image Logs,,"Gao, Jianshen; Liu, Xin; Zhao, Jianpeng; Xie, Xicao",A new electrical imaging logging method in oil-based mud for low-resistivity formation based on concave electrode couples,Electrical imaging logging; Oil-based mud; Concave electrode couple; Low-resistivity formation; Formation resistivity; Standoff,RESERVOIRS; RANGE,"Electrical imaging logging can provide high-resolution information and occupies a pivotal position in reservoir exploration and evaluation. To realize clear electrical imaging in high-resistivity oil-based mud (OBM), researchers have tried various methods. In the existing methods, there are some worrisome issues such as the challenge in clear imaging in low-resistivity formation, the complication and robustness in the inversion of quantitative interpretation and few obtained parameters etc. In this paper, a gratifying way with the help of concave electrode couple is presented and analyzed particularly to focus on the quantitative evaluation in low-resistivity formation. The imaging pad structure and its work principle are first introduced. Then, a systematical and mathematical statement is carried out to obtain desired formation resistivity and standoff between imaging pad and borehole wall. Furthermore, sensitivity analysis is implemented to make clear the performances of measured values including equivalent formation resistance, tool factor and calculated standoff under the influence of multiple parameters. Finally, several imaging tests are shown to demonstrate the effectiveness of this new method presented in this paper. The results shown that profiting from the change of traditional electrode array to concave electrode couples, the formation resistivity and standoff between the pad and borehole wall in low-resistivity formation can be measured simultaneously. Another major advantage of this new method is that the unknown OBM parameters are unnecessarily mastered, and the entire process is free from complicated iterative computation. This study provides another new choice for the electrical imaging logging in OBM.",1,1,5
Image Logs,,"Long, Shengxiang; You, Yuchun; Jiang, Shu; Liu, Guoping; Feng, Qiong; Gao, Yang; Niu, Xiaofang","Integrated characterization of ultradeep reef-shoal reservoir architecture: A case study of the Upper Permian Changxing Formation in the giant Yuanba gas field, Sichuan Basin, China",Reef; Shoal; Reservoir architecture; Integrated characterization; Pseudo-acoustic inversion,SPECTRAL DECOMPOSITION; CARBONATE RESERVOIR; ACOUSTIC PROPERTIES; PARIS BASIN; SEDIMENTOLOGY; DISCOVERY; POROSITY; RAMP,"The Yuanba giant gas field in the Sichuan Basin produces from Upper Permian Changxing heterogeneous reef-shoal reservoirs. It is an ultradeep tight gas reservoir with burial depth of 7000 m. This paper proposes an integrated methodology incorporating the reservoir geology description, petrophysics characterization, seismic response analysis, forward seismic modeling, pseudo-acoustic inversion, and reservoir architecture imaging to identify the geologically complex reef-shoal reservoirs and predict the distribution of the producible reservoirs. The facies of reef cap, reef core, reef base and shoal are first identified based on observations and interpretations of cores, thin sections, mud logging, wireline logs, and formation microscanner images (FMIs). High-energy shoals, reef cores, and reef caps are the most favorable reservoir microfacies. Seismic responses of reef-shoal reservoirs are then investigated through forward modeling and well-seismic calibration. Four reef belts are identified based on seismic reflections and edge detection by seismic paleogeomorphologic features. Reservoir distribution and quantitative properties are predicted using the facies-controlled postattack seismic inversion technique through the correlation between reservoir properties and seismic attributes, which is aided by pseudogamma acoustic inversion to exclude the shale-bearing non-reservoir and pseudo-neutron acoustic inversion based on its good relationship with porosity. The reef reservoir thicknesses range from 10 m to 130 m, and the thickest reservoir is located in the northwestern Yuanba gas field. Finally, 3-D visualization is used to characterize the spatial variation of the interior architecture, connectivity, and distribution of a good reservoir in the reef system. The accuracy rate of prediction for reservoirs and non-reservoirs reaches 88% using this method. The technique has also been successfully used for the deployment of development wells and well trajectory optimization, and the rate of encountering the predicted reservoirs is 100%. This study provides a practical approach to identify and predict the tight carbonate gas reservoir with similar petrophysical responses of density and acoustic to non-reservoirs in the complex carbonate system.",1,1,4
Corrosion,,"Wang, Yefei; Zhao, Min; Dong, Xing; Li, Qiang; Yang, Zhen; Ding, Mingchen",Potential of the base-activated persulfate for polymer-plugging removal in low temperature reservoirs,Polymer flooding of reservoirs; Low temperature; Plugging removers; Hydrolyzed polyacrylamide gel; Base-activated persulfate; Corrosion,CHEMICAL DEGRADATION; CONTAMINATED SOIL; HYDROXYL RADICALS; MOLECULAR-WEIGHT; WASTE-WATER; OXIDATION; PEROXYMONOSULFATE; SULFATE; POLYACRYLAMIDE; CHEMISTRY,"Conventional polymer-plugging removers perform badly in low temperature reservoirs and this has prompted researchers to look for more effective removers. In this work, base-activated sodium persulfate (PDS) was used to degrade polymer-plugging. The performance of the novel remover was first compared with that of conventional removers at 35 degrees C. Then, the degradation mechanism involved and factors of influence were investigated by carrying out radical scavenger and single-factor experiments, respectively. Finally, corrosion tests were performed and the ability of the new remover to remove plugging in porous media was investigated by carrying out flooding tests. The results show that the PDS/NaOH system is a much more potent remover at temperatures as low as 35 degrees C (giving a degradation efficiency of 100% compared to 10-70% using conventional removers). Furthermore, the radical scavenger experiments show that Ha is the predominant radical responsible for polymer gel degradation. The degradation efficiency is affected by the concentrations of the PDS and NaOH solutions, the temperature, and also by the salinity of the polymer gel. We also demonstrate that the polymer gel can be completely degraded when its salinity is 30,000 mg/L by optimizing the temperature and concentration of PDS and NaOH. The corrosion rate using PDS/NaOH was found to be 1.085 g m(-2) h(-1) which satisfies the requirements for entry well fluid. In addition, the static plugging degradation and dynamic plugging removal tests show that PDS/NaOH can degrade the plugging effectively and recover the permeability of the sandpack to over 65%. Our results suggest that the PDS/NaOH system is a highly promising plugging remover for use in low-temperature polymer flooding reservoirs and is a good replacement for the ones conventionally used.",3,4,3
Corrosion,,"Lai, Ruiqiu; Li, Qiang; Cheng, Changkun; Shen, Hui; Liu, Siqi; Luo, Yijing; Zhang, Zhongzhi; Sun, Shanshan",Bio-competitive exclusion of sulfate-reducing bacteria and its anticorrosion property,Sulfate-reducing bacteria (SRB); Nitrate-reducing bacteria (NRB); Bio-competitive exclusion technology; Anticorrosion simulation performance; Acidification; Point corrosion,OIL-FIELD; SULFIDE REMOVAL; H2S PRODUCTION; CORROSION; RESERVOIR; NITRATE; INHIBITION; BIOCIDES; NITRITE; STEEL,"The bio-competitive exclusion (BCX) method is a practical, environment-friendly, and low-cost method of controlling sulfate-reducing bacteria (SRB) and focuses on research and preliminary applications. In this study, a nitrate-reducing bacteria (NRB) were screened and selected from oil-producing water and identified as heterotrophic Pseudomonas sp. through 16S rDNA. The NRB activation and the SRB inhibition systems were studied via the addition of the bio-activators NO3- and NO2-. In addition, the synergistic inhibitory effect of NRB and molybdate on SRB was studied. Results showed that the inhibitory effect of NO2- was better than that of NO3-. At NO3- to NO2- ratio of 1:4, the inhibitory effect was optimum. The addition of 5% activated NRB and a small amount of molybdic acid salt played a synergistic effect. The optimal inhibition system contained the following: 5% NRB, NO3-/NO2- of 1:4, and the amount of molybdate was 1/5 that of NO3-. In this inhibition system, S2- can maintain an extremely low content, and SRB activity was well inhibited. Static corrosion simulation experiments showed that SRB was the main cause of corrosion. The effects of biological inhibitors, fungicides, and corrosion inhibitors on the corrosion inhibition were investigated. Results showed that the corrosion rate of biological inhibitors was the lowest, and the best effect of corrosion inhibition was achieved. The surface morphology of the corroded steel sheet was analyzed via scanning electron microscope. In addition, the surface corrosion of the steel sheet was low, and no pitting was observed.",3,3,2
Corrosion,,"Dias, Heloisa P.; Barros, Eliane, V; Gomes, Alexandre O.; Moura, Robson R.; Pinto, Fernanda E.; Goncalves, Arlan S.; Aquije, Gloria M. F., V; Xu, Zhenghe; Romao, Wanderson","Corrosion rate studies of AISI 1020 steel using linear, cyclic, and aromatic naphthenic acid standards",Naphthenic acid; TAN; Carbon steel; Corrosion rate; SEM/EDX; AFM,CRUDE-OIL; CARBON-STEEL; MASS-SPECTROMETRY; SULFUR-COMPOUNDS; SPECTROSCOPY; DEGRADATION,"The use of total acid number (TAN) to measure the acidity of crude oil samples is a common practice. Daily practice in petroleum refineries shows that oil with a TAN less than 0.5 mg KOH g(-1) can usually have unexpected corrosive behavior. Although naphthenic corrosion has been studied for many years, its process is not entirely understood. Therefore, this study investigated the influence of linear, cyclic and aromatic NAs molecules, evaluating the effect of their concentrations, molar weight (M-w), structural and electronic properties on the corrosion rate of AISI 1020 steel samples at 320 degrees C. The type and extension of corrosion were determined by surface characterization of the sample using optical microscopy (LM), atomic force microscopy (AFM), and scanning electron microscopy (SEM). The results showed that even when TAN was below the detection limit, the corrosion rate (CR) value was significant (CR < 0.19 mm year(-1)) and considered high for the industry. For concentrations of benzoic (BENA) and stearic (STA) acids higher than 5000 ppm, the corrosion rate varied proportionally with the TAN. Also, there was an inverse proportional correlation between molecular weight (M-w), the number of aromatic rings and NAs corrosiveness. In general, NAs standards containing a lower molar volume were found to cause a higher corrosion rate. SEM micrographs revealed changes in the surface area of all samples exposed to linear, cyclic and aromatic NAs, indicating the formation of a protective layer under the surface of the carbon steel specimen. AFM imaging showed drastic changes in the topographic profile and phase images characterized by the formation of valleys and peaks, as well as variations in the mechanical properties of the surface of the AISI 1020 steel sample. Results obtained in this study confirm the influence of the electronicstructural properties of the molecules of organic acids on the naphthenic corrosion.",3,3,1
Corrosion,,"Yang, Yan; Luo, Xuan; Hong, Chuanshi; Yadav, Abhijeet; Rogowska, Magdalena; Ambat, Rajan","Characterization, formation and development of scales on L80 steel tube resulting from seawater injection treatment",Sediment; Corrosion products; Morphology; Layered structure; Ion migration,IRON CORROSION SCALES; MICROBIOLOGICALLY INFLUENCED CORROSION; EXTRACELLULAR POLYMERIC SUBSTANCES; CARBON-STEEL; STAINLESS-STEEL; PHYSICOCHEMICAL CHARACTERISTICS; DISTRIBUTION-SYSTEMS; PIPE CORROSION; CAST-IRON; WATER,"Scale formation in oil and gas production wells is a serious problem that could cause flow reduction and increase the risk of corrosion perforation. In this paper, several characterization methods including visual observation and digital photography of the interior surface of the tubes and scales, high resolution scanning electron microscopy (SEM), transmission electron microscopy (TEM), X-ray photoelectron spectroscopy (XPS) and X-ray diffraction (XRD), have been utilized to investigate the scales. Results show that the scale has a layered structure. Moving from the steel matrix towards the inner tube surface, the scale consists of a dense layer of iron oxy-hydroxide, a porous layer of iron hydroxide and chloride -rich products, a bulk layer of akagneite (Fe 8 O 8 (OH) 8 Cl 1.35 ) and hibbingite ( ?-Fe 2 (OH) 3 Cl), a thin layer of copper sulphide (Cu 2 S) and a granular layer of barite (BaSO 4 ). The different layers have their unique morphological characteristics and mineral phases, implying different formation mechanisms of the layers. A mechanism is proposed for the formation and growth of the scales considering the history of the well. The mechanism suggests that corrosion scales develop from the inner tube surface via cor- rosive reactions. Scale growth is a result of continuous corrosion followed by a combination of deposition and oxidation of the corrosion products. Scale structure and composition play important roles in the migration of chloride ions and in the reactions of corrosion scales that lead to iron release.",3,3,0
Corrosion,,"Wang, Kai; Li, Chenpei; Li, Yanhui; Lu, Jinling; Wang, Yueshe; Luo, Xingqi",A fully coupled model of hydrodynamic -chemical -electrochemical processes for CO 2 uniform corrosion in multi -physics environment,CO 2 uniform corrosion; Multi-physics model; Flow effect; Multi-ion transport; Multi-component reactions,CARBON-DIOXIDE CORROSION; MILD-STEEL; PART 1; ELEVATED-TEMPERATURES; INCUBATION PERIOD; AQUEOUS-SOLUTIONS; PASSIVE METALS; WATER; OIL; PREDICTION,"Carbon dioxide uniform corrosion occurs widely in the petroleum industry and threatens the safe production and transportation of petroleum resources. It is a complex issue involving a variety of physical, chemical and elec- trochemical processes in multiple temporal and spatial scales. A fully coupled model, taking into account all involved processes in a coupled fashion, such as fluid flow, multi -ion transport, multi -component chemical/ electrochemical reactions, is established to comprehensively investigate the mechanism of CO 2 corrosion in multi -physics environment. The reliability of this model is validated by the good consistency between the pre- dicted corrosion rates and the experimental results in the literature, and this model performs better in corrosion rate prediction than the previous models due to the explicit solution for the convective mass transfer. Based on this fully coupled model, the corrosion mechanism in the multi -physics coupled environments is revealed in terms of the time -dependent ion concentration field, mass transfer and electrode reaction kinetics. The inter- relationship between the corrosion kinetics and the flow effect is explored. The results indicate that the time - dependent corrosion behavior is determined by the combined effect of the solution chemistry and electrical field. By accelerating the mass transport of corrosive species and the involved multi -component reactions, the fluid flow can significantly promote the corrosion process, while the promotion effect weakens gradually at higher flow velocities. Additionally, the flow effect at lower pH values is much more pronounced due to the transformation of the predominant controlling factors for electrode kinetics.",2,2,11
Corrosion,,"Wang, Kai; Wang, Zi Ming; Song, Guang-Ling",Batch transportation of oil and water for reducing pipeline corrosion,Oil production; Multiphase flow; Corrosion; Water wetting,CARBON-DIOXIDE CORROSION; 2-PHASE FLOW; CRUDE-OIL; NUMERICAL-SIMULATION; INTERNAL CORROSION; STEEL; MECHANISM; EMULSIONS; GREEN,"Different from the conventional transportation of oil-water mixtures, we proposed a method to reduce pipeline corrosion based on a concept of flow management, where the mixed fluids were firstly separated into oil and water and then a batch transportation of oil and water was introduced to tune the water wetting state at pipeline bottom. In this way, the corrosion risk of pipe bottom can be properly reduced with a minor modification of the transportation procedure. In this paper, the idea was theoretically and experimentally verified, and the modified procedure was effective in corrosion mitigation compared with the conventional oil gathering system in a CO2-enhanced oil recovery (EOR) production system. It was found that the corrosion mitigation efficiency held a positive relationship with the dimensionless length of the oil phase, which was determined by the input length of oil and water batch and the evolution of flow pattern at the oil/water interface. This is of special benefits for the case where a large amount of free water is unable to be entrained into oil phase. Such a concept of corrosion mitigation can be applied in the transportation of corrosive oil-water mixtures in petroleum industry, such as in CO2-EOR and offshore oil production.",2,2,6
Corrosion,,"Alef, Khalid; Barifcani, Ahmed","Effect of N-methyl-diethanolamine and film forming corrosion inhibitor on gas hydrate, and empirical modeling for degradation",Hydrate inhibition; Monoethylene glycol (MEG); Kinetic hydrate inhibitor (KHI); Methyldiethanolamine (MDEA); Film forming corrosion inhibitor (FFCI); Empirical modeling,INTERNAL CORROSION; PHASE-EQUILIBRIA; METHANE; MEG; TEMPERATURE; PERFORMANCE; NUCLEATION; PREVENTION; PIPELINE; GROWTH,"Chemical inhibition is a common solution to hydrate formation in gas pipelines. Monoethylene glycol (MEG) and kinetic hydrate inhibitor (KHI) are the most commonly used hydrate inhibitors, whilst N-methyl-diethanolamine (MDEA) and film forming corrosion inhibitor (FFCI) are usually used as part of a corrosion control program to go alongside these hydrate inhibitors. In this study, the methane hydrate inhibition performance of MDEA and FFCI in the presence and absence of a hydrate inhibitor were assessed. The study found that both MDEA and FFCI may improve the overall hydrate inhibitory performance of the combined solution. When combined with KHI an increase in induction times was found. FFCI may act as a thermodynamic hydrate inhibitor, and thus enhance the hydrate inhibitory performance alongside MEG. Furthermore, two empirical models were developed to cater for MEG and MDEA + MEG degradation effect on hydrate phase equilibrium temperature, as this effect cannot be simulated in flow assurance prediction software. Moreover, these models and previously developed models were combined wholesomely in the form of an algorithm to determine the hydrate phase equilibrium temperature.",1,1,3
Corrosion,,"Chen, Shengshan; Wang, Hanxiang; Wang, Yuting; Liu, Yanxin; Zhang, Xin; Lv, Xiaoxiao; Lan, Wenjian",Residual mechanical strength evaluation of corroded tubing in cryogenic carbon dioxide injection wellbore,,FROST HEAVE; HORIZONTAL WELLS; YOUNGS MODULUS; CORROSION; MODEL; STATE; ICE; PRESSURE; SURFACE; TUNNEL,,1,1,1
Methane Adsorption,,"Jiang, Bingyou; Zhao, Yang; Lin, Baiquan; Liu, Ting",Effect of faults on the pore structure of coal and its resultant change on gas emission,Pore structure; Desorption hysteresis; Fault; Multifractal; Coal and gas outburst,MULTIFRACTAL ANALYSIS; FRACTAL CHARACTERISTICS; ADSORPTION-PORES; DEFORMED COALS; METHANE; EVOLUTION; NITROGEN; OUTBURSTS; SEEPAGE,"Faults are one of the important factors influencing coal and gas outburst in outburst coal seams. In this paper, 3# and 8# coal seams in Xinjing Coal Mine were taken as the research objects in the hope of revealing the mechanism of how faults affect coal seam. The pore structure and its resultant change on gas emission of coal samples at different distances from the faults were studied by means of scanning electron microscope, nuclear magnetic resonance and adsorption/desorption experiments. The results show that the fault significantly influences the pore structure. The coal sample closer to the fault has a greater number of well-developed macropores and fractures as well as better connectivity between pores and fractures. Besides, compared with 8# coal seam, 3# coal seam which is more notably impacted by the fault possesses a more developed pore structure at the micron scale. As the distance from the fault increases, the gas adsorption volume declines while the desorption hysteresis coefficient grows on the whole. The coal sample closer to the fault adsorbs a larger volume of gas and meanwhile desorbs gas more easily, so it is more prone to coal and gas outburst. The initial velocity of gas emission falls gradually as the distance from the fault increases. The desorption hysteresis coefficient generally drops with the rise of the initial velocity of gas emission. Judged by the influence scope of the fault, 3# coal seam possesses a much higher outburst risk than 8# coal seam. The research results reveal the mechanism of how faults affect coal pore structure and gas sorption characteristics, which can provide a basis for the prevention and control of gas dynamic disasters in fault-containing coal seams.",3,3,7
Methane Adsorption,,"Liu, Xiaolei; Wu, Caifang; Wei, Guoying; Zhang, Xiaodong; Jia, Tianrang; Li, Huaizhen; Du, Mingyang",Adsorption deformation characteristics of coal and coupling with permeability during gas injection,CBM; Injection pressure; Adsorption strain; Permeability; Free adsorption boundary,BITUMINOUS COAL; SORPTION; SHRINKAGE; METHANE; CO2; DESORPTION; EVOLUTION; POROSITY; STRAIN; IMPACT,"The study of coal adsorption-induced strain is of great significance to the development of coalbed methane (CBM). In this text, the relationship between adsorption-induced strain and injection time, injection pressure, flux and permeability were studied by He and N-2 injection respectively. The variation of adsorption strain with time at different stages was mainly studied. It was found that the strain increases linearly with increasing injection pressure within the experimental range. The relationship between strain and time is according to Langmuir's law under the same injection pressure. Meanwhile, there is a free adsorption boundary in the initial linear stage of adsorption. Within the free adsorption boundary, the adsorption-induced strain rate is independent of pore pressure; afterwards the adsorption-induced strain rate begins to be dominated by pore pressure. Moreover, the permeability increases with the increase of pore pressure. Because of the negative effect of adsorption expansion, the variation of N-2 permeability with injection pressure is slower than that of He. The lower the initial permeability is, the more serious the permeability damage caused by adsorption expansion will be. The final research results show that pore pressure has a dual effect of ""one positive and one negative"". The positive effect is the promotion of gas migration, and the negative effect is the inhibition of adsorption expansion on gas migration.",3,3,7
Methane Adsorption,,"Ma, Longjie; Yu, Qingchun",Dynamic behaviors of methane adsorption on partially saturated shales,Partially saturated shales; Methane adsorption dynamic behavior; Dynamic adsorption model; Gas flow control stage; Transition stage; Interface interaction stage,NORTHEASTERN BRITISH-COLUMBIA; EASTERN QAIDAM BASIN; NATURAL-GAS; CARBON-DIOXIDE; PORE STRUCTURE; GEOLOGICAL CONTROLS; UNCONVENTIONAL GAS; POROUS CARBONS; DIFFUSION; WATER,"The dynamic behavior of methane adsorption onto shales plays an important role in many resource and environmental problems. Previous studies have mainly analyzed gas diffusion, but the studies have also shown that the adsorption process consists of multiple forms of gas movement. In fact, water always exists in shale, but the process of methane adsorption onto partially saturated shales has received little attention. To study the movement behavior of methane in the adsorption process and determine how water influences the dynamic behaviors of methane adsorption, a dynamic adsorption model (DAM) was proposed. In this study, dynamic adsorption experiments involving three shale samples with four water saturation levels were conducted. Based on the experiments, 48 adsorption process curves were obtained. The dynamic adsorption process was divided into three stages based on the curves. The first stage occurred when the adsorption amount reached 50% of the equilibrium adsorption amount, and the corresponding time range was t < t(50); the second occurred when the adsorption amount increased from 50% to 80%, and the corresponding time range was t(50) < t < t(50); and the third occurred when the adsorption amount increased from 80% to 100%, and the corresponding time range was t(80) < t < t(1)(00). These stages were defined as the gas flow control stage, transition stage and interface interaction stage, respectively. The basis for this determination was that the adsorption rate was mainly controlled by the gas flow, gas flow and interface interaction, and interface interactions during these stages, respectively. The experimental data were fitted with the unipore diffusion model (UNM) based on Fick's second law and the modified unipore diffusion model (MM). The results showed that the UNM was better fit to the gas flow control stage but cannot describe the entire adsorption process. The MM was well fit to the dry shale methane adsorption process, although the wet shale fitting effect was inferior to that of the DAM. Analysis of the effect of water on the adsorption rate in each stage revealed that the inhibition of water acted against the methane gas flow more strongly than against the interface interaction. The effective pore volume (the fraction of pores not occupied by water molecules that could be reached by methane molecules) had a strong positive correlation with the adsorption rate in the early stage of the adsorption process, whereas the correlation was weak in the later stage. Under low water saturation conditions, the reduction of the adsorption rate due to the increase in the unit water saturation was larger, whereas this effect was smaller under high water saturation conditions. Gas flow was greatly affected by water in the clay matrix, whereas the interface interaction was less affected. The pattern was diametrically opposite in the organic matrix.",3,4,7
Methane Adsorption,,"Yang, Xin; Zhang, Hongbin; Wu, Wenbo; Gong, Zhihao; Yuan, Weifeng; Feng, Xi-Qiao; Gu, Bin",Gas migration in the reservoirs of ultra-low porosity and permeability based on an improved apparent permeability model,Gas migration; Solid-fluid coupling; Apparent permeability; Stress dependence; Initial deformation state,SHALE-GAS; COAL PERMEABILITY; TRANSPORT MECHANISMS; MATRIX DEFORMATION; STRESS-DEPENDENCE; SURFACE-DIFFUSION; ADSORPTION; FLOW; NANOPORES; METHANE,"An apparent permeability model considering the solid-fluid coupling is established to analyze the gas transport in the reservoirs of ultra-low porosity and permeability. In the new model, multiple flow mechanisms including viscous flow, the dynamic effects induced by gas molecules collision with the pore walls and surface diffusion are taken into account according to the flow distributions. The effect of solid deformation is embodied with the stress dependence model of the intrinsic permeability which is based on the poroelasticity theory, discards the assumption of constant total stress and accounts for the influence of the initial deformation state. Numerical results show that the dynamic effects and surface diffusion can promote the apparent permeability, especially when the pore pressure drops to a low level. The geomechanical deformation generally results in the reduction of the intrinsic permeability while the large sorption strain may induce rebound of the intrinsic permeability. The assumption of constant total stress only slightly affects the permeability, but it eliminates the instantaneous equilibrium stage in the gas migration process. Correct determination of the initial deformation state is critical to evaluate the gas flow capacity. Finally, parametric analysis is conducted to identify the key factors in gas transfer.",3,3,2
Methane Adsorption,,"Xue, D. J.; Liu, Y. T.; Zhou, J.; Sun, X. T.",Visualization of helium-water flow in tight coal by the low-field NMR imaging: An experimental observation,Low-field NMRI; Visualization; Helium-water flow; T-2 spectrum; Saturation evolution; Porosity,PORE STRUCTURE CHARACTERIZATION; NUCLEAR-MAGNETIC-RESONANCE; SOLID-STATE NMR; FRACTAL CHARACTERIZATION; SIZE DISTRIBUTIONS; GAS; RELAXATION; METHANE; ADSORPTION; DIFFUSION,"The low-field NMR imaging (NMRI) technology plays a key role of visualization of helium-water flow in tight coal. Combined with the traditional description by T-2 spectrum, the NMRI description provides an auxiliary illustration on spatial distribution of water in various pores. To distinguish the different contribution of various pores in helium-water flow, a flow function-based classification of adsorption pore (AP), percolation pore (PP) and migration pore (MP) are suggested. It depends on the periodic appearance of peak and valley of the T-2 spectrum. Although all pores contribute to porosity, the unchanged AP peak of T-2 spectrum and the trapped water in 2D distribution shows AP contributes little to the helium-water flow. Further, the saturation evolution is clearly illustrated by CPMG sequence and NMRI visualization. Both descriptions show a strong dependence of saturation evolution on pore size distribution. Finally, the porosity is modified based on the squeezing effect of enhancing the peak of T-2 spectrum. The experimental result shows the helium-water flow is properly demonstrated by the low-field NMRI method, but the drainage efficiency of helium displacing water is not high due to the trapped water in AP.",2,3,10
Methane Adsorption,,"Dong, Yintao; Ju, Binshan; Zhang, Suian; Tian, Yapeng; Ma, Shuai; Liu, Nannan; Lu, Guangzhong",Microscopic mechanism of methane adsorption in shale: Experimental data analysis and interaction potential simulation,Shale; Methane; Adsorption; Interaction potential; Microscopic mechanism,MOLECULAR SIMULATION; MESOPOROUS CARBONS; PORE STRUCTURE; GAS; COAL; CAPACITY; BEHAVIOR; CO2,"The adsorbed methane in shale determines the geological reserves of shale gas and production of the well. Therefore, it is of great importance to clarify the microscopic mechanism of methane adsorption in shale for evaluating the geological condition and formulating exploitation plan. In this study, the experimental data and the simulation result were combined to research the microscopic mechanism of methane adsorption in shale. The experimental data for 99 groups of low-temperature nitrogen adsorption and methane isothermal adsorption were collected, to calculate the number of adsorption layers of methane in shale at the micro-level. The surface, microfracture and micropore structures of the organic matter in shale were constructed by graphite structure with the hydroxyl group. Thereafter, they were used to simulate the interaction potential of the organic matter on methane molecules and the adsorption layer's number by using the theory of intermolecular interaction potential field. Furthermore, the effects of different fracture widths and pore diameters on methane adsorption were analyzed and verified. The results show that the adsorption capacity of methane in shale is related to shale's structure, and the order of the adsorption capacity is surface < microfracture < micropore. Meanwhile, the multilayer adsorption can occur in microfractures with a width of 1.44-1.59 nm and micropores with a diameter of 1.49-1.83 nm, whereas the surface structure just can be the monolayer adsorption. These quantitatively results establish a foundation for the development of adsorption theory for methane in the shale.",2,3,4
Methane Adsorption,,"Zhou, Dong; Liu, Zhixiang; Feng, Zengchao; Shen, Yongxing; Wu, YuCheng",The study of the local area density homogenization effect of meso-structures in coal during methane adsorption,Adsorption; Swelling deformation; Density homogenization; Local area; CT,FRACTAL CHARACTERISTICS; ANTHRACITE COAL; GAS-TRANSPORT; DESORPTION; DEFORMATION; PERMEABILITY; EVOLUTION,"The swelling deformations of coal structures during the methane adsorption cause the changes of the gas migration channels such as mesopores and fractures, which poses a great challenge to evaluate the methane migration efficiency in pore-fracture network structures of coal. Because of the complexity of the multi-scale inhomogeneity meso-structure in coal, the previous studies were failed to propose a unified equation to accurately describe and predict the complex deformation of coal structures during methane adsorption. Through lots of researches of meso structures deformation during methane adsorption in coal, the local area density homogenization effect of the meso structures in coal during methane adsorption was discovered. In view of this, the mechanism of the local area density homogenization effect was analyzed by establish a new model of coal structure, and the local area density homogenization equation of methane adsorption in coal was derived. It indicated that the deformation of meso target structure in coal during the methane adsorption is mainly determined by the density ratio of the target structure to the local area, and the swelling deformation of the local area that contains the target structure, as well as the density homogenization coefficient. Through multi-scale three-dimensional segmentation and statistics of the Computed Tomography (CT) scan data of anthracite sample adsorbed methane under different adsorption pressures, the rule of the local area density homogenization effect was verified. It was found that the deformations of the meso structures in coal during the methane adsorption was capable to fit to the local area density homogenization equation of methane adsorption in coal under different adsorption pressures and observation scales. The calculation accuracy of this equation was determined by the analysis of the 95% confidence intervals of the density homogenization coefficient.. The local area density homogenization equation provides a way to describe and predict deformation behavers of coal structures based on the their density information obtained by CT scanning, and has great significance for the numerical simulation of methane dynamic seepage characteristics in multi-scale structures of coal in the CBM exploitation process.",1,1,4
Anisotropy,,"Han, Songcai; Cheng, Yuanfang; Gao, Qi; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Analysis of instability mechanisms of natural fractures during the approach of a hydraulic fracture,Hydraulic fracture propagation; Numerical simulation; Induced stresses; Pore pressure; Natural fracture stability; Arrested/crossing criterion,SHALE GAS; FLUID-FLOW; PROPAGATION; BEHAVIOR; MODEL; INTERFACES; SIMULATION; CRITERION; LEAKOFF,"A fluid-driven fracture propagation model dominated by viscosity-leak-off regime was presented to investigate the mechanical stability of natural fracture (NF) when hydraulic fracture (HF) approaches. The induced stresses generated by the approaching HF were calculated by a fully coupled integro-differential equation. The pore pressure effect caused by fracturing fluid leak-off was simulated based on dual porosity medium theory. The critical failure conditions of NF were determined based on maximum tensile criterion and Barton-Bandis criterion. The sensitivity of the stability of NF to in-situ stress anisotropy, approaching angle and distance, injection rate, fracturing fluid viscosity, and NF properties was analyzed in detail. Simulation results reveal that the shearing-mode failure of NF is obviously easier than the opening-mode failure, and the shear slip zone is much larger than the tensile failure zone. As HF approaches NF non-orthogonally, the induced debonding process is unstable, and the debonding zone is asymmetric with respect to the center of NF. The tensile-induced expansion zone is primarily located in the portion of NF ahead of the HF tip, however the shear-induced slip zone can even occur on NF behind of the HF tip. Induced stresses alone have negligible effect on the stability of the NF that is unconnected to the HF. The change in pore pressure due to leak-off effect dominates the final stimulated reservoir volume during large-scale fracturing. The instability of the NF dominates the propagation trajectory of the subsequent HF. A more suitable arrested/crossing condition by extending Gu-Weng criterion was established to predict the path of HF propagation.",3,3,3
Anisotropy,,"Li, Jia; Qiu, Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian; Yang, Yifan",Parametric study on near-wellbore fracture geometry for wellbore strengthening in anisotropic formation,Wellbore strengthening; Anisotropy; Fracture geometry; Extended finite element method; Lost circulation,HYDRAULIC-FRACTURE; LOST CIRCULATION; PREDICTING WIDTH; DRILLING-FLUID; PROPAGATION; ROCK; FLOW; SIMULATION; STABILITY; MECHANICS,"Wellbore strengthening technique is one of the most commonly used treatment to prevent leakage into natural or induced fractures. The accurate prediction of fracture geometry is essential for the particle size distribution (PSD) optimization of wellbore strengthening material (WSM). Due to the existence of weak planes, the rock has the anisotropic characteristic, which results in fracture distortion. Thus, a fully coupled poro-elastic model is solved with Abaqus by using the extended finite element method (XFEM) - based cohesive zone method (CZM) to investigate the geometry of near-wellbore fracture. The fracture trajectory and opening are captured before and after bridging by coupling the rock deformation, seepage flow of pore fluid, fluid flow in fracture and leak-off of drilling fluid. The sensitive analysis results illustrate that the fracture tends to propagate along the principal material direction with the effect of anisotropy. The larger ratio of Young's modulus aggravates fracture distortion in the near-wellbore area. The increase of ratio of horizontal in-situ stress weakens the effect of anisotropy. The anisotropic permeability has minor effects on fracture geometry with the combined influence of anisotropic mechanical properties and horizontal stress. The lower injection rate decreases fracture width after bridging and makes the fracture propagation process more controllable through the influence of filtration. The increase of viscosity widens the fracture aperture and increases cuttings transport capacity of drilling fluid.",3,3,2
Anisotropy,,"Oliveira, G. P.; Araujo, E. A.; Santos, M. D.; Roque, W. L.",Non-uniform injector/producer well pattern designs induced by morphology and anisotropy of flow units,Well pattern description; Well placement; Anisotropy; Ellipsoid fitting; Oilfield development,,"Well patterns are designed to comply with specific demands of engineering and usually applied in multilateral layouts for steam-/water-/fire-flooding or other operations in oilfields. Up to now, there is no much information about the linkage between anisotropy effects and preferential flow direction as a driving factor for enhanced well pattern designs, especially in heterogeneous reservoirs. This paper introduces a methodology to design non-uniform areal well patterns typified as 5-spot injector/producer arrangements of vertical wells. In particular, its original feature relies on well patterns derived in relation to flow units. Once these volumetric bodiesare detected, the well placement is formed in coherence with their morphology to pursue the predominant flow direction implicitly. We apply an ellipsoid-fitting technique that provides ""boundary-fitted"" locations for the injector wells that coincide with anchor points on the volume of interest's convex hull. Anchor points are those determined from minimum distances of other points that lie on the principal axes of the best-fit ellipsoid to the flow unit. A class of well patterns derived through rotations by common angles (pi/6, pi/4 and pi/3) and aligned to match the volume's anisotropy is obtained by combining injection points and production spots found from the maximum closeness centrality of the graph associated to the shape. Flow simulations with water-flooding performed in two reservoir models with heterogeneous features show that the hydrocarbon recovery is higher or lower depending on the positions of the injection spots. Single and multiple perforation strategies are examined over flow units with distinct shapes and characteristics to broaden the spectrum of testing conditions. When compared with the traditional water-flooding 5-spot configuration, many cases achieve similar ultimate productions that are influenced to an extent by morphological aspects. The main advantage of the method is to deliver a pragmatic workflow to design directional well patterns which dismisses the solution of more complicated differential models to determine the patterns.",3,3,1
Anisotropy,,"Li, Kesai; Gao, Jie; Zhao, Xiang",Tool design of look-ahead electromagnetic resistivity LWD for boundary identification in anisotropic formation,Anisotropic formation; Boundary identification; Forward modeling; Look-ahead electromagnetic resistivity LWD; Symmetrical structure,INDUCTION; WELL,"In this paper, a novel look-ahead electromagnetic resistivity LWD (LAEM-LWD) tool is designed to obtain accurate real-time information about the formation boundary in anisotropic formations. Based on the fast Hankel transform method, the effect law of environmental factors on logging response is simulated and analyzed in different formation models to discuss tool application conditions. The look ahead distance (LAD) is analyzed using a two-layer formation at different inclination angles, indicating that the tool can be applied well when the resistivity of tool formation is approximately 20-200 Omega m. Next, the use of symmetrized signals in the Oklahoma model for boundary identification under different inclination angles is discussed. Several anti-symmetrized signals and resistivity cross-plots for the anisotropy coefficient and horizontal resistivity extraction are created in the vertical well and verified by a five-layer model, which lays a theoretical basis for tool design of LAEM-LWD, effective geosteering, and real-time formation evaluation.",2,3,4
Anisotropy,,"Wang, Y.; Liu, D. Q.; Zhao, Z. H.; Wang, H. J.",Investigation on the effect of confining pressure on the geomechanical and ultrasonic properties of black shale using ultrasonic transmission and post-test CT visualization,Velocity anisotropy; Confining pressure; CT imaging; Crack pattern,LONGMAXI FORMATION SHALE; ELASTIC-WAVE VELOCITIES; X-RAY CT; MECHANICAL-PROPERTIES; ANISOTROPY; DEFORMATION; BEHAVIOR; ROCKS,"Knowledge of the influence of confining pressure on the geomechanical and ultrasonic characteristics is essential to exploration and development of gas shale reservoirs. In contrast to the extensive studies on the physical and mechanical properties of shale, the velocities of P-wave and S-wave during continuous deformation are not thoroughly understood. In this study, a suite of triaxial compression tests were done on the shale samples collected from the Sichuan Basin and were cored with horizontal bedding structure under various confining pressure. In-situ ultrasonic transmission technique combined with post-test CT imaging analysis was used to reveal the velocity-pressure characteristics and crack patterns. The experimental results indicate that strength, elastic parameter, P- and S-wave velocities, and failure pattern are influenced by the applied confining pressure. At the pre-peak stage on the stress-strain curve, the P-wave velocity increases with elevated stress; however, the S-wave velocity first increases and then decreases, which is related to the crack damage evolution. The mesostructural changes during deformation are considered to be the main factor controlling the pressure sensitivity of the velocities. Under compression, the relatively soft pores, micro-cracks and minerals were compacted gradually, and it is the primary reason leading to the increment of velocities. Based on the CT scanning technique, the crack pattern was obtained after triaxial testing, the crack pattern analysis suggests that the fractal dimension of fracture distribution almost increases with confining pressure. What is more, the stimulated fracture density increases with increasing confining pressure. It suggests that, for the Longmaxi black shale, a high confining pressure condition is beneficial to form a complex fracture network.",2,2,4
Anisotropy,,"Pan, Xinpeng; Li, Lin; Zhang, Guangzhi",Multiscale frequency-domain seismic inversion for fracture weakness,Multiscale frequency-domain inversion; AVOAz inversion; Bayesian inversion; Fracture weaknesses; Fourier operator,WAVE-FORM INVERSION; AVO INVERSION; MODEL; COEFFICIENTS; ANISOTROPY; AMPLITUDE; AZIMUTH; PHASE; ANGLE,"Amplitude variation with offset and azimuth (AVOAz) inversion is an effective tool to invert the azimuthal seismic reflection data for fracture weaknesses, which play an important role in seismic characterization of fractures. Conventional AVOAz inversion is implemented in the time domain, which simultaneously uses full-frequency components of the seismic data causing an unstable and inaccurate inversion result in the case of noisy seismic data. Here we propose a novel multiscale frequency-domain seismic inversion approach to improve resolution and accuracy of fracture weakness estimates. Based on new derived frequency-domain expression of azimuthal seismic amplitude difference for a horizontal transversely isotropic (HTI) medium, we build the kernel function incorporated with the Fourier operator, which avoids the Fourier inverse transform in the frequency-domain inversion. Low frequency information in seismic data is often missing or contaminated with noises, thus we establish an inversion objective function combining low frequency regularization term and Cauchy sparse regularization term in the Bayesian framework. We adopt the multiscale strategy and perform inversion successively from low to high frequency group utilizing a limited number of frequency components with a high signal-to-noise (S/N) ratio. In addition, we compare the multiscale frequency-domain inversion approach, the frequency-domain simultaneous inversion approach, and the time-domain inversion approach using synthetic data and field data. Synthetic example demonstrates that the cross-correlation coefficients (CCs) between the true fracture weaknesses and the inversion results obtained by multiscale frequency-domain inversion approach are above 0.83 even with a S/N of 2. Compared to the time-domain inversion approach and the frequencydomain simultaneous inversion approach, the inversion results with multiscale frequency-domain inversion approach have higher resolution and accuracy. Field data example further validates the feasibility and superiority of the proposed multiscale frequency-domain inversion approach.",2,2,0
Anisotropy,,"Han, Yannong; Feng, Yongcun; Li, Xiaorong; Zhang, Shuai",Evaluation of in-situ stress orientation: A laboratory approach combining paleomagnetic test and acoustic anisotropy test,In-situ stress orientation; Acoustic anisotropy; Paleomagnetism; Kaiser effect,,"It is of great significance to determine the geographic orientation of in-situ stresses for the efficient development of oil and gas resources. Most existing in-situ stress orientation testing techniques can only obtain the relative orientation of in-situ stress and have certain limitations in field applications. In this paper, a new method is proposed to determine in-situ stress orientation by combining laboratory acoustic anisotropy test and paleomagnetic test. This method solves the difficulty in using acoustic anisotropy to determine the geographic orientation of horizontal in-situ stresses. Laboratory test and field case study shows that, compared with the method combining acoustic emission Kaiser effect test and paleomagnetic test, the new method has higher precision and reliability. Meanwhile, the new method has the advantages of higher core utilization rate, simpler test procedures, and lower cost.",1,1,2
Anisotropy,,"Gong, Fei; Di, Bangrang; Zeng, Lianbo; Wei, Jianxin; Ding, Pinbo",Static and dynamic linear compressibility of dry artificial and natural shales under confining pressure,shale gas; Clay minerals; Static properties; Dynamic properties; Anisotropy; Stress sensitivity,EXPERIMENTAL MECHANICAL COMPACTION; ELASTIC PROPERTIES; SEISMIC ANISOTROPY; YOUNGS MODULI; STRESS; CLAY; ROCKS; PERMEABILITY; SENSITIVITY; PARAMETERS,"Clays are among the main mineral components of shales and play a significant role in mechanical properties and anisotropy. However, it is difficult to quantify the impact of clay minerals on the mechanical properties of rocks because of the complex influence factors. In this study, we construct two artificial clay-rich shale samples containing kaolinite and smectite, respectively, and prepare one natural sample to study the static and dynamic responses of dry samples containing different types of clay during confining loading and unloading. The physical and mechanical properties of shales can be greatly affected by the type of clay minerals due to their structural difference. The kaolinite-rich sample exhibits higher porosity and permeability than those in smectite-rich sample. Both the static and dynamic linear compressibility of our samples generally decrease with confining pressure and display obvious anisotropy. The static compressibilities are larger than dynamic compressibility during loading; however, static compressibilities are not always larger than their equivalent dynamic compressibilities due to the elastically response of samples during early unloading stage. The damage parameters based on the existence of crack-like pores are used to explain the observed nonlinear elastic behavior, and the hysteresis in elastic properties can partly explain the difference in damage parameters between loading and unloading.",1,1,1
Large Scale,,"Li, Haitao; Hu, Xufei; Deng, Shaogui; Xu, Miaomiao",Fast multidimensional NMR inversion based on randomized singular value decomposition,Multidimensional NMR inversion; NMR data compression; Singular value decomposition; Randomized singular value decomposition; Computational efficiency,RESERVOIR,"Multidimensional NMR inversion has been proposed to improve the capacity of qualitative and quantitative fluids evaluation contained in porous media. However, one reason that restrict the development and application of downhole multidimensional NMR techniques is about the inversion efficiency. Fast and robust inversion algorithm can greatly reduce the downhole NMR logging cost. Taking into consideration the computational efficiency, it is critical to compress the NMR data. Singular value decomposition (SVD) has been recognized as an efficient algorithm for one dimensional (1D) NMR data compression. It is also applicable under certain circumstance for multidimensional NMR inversion, for example, when the NMR kernel matrices are separable. However, in the highly resolution inversion of two dimensional (2D) NMR and three dimensional (3D) NMR, large - scale of kernel matrices would be generated which greatly restrict the application of SVD. In such cases, SVD consumes considerable computational time and memory. We introduce an algorithm, named randomized singular value decomposition (RSVD), as an alternate of SVD. RSVD could produce results that are comparable to the ones produced by SVD. Furthermore, compared with SVD, it requires far less computation time and memory in the large-scale matrix factorization. Sometimes, it is possible to reduce more than 100 times of computation time and memory. Numerous of numerical simulations have been done to demonstrate the robustness and efficiency of multidimensional NMR inversion based on RSVD. We also analyze its anti-noise ability. Because of the highly computational efficiency of RSVD, it deserves widely application promotion in the multidimensional NMR inversion.",3,3,3
Large Scale,,Yin Yanshu; Hu Xun; Huang Jixin; Feng Wenjie; Wang Linxin; Duan Taizhong; Zhao Lei; Zhang Wenbiao,"A three-dimensional model of deep-water turbidity channel in Plutonio oilfield, Angola: From training image generation, optimization to multi-point geostatistical modelling",Multi-point geostatistics; Training image; Alluvsim; Optimization method; The Plutonio oilfield in Angola,SIMULATION; RESERVOIRS; DISTANCE,"The deep-water turbidity channel system in the Oligocene O73 sand layer in the Plutonio oilfield in Angola of west Africa has good oil and gas reservoir capability. As the well spacing is large due to operation cost, and the seismic resolution of the target layer is relatively low, identification of turbidity channel boundary was difficult. To establishes a fine model is a problem faced by the modelers. In this paper, a complete multi-point geostatistical modeling flowchart is presented for the construction of fine deep-water turbidity channel model. According to the investigation of seismic, well logging, drilling data and references in the study area, the genesis, reservoir scale, lithofacies type, morphological characteristics and evolution of the deep-water turbidity channel of the target layer were obtained. The improved Alluvsim algorithm was utilized to generate a set of adaptive deep-water turbidity channel training images with specified curvatures. Net-to-gross, variogram and a high-order statistics method based on the single data event were compared to evaluate and sort the training images. Then, the Snesim method was utilized to construct the models using the sorted compatible training images with a same set of parameters. At last, the quality of different models was compared based on the seismic attribute slices and a composite correlation coefficient optimization method based on seismic data. The results suggest that the improved Alluvsim algorithm can reproduce the channel morphology and stacking patterns better. Compared with the first-order and second-order statistics comparison method, the method using higher-order statistics of single data event taken spatial patterns into consideration and sorted training images better. The reservoir model was established using the optimal selected training image which has a high correlation with seismic attributes, and the model is more consistent with the characteristics of subsurface reservoirs. At the same time, this paper also provides a complete research program for the application of multi-point geostatistical modeling method which is from training image generation, optimal training image selection and multi-point geostatistics modeling to realizations selection for practical subsurface reservoir modelling.",3,3,2
Large Scale,,"Salimi, Hamidreza; Bruining, Johannes; Joekar-Niasar, Vahid",Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities,Percolation theory; Effective-medium approximation; Relative permeability; Pore-network theory; Primary and secondary drainage; Noncircular pore throats,2-PHASE FLOW; POROUS-MEDIA; PERCOLATION THEORY; WETTING LIQUID; LAMINAR-FLOW; IMBIBITION; CORNERS,"Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation-at which there is no infinite cluster of completely filled water pores-but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 x 301 x 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).",2,2,2
Large Scale,,"Liu, Ye; Guo, Chao; Cao, Jie; Cheng, Zhong; Ding, Xiangxiang; Lv, Lintao; Li, Fan; Gong, Meichen",A new resolution enhancement method for sandstone thin-section images using perceptual GAN,,,"The thin section is a sliver cut of rock sample and photographed by a microscope to help researchers investigate the mineral, structure, and geology details of a rock sample. For the purpose of photographing using the microsctope, only a small portion of the thin section can be visualized. The results, however, can hardly satisfy the requirement of a high resolution and larger scale visualization. The thin section is then trapped into a dilemma of contradiction between resolution and field of view. To solve this problem, we propose the Generative Adversarial Networks(GAN) based architectures representing the perceptual SR in this paper. Four perceptual super-resolution methods and two pixel-wise super-resolution methods are trained and tested for comparison with the dataset of sandstone thin-section. The perceptual GAN based super-resolution method is demonstrated to compensate for this limitation by enhancing the resolution of a large field of view image, which will provide a higher resolution detail recovery and larger field of view simultaneously. Based on the digital experiment analysis and comparison, thin-section perceptual loss with Residual-in-Residual Dense Block (RRDB) and Relativistic average GANs (RaGAN) shows a more realistic texture and evident edge for minerals and pores than other methods. With the new perceptual GAN based image enhancement method, the petroleum geologist can significantly improve the accuracy and reliability of all their thin section based research quality.",1,1,2
Large Scale,,"Azamifard, Arash; Ahmadi, Mohammad; Rashidi, Fariborz; Pourfard, Mohammadreza; Dabir, Bahram",QuiltEdge: Novel geostatistical workflow for heterogeneous reservoirs with an innovative combination of multi-variable image quilting and edge property concept to model heterogeneity and flow barriers,Edge property; Permeability texture; Geostatistic; Image quilting; Reservoir heterogeneity; Multiple point statistics,MULTIPLE-POINT GEOSTATISTICS; SEISMIC DATA; SIMULATION; CONDUCTIVITY; ENVIRONMENT; MEDIA; BASIN,"Detailed and accurate techniques which plays a vital role in providing more reliable predictions of reservoir performance are needed for spatial modeling of reservoirs with complex heterogeneity. Additional auxiliary parameters are usually defined to emulate the reservoir complex geometry and high degree of heterogeneity. Edge property concept can be used to model the effect of large-scale flow barriers or highly conductive channels such as sealing or conductive fault planes. In this study, the edge properties are overlaid on a grid of extremely heterogeneous permeability to examine the predictability of the reservoir model. Image quilting is applied to simultaneously build the cell-wise and edge properties of the reservoir model. Image quilting in this study utilizes a multivariable approach for simultaneous cell-wise and edge property modeling. Our proposed approach has been successfully examined on modified SPE 10 benchmark model, where the permeability spatial variation was modified and edge properties were added to represent the large-scale sealing or conductive faults. Several realizations were generated using image quilting technique based on training images. The geological patterns of permeability variation and the large scale barriers or conduits are conveyed properly from training images into reservoir model, even in this extremely heterogeneous studied reservoir. The difference of gas breakthrough time between inferred value of model realizations and the reference model is almost 12 days for minor modifications of famous SPE10 benchmark. Moreover, maximum oil production rate is predicted with more reliability as a consequence of proposed approach. The slope of oil production rate is identical to the reference case for the times after breakthrough. In addition, breakthrough time is estimated efficiently. With this approach (derived from permeability texture concept), the modelled properties become more and more realistic (geologically-consistent realizations) and the reservoir simulation outputs are become more reliable. This approach constrains the variability of geological properties and consequently the uncertainty with reservoir forecast is substantially reduced.",1,1,1
Large Scale,,"Naderi, Meysam; Khamehchi, Ehsan; Karimi, Behrooz",A rigorous approach to uncertain production optimization using a hybrid algorithm: Combination of a meta-heuristic and a Quasi-Newton method,Bat algorithm; BFGS; Cholesky decomposition; Fullfield integrated modeling; Net present value; Surface facilities,BAT; MODELS,"Integrated production optimization from a typical large scale hydrocarbon field is a very complicated task because of geological and economic uncertainty, existence of several linear and nonlinear constraints, and time consuming nature of reservoir simulation. Therefore, it is crucial to develop an efficient framework to perform full field optimization under uncertainty to maximize the returns. This paper, first tries to bridge the gap between reservoir and wells with the surface facilities such as pipelines, separators, injection manifolds. This integrated modeling maximizes the reliability of simulation output. Then, the Broyden-Fletcher-Goldfarb-Shanno (BFGS) coupled with meta-heuristic bat algorithm (BA) is applied for production optimization under geological and economic uncertainty. Cholesky decomposition is used to construct reservoir realizations. The bi-objective function is expected net-present-value (NPV) and its standard deviation. Results reveal that the expected NPV increases over the base case NPV between 2.35% and 9.27% for various time steps. Also, the uncertainty assessment shows that the most likely cumulative oil production (P5 s0o) could be improved over the current value at least by 2.23% under geological and economic uncertainty. Therefore, the optimization framework based on integrated modeling, and combining gradient-based with meta-heuristic algorithms could efficiently solve the full-field worldwide problem.",1,1,0
Clay Minerals,,"He, Jie; Wang, Hua; Tang, Jianrong; Shangguan, Yunfei; Yang, Xiangrong; Gong, Yin; Zhao, Rui; Zhou, Xuefeng","Evaluation of lacustrine mudstone top sealing capacity in the Lenghu-5 area, Qaidam Basin, Tibetan Plateau",Sealing capacity; Nitrogen adsorption; Mercury injection capillary pressure; Diagenesis; Overpressure; Brittleness index,PORE-SIZE DISTRIBUTION; FRACTAL CHARACTERISTICS; NORTHERN MARGIN; GAS-ADSORPTION; CAP-ROCK; MECHANICAL-PROPERTIES; THRESHOLD PRESSURE; REGIONAL TECTONICS; SURFACE-AREA; NATURAL-GAS,"Top seal capacity is one of the fundamental geological factors that must be considered during petroleum exploration. Based on thin section, low-pressure N-2 adsorption, bulk mineralogy, X-ray diffraction (XRD), mercury injection experiment and pressure data, the sealing capacity, lithofacies, petrophysics, diagenesis, capillary breakthrough pressure, overpressure, and brittleness index characteristics of a lacustrine mudstone top seal from the Lenghu-5 area, Qaidam Basin, Tibetan Plateau was investigated. The bulk rock composition of the top seal was dominated by clay minerals with carbonate cements and has a gross mudstone to sandy mudstone lithofacies. The isotherms from low-pressure nitrogen adsorption tests which presents as reversed S-shaped, belong to type B and the characteristics of hysteresis loops indicating the silt-like pores in the samples. The pores of the mudstone top seals are predominantly mesopores according to the N-2 adsorption and mercury injection experiment results. The cumulative mudstone thickness varies from 100 to 1400 m. The overpressured mudstone top seal in the Lenghu-5 area has three potential hydrocarbon preservation implications: overpressure cannot seal oil and gas, overpressure seals oil and gas directly, and overpressure seals oil and gas indirectly. The brittleness index (BI) values calculated by four methods based on the mineralogical composition of the mudstone top seals and the BI is higher at the top and bottom of the studied interval than in the middle mudstone layer. Based on the mud content, pore diameter, thickness, diagenetic stage, capillary breakthrough pressure, overpressure coefficient and brittleness index of the lacustrine mudstone, the top seal in the Lenghu-5 area is classified into four types: type I, II, III and IV, representing good to poor sealing capacities. The method for evaluation of the sealing capacity in this study can not only provide useful guidance for hydrocarbon exploration in Lenghu-5 area, Qaidam Basin, but also can be used in basins around the world by selecting the main influencing factors of sealing capacity in the basin.",3,3,6
Clay Minerals,,"Szczerba, Marek; McCarty, Douglas K.; Derkowski, Arkadiusz; Kowalik, Mariola",Molecular dynamics simulations of interactions of organic molecules found in oil with smectite: Influence of brine chemistry on oil recovery,Molecular dynamics; Oil shale; Porosity; Low salinity water flooding,SALINITY; CHARGE; WATER; SURFACES; POROSITY; ILLITE,"The study is aimed at employing molecular dynamics simulations to study the interactions between smectite and major oil constituents, along with the impact of different brine chemistry (type of cation in a solution) and ionic strength on the compound mobility in fine pores. Clay minerals with smectitic type of mineral outer surface (smectite, illite-smectite, illite) are major constituents in many unconventional oil and gas reservoirs. Therefore, smectite was used as a model compound to test interactions of oil compounds with mineral surfaces. Natural crude oil is a complex mixture, which - for the purpose of simulating an influence of surrounding fluid on its interactions with smectite surfaces - needs to be simplified. The following molecules were selected as organic model compounds: decane, quinolone, nonanoic acid, benzamide, and heptylamine. Various protonation states were considered. The first two sets of simulations showed remarkably different interactions of the selected organic molecules with the smectite surface. In the first one, three water/oil coverage models of the surface were considered. In the second one, two different pore sizes were taken into account: 3 nm and 5 nm. Significant differences were readably visible between polar and non-polar organic molecules. Also, the degree of protonation was found to be a crucial factor affecting the molecules' affinity to the mineral surface. The molecules that are well soluble in cyclohexane (here representing crude hydrocarbons phase) formed droplets in the water phase, whereas organic compounds miscible in water were concentrated at the water-monolayer film on the smectite surface. Neutral organic molecules in the interlayer influences hydration spheres of the cations and their distance from the surface, while organic cations tend to substitute for inorganic ones. The third set of calculations aimed at testing mobility of organic model compounds within a wide-open smectite interlayer space (acting as a narrow pore model), under one-dimensional pressure. The results show significant differences in the pressure that allows expulsion of organic molecules in different systems and different ions from a narrow slit. The mobility of oil compounds depends mainly on differences in the type of molecules and the size of effective hydration sphere of the cations adsorbed on a mineral surface, which is clearly visible in the simulations.",3,3,5
Clay Minerals,,"Siddiqui, Mohammed Abdul Qadeer; Ueda, Kenji; Komatsu, Hideo; Shimamoto, Tatsuo; Roshan, Hamid",Caveats of using fractal analysis for clay rich pore systems,Low permeability sandstone; Fractal; Reservoir simulation; Relative permeability; Clay content; Fractal dimension,UNSATURATED POROUS-MEDIA; TIGHT-GAS SANDSTONE; RELATIVE-PERMEABILITY; ORDOS BASIN; SPONTANEOUS IMBIBITION; APPARENT PERMEABILITY; MULTIPHASE FLOW; LONGMAXI SHALE; SICHUAN BASIN; MATRIX BLOCKS,"The conventional techniques cannot accurately predict the multiphase flow behaviour in clay rich low permeability rocks. This is particularly important in applications such as hydraulic fracturing where fluid uptake into low permeability rocks is of interest. This inability has given rise to the use of fractal-based estimation of petrophysical properties of such rocks. The concept of fractal theory revolves around the fractal dimension (D-f) representing the entire pore structure which is often estimated using the mercury-intrusion capillary pressure (MICP) data among other techniques. However, rocks containing high clay content often exhibit higher capillary pressures than those based on MICP. This is due to interaction of clay minerals with external fluids such as hydraulic fracturing fluid and subsequent transient change in pore structure. This also in turn causes the D-f value to vary thus leading to errors and uncertainties in fractal-estimated petrophysical properties of clay rich rocks. This transient aspect of clay rich rocks' pore network is not yet fully understood nor systematically investigated or incorporated in current fractal methods. We have therefore conducted a comprehensive study to narrate a cautionary tale on the use of MICP-based fractal methods in clay rich tight rocks analyses. We first highlighted the uncertainty in the MICP-based D-f value by comparing experimental and simulated oil recoveries from three clay-rich low permeability sandstone samples. We then developed, for the first time, a new set of physical equations to describe the transient pore network based on MICP-based fractal theory in order to partially overcome these uncertainties. We next compared the new theoretical model with experimental oil-water capillary pressure data. Through such rigorous analyses, it was concluded that MICP-based fractal theory relying on an unchanging pore structure is not accurate in its current form. Although our new approach can address the issue with the transient nature of clay rich pore network, there is yet immense space for improvement to overcome the limitations associated with fractal based petrophysical property estimation.",3,3,2
Clay Minerals,,"Shepidchenko, Taisiia; Zhang, Jinchuan; Tang, Xuan; Liu, Tong; Dong, Zhe; Zheng, Guo; Yang, Liu",Experimental study of the main controlling factors of desiccation crack formation from mud to shale,Desiccation cracks; Experiments; Crack formation; Controlling factors; Shale; Shale micro-cracks,SHRINKAGE CRACKS; CLAY; DYNAMICS; BEHAVIOR,"Numerous studies have been done on the formation mechanism and distribution law of desiccation cracks. However, the formation mechanism of micro-cracks in shale is still unclear. In this study, the most common clay minerals of shale (montmorillonite, illite, kaolinite) were experimentally studied to identify the main controlling factors of desiccation crack formation, and show the influence of these factors on crack geometry. To imitate the process of desiccation crack formation, a diagenetic crack imitator machine and a laboratory air drying were used. The results show that clay content, temperature, and thickness of the clay layer are the main factors that control the crack formation. Our samples suggest that crack width increases with increased montmorillonite content, and decreases with increased kaolinite and illite content. Temperatures of 100 degrees C and 230 degrees C induced further desiccation cracks in pure mineral solutions, while the mixed samples did not show any additional crack propagation. Crack width was shown to increase with layer thickness. In addition, 92% of all samples exhibited the three-armed pattern, where the angle distribution was between 90-100 and 170-180 degrees. We further propose that the water content in the dehydration process plays an important role in the formation of cracks, and the crack formation can be divided into four stages. The majority number of cracks occur at the initial and development stages, where the main mono-crack forms and starts to divide. The cracks intersect each other at the complex third stage. Ultimately, at the weak stage the last few random thin cracks might form. The formation of the first crack also depends on clay type and varies in time within an order from early to late: montmorillonite, kaolinite, illite. Based on the visual similarity between diagenetic micro-cracks in shale and mud desiccation cracks, as well as their mechanism of cracks formation, this study may provide a new perspective on the formation of the diagenetic micro-cracks in shale reservoirs and complements previous studies through virality of pure homogeneous and mixed clay samples.",3,4,1
Clay Minerals,,"Bai, Chenyang; Yu, Bingsong; Han, Shujun; Shen, Zhenhuan",Characterization of lithofacies in shale oil reservoirs of a lacustrine basin in eastern China: Implications for oil accumulation,Lithofacies (assemblages); Shale oil; Shahejie formation; Bohai bay basin,BOHAI BAY BASIN; MISSISSIPPIAN BARNETT SHALE; ORGANIC-RICH SHALE; FORT-WORTH BASIN; LOWER 3RD MEMBER; DONGYING DEPRESSION; SHAHEJIE FORMATION; JIYANG DEPRESSION; PORE STRUCTURE; ZHANHUA SAG,"The present research study was aimed to identifies the effect of the lithofacies (assemblages) on lacustrine shale oil accumulation, the shale oil layers of the Eocene Shahejie Formation in the Bohai Bay Basin, China, were characterized. The petrological analysis, included core, thin section and scanning electron microscopy observations and X-ray diffraction, indicated that the shale oil layers of the Shahejie Formation are dominated by carbonates, which are characterized by uniform or laminar distributions. The laminar carbonate components were formed through sedimentogenesis or diagenesis. Based on the genesis patterns and the petrology, five major lithofacies (assemblages) were identified in the formation: LF (lithofacies) 1 + 5 is characterized by thin lenticular laminae of crystalline carbonates with black shale; LF2+3 depicts laminae of micritic carbonates with massive lime mudstone; LF3 is a thick layer of massive lime mudstone; LF4 is massive claystone; and LF5 is black shale. The relationship between the lithofacies and the favorability for hosting shale oil reservoirs was investigated using microdrill sampling of the total organic content, reservoir quality analysis, and shale oil-bearing property. In LF1+5, the crystalline carbonates contain abundant interparticle pores, which can act as reservoir spaces, whereas the shale layers have a high potential for hydrocarbon generation. In addition, the hydrocarbon reserves can enter the crystalline carbonates of the assemblage after migrating a short distance. Consequently, LF1+5 is the most favorable assemblage for shale oil accumulation. In addition, LF4 and LF5 have high hydrocarbon generation potentials, and thus a relatively smaller amount of hydrocarbons could accumulate in these assemblages through clay mineral adsorption. Thus, LF4 and LF5 are also valuable sites for shale oil accumulation.",2,2,4
Clay Minerals,,"Klaja, Jolanta; Przelaskowska, Anna; Kulinowski, Piotr; Bujok, Petr; Klempa, Martin",Investigation of fine-grained siliciclastic rocks of different clay content using thermal methods,Microporous rocks; Simultaneous thermal analysis; Retort; Clay bound water; Organic matter,SURFACE-AREA; SMECTITE; WATER,"Thermal methods (simultaneous thermal analysis coupled with quadrupole mass spectrometry STA- QMS and retort) were applied to characterization of microporous rocks of different clay content. Two series of samples were investigated: highly diagenetic lower Paleozoic mudstones from Polish Lowlands and less altered Miocene and Paleocene rocks from the Carpathian Foredeep. The aim of the presented work was to differentiate between ""free"" and ""bound"" water in the pore space, to estimate the amount of fluids obtained by using retort method in regard to the distinction between free water, capillary water, clay bound water and organic matter fluids. In order to evaluate the retort results it was necessary to determine the temperatures at which a particular kind of water is released. The interpretation was based on the results of STA - QMS investigations together with XRD analysis of the mineral content, cation exchange capacity (CEC) and organic carbon content (TOC) measurements. In STA investigations the loss of mass connected with water release from clay minerals was observed in two temperature ranges: from 40 degrees C to 150 degrees C (adsorbed water) and from 440 degrees C to 620 degrees C (structural water). When analysing retort measurements, a considerable upward shift of adsorbed water release temperature can be observed. In case of Miocene and Paleocene rocks interpretation results of adsorbed water content indicate the temperature range from 150 to 450 degrees C, and in case of Lower Paleozoic rocks from 150 degrees C to 350 degrees C. Structural water is released at temperatures 500 degrees C -650 degrees C. A condensate connected with organic matter was observed within the temperature range 350-500 degrees C for Lower Paleozoic rock samples of high organic matter content (TOC>2). Taking into account the methodical discrepancies, a satisfactory compliance of results obtained by both methods in regard to the volume of clay bound water and condensate connected with organic matter was found. The results show that thermal methods can be successfully used for evaluation of saturations necessary for proper estimation of reservoir properties.",1,1,1
Clay Minerals,,"Gong, Fei; Di, Bangrang; Zeng, Lianbo; Wei, Jianxin; Ding, Pinbo",Static and dynamic linear compressibility of dry artificial and natural shales under confining pressure,shale gas; Clay minerals; Static properties; Dynamic properties; Anisotropy; Stress sensitivity,EXPERIMENTAL MECHANICAL COMPACTION; ELASTIC PROPERTIES; SEISMIC ANISOTROPY; YOUNGS MODULI; STRESS; CLAY; ROCKS; PERMEABILITY; SENSITIVITY; PARAMETERS,"Clays are among the main mineral components of shales and play a significant role in mechanical properties and anisotropy. However, it is difficult to quantify the impact of clay minerals on the mechanical properties of rocks because of the complex influence factors. In this study, we construct two artificial clay-rich shale samples containing kaolinite and smectite, respectively, and prepare one natural sample to study the static and dynamic responses of dry samples containing different types of clay during confining loading and unloading. The physical and mechanical properties of shales can be greatly affected by the type of clay minerals due to their structural difference. The kaolinite-rich sample exhibits higher porosity and permeability than those in smectite-rich sample. Both the static and dynamic linear compressibility of our samples generally decrease with confining pressure and display obvious anisotropy. The static compressibilities are larger than dynamic compressibility during loading; however, static compressibilities are not always larger than their equivalent dynamic compressibilities due to the elastically response of samples during early unloading stage. The damage parameters based on the existence of crack-like pores are used to explain the observed nonlinear elastic behavior, and the hysteresis in elastic properties can partly explain the difference in damage parameters between loading and unloading.",1,1,1
Elastic Parameter,,"Liu, Kouqi; Ostadhassan, Mehdi; Xu, Xiaomeng",A comparison study of the unloading behavior in shale samples in nanoindentation experiments using different models,Nanoindentation; Unloading curve; Shale samples; Model comparison,NANOSCALE MECHANICAL-PROPERTIES; NANO-INDENTATION METHODS; ELASTIC-MODULUS; HARDNESS; CONCRETE; STRESS; CURVE; BONE; LOAD,"Recently, nanoindentation has become an increasingly popular method for geomechanical analysis of rock samples in petroleum industry. Unloading curves of shale samples from the nanoindentation, which are considered as the pure elastic response, are used to determine the mechanical properties such as Young's modulus. In order to find a suitable model to characterize the unloading behavior of shale samples, in this study, we collected one Bakken Shale sample and performed nanoindentation tests on aliquots. First, the characteristics of the unloading curves were analyzed and then parameters such as: contact displacement and Young's modulus, based on two different prominent models (Oliver-Pharr model and Zeng-Chiu model) were calculated. Finally, values obtained from these two models were compared. The results showed that the unloading curves from the shale samples are nonlinear while Oliver-Pharr and Zeng-Chiu models both can be applied to represent the unloading curves. The mean Young's modulus from Oliver-Pharr model is around 1.2 times the value from Zeng-Chiu model. Using the Mori-Tanaka method, the upscaled Young's modulus value (32.14 GPa) from the Oliver-Pharr model is slight larger than the value from Zeng-Chiu model (28.70 GPa). In conclusion, the Oliver-Pharr model and Zeng-Chiu model can be both applied to study the unloading behavior of the nanoindentation curves.",3,3,8
Elastic Parameter,,"Jiang, Jiwei; Li, Jun; Liu, Gonghui; Lian, Wei; Xi, Yan; Yang, Hongwei; Li, Wai",Numerical simulation investigation on fracture debonding failure of cement plug/casing interface in abandoned wells,Abandoned wells; Cement plug/casing interface; Wellbore integrity; Fracture debonding height; Cohesive zone method,HYDRAULIC FRACTURE; FINITE-ELEMENT; COUPLED FLOW; WELLBORE; PLUG; PROPAGATION; INTEGRITY; PRESSURE; LEAKAGE; XFEM,"The fracture debonding failure of cement plug/casing interface caused by the migration of underground fluid with pressure accumulation imposed serious challenges to wellbore integrity of abandoned wells. This paper presents an investigation with a view of quantifying the relationships between the fracture debonding height and the migration time of underground fluid. A new 3D numerical model of cement plug/casing/cement sheath/formation system based on the cohesive zone method, which was validated by microannulus experiment, was developed to simulate the fracture debonding process. And then the relationships between fracture debonding height and propagation pressure was studied. Additionally, the influence of horizontal in-situ stress, cement plug mechanical parameters, and interface properties on the fracture debonding height and development geometry were also analyzed. The results of research indicated that the minimum horizontal in-situ stress played a decisive role in controlling the fracture propagation of cement/casing interface. Debonding fracture propagated along the whole circumference of the interface with the same height for the case that the horizontal in-situ stress was uniform, while propagated along a certain circumference angle of the interface with the maximum height in the direction of maximum horizontal principal stress for the case that the horizontal in-situ stress was non-uniform. The results of numerical analysis showed that lower elastic modulus and Poisson's ratio of cement plug, higher cement plug permeability, and larger critical normal strength and critical shear strength were beneficial to decrease the fracture debonding height and reduce the risk of debonding failure of the cement plug/casing interface. Finally, some effective measures to maintain the sealing integrity of abandoned wells were proposed.",3,3,5
Elastic Parameter,,"Xu, Miaomiao; Yin, Xingyao; Zong, Zhaoyun; Li, Haitao","Rock-physics model of volcanic rocks, an example from Junggar Basin of China",Rock-physics model; Volcanic rock; Mineral content; Pore structure; Elastic modulus,GAS-FIELD; X DEPRESSION; RESERVOIR; EXPLORATION; GROUNDWATER; VELOCITY; POROSITY; OIL,"A variety of resources such as geothermal, mineral, groundwater, oil and gas, etc., are explored in the volcanic rock reservoirs, which has aroused widespread focus in the world. The researches on the relationship between macroscopic physical properties and microstructures are conducive to the resource exploration and development, in which the rock-physics model is an important and valid media. Taking the Junggar Basin in Western China as an example, a novel rock-physics model for volcanic rocks is proposed. The mineral contents are initially estimated with the proposed evolutionary complex algorithm based on a novel volume interpretation model suitable for the diversity of the minerals of different lithology. The simultaneous inversion of the porosity and aspect ratio of different kinds of pores constrained by the P-wave and S-wave velocities is further implemented and then the heterogeneity of the rock can be carved. In addition, to satisfy the hypothesis of the fluid saturation model, the disconnected pores including bound water and invalid pass are introduced by the acoustic porosity formula as a part of the matrix. Furthermore, due to the approximate aligned cracks, the volcanic rock reservoirs can be simplified as transversely isotropic media with horizontal symmetry axis. The Eshelby-Cheng model and BrownKorringa theory are further utilized for the estimation of the elastic modulus of the anisotropic dry rock and saturated rock, respectively. The example demonstrates that the proposed rock-physics model is able to predict the elastic parameters of different lithology of volcanic rocks and the modelling method can give some enlightenment for the exploration of other volcanic resources.",2,2,6
Elastic Parameter,,"Wang, Y.; Liu, D. Q.; Zhao, Z. H.; Wang, H. J.",Investigation on the effect of confining pressure on the geomechanical and ultrasonic properties of black shale using ultrasonic transmission and post-test CT visualization,Velocity anisotropy; Confining pressure; CT imaging; Crack pattern,LONGMAXI FORMATION SHALE; ELASTIC-WAVE VELOCITIES; X-RAY CT; MECHANICAL-PROPERTIES; ANISOTROPY; DEFORMATION; BEHAVIOR; ROCKS,"Knowledge of the influence of confining pressure on the geomechanical and ultrasonic characteristics is essential to exploration and development of gas shale reservoirs. In contrast to the extensive studies on the physical and mechanical properties of shale, the velocities of P-wave and S-wave during continuous deformation are not thoroughly understood. In this study, a suite of triaxial compression tests were done on the shale samples collected from the Sichuan Basin and were cored with horizontal bedding structure under various confining pressure. In-situ ultrasonic transmission technique combined with post-test CT imaging analysis was used to reveal the velocity-pressure characteristics and crack patterns. The experimental results indicate that strength, elastic parameter, P- and S-wave velocities, and failure pattern are influenced by the applied confining pressure. At the pre-peak stage on the stress-strain curve, the P-wave velocity increases with elevated stress; however, the S-wave velocity first increases and then decreases, which is related to the crack damage evolution. The mesostructural changes during deformation are considered to be the main factor controlling the pressure sensitivity of the velocities. Under compression, the relatively soft pores, micro-cracks and minerals were compacted gradually, and it is the primary reason leading to the increment of velocities. Based on the CT scanning technique, the crack pattern was obtained after triaxial testing, the crack pattern analysis suggests that the fractal dimension of fracture distribution almost increases with confining pressure. What is more, the stimulated fracture density increases with increasing confining pressure. It suggests that, for the Longmaxi black shale, a high confining pressure condition is beneficial to form a complex fracture network.",2,2,4
Elastic Parameter,,"Wang, Yanbin; Zeng, Jing; Gao, Deli",Assessment on the sustained casing pressure (SCP) with consideration of the infiltration of formation fluid into the annulus of deepwater wells,Deepwater wells; Subsea wellhead; Sustained casing pressure; Formation fluid infiltration; SCP relief tool,,"The sustained casing pressure (SCP) is a common problem in deepwater wells, which is caused by the coupling effects of temperature and pressure and brings about significant challenges to the wellbore integrity. In this paper, the analysis model of temperature distribution along the wellbore has been presented firstly based on the casing program and the basic principle of heat transfer, which is adopted as the boundary condition and initial condition of the SCP model. In this model, the annular spaces of the oil tubing-production casing, production casing-intermediate casing, intermediate casing-surface casing are named as annulus A, annulus B and annulus C, respectively. Secondly, the mechanical model and governing equation of the SCP have been established based on the thermal elastic mechanics with consideration of the formation fluid infiltration into the annulus. Then, the SCP and its maximum allowable value have been figured out by solving the governing equation through the iteration calculation approach. At last, a SCP relief tool has been proposed to improve the stress state of casing string and its performance has been evaluated. On this basis, the parameter sensitivity analysis has been carried out, where the influence of yield, production time, the comprehensive permeability of cement sheath, physical parameters of fluid in the annuli and the formation fluid infiltration on the SCP are discussed in detail. Analysis results show that the ranking order of temperature variation is annulus A, annulus B, annulus C, while the ranking order of the SCP is annulus B, annulus C, and annulus A. The SCP at wellhead increases approximately linearly with the yield and the thermal expansion coefficient of the fluid in annulus. At the initial stage of production, the well temperature and SCP gradually increase with the time, and then remain constant with the production going on. However, the time of the SCP reaching stable decreases with the comprehensive permeability of the cement sheath. In addition, the maximum allowable value of the SCP is mainly restricted by the collapse resistance of the production casing, which occurs under the circumstance of annulus A is tunneled. The relief tool can significantly reduce the SCP in annulus B and C with about 30% of the reduction rate, which plays a positive role in improving the mechanical state of the casing. This paper has reference significance for prediction of the SCP and evaluation of the well integrity of deepwater wells.",1,1,3
Elastic Parameter,,"Chai, Yibo; Lu, Jun; Chen, Benchi; Zhang, Tieqiang",Elastic parameter inversion of a sand body based on the exact reflection coefficient,AVA inversion; Jacobian matrix; Oil-gas exploration; Elastic parameter; Gas-bearing sandstone,AVO INVERSION; LEAST-SQUARES; SEISMIC DATA; WAVE; APPROXIMATIONS; ALGORITHM; EQUATIONS; GAS; PP,"Prestack seismic inversion is an important technology for oil and gas exploration that can provide accurate lithology and pore fluid information on underground media. Prestack inversion is theoretically based on the Zoeppritz equations, which establish the relationship between the seismic reflection coefficients of different offsets and elastic parameter contrasts between the interface of two lithologies. However, these are fourth-order matrix equations with a complex form and are difficult to be directly applied to inversion. Approximate analytical solutions have been used to establish a linear relationship between the seismic reflection coefficients and elastic parameters. And the approximations are based on the assumptions of a small angle and weak contrast, they cannot be applied to layers of high contrast, such as gas-bearing sandstones and coal seams. In this paper, we present an accurate prestack seismic inversion method that can be applied to a wider range of geological models. First, we derive the partial derivatives of the exact reflection coefficients of PP waves based on the Zoeppritz equations with respect to the elastic parameters and establish the exact Jacobian and Hessian matrices. Then, we use the least-squares algorithm to construct objective functions for the simultaneous inversion of three elastic parameters: The P-wave velocity, S-wave velocity, and density. Examples show that our inversion method is more accurate for strata with strong reflection interfaces than the approximate prestack inversion methods and stable under noisy conditions. The inversion method was applied in channel sand depositions of the Lower Permian Shanxi and Shihezi Formation of the Ordos Basin, and it was efficient to identify the gas-bearing sand layers and determine the range of potentially favorable areas.",1,1,1
Elastic Parameter,,"Gong, Fei; Di, Bangrang; Zeng, Lianbo; Wei, Jianxin; Ding, Pinbo",Static and dynamic linear compressibility of dry artificial and natural shales under confining pressure,shale gas; Clay minerals; Static properties; Dynamic properties; Anisotropy; Stress sensitivity,EXPERIMENTAL MECHANICAL COMPACTION; ELASTIC PROPERTIES; SEISMIC ANISOTROPY; YOUNGS MODULI; STRESS; CLAY; ROCKS; PERMEABILITY; SENSITIVITY; PARAMETERS,"Clays are among the main mineral components of shales and play a significant role in mechanical properties and anisotropy. However, it is difficult to quantify the impact of clay minerals on the mechanical properties of rocks because of the complex influence factors. In this study, we construct two artificial clay-rich shale samples containing kaolinite and smectite, respectively, and prepare one natural sample to study the static and dynamic responses of dry samples containing different types of clay during confining loading and unloading. The physical and mechanical properties of shales can be greatly affected by the type of clay minerals due to their structural difference. The kaolinite-rich sample exhibits higher porosity and permeability than those in smectite-rich sample. Both the static and dynamic linear compressibility of our samples generally decrease with confining pressure and display obvious anisotropy. The static compressibilities are larger than dynamic compressibility during loading; however, static compressibilities are not always larger than their equivalent dynamic compressibilities due to the elastically response of samples during early unloading stage. The damage parameters based on the existence of crack-like pores are used to explain the observed nonlinear elastic behavior, and the hysteresis in elastic properties can partly explain the difference in damage parameters between loading and unloading.",1,1,1
Coal Seam,,"Jiang, Bingyou; Zhao, Yang; Lin, Baiquan; Liu, Ting",Effect of faults on the pore structure of coal and its resultant change on gas emission,Pore structure; Desorption hysteresis; Fault; Multifractal; Coal and gas outburst,MULTIFRACTAL ANALYSIS; FRACTAL CHARACTERISTICS; ADSORPTION-PORES; DEFORMED COALS; METHANE; EVOLUTION; NITROGEN; OUTBURSTS; SEEPAGE,"Faults are one of the important factors influencing coal and gas outburst in outburst coal seams. In this paper, 3# and 8# coal seams in Xinjing Coal Mine were taken as the research objects in the hope of revealing the mechanism of how faults affect coal seam. The pore structure and its resultant change on gas emission of coal samples at different distances from the faults were studied by means of scanning electron microscope, nuclear magnetic resonance and adsorption/desorption experiments. The results show that the fault significantly influences the pore structure. The coal sample closer to the fault has a greater number of well-developed macropores and fractures as well as better connectivity between pores and fractures. Besides, compared with 8# coal seam, 3# coal seam which is more notably impacted by the fault possesses a more developed pore structure at the micron scale. As the distance from the fault increases, the gas adsorption volume declines while the desorption hysteresis coefficient grows on the whole. The coal sample closer to the fault adsorbs a larger volume of gas and meanwhile desorbs gas more easily, so it is more prone to coal and gas outburst. The initial velocity of gas emission falls gradually as the distance from the fault increases. The desorption hysteresis coefficient generally drops with the rise of the initial velocity of gas emission. Judged by the influence scope of the fault, 3# coal seam possesses a much higher outburst risk than 8# coal seam. The research results reveal the mechanism of how faults affect coal pore structure and gas sorption characteristics, which can provide a basis for the prevention and control of gas dynamic disasters in fault-containing coal seams.",3,3,7
Coal Seam,,"Niu, Yue; Song, Xiaoyan; Li, Zhonghui; Wang, Enyuan; Liu, Quanlin; Zhang, Xin; Cai, Guannan; Zhang, Qiming",Experimental study and field verification of stability monitoring of gas drainage borehole in mining coal seam,Gas drainage; Borehole stability; Destructive degree; Relative pressure; Coal seam,RELAXATION ZONE; ROCK MASS; METHANE; EVOLUTION; STRAIN; MODEL; MICROSTRUCTURE; INSTABILITIES; VENTILATION; EMISSIONS,"Gas drainage through boreholes can effectively reduce gas disasters and significantly promote the efficient drainage and clean utilization of gas during mining activities. Gas drainage boreholes will deform and fail as the mining proceeds, but there is a lack of effective measures for real-time monitoring of borehole stability currently. Concerning this problem, a new test system was discussed to measure borehole deformation in this study. Further, an index for calculating the destructive degree (DD) of boreholes based on the residual area was proposed, and a coupling relationship between the relative pressure (RP) of sensors and DD was established as well. Moreover, the calculation model of DD was modified to determine the determination conditions of borehole failure. Finally, effectiveness of the test system was verified in a mining coal seam. The results show that DD first surges with time and then tends to stabilize, as verified by gas drainage quantity. Spatially, DD first rises and then declines with increasing depth, which agrees with the coal stress distribution and the simulation results. The study can enlighten the deformation measurement and failure determination of gas drainage boreholes.",3,3,7
Coal Seam,,"Ossai, Chinedu, I",Modified spatio-temporal neural networks for failure risk prognosis and status forecasting of permanent downhole pressure gauge,Anomaly detection; Fisher's discriminant function; Multi-layer perceptron artificial neural network; Operational risk; Permanent downhole pressure gauge; Spatiotemporal graph,MULTILAYER PERCEPTRON; MACHINES; GMM,"Permanent Downhole Pressure Gauges (PDPGs) are sensors installed in the wellbores to measure the downhole pressure. Due to the abrupt changes in pressure, the PDPG can fail, and this will result in difficulties in production optimization. To manage the operational risk levels (negligible, low, mild, high and severe), a signal processing technique that utilizes anomaly detection, Fisher's Discriminant Function (FDF) and Mean Deviant Function (MDF) is developed. The operational risk levels were established with the Bayesian Gaussian Mixed Model (BGMM) and a Spatiotemporal Graphical Model (STGM) helped to compute the risks transition probabilities at different time intervals. After balancing the resulting input-output data with Synthetic Minority Oversampling Technique (SMOTE) and using Mull-layer Perceptron Artificial Neural Network (MLP-ANN) classifier, an online PDPG monitoring strategy was developed. The model was tested with Coal Seam Gas (CSG) PDPG data from thirty-eight wells and the results showed an average accuracy of -93%. This result indicates the potency of the model for managing the risk profile of PDPGs and other telemetric equipment used for critical missions in the oil and gas, space, medical and defence industries.",3,3,2
Coal Seam,,"Guo, Xiao; Wang, Zhiming; Zeng, Quanshu; Liu, Liangqian",Gas crossflow between coal and sandstone with fused interface: Experiments and modeling,Multilayered coal seams; Sandstone; Crossflow; Experiment; Model,PRESSURE-TRANSIENT ANALYSIS; METHANE; BASIN; PERMEABILITY; BLOCK; WATER,"Multi-layered CBM (Coalbed Methane) reservoirs contain dozens (20-40) of thin coal seams (0.5 m-10 m) and sandstone seams and a commingled production strategy is preferred. Gas crossflow between coal seams and sandstone seams contributes much to the commingled gas production. Our study is focused on gas crossflow between coal and sandstone with fused interface. The experimental apparatus designed for this study consisted of a sandstone sample holder and a coal sample holder, where nitrogen was injected at a constant pressure difference between the sandstone and coal. The gas crossflow rate between coal and sandstone was monitored. Factors including confining stress, effective horizontal stress, axial stress and the permeability of sandstone influencing the gas crossflow were analyzed based on the experimental results. Based on the interface characteristics, a crossflow model for fused interface between coal and sandstone was proposed and gas crossflow resistant coefficients were defined. The experimental results show that gas crossflow rates decreased dramatically with the increment of confining stresses loading on the coal sample and increased linearly with the increment of average pore pressure on the condition of constant effective horizontal stresses. Compared with stresses loading on sandstone samples, the axial stresses and confining stresses loading on coal make larger influence on the gas crossflow rates. With the increment of the sandstone permeability, gas crossflow rates become less sensitive to the change of sandstone permeability. The comparison between model results and experimental results demonstrate that the proposed mathematical models can effectively predict gas crossflow between coal and sandstone with fused interface.",3,3,1
Coal Seam,,"Chai, Yibo; Lu, Jun; Chen, Benchi; Zhang, Tieqiang",Elastic parameter inversion of a sand body based on the exact reflection coefficient,AVA inversion; Jacobian matrix; Oil-gas exploration; Elastic parameter; Gas-bearing sandstone,AVO INVERSION; LEAST-SQUARES; SEISMIC DATA; WAVE; APPROXIMATIONS; ALGORITHM; EQUATIONS; GAS; PP,"Prestack seismic inversion is an important technology for oil and gas exploration that can provide accurate lithology and pore fluid information on underground media. Prestack inversion is theoretically based on the Zoeppritz equations, which establish the relationship between the seismic reflection coefficients of different offsets and elastic parameter contrasts between the interface of two lithologies. However, these are fourth-order matrix equations with a complex form and are difficult to be directly applied to inversion. Approximate analytical solutions have been used to establish a linear relationship between the seismic reflection coefficients and elastic parameters. And the approximations are based on the assumptions of a small angle and weak contrast, they cannot be applied to layers of high contrast, such as gas-bearing sandstones and coal seams. In this paper, we present an accurate prestack seismic inversion method that can be applied to a wider range of geological models. First, we derive the partial derivatives of the exact reflection coefficients of PP waves based on the Zoeppritz equations with respect to the elastic parameters and establish the exact Jacobian and Hessian matrices. Then, we use the least-squares algorithm to construct objective functions for the simultaneous inversion of three elastic parameters: The P-wave velocity, S-wave velocity, and density. Examples show that our inversion method is more accurate for strata with strong reflection interfaces than the approximate prestack inversion methods and stable under noisy conditions. The inversion method was applied in channel sand depositions of the Lower Permian Shanxi and Shihezi Formation of the Ordos Basin, and it was efficient to identify the gas-bearing sand layers and determine the range of potentially favorable areas.",1,1,1
Buckling,,"Li, Wei; Huang, Genlu; Yu, Fan; Ni, Hongjian; Jiang, Wu; Zhang, Xiaobing",Modeling and numerical study on drillstring lateral vibration for air drilling in highly-deviated wells,Drillstring dynamics; Lateral vibration; Finite element model; Bottom hole assembly; Air drilling,DYNAMIC-MODEL; STICK-SLIP; FRICTION; MOTIONS,"The combination of directional well technique and air drilling has been regarded as an effective technique for drilling engineering. Given the currently inadequate understanding of drillstring lateral vibration for air drilling in highly-deviated wells, the modeling and numerical study is conducted. Therefore, a new finite element (FE) model with full-dimensional beam elements was built in the paper, which combined the advantage of FE method and beam-column theory to avoid complicated derivation and solution. The model also included contact model, static-kinetic friction model, mass eccentricity, and Rayleigh damping. To verify the stability and applicability of the model, a numerical simulation was conducted to study the effects of rotation speed, weight on bit (WOB), well inclination, friction coefficient, and stabilizer (STB) on lateral vibration for air drilling in highly-deviated wells. Besides, the effects of drilling mud on lateral vibration were discussed. The results show that the FE model can be used effectively to analyze drillstring lateral vibration. Meanwhile, rotation speed and friction coefficient have promoting effects on lateral vibration, full-packed STB has a suppressing effect, while WOB has a relatively small effect. Moreover, well inclination has a suppressing effect on lateral displacement, and a promoting effect on lateral acceleration. Compared with mud drilling, the lateral displacement and lateral acceleration of air drilling are obviously large. When air drilling is used in highly-deviated wells, a smaller rotation speed is proposed as long as it satisfies the ROP demand, and a slightly larger WOB is proposed as long as it does not lead to drillstring buckling, and full-packed STBs are proposed to limit lateral vibration. In addition, the formations with large friction coefficients can make lateral vibration more violent, and the drilling process needs more attention. Furthermore, increasing the lubricity of the circulating medium is recommended to reduce lateral vibration. The study in this paper can help to further develop drillstring dynamics, understand lateral vibration characteristics, and select suitable parameters for air drilling in highly-deviated wells.",3,3,5
Buckling,,"Zhu, Zhao Liang; Hu, Gang; Fu, Bi Wei",Buckling behavior and axial load transfer assessment of coiled tubing with initial curvature in constant-curvature wellbores,Buckling behavior; Coiled tubing; Axial force; Initial curvature; Constant-curvature wells,FRICTION,"This paper presents a mechanical equilibrium equation for coiled tubing (CT) with an initial curvature for use in a constant-curvature wellbore, based on the beam-column method. The critical sinusoidal and helical buckling loads, the rules for the contact between the CT and wellbore, and the transmission of the axial force along the length are determined. The proposed model shows that the initial curvature of the CT has a greater influence on the critical sinusoidal buckling than on the helical buckling. In addition, both critical buckling loads increase with the initial angular radian value, and the buckling loads in constant-curvature wellbores are greater than those in vertical wells. The critical buckling loads decrease exponentially with an increase in the borehole curvature radius, which changes slightly when the curvature radius of the well increases to a certain extent. When the CT is undergoing sinusoidal buckling, the contact force between the CT and well is sensitive to the initial angular radian value, axial force, and curvature radius of the well. However, when the CT experiences helical buckling, the contact force is primarily affected by the axial force. When the CT has a small amount of residual buckling, its buckled shape is similar to that of a straight pipe. Thus, the distribution and magnitude of the contact force are similar. Meanwhile, the transmission of an axial force along the length is affected more significantly by the friction coefficient and outer diameter of the CT than by the initial angular radian value and curvature radius of the well.",3,3,3
Buckling,,"Mohammed, Auwalu, I; Oyeneyin, Babs; Bartlett, Mark; Njuguna, James",Prediction of casing critical buckling during shale gas hydraulic fracturing,Casing buckling; Rock slippage; Fracturing; In-situ stresses; Shale gas wells,DEFORMATION; FIELD; SIMULATION; FAILURE; BRITTLE; STRESS; DAMAGE; WELL; SLIP,"Casing deformation during volume fracturing in shale gas horizontal wells is caused by both existing and induced stresses. These stresses jointly alter and compound the stress field around the casing leading to inefficient well stimulation as planned, lack of access into the well for recompletion, future workovers and present imminent danger of well integrity. Using two simulation scenarios, casing structural integrity was investigated in both radial and axial configurations under the mechanics of a combine system - casing, cement and formation rock. Results obtained show that time dependent rock slippage - creep during stimulation lead to an increase transverse displacement and corresponding stresses on the casing. In addition, the effect of combined loading results in significant increase in both displacements and stresses that can cause radial and axial permanent failure of the casing. This explains the lack of access into the casing during multi-stage hydraulic fracturing and future well intervention and recompletions and increased current understating of the downhole dynamics and casing structural integrity during volume fracturing. This new understanding is a major breakthrough in establishing casing health status during shale gas well stimulation.",2,2,2
Buckling,,"Zhang, Jiantao; Yin, Guofu; Li, Yufei; Zhang, Lin",Buckling configurations of tubular strings constrained in three-dimensional curved wellbores,Tubular string; Buckling; Contact force; Bending moment; Wellbore,THIN ROD; CONNECTORS; CURVATURE; FORCE,"A new model depicting the buckling configuration of a tubular string in a three-dimensional curved wellbore is proposed. During modeling, the toolface angle is considered, and the sinusoidal buckling and helical buckling of the tubular string are considered on the basis of alignment with either the lower curved side or the outer curved side of the wellbore. After modeling, the energy method is used to solve the model, and the critical buckling load, which is related to the relationship between the buckling configuration and the axial load, can be obtained. The critical buckling loads calculated using the model presented in this paper are consistent with the measured data from published experiments and the trends of the He and Kyllingstad model. The results of the new model also show that with an increasing wellbore curvature, the influence of the toolface angle on the critical buckling load and the characteristic parameters of the buckling configuration (wavelength, amplitude, and pitch) decreases. Based on the expressions for the quantitative relationships between these characteristic parameters and the axial load, procedures for calculating the contact force and the bending moment are given. The results for the contact force show that the calculated values from the Johancsik et al. model and the Mitchell model are the average values calculated using the procedures presented in this paper for tubular strings under sinusoidal buckling and helical buckling, respectively. The calculation results show that the influence of the toolface angle on the bending moment of a tubular string under helical buckling is less than that under sinusoidal buckling. By using this model, not only can the critical buckling loads, contact forces and bending moments of tubular strings in three-dimensional curved wellbores be calculated, but the trends of these calculated values with the buckling configuration can also be identified to guide the selection of the control parameters for tubular strings in the field.",1,1,1
Liquid Holdup,,"Kim, Tea-Woo; Al-Safran, Eissa; Pereyra, Eduardo; Sarica, Cem",Experimental study using advanced diagnostics to investigate slug aeration and bubble behavior in high liquid viscosity horizontal slug flow,,PARTICLE IMAGE VELOCIMETRY; UNIFIED MECHANISTIC MODEL; GAS BUBBLE; HOLDUP; VELOCITY; SHAPES; MOTION; AIR; FRACTION,,3,3,0
Liquid Holdup,,"Santim, C. G. S.; Fulchignoni, L. P.; Rosa, E. S.; Gaspari, E. F.",Transient multiphase flow modeling and validation in a real production system with high CO2 content using the drift-flux model,Three-phase flow; Drift-flux model; Non-isothermal model; Transient; Production system,FRICTIONAL PRESSURE-DROP; GAS-LIQUID FLOW; 2-PHASE FLOW; SLUG FLOW; LONG BUBBLES; TRANSITIONS; VISCOSITY; VELOCITY; MOTION,"This study presents a transient multiphase flow simulator based on the non-isothermal Drift-Flux model that aims to reproduce oil and gas production systems. The mathematical model consists of three mass conservation equations, one equation for the momentum mixture and one equation to reproduce the energy conservation of the gas-liquid-liquid mixture, assuming mass transfer between the produced liquid and gas phases and neglecting the slip between the liquid phases. The solver utilizes the finite volume method with a semi-implicit approach making use of the upwind first order scheme with staggered grid. Liquid holdup and liquid amount between the liquid phases are evaluated explicitly whereas the coupling between velocities and pressure fields is implicit by building a global matrix. The temperature field is obtained in an uncoupled way after the volumetric fraction, mass flow rates and pressure calculus. For the sake of validation of the solver, the simulated profiles of pressure, temperature and liquid holdup along the production line are compared with those given by the reference benchmark for multiphase flow simulation in the Oil & Gas industry, OLGA (R) (OiL and GAs simulator), and real field data in the steady-state regime of an offshore oil producer well with high CO2 content. The influence of input parameters on the simulation results is investigated. A sensitivity analysis is performed on the fluid modeling, considering the Black-Oil model making use of two different R-s correlations and the compositional approach. The influence of drift parameters on the numerical solutions is also verified. Liquid holdup, pressure and temperature trends are analyzed upstream and downstream of the master valve as well as in the well bottom and on the separator regions. Finally, important production procedures such as well shutdown and start-up are analyzed. The main motivation is to verify the solver capability to reproduce the multiphase flow behavior during the oil and gas production, especially for a fluid with high GOR and high amount of CO2.",2,2,0
Liquid Holdup,,"Kim, Tea-Woo; Kim, Sungil; Lim, Jung-Tek",Modeling and prediction of slug characteristics utilizing data-driven machine-learning methodology,Liquid-gas two-phase slug flow; Horizontal and near-horizontal slug flow; Slug flow parameters; Slug liquid holdup; Translational velocity; Slug length,LIQUID SLUG; 2-PHASE FLOW; HOLDUP; FRACTION,"Slug liquid holdup, translational velocity, and slug length are representative slug characteristics. The precise prediction of these parameters is essential for the accurate calculation of the average liquid holdup and pressure gradient in pipes. Nevertheless, existing correlations have mainly been developed by an empirical approach. Each correlation can only be applied to a restricted fluid property and geometrical condition, preventing people from selecting a suitable one without professional knowledge. In this study, slug characteristics were predicted by several machine learning methodologies with 2590 experimental data to overcome the limitation of selecting the proper model or correlation. The experimental dataset includes -10 degrees <= theta (pipe inclination angle) <= 10 degrees, 0.0258 m <= I.D. (pipe inner diameter) <= 0.0780 m, 0.01 m/s <= vSL (superficial liquid velocity) <= 3.4 m/s, 0.03 m/s <= vSg (superficial gas velocity) <= 20 m/s, 769 kg/m(3) <= rho(L) <= 998 kg/m(3), 1.12 kg/m(3) <= rho(G) <= 7.36 kg/m(3), 0.001 Pa s <= mu(L) <= 4.65 Pa s, and 6 <= Re-M (mixture Reynolds number) <= 863,920. The existing dataset has been preprocessed to pursue better machine learning performance. The random forest results reveal a better training performance and prediction than that of a deep neural network and present a competitive prediction compared with the existing correlations, indicating a great potential of utilizing the data-driven machine learning methodology.",2,2,0
Liquid Holdup,,"Liu, Yonghui; Luo, Chengcheng; Zhang, Liehui; Wu, Pengbo; Zhao, Yulong; Wang, Lang",Experimental investigation of the surfactant effect on liquid removal in vertical pipes,Surfactant; Film reversal; Liquid holdup; Foaming; Lifting efficiency,FLOW; PREDICTION,"In order to investigate the effect of surfactant on liquid removal in vertical pipes, an experimental study has been conducted in a 50 mm inner diameter vertical pipe. The superficial gas velocities ranged from 0.06 m/s to 27 m/s to include bubble, slug, churn, and annular flow. The superficial liquid velocities were 0.01 m/s and 0.1 m/s. The surfactant concentration was 2000 ppm. In the presence of surfactant, foaming postpones film reversal dramatically and makes the flow much more regular at low superficial gas velocities, due to the decrease of film density and increase of interfacial-friction factor. However, the slug-churn and bubble-slug transitions are barely influenced with surfactant injecting. At high superficial gas velocities, adding surfactant in the air-water flow creates an increased frictional pressure gradient, leading to an increase in the total pressure gradient. When the superficial gas velocity decreases to some point, there is a limit where the pressure gradients in the flow with and without surfactant are equal. A higher superficial liquid velocity leads to a smaller value for this equality. Thus, proper timing for surfactant injection is of significant importance in gas wells. As the superficial gas velocity decreases, the lifting efficiency of the surfactant increases at first and subsequently decreases dramatically, due to the interaction effect of liquid holdup and hydrodynamic agitation. An optimal area in lifting efficient is in the churn flow near the slug-churn transition. Furthermore, a decrease in lifting efficiency is observed with the increase of superficial liquid velocity and thus we infer that the transition to dispersed bubble flow is the limit for superficial liquid velocity to prevent foaming.",1,1,2
Oil-well Cement,,"Xu, Bingwei; Zhou, Shouwei; He, Faqi; Wang, Fubin; Guo, Jianchu",Using particle image velocimetry to evaluate the displacement efficiency of drilling mud in horizontal well cementing,Cementing; Particle image velocimetry; Eccentricity; Displacement efficiency; Horizontal wells,ANNULAR DISPLACEMENTS; COMPLETION FLUIDS; OIL-WELL; MODEL; FLOW,"For a horizontal well cementing, successful displacement of the drilling mud from the annulus using the cement slurry were paramount for achieving zonal isolation. This study evaluated the displacement efficiency of drilling mud from the annulus by applying particle image velocimetry incorporating the development of a large-scale displacement efficiency device. Displacement efficiency measurements revealed that increasing the injection displacement and reducing the eccentricity cleans up residual drilling mud and significantly improves displacement efficiency. Slurry density significantly affected displacement efficiency, because high- and lightdensity slurries were shown to lead to low velocities and to increase the boundary layer thickness of the drilling mud. High injection displacement swirling flows were found to be more effective for reducing drilling mud adhesion to the casing and wellbore walls. The eccentric annuli tended to result in a narrow channel, which results significantly reducing the displacement efficiency owed to the laminar fluid flow.",3,3,3
Oil-well Cement,,"Lichinga, Kevin Nsolloh; Maagi, Mtaki Thomas; Ntawanga, Athanas Christopher; Hao, Haiyang; Gu, Jun",A novel preflush to improve shear bond strength at cement-formation interface and zonal isolation,Cement-formation interface; Water-based mud; Filtercake; Preflush; Shear bond strength; Zonal isolation,OIL,"The effective removal of filtercake during the oil-well cementing job is of utmost importance for the reduction of well integrity problems during well drilling and production activities. Poor removal of filtercake will lead to a failure in the ability of the cement to provide zonal isolation at the cement-formation interface (CFI), during completion and for the well's lifetime. Several chemical mechanisms (chelating agents, acids, enzymes, and oxidizers) have been widely employed to remove filtercake. Nonetheless, at certain circumstances, these strategies have drawbacks that can adversely impact oil-well productivity. This research introduces a novel preflush (KV-IIA as well as KV-IIB) developed in the laboratory to transform the water-based filtercake at CFI into cement-based materials to enhance shear bonding. KV-IIA solution contained 16% CaCl2, and 1% Alkyl Polyglucoside (APG-1214), while KV-IIB fluid comprised 1% Alkyl Polyglucoside (APG-0810), 12% NaOH, 15% Na2SiO3 and water. Simulated wellbores (SWB) with porosity and permeability of 18% and 150'10(-3) mu m(2) respectively, were also used. The results showed the Reynold numbers for the preflushes KV-IIA and KV-IIB were 46,509 and 29,660 respectively. Since Reynold numbers are greater than 4000 value, the flow regime in the annulus is turbulent. The reactions among H3AlO42 and H3SiO4 from alkali-dissolved reaction, Ca2+, Na+ and H3SiO4 in the KV-II solution, and Ca2+ and OH from cement slurry form the natrolite and calcium silicate hydrate (CSH) with different silicate-calcium ratio. Based on that, the wellbore shear bond strength (SBS) and the cementing quality were improved. Analysis of the FTIR demonstrated that the CFI of the specimens tested produced additional cement binder material which resulted in increased bonding strength. The results of this work are anticipated to provide insights into the bond strengthening mechanisms in water-based mud that could help cementing specialists customize the preflushes to enhance the rock-cement bonding for better annular sealing to ensure a long-term zonal isolation.",3,3,3
Oil-well Cement,,"Adjei, Stephen; Elkatatny, Salaheldin",A highlight on the application of industrial and agro wastes in cement-based materials,Industrial waste; Agro waste; Supplementary cementitious materials; Oil-well cement (OWC),OIL-WELL CEMENT; RICE-HUSK ASH; SUGARCANE BIOMASS WASTE; FLY-ASH; BLENDED CEMENT; BAGASSE ASH; COCONUT SHELL; SILICA FUME; COMPRESSIVE STRENGTH; POZZOLANIC ACTIVITY,"In oil-well cementing, Portland cement is commonly used as a binder in cement slurry formulations. However, a significant amount of CO2 is released into the atmosphere during the production of clinker, the main in-process materials in cement manufacturing. Again, the use of non-renewable resources in cement production makes the process unsustainable. Over the years, chemical and physical analyses of some industrial and agro wastes have revealed characteristics that make them useful as supplementary cementitious materials. Some of these byproducts contain chemicals that can be extracted to modify the fresh and hardened properties of cement-based materials. These materials include coal fly ash, ground granulated blast furnace slag (GGBFS), silica fume, granite waste powder (GWP), rice biomass, palm oil biomass, sugarcane biomass, wood biomass, coconut biomass, and corn biomass. The purpose of this study is to investigate the industrial and agro wastes that were used in cement-based materials and make recommendations for future applications of these materials in oil-well cementing. An overview of experimental procedures and conclusions from laboratory and field studies conducted to evaluate the performance of such materials as cement admixtures is presented. A summary of key findings has also been reported. We recommend extensive evaluation of GWP as a filler/pozzolanic material or alternative to silica flour as an anti-strength retrogression agent. Secondly, we recommend an investigation into the use of other waste materials such as RHA as fillers in cement formulations to enhance the early-age strength development of fly ash and GGBFS oil-well cement systems, especially at low-temperature conditions. Finally, we recommend an assessment of POFA as an extender and the evaluation of both POFA and RHA as anti-strength retrogression agents in oil-well cement formulations.",3,3,2
Oil-well Cement,,"Wang, Sheng; Wu, Liyu; Jiang, Gui; Jian, Liming; Zhang, Tongde; Chen, Shaohua; Chen, Liyi",A high temperature composite cement for geothermal application,Exploitation of geothermal reservoirs; Nano SiO2; Basalt fiber; Casing cementing; Wall protecting and leakage plugging; Zonal isolation,FLY-ASH; PERFORMANCE; CONCRETE; STRENGTH; RETARDER,"In the process of geothermal reservoir exploitation, the performance of cementing material in high temperature environment is the key to ensure the quality of cemented casing for wall protecting and leakage plugging or effective zonal isolation. Based on a systematic approach of theoretical analysis, experimental research and microscopic analysis, this paper presents a new Nano SiO2-basalt fiber composite cement (NSBF) for application in geothermal reservoir exploitation. The NSBF consists of a modification of Class G oil-well cement with optimized additions of fly ash, Nano SiO2, basalt fiber, early strength agent (ZQ), and a water reducing agent (GB). The physical properties of the NSBF (fluidity, pump-ability, setting time and compressive strength), obtained by carefully prepared lab tests, were shown to be suitable for high temperature application. Finally scanning electron microscopy (SEM) and X-ray diffraction (XRD) were used to analyze the micro characteristics for an interpreted hydration mechanism of NSBF at high temperature. Our study results may provide a new product for a quality cementing material or better zonal isolation material in the exploitation of geothermal reservoir.",1,1,6
Particle Image Velocimetry,,"de Araujo, C. A. O.; Scheid, C. M.; Loureiro, J. B. R.; Klein, T. S.; Medronho, R. A.",Hydrocylone for oil-water separations with high oil content: Comparison between CFD simulations and experimental data,Hydrocyclones Oil-water separation; Computational fluid dynamics; Particle image velocimetry; Factorial design; CFD; PIV,PERFORMANCE PREDICTION; FLOW-FIELD; HYDROCYCLONE; DESIGN; EFFICIENCY; VELOCITY; MODEL,"Production separators for gas-oil-water separation are huge, require long residence times, and present several internals to improve oil-water separation. As an alternative to production separators, specially for subsea facilities, this work presents a hydrocyclone which separates a 40% oil-in-water mixture with 93% +/- 2% total efficiency and flow ratio of 7%. Such high oil concentration is typical of mature wells and hydrocyclones have not been designed for such purpose before. In order to design this hydrocyclone, fractional factorial techniques have been used to consider the influence of seven geometrical variables. CFD has been used to assess the performance of each hydrocyclone of the factorial design. The selected hydrocyclone has been tested experimentally in order to validate its performance. PIV measurements have also been carried out in order to assess tangential and axial mean velocity profiles for only water flowing in the hydrocyclone. FBRM has been used to measure droplet size distribution at inlet, overflow and underflow streams. As results, computational reduced total efficiency has been experimentally confirmed. Numerical simulations captured tangential velocity near the centerline of the hydrocyclone, but failed in predicting axial velocity profiles and tangential velocity peaks and near wall regions. It has been discussed though that these are probably not responsible for oil droplets separation in the hydrocyclone when water is the continuous phase. A methodology to analyze the effect of droplet breakup and coalescence, using measured inlet, overflow and underflow cumulative size distribution, has been presented. It has been shown that for the inlet cumulative undersize distribution used, breakup was negligible and coalescence occurred only for droplet diameters higher than those separated with 100% grade efficiency. In this case, no breakup and coalescence models are thus needed in the mathematical model and this explains why reduced total efficiency has matched in both numerical simulations and experiments.",3,3,4
Particle Image Velocimetry,,"Xu, Bingwei; Zhou, Shouwei; He, Faqi; Wang, Fubin; Guo, Jianchu",Using particle image velocimetry to evaluate the displacement efficiency of drilling mud in horizontal well cementing,Cementing; Particle image velocimetry; Eccentricity; Displacement efficiency; Horizontal wells,ANNULAR DISPLACEMENTS; COMPLETION FLUIDS; OIL-WELL; MODEL; FLOW,"For a horizontal well cementing, successful displacement of the drilling mud from the annulus using the cement slurry were paramount for achieving zonal isolation. This study evaluated the displacement efficiency of drilling mud from the annulus by applying particle image velocimetry incorporating the development of a large-scale displacement efficiency device. Displacement efficiency measurements revealed that increasing the injection displacement and reducing the eccentricity cleans up residual drilling mud and significantly improves displacement efficiency. Slurry density significantly affected displacement efficiency, because high- and lightdensity slurries were shown to lead to low velocities and to increase the boundary layer thickness of the drilling mud. High injection displacement swirling flows were found to be more effective for reducing drilling mud adhesion to the casing and wellbore walls. The eccentric annuli tended to result in a narrow channel, which results significantly reducing the displacement efficiency owed to the laminar fluid flow.",3,3,3
Particle Image Velocimetry,,"Kim, Tea-Woo; Al-Safran, Eissa; Pereyra, Eduardo; Sarica, Cem",Experimental study using advanced diagnostics to investigate slug aeration and bubble behavior in high liquid viscosity horizontal slug flow,,PARTICLE IMAGE VELOCIMETRY; UNIFIED MECHANISTIC MODEL; GAS BUBBLE; HOLDUP; VELOCITY; SHAPES; MOTION; AIR; FRACTION,,3,3,0
Particle Image Velocimetry,,"Murphy, A.; Soga, K.; Yamamoto, K.",Experimental investigation into sand production from turbidite strata,Sand production; Gas hydrates; Turbidites; Sediment transport; High pressure plane-strain apparatus; Particle image velocimetry (PIV),HYDRATE-BEARING SEDIMENT; EASTERN NANKAI TROUGH; PRODUCTION TEST-SITE; DAINI-ATSUMI KNOLL; DEFORMATION MEASUREMENT; STABILITY; MODEL; CORE; SIZE; FLOW,"This study investigates whether the heterogeneity of deepwater turbidite strata, particularly the layering and grainsize, could be contributing to catastrophic sand production during extraction of fluid from the subsurface through a wellbore. This type of sand production was seen from the producing interval over turbidite strata during the 2013 gas hydrate trial at the Daini-Atsumi Knoll, Nankai Trough, offshore Japan. To investigate this sand production, an apparatus was designed to simulate a plane-strain case of sand production in the openhole gravel packed hydrate production well. Two scenarios of turbidite strata grainsize and layering were tested in the apparatus. The results of these sand production experiments suggest that the layering and grain size variations of the turbidites encourages sanding. The sand production preferentially came from specific layers in the turbidite sequence. This behaviour was explained by the development of shear induced negative excess pore pressure in the silt layer in undrained conditions which created a slab effect and encouraged the creation of a high permeability zone below the layer. The increase in permeability and fluid flow velocity in this zone increased the carrying capacity of the fluid flow. Modified versions of surface sediment transport theories are able to describe the conservative estimate of this erosion and transport of sand.",3,4,0
Axial Oscillation Tools,,"Omojuwa, Emmanuel; Ahmed, Ramadan",Analytical modeling of axial oscillation-supported drillstrings in high-angle wells,Axial oscillations; Directional drilling; Oscillation tools; Borehole; Friction reduction; Modeling; Displacement excitation,FRICTION-REDUCING PERFORMANCE; REDUCTION; TOOL,"Downhole vibrations generated from axial oscillation tools (AOTs) in axial oscillation-supported drillstrings (AOSDs) has become one of the efficient means of reducing friction and improving weight transfer during sliding operations in horizontal and extended-reach wells. Dynamic modeling of AOT-excited drillstrings is needed for validating the functionality of axial oscillation tools during surface tests and predicting their response under downhole conditions. An analytical model is presented in this study to predict the behavior of axial oscillation-supported drillstrings working under downhole and surface conditions. The model is useful to perform parametric studies, downhole data correlation and placement study of AOTs along the drillstring in horizontal and extended-reach wells. Unlike existing models, the nonlinear equation of motion is derived from a model damped in a viscous medium with Coulomb friction and subjected to displacement excitation. The model also accounts for the spring rate of the axial oscillation tool. The displacement excitation is obtained from the spring rate, which is a critical input to the model. The nonlinear damping is approximated with an equivalent viscous damping coefficient to obtain an analytical solution. The developed model in this study is validated with published experimental measurements obtained from field-scale drillstrings. Correlations between predicted and measured axial displacement and accelerations at different excitation frequencies, pressure drops and spring rates show an approximate average deviation of 14.5%. Also, results from this study strongly accentuates that flow rate is the most critical operating parameter for axial oscillation tools because it affects the amplitude of pressure drop, excitation force, and operating frequency of AOTs.",2,2,2
Axial Oscillation Tools,,"Liu, Jianxun; Zheng, Hualin; Kuang, Yuchun; Yu, Bin; Zhou, Yang; Deng, Ming",A feasible model for friction-reduction investigation of drillstrings in long-horizontal wells with axial oscillation tools and analysis of key influencing factors,Long-horizontal wells; Axial oscillation tools; A feasible model; Friction reduction; Influence factors,PENETRATION,"Most researchers focused on investigating of the friction-reduction effect of the working parameters of the axial oscillation tool (AOT), and didn't pay sufficient attention to the influences of drillstring material properties and wellbore parameters. In this paper, a FEA model was established by considering the coupling of the drillstring-wellbore contact and the action of AOT. The ""far end"" boundary condition and a dynamic boundary condition are introduced into the FEA model, which was verified analytically and experimentally. Finally, the effect of AOT parameters (excitation force, excitation frequency and location), drillstring material properties and wellbore parameters (inclination angle, friction coefficient) on the friction-reduction and the drillstring vibration are systematically explored. The results show that the friction-reduction is mainly influenced by AOT parameters, drillstring material properties and friction coefficient, and is slightly influenced by the inclination angle. Based on the analysis, the friction-reduction of the AOT is mainly caused by the change of friction direction. Though less than the effect of friction-direction change, the effect of velocity-based friction coefficient should not be ignored.",2,2,0
In-depth Profile Control,,"Li, Junjian; Wang, Ze; Yang, Hanxu; Yang, Hai'en; Wu, Tianjiang; Wu, Hao; Wang, Hao; Yu, Fuwei; Jiang, Hanqiao",Compatibility evaluation of in-depth profile control agents in dominant channels of low-permeability reservoirs,In-depth profile control; Profile control agent; Compatibility; Low-permeability reservoir,CONFORMANCE CONTROL; POLYMER MICROSPHERES; PARTICLE GEL; PERFORMANCE; MECHANISM; HYDROGEL; SYSTEM,"Inspired by the promising prospects of in-depth profile control technology in low-permeability reservoirs, a series of experiments were conducted to investigate the compatibility between the profile control agents (PCAs) and the dominant channels, which are the major target of PCAs in low-permeability reservoirs. Three types of frequently used PCAs and three levels of dominant channels represented by their permeabilities were examined. An optimized coreholder was designed to simulate actual field injection. Nanosphere suspension, poly(ethylene glycol) single-phase gel particle (PEG) and cross-linked bulk gel & swelling particle (CBG-SP) were investigated in core flooding experiments. The results revealed that with excellent in-depth mobility, nanosphere was applicable in low- and medium-permeabiliity dominant channels, which represented the small and medium channels. 100 nm nanosphere injected at 0.35 mL/min could achieve a top-notch performance among all PCAs in 50-500mD cores, while 300 nm nanosphere was highly adaptable to medium channels. The plugging rate difference between pressure taps reduced with the increase of injection volume and concentration (IVC). PEG performed well mainly in the medium and large channels, where the pressure at the back section exceeded the front section, indicating a smooth migration into the depth. According to the injectivity tests, the injection rate of nanosphere and PEG is influential in improving its in-depth plugging. The overall plugging performance of CBG-SP was above 80% when the channel permeability was higher than 1300mD. Limited injectivity of PCA makes it more suitable for large-channel blocking near the borehole. Considering the dual-zone permeability differences, systematic criteria were proposed to optimize slug configuration and engineering parameters with the comparison of PCA results. Based on the principle ""blocking, controlling and displacing"", reference was provided for the PCA screening and parameter selection of field implementation.",3,3,7
In-depth Profile Control,,"Du, Dai-jun; Pu, Wan-fen; Zhang, Sheng; Jin, Fa-yang; Wang, Sheng-kui; Ren, Fang",Preparation and migration study of graphene oxide-grafted polymeric microspheres: EOR implications,Graphene oxide-grafted polymeric microsphere; Migration; Plugging; Adsorption and desorption,ELASTIC MICROSPHERES; PROFILE CONTROL; POLYACRYLAMIDE; GEL; PERFORMANCE; SYSTEM,"Through an inverse emulsion polymerization technique, graphene oxide-grafted polymeric microspheres (RGO-PMSs) with superior suspension properties, thermostability, hydration swelling, elasticity and strength were developed for in-depth profile control and displacement. RGO-PMSs undergo migration and adsorption in large pores; capture by means of single plugging, coincidence plugging and bridging plugging; and elastic deformation-recovery in small pores to increase seepage resistance. When matching coefficient was 2.11, RGO-PMSs particles could not enter the porous media. However, RGO-PMSs particles entered core samples smoothly and perform plugging when the matching coefficient ranged from 0.78-1.44, while RGO-PMSs particles could not effectively block the pores when the matching coefficient was 0.67. An increase in the injection rate improved RGO-PMSs injectivity while weakening plugging efficiency. Additionally, the increase in the RGO-PMSs concentration and strength enhanced the plugging efficiency. Moreover, RGO-PMSs had a favorable anti-outwash property with a retention ratio of 88.7%, maximum additional flow resistance of 7.12 kPa and additional flow resistance of 4.53 kPa during migration. All the results indicated that RGO-PMSs could be an applicable candidate for in-depth profile control and displacement.",2,2,2
Other topics ,,"Huang, Kuilin; Yang, Yingxin; Liu, Yang; Zhong, Yunpeng; Ren, Haitao",Study on rock breaking mechanism of PDC bit with rotating module,Rotating module; Rock breaking mechanism; Alternate work,,"In view of the problems of low ROP, short bit life and high energy consumption of bits in deep and difficult formations. Basing on the 360.rotating teeth and disc PDC bit, a rotating modular PDC bit is proposed. The rock breaking efficiency of the bit is improved by ""cross scraping"" of the rotating module element (RME) and fixed cutting teeth. In addition, the rotating module element works alternately, which cools the cutting teeth in time, slowing the wear of the cutting teeth and prolongs bit life. This paper introduces the structural characteristics and working principle of the novel bit, and carries out variable parameter experiments on the rotating module element (side angle, journal angle, and tooth arrangement density, etc.) The experimental results show that the rotating speed of the rotating module element increases with the increase of the side angle, and decreases with the increase of the axial angle. The variation rules of cutting load and MSE of rotating module element under different structural parameters are studied. The indoor test shows that the ROP of rotary modular PDC bit is increased by 15% and the MSE is reduced by 14%, It is implies that the ""cross scraping"" of the rotary module element and the fixed cutting teeth can reduce the rock breaking specific work, and provide theoretical basis and support for the design of the subsequent rotary modular PDC bit.",3,3,6
Other topics ,,"Liang, Jintong; Wang, Hongliang; Blum, Mike J.; Ji, Xinyuan","Modeling of hydrocarbon migration and accumulation on the Chengzikou uplift, Bohai Bay Basin, China: Implications for petroleum exploration on slope belts in rift basins",Hydrocarbon migration pathways; Hydrocarbon accumulation modeling; Slope belts; Chengzikou uplift; Bohai Bay Basin,SECONDARY OIL MIGRATION; TECTONOSEDIMENTARY EVOLUTION; CHARGE CONCENTRATION; DONGYING DEPRESSION; BOZHONG SUBBASIN; FAULTS; GENERATION; PATHWAYS; ENRICHMENT; HISTORY,"The Chengzikou Uplift (CZKU) is a second-order structure surrounded by several hydrocarbon generative kitchens in the Bohai Bay Basin. However, six recently drilled wells on the CZKU failed to prove hydrocarbon occurrences, which causes confusion for the understanding of hydrocarbon migration and accumulation on the CZKU. Mainly based on the seismic database, this paper attempted to determine the hydrocarbon migration pathways and enrichment mechanisms on the CZKU. The results show that the lateral and vertical hydrocarbon migration seems to take place through a stepped pathway system consisting of permeable layers within unconformities, permeable carrier beds, and faults. Through a simple 3D modeling considering topography changes only, the hydrocarbons tend to migrate from the northern sags to the southern slope and uplift with parallel mainstreams and accumulate with convergent mainstreams. The potential hydrocarbon traps mainly include stratigraphic, structural, and structural-lithologic traps, most of which have been confirmed by previous explorations. Subsequently, two preliminary interpretations for the dry well on the CZKU are made: the first is hydrocarbons mainly accumulated in the Paleogene stratigraphic (onlapping) traps within the sag and slope area, conducting no further migration to the uplift; the other is hydrocarbons may migrate to the slope and uplift but were trapped in structural-lithologic traps associated with faults beyond the area of the dry wells. Moreover, favorable hydrocarbon accumulation targets are predicted to reduce exploration risk.",3,3,5
Other topics ,,"Cao, Federico; Eskin, Dmitry; Leonenko, Yuri",Modeling of ex-situ dissolution for geologic sequestration of carbon dioxide in aquifers,Ex-situ dissolution; Geologic sequestration; Modeling,CO2 STORAGE; MASS-TRANSFER; SALINE AQUIFERS; COALESCENCE; DISPERSION,"Underground carbon dioxide (CO2) sequestration is considered to be one of the main methods to mitigate greenhouse gas (GHG) emissions. In this technology, pure CO2 is injected into an underground geological formation and since it is less dense than residual fluids, there is always a risk of leakage to the surface. To increase security of underground CO2 disposal, ex-situ dissolution can be implemented. When CO2 is dissolved in brine before injection, it significantly reduces the risks of leakage. In this approach, pure CO2 is dissolved on the surface before injection. Surface dissolution could be achieved in a pipeline operating under the pressure of a target aquifer into which the CO2 is injected. In a pipeline, CO2 droplets are dissolved being dispersed in a brine turbulent flow. In this paper, a comprehensive model of droplet dissolution along a pipeline is presented. The model accounts for droplet breakup and coalescence processes and is validated against available experimental data.",3,3,4
Other topics ,,"Sechman, H.; Kotarba, M. J.; Kedzior, S.; Dzieniewicz, M.; Romanowski, T.; Gora, A.","Distribution of methane and carbon dioxide concentrations in the near-surface zone over regional fault zones and their genetic characterization in the Pszczyna-Oswiecim area (SE part of the Upper Silesian Coal Basin, Poland)",Soil gas; Methane origin; Carbon dioxide origin; Coalbed gases; Stable isotopes; Polish upper silesian coal basin,HYDROCARBON MICROSEEPAGE; LIGHT-HYDROCARBONS; GASES; ORIGIN; DIFFUSION; EMISSIONS; MIGRATION; OXIDATION; PROFILES; BEARING,"The objective of this paper was to characterize the variability of methane (CH4) and carbon dioxide (CO2) concentrations in the near-surface zone, measured along 4 selected sampling lines positioned perpendicularly to regional fault zones, in the SE part of the Upper Silesian Coal Basin (USCB), Poland. This way it was possible to check the migration activity of these gases to the surface through low-permeable Miocene strata. It was also possible to evaluate the applicability of surface geochemical survey methodology to the identification of potential accumulations of free natural gas in the topmost parts of the Carboniferous formations in the USCB. The results of 319 soil-gas samples were supported by stable isotope analyses and related to the geological setting and the distribution of methane potential at various depths. Moreover, the sampling included the area of the closed and remediated Andrzej VII mining shaft, where 5 soil-gas samples were taken. Additionally, gas flux was evaluated at 3 measurement points at which increased gas concentrations were detected. The maximum concentrations of CH4 and CO2 in soil gases were 15.4 and 9.39 vol%, respectively. Soil gases contain both thermogenic and microbial CH4 and CO2 that migrated from secondary and primary gas zones within the Pennsylvanian coal-bearing strata. In some sites, CO2 was also generated by the oxidation of soil organic matter and/or CH4 in a near-surface zone. Anomalous CH4 concentrations were generally found over elevated fragments of erosional structures of Carboniferous coal-bearing formations. This indicates the presence of free CH4 accumulations beneath the Miocene overburden. However, the surface anomalies did not always correlate with the zones of CH4 secondary accumulations. Anomalous concentrations of CH4 and CO2 correlated with the regional fault zones that cut through the Carboniferous formations. This indicates the potential presence of fault traps saturated with free CH4 in the upper parts of Carboniferous formations. Relatively low values were observed for both CH4 and CO2 emissions (maximum: 25 and 4320 mg m(-2) d(-1), respectively). This suggests relatively low dynamics of gas migration from the depth to the soil zone.",3,3,3
Other topics ,,"Gabova, Anastasia; Popov, Yuri; Savelev, Egor; Romushkevich, Raisa; Chekhonin, Evgeny; Plotnikov, Vladimir; Emelyanov, Dmitry; Akhmadishin, Alisher",Experimental investigation of the effect of temperature on thermal conductivity of organic -rich shales,,PHYSICAL-PROPERTIES; OIL SHALES; ROCKS; DIFFUSIVITY; DEPENDENCE,,3,4,3
Other topics ,,"Lyu, Chaohui; Ning, Zhengfu; Cole, David R.; Wang, Qing; Chen, Mingqiang",Experimental investigation on T-2 cutoffs of tight sandstones: Comparisons between outcrop and reservoir cores,Tight sandstones; T-2 cutoff; Mobile fluid percentage; Permeability estimation; NMR,,"T-2 cutoff is a key representative parameter of rock pore structure, which can reflect the degree of mobile fluid as a function of variable water saturation controlled by the extent of centrifuging. However, few studies of T-2 cutoff have been done on tight sandstones. In this study, residual fluid of samples after a series of centrifuges were scanned by NMR to determine T-2 cutoffs (the relaxation time separating mobile from immobile water) and the extent of mobile fluid as a function of variable water saturation controlled by the extent of centrifuging. Results indicate that all reservoir cores exhibit bimodal NMR T-2 distributions, while outcrop cores mainly show unimodal NMR T-2 distributions. Tight sandstones showlittle or no mobile fluid controlled by pore throats with radii >= 1 mu m, including outcrops and reservoir samples. In conclusion, T-2 cutoffs of cores with bimodal NMR T-2 distributions and the ones with unimodal NMR T-2 distributions were obtained,respectively,at 418 psi and 208 psi, while the former cores exhibit larger T-2 cutoffs than the later ones. The critical mobile pore radius for outcrop samples exhibiting a unimodal spectral NMR T-2 distribution is 100 nm, whereas the critical pore radius of 50 nm is identified for reservoir samples which display a bimodal T-2 distribution. T-2gm (The geometric means of T-2 fluid distribution at 100% saturation) may propagate error when applying the Schlumberger Doll Research (SDR) model to tight sandstones, whereas T-2wa (the weighted average NMR T-2 values for the mobile fluid distribution) shows promise as a parameter to predict pore connectivity.",3,3,3
Other topics ,,"Davtyan, Aram; Rodin, Alexander; Muchnik, Ilya; Romashkin, Alexey",Oil production forecast models based on sliding window regression,Oil production; Forecast models; Machine learning,,"The article presents a method of statistical modeling and forecasting of oil production rate at a real field that has been in operation for a long time. Nowadays such fields form the basis of the oil production industry. The ""aging"" of oil production on such fields requires continuous change of the management of the oil production system. Therefore, production modeling and forecast must be dynamic, varying over time. Moreover the system for measuring production parameters, like production and injection series that are used to fit the proposed model, does not work regularly and has a large number of random gaps. So the development of our model starts with combination of interpolation and averaging procedures to produce a regular grid of data points. On such a regular grid, we construct the desired dynamic regression model using a machine learning method that we refer to as the sliding window regression. Our model predicts the total oil production rate for the next month taking into account some manually designed features of the oil field from the bounded history interval. For convenience, the features of the model are divided into four groups: integral, local, pressure and autoregressive. After prediction for the next month the history window moves one step forward and the model is retrained to fit the new data. Further we generalize the idea of sliding window to obtain a model with stable coefficient dynamics and ability for long-term forecast. In particular, we consider two approaches: introducing some regularization terms to the objective loss functional or weighing sample objects with weights decreasing in the past. The model is verified on data from a real oil field and shows good results in terms of relative error.",3,3,2
Other topics ,,"Meng, Wei; Niu, Zicheng; Hu, Yang; An, Tianxia; Liu, Keqi; Qiang, Gao","Genesis of authigenic kaolinite and its indicative significance to secondary pores in petroliferous basins: A case study in the Dongying Sag, Bohai Bay Basin, Eastern China",Authigenic kaolinite; Characteristics; Genesis; Secondary pores; Indicative significance,SEQUENCE-STRATIGRAPHIC FRAMEWORK; RESERVOIR QUALITY; DIAGENETIC ALTERATIONS; CARBONATE CEMENTATION; CRETACEOUS SANDSTONES; FELDSPAR DISSOLUTION; GEOCHEMICAL SYSTEMS; JOAQUIN BASIN; ORGANIC-ACIDS; HIGH-POROSITY,"Porosity of sandstone generally declines as the formation burial depth rises, during which transformation of unstable minerals (e.g. feldspar) in sandstone significantly contributes to abnormally high porosity zones. It is still controversial that whether transformation of feldspar being massive in sandstone can lead to formation of considerable secondary pores. As the main diagenetic product of feldspar transformation, namely authigenic kaolinite, in terms of the physical and chemical features, acts as indicators of the transformation process of feldspar and the consequent formation of secondary pores. In this study, a series of analyses are implemented on sandstone samples collected from the Dongying Sag, Bohai Bay Basin, Eastern China, including microscopic observation, SEM, EDX, XRD, isotope, and fluid inclusion analysis, with specific attention to genesis and formation process of authigenic kaolinite as well as their indicative significance to secondary pores. It is demonstrated that there are mainly three types of authigenic kaolinite (denoted as K1, K2, and K3), the occurrence and geochemical characteristics of which are greatly different. Based on contact relationship between authigenic kaolinite and other diagenetic products, the three authigenic kaolinite are distinguished into two stages, namely the first-stage K1and the second-stage K2 and K3, which are of obviously different genesis. Specifically, K1 is formed under the effect of acidic fluids that are rich in carboxylic acids. In contrast, K2 and K3 are formed under the effect of acidic fluids that are rich in CO2. During formation of K1, plagioclase dissolution pores are formed and well preserved, and carbonate cements get well preserved, showing no sign of dissolution. During formation of K2 and K3, K-feldspar is kaolinitized as K2, and a small amount of Si and Al elements migrates with shortdistance and precipitates as K3 in the vicinity of K2. During this process, K-feldspar is transformed into kaolinite, accompanied by dissolution of carbonate cements and massive formation of secondary pores.",3,3,2
Other topics ,,"Lobanov, A. A.; Struchkov, I. A.; Belozerov, I. P.; Shulev, V. E.; Yuriev, A., V; Pustova, E. Ju; Kovalenko, V. A.; Sergeev, G. D.",Prediction of asphaltenes deposition in the Russian oilfield: Laboratory investigations and modeling,Asphaltenes; Organic-scales; Precipitation; Deposition; Permeability reduction,WETTABILITY; PRECIPITATION,"The purpose of this study is to investigate the asphaltenes precipitation in oil and their deposition in the pore volume, as well as to model the possible production scenario in case of asphaltenes deposition in the near wellbore area of the Russian oil field. The study of asphaltene envelope in reservoir oil was carried out using light-scattering and microscopy under high-pressure methods. Three experiments were carried out in the isothermal pressure reduction mode at three different temperatures (70.3, 60 and 50 degrees C). Pressure decreased from 28.87 to 14.0 MPa in each experiment with rate of 0.2 MPa/min. Asphaltenes envelop is generated from laboratory experiments. In addition, potential areas of asphaltenes deposition along the tubing were identified using the pressure and temperature profiles along the wellbore of the producer. The effect of asphaltenes deposition in the pore volume on permeability was studied on three core samples. Filtration of reservoir oil was carried out in the mode of step-by-step backpressure reduction from 28.87 to 14 MPa by maintaining constant confining pressure and reservoir temperature. The results showed that there is a sharp decrease in core permeability due to the asphaltenes deposition when Asphaltenes Onset Pressure (AOP) is reached. The maximum decrease in permeability corresponds to 68.3% at 17 MPa. It is noted that a number of producers of the Russian oil field operated with high oil rates, so areas of low pressure (drawdown pressure cone) in the near wellbore areas were formed, contributing to the aggravation of the issue. Based on the laboratory results, the calculation of the permeability decrease in near wellbore area due to the asphaltenes deposition was provided for three cases (drawdown pressure cone 20, 100 and 500 m). Results show that gradual expansion of drawdown pressure cone deep into the reservoir during field operation will be accompanied by an increase in the skin factor from 9.7 to 12.5 (for 969 days of well operation). The prevention and remediation methods of the organic-scales formation in the field are proposed.",3,3,1
Other topics ,,"Cho, Yongchae; Cao, Yang; Zagayevskiy, Yevgeniy; Wong, Terry; Munoz, Yuribia","Kriging-based monitoring of reservoir gas saturation distribution using time-lapse multicomponent borehole gravity measurements: Case study, Hastings Field",Hastings field; Borehole gravity; Time-lapse; Kriging,PERMEABILITY; INVERSION; PRESSURE,"Conventional airborne and surface gravity surveys are often conducted for basin-scale density measurements during hydrocarbon exploration to provide information with respect to potential locations of petroleum reservoir fluid, such as oil and gas. Additionally, these gravity measurements are used during the reservoir development stage to monitor fluid propagation in time and space because of density difference within displaced and injected fluids. However, some challenges exist with the direct use of these conventional gravity measurements. First, airborne and surface gravity surveys provide coarse data resolution. Second, the application of these measurements may require a computationally costly solution of an inverse problem because of large matrix mathematical operations to construct a three-dimensional (3D) earth property model. Therefore, a method is proposed that rapidly generates a high resolution time-lapse fluid saturation (or bulk density) model to monitor reservoir fluid propagation in time and space from multicomponent borehole gravity measurements. In this study, equations used to calculate synthetic multicomponent borehole gravity are discussed. Simple kriging was applied to interpolate gravity data between wells for 3D model construction. Further, data from the Hastings Field were used to create a reservoir model and validate the proposed fluid propagation approach. The fluid flow simulation was conducted on the Hastings gas injection reservoir model for ten years, and corresponding multicomponent borehole gravity modeling was performed at yearly intervals. A correlation is demonstrated between interpolated multicomponent gravity data and the distribution of injected gas in time and space. The proposed workflow can be successfully used to monitor fluid propagation within the reservoir under gas regime and, potentially, under other injected agent development regimes at low cost.",3,3,1
Other topics ,,"Zhang, Yang; Zhao, Pingqi; Cai, Mingjun; Lu, Fengming; Wu, Xi; Guo, Zhiqiao",Occurrence state and forming mechanism of microscopic remaining oil controlled by dynamic and static factors,,GRAVITY DRAINAGE; POROUS-MEDIA; SANDSTONE; RESERVOIR; VISUALIZATION; MORPHOLOGY; SATURATION; FLOW; WET,,3,4,1
Other topics ,,"Badings, Thom S.; van Putten, Dennis S.",Data validation and reconciliation for error correction and gross error detection in multiphase allocation systems,Data validation and reconciliation; Sales allocation; Gross error detection; Multiphase allocation systems,,"In upstream oil and gas production, flow measurement errors are common at multiple locations in the production system. These measurement errors lead to imbalances, which are reconciled by using allocation methods. The allocation method should redistribute the imbalance in a fair manner to all involved stakeholders. In this paper, data validation and reconciliation (DVR) is proposed as an alternative allocation method in multiphase production systems. DVR is a model-based optimization method that exploits redundancies in process data to minimize random measurement errors, and simultaneously provides a basis for the detection of gross errors. To study the applicability of DVR compared to conventional allocation methods, a model for generic multiphase production systems is developed, and the corresponding DVR problem is formulated. In order to deal with nonlinear flow effects (e.g. interphase mass transfer) the model is linearized around the operating conditions and the DVR problem is solved iteratively. From the simulation studies, it is concluded that DVR reduces measurement errors by up to 56% for gas allocation systems and 33% for multiphase systems. Gross errors in interior locations of the network can be located precisely, while allocating gross errors to exterior locations is generally not possible, due to limited network redundancy. Compared to conventional methods, DVR provides a better means for the detection of gross errors, and results in more accurate attribution of oil/gas ownership and more fair division of revenues between stakeholders.",3,3,1
Other topics ,,"Weijermars, Ruud",Improving well productivity ? Ways to reduce the lag between the diffusive and convective time of flight in shale wells,,FLOW INTERFERENCE,,3,3,0
Other topics ,,"Oliver, Dean S.",Diagnosing reservoir model deficiency for model improvement,,ENSEMBLE KALMAN FILTER; DATA ASSIMILATION; INFERENCE,,3,3,0
Other topics ,,"Deng, Qiao; Zhang, Hui; Chen, Anming; Li, Jun; Hou, Xuejun; Wang, Hao",Effects of perforation fluid movement on downhole packer with shock loads,Downhole packer; Perforation fluid; Shock loads; Numerical simulation; Optimization measures,PENETRATION,"With the rapid development of oil and gas well production techniques, perforation technologies have made rapid progress, accompanied by perforation safety problems has become an important challenge in the field operation. The shock loads generated during perforating have a strong impact on downhole tools as well as perforation fluid, which poses a threat to the safety of downhole perforating string system, especially for the packer. Firstly, this paper explores the perforation fluid movement mechanism, the calculation model is proposed to describe the two periods of perforation fluid movement. Secondly, the process of perforation with many bullets has been simulated by using the software ANSYS/LS-DYNA. The movement in two periods of perforation fluid can be calculated based on the simulation result, which the set distance of packer needs to be optimized. The propagation attenuation law of shock wave is studied, and a model based on simulation data is proposed to predict the peak pressure of perforation fluid under different perforation conditions. Thirdly, a prediction model for determining the safety distance of the packer has been created by considering the reflection and transmission of shock waves. Finally, the simulated result has been verified by the field case, optimization measures are put forward by combining the design of shock absorption with the safety distance of downhole packer. The results show that the research method in this paper is practical, reasonable and effective, which can provide a theoretical basis for field perforation operation and safety improvement.",2,2,12
Other topics ,,"Solling, Theis, I; Olesen, Kristian B.; Palm-Henriksen, Gustav; Abdel-Azeim, Safwat; Skov, Anders B.",Crystalizing the interface - The first X-Ray structure of an oil/surfactant/brine transition layer,Interface; Interfacial tension; Surfactants; Crystal structure; Zink,WATER; PREDICTION; MOLECULES; SURFACE; LASERS,"Liquid-liquid interfacial phenomena are central in a wide variety of scientific disciplines and encompass down-to-earth aspects such as mayonnaise production, more complex processes in cellular biology and determine what drives the flow below the surface of the earth in an oil reservoir. It is the actual molecular structure at the boundary between two immiscible liquids that determines the interfacial properties. The experimental determination of such a structure has previously been unsuccessful. We have designed an experiment to enable crystallization of the interface between brine and a surfactant/organic phase. A single-crystal structure reveals, for the first time, how the structure and orientation of surfactants impact macroscopic measures such as interfacial tension.",2,2,11
Other topics ,,"Michael, Feven Mattews; Krishnan, Mohan Raj; AlSoughayer, Shahla; Busaleh, Ahmad; Almohsin, Ayman; Alsharaeh, Edreese H.",Thermo -elastic and self -healing polyacrylamide-2D nanofiller composite hydrogels for water shutoff treatment,,PREFORMED PARTICLE GEL; NANOCOMPOSITE HYDROGELS; CONFORMANCE CONTROL; GRAPHENE; TOUGH,,2,2,6
Other topics ,,"Li, Yongjiang; Yu, Zhiyi",Distribution and motion characteristics of bubbles in a multiphase rotodynamic pump based on modified non-uniform bubble model,Bubble distribution; Motion characteristics; Multiphase rotodynamic pump; Gas cavity,GAS-LIQUID FLOW; VOID FRACTION DISTRIBUTION; FILLED CAVITY STRUCTURES; REACTORS,"Multiphase rotodynamic pumps are important equipment that transport gas-liquid mixtures in offshore oilfields, suggesting it is necessary to investigate the flow characteristics in such pumps. In this study, the Eulerian twofluid model is solved to obtain the bubble distribution in the pump, while the non-uniform bubble model is used to predict the break-up and coalescence of bubbles. The gas cavity equation is introduced to capture the rapid coalescence of bubbles near the suction side of the impeller blades, and the interphase forces in the cavities are modified. Compared with the experimental measurements for the gas volume fraction and bubble size, it is found that the simulations with the modification have better accuracies than without it. The effects of the inlet gas volume fraction (IGVF) on the bubble distribution are analyzed. Due to the formation of vortices, a large bubble number density is observed near the shroud of the impeller inlet, which increases with greater IGVF. The gasliquid separation in the diffuser becomes more significant as the IGVF increases. Bubbles from the impeller inlet are observed to continuously gather near the suction side of the impeller blades. This forms a gas cavity that moves towards the impeller outlet with a low gas volume fraction. The rotor-stator interactions cause the air pockets to discontinuously move along the pressure side of the diffuser blade.",2,2,5
Other topics ,,"Jing, Cheng; Dong, Xiaowei; Cui, Wenhao; Dong, Zhenzhen; Ren, Long; Gu, Xiaoyu; He, Yanlong; Pu, Chunsheng; Liu, Xiaoyu",Artificial neural network-based time-domain interwell tracer testing for ultralow-permeability fractured reservoirs,Ultralow-permeability fractured reservoirs; Time-domain interwell tracer; Artificial neural network; Sample learning,SPONTANEOUS IMBIBITION; MECHANISM,"Affected by water injection, the interwell parameters of injection-production wells in ultralow-permeability fractured reservoirs are changed in the time domain, and interwell tracer testing can characterize interwell characteristics quantitatively. For an oil field in the middle and late stages of development, the number of interwell tracers is reduced to control costs, meaning that some injection-production well groups cannot be monitored effectively. Given the rapid development of artificial intelligence technology by which the complex implicit relationship of parameters can be obtained through sample learning, it is possible that future interwell parameters can be predicted by combining a large accumulation of data from interwell tracer testing of well groups with historical production data. This work took a shallow, ultralow-permeability, fractured reservoir in the eastern part of the Ordos basin as its object, and based on the interpreted parameters of previous interwell tracer tests, combined with the dynamic production data and static geological parameters, an analysis method of time-domain interwell tracer testing was developed for ultralow-permeability fractured reservoirs using an artificial neural network. Learning from actual field samples and analyzing two schemes of neural network structure, the minimum error was found for the scheme that predicted the next interwell parameter based on the interpreted parameters of the last time the tracer reached the minimum, with a relative error of 1.94%. The proposed method can predict future interwell parameters reliably and can provide a new low-cost monitoring method for the middle and late stages of water injection development in ultralow-permeability fractured reservoirs.",2,2,4
Other topics ,,"Tozzo, Everton; Seixas Costa, Ana Paula Cabral; Lins, Isis Didier",A hybrid multi-objective genetic algorithm for scheduling heterogeneous workover rigs on onshore oil fields,Workover rig problem; Heterogeneous fleet; Multi-objective optimization; Hybrid genetic algorithm; Variable neighborhood descent,VEHICLE-ROUTING PROBLEM; OPTIMIZATION; MODELS; FLEET,"Onshore oil fields are composed of a set of geographically distributed wells that, after some time of operation, might present some malfunction and have their production interrupted. When the oil production of some wells is interrupted, specially-equipped vehicles, also called workover rigs, are deployed to service the wells and guarantee that their activity is restored. Given the limited number of workover rigs and the large number of wells around the oil field, the workover rig problem consists of finding the best scheduling for the workover rigs, so the total production loss of wells is minimized. The scheduling considers some factors such as the production loss rate of each well, the service level required and the planning time horizon in which the schedule must be executed. This research presents a hybrid genetic algorithm to solve the multi-objective workover rig problem with a heterogeneous fleet and a finite time horizon. The hybrid genetic algorithm incorporates a variable neighborhood descent heuristic as a local search procedure to increase the convergence speed of the set of solutions. Both objectives of minimization of the production loss and fleet cost associated with the rent of workover rigs are taken into consideration. The fleet is held variable, so a workover rig depot is included at a strategic position on the oil field to guarantee that new workover rigs, besides the already existent ones on the oil field, might be included in the scheduling when required. The genetic algorithm was tested on a set of practical-sized instances up to 200 wells, 10 workover rigs and 300 as time horizon. Results show a high conflict between the objectives of minimizing the production loss and fleet cost for the workover rig problem, besides important aspects of the solutions obtained by the proposed algorithm.",2,2,3
Other topics ,,"Kim, Dokyeong; Choi, Junhwan; Kim, Dowan; Byun, Joongmoo",Predicting mineralogy by integrating core and well log data using a deep neural network,Mineralogy; Fancy principal component analysis (PCA); Deep neural network (DNN); X-ray diffraction (XRD),RAY-POWDER DIFFRACTION; VELOCITIES; POROSITY,"Mineralogy is an essential parameter for calculating the rock properties of reservoir formations. To evaluate mineralogy, mineralogy logs and core analysis results are generally used. Additional logs can provide information on mineralogy at all depth intervals of the borehole, but the provided information is acquired from indirect measurement with increasing costs. Core data can give direct measurements, but it is often uneconomical to acquire cores for all depth intervals. A deep neural network (DNN) can be used to extract relationships among multiple nonlinear features. Due to this advantage, DNNs have been actively applied to geophysical problems, which are solved through nonlinear equations. In this study, we propose a DNN model to predict the weight fractions of minerals from integrated conventional log data and X-ray diffraction (XRD) results analyzed using core data. To compensate for the limited XRD results, Fancy principal component analysis was adopted to augment the XRD results before training the DNN. We conducted blind tests to verify the effectiveness of the trained DNN model using field data. The trained DNN model is reliable and cost effective, demonstrating applicability to the prediction of mineralogy.",2,2,3
Other topics ,,"Chu, Zhicheng; You, Zuoling; Wang, Fa; Chen, Xi; Zhang, Bo",A targeted risk prediction method based on statistical analysis of accidents in petroleum geophysical exploration,Statistical analysis; Targeted risk prediction (TRP); Petroleum geophysical exploration (PGE); Fieldwork accident; Accident information statistic template (AIST),GREY RELATIONAL ANALYSIS; OCCUPATIONAL ACCIDENTS; SEVERITY; CRASHES; FAILURE; OIL,"Petroleum geophysical exploration (PGE) has a significant impact on the oil industry, but still trapped by fieldwork accidents. How to predict risks of accidents at worksites in a targeted way is still a challenge, but few researchers have focused on this issue because of the lack of data from the worksite. To address this problem, statistical analysis is carried out based on accident information acquired from a well-known oil corporation and a targeted risk prediction (TRP) method has been proposed in this paper. Firstly, an accident information statistic template (AIST) for key indexes extracted from accident investigation reports is established as the basis. Secondly, the combination of Chi-Square test and grey relational analysis (GRA) method is applied to determine the relationship between accidents' causation variables and accident types. Chi-Square test is used to narrow the range of causation factors relating to specific accident types, whereas the GRA method is employed to help locate the accident type that most likely to occur under certain conditions. Finally, a TRP method of PGE fieldwork is proposed based on the statistical calculation results. With this method, fieldworkers can be aware of the overall risk at worksites as well as concentrating on preventing accident types that most likely to occur in a specific working condition before a fieldwork. An application study of this method has also been discussed. This method can be used to provide targeted pre-warning messages and corresponding prevention strategies before performing a PGE fieldwork. Thus can hopefully enhance the PGE fieldwork safety.",2,2,3
Other topics ,,"Sosa, Mariana D.; Canneva, Antonela; Kaplan, Andrea; D'Accorso, Norma B.; Martin Negri, R.",From superhydrophilic to superhydrophobic polymer-nanoparticles coated meshes for water-oil separation systems with resistance to hard water,Oil-water separation; Polymers; Composites; Nanostructure; Superhydrophobic membranes,ONE-STEP PREPARATION; MEMBRANE; SURFACE; ROBUST; SELF; FABRICATION; COATINGS; SOLUBILITY; BEHAVIOR; SILICA,"A one-step procedure is presented for developing novel superhydmphobic oil-water separation membranes, based on composites of nanoparticles and polymers. The combination of hydrophilic particles with hydrophobic polymers allows obtaining superhydrophobic coatings on metal meshes, with chemical and physical stability. The methodology consists of coating SiO2 hydrophilic nanoparticles with two hydrophobic polymers (polydimethylsiloxane and polyvinylidene fluoride, PDMS and PVDF, respectively) on metal meshes. The nanoparticles generate roughness in the nanoscale, while the combination of PVDF and PDMS provides hydrophobicity, chemical resistance, and reinforce of mechanical properties. Membranes were characterized by XPS, SEM, TEM, FTIR, TGA, water-contact-angles (WCA) measurements, and elongation tests. The membranes present oil flux in the order of 10(2) Lm(-2) s(-1), with stable performance during several months for water/oil separation tests when using saline (Na+, Cl-) and hard water (Ca+2, Mg+2) solutions. The synergetic mixture of three components, PDMS-PVDF-SiO2, provides superhydrophobic behaviour while coatings formed by any combination of only two components do not show the targeted properties.",2,2,3
Other topics ,,"Yang, Runze; Zhao, Xianzheng; Li, Hongjun; Zhao, Changyi; Pu, Xiugang; Liu, Haitao; Fu, Lixin; Li, Chuanming","Evolution characteristics of the upper Paleozoic source kitchen and its controlling effects on hydrocarbon accumulation in the Paleozoic petroleum system in Huanghua Depression, Bohai Bay Basin, China",,GENERATION KINETICS SINGLE; ORDOS BASIN; SOURCE-ROCK; SHALE OIL; EXPULSION; FIELD,,2,2,2
Other topics ,,"Yu, Peng; Liu, Yuetian; Wang, Jun; Kong, Chuixian; Gu, Wenhuan; Xue, Liang; Cheng, Ziyan; Jiang, Long",A new fracture permeability model: Influence of surrounding rocks and matrix pressure,,FLUID-FLOW; KOZENY-CARMAN; MECHANICAL-PROPERTIES; DEFORMATION; POROSITY; INCLUSION; APERTURES; RESERVOIR; EQUATION; TENSOR,,2,2,2
Other topics ,,"Li, Yong; Zhang, Qi; Wang, Daigang; Song, Benbiao; Liu, Pengcheng",A fast method of waterflooding performance forecast for large-scale thick carbonate reservoirs,Carbonate reservoir; Waterflooding; Performance forecast; Stacking pattern; Type curve,CURVE; MODEL,"Due to the severe heterogeneity of carbonate reservoirs, the traditional reservoir engineering methods for waterflooding performance forecast, mainly including the material balance equation, waterflooding characteristic curve and production decline curve, suffer from less reliability. The fine-scale reservoir numerical simulation is extremely time-consuming, because petrophysical properties in carbonate geological models change so drastically. To predict the development performance rapidly, a new method for large-scale thick carbonate reservoirs is proposed. By combining the geological characteristics and dynamic performance of each well, vertical stacking pattern of the reservoir are classified, and also good insights into the lateral distribution of typical stacking patterns are also gained. The stacking pattern distributions are further projected onto the waterflooding well pattern, followed by rapid evaluation of production and injection rate of every block. Based on the simulation results for typical stacking pattern blocks, type curves of water flooding on different stacking pattern reservoirs are workout. Then the waterflooding performance for the whole carbonate reservoir is step-by-step quickly predicted at a constant liquid rate so as to keep the reservoir injection-production balance with voidage replacement ratio 1. Finally, a large-scale thick porous carbonate reservoir in the Middle East is taken as an example to show the workflow of the proposed method. The accuracy is further validated by comparing the predicted results from numerical simulation, indicating that the proposed method can save a lot of calculation time while ensuring the accuracy of performance forecast.",2,2,2
Other topics ,,"Bernasconi, Giancarlo; Giunta, Giuseppe",Acoustic detection and tracking of a pipeline inspection gauge,Pipeline inspection; PIG tracking; Pressure transients,PIG; SIMULATION,"Pipeline Inspection Gauges (PIGs) are widely used for monitoring and managing pipeline integrity. During a pigging operation it is fundamental to have a continuous measurement of the PIG position and movement, in order to achieve the best inspection and to have an early warning in the case the device is stuck. Currently, the tracking is performed by installing on the PIG ""active"" systems (e.g. acoustic pingers or electromagnetic emitters) that communicate with a set of receivers, making it possible the localization of the travelling gauge. Another solution is the deployment of an appropriately dense network of sensors along the pipe track, or the utilization of a dedicated system/crew that moves close to the pipe, so to physically perceive the vibrations generated by the nearby passage of the device. In fact, the moving PIG produces pressure transients and vibm-acoustic noise due to the velocity fluctuations, to the friction against the internal walls and to the crossing of the welding dents. It is important to mention that the conduit acts like an acoustic waveguide and the ""sound"" generated by the PIG, in many practical situations, can be sensed within the fluid at several kilometres from the originating point. This paper presents three different tracking procedures that exploit the noise generated by the PIG to locate it, remotely and passively, without requiring any additional equipment to be mounted on the gauge. The key points of the procedures are the availability of pressure measurements at a small number of positions along the pipeline, at relative distances of tens of kilometres, an accurate synchronization of the measurements, the real time transmission and multichannel processing of the data. The first method locates the PIG by performing a cross-correlation analysis between the acoustic signal recorded on opposite sides of the moving gauge, the second method is based on the counting of the transients generated at known positions, the third one describes the pipe section between the PIG and the arrival terminal like a resonant structure, and obtains the length of this section (the distance of the PIG to the arrival) from the resonance frequency. All the methods are presented starting from real examples, in order to highlight their effective applicability. Moreover, the localization results are in agreement with the output of more sophisticated technological solutions.",2,2,2
Other topics ,,"Ben, Jianlin; Qiao, Wenxiao; Che, Xiaohua; Ju, Xiaodong; Lu, Junqiang; Men, Baiyong",Experimental simulation of obtaining the reflector azimuth using azimuthal acoustic reflection tool in the underwater environment,Acoustic logging; Reflection; Reflector azimuth; Beamforming,BOREHOLE,"The azimuth and distance of reflector from the logging tool can be obtained by downhole azimuthal acoustic reflection measurements and the supporting reflection logging tool was developed. The special azimuthal acoustic receiver sonde of the tool results in azimuthal acoustic data, permitting the evaluation of the reflector location by reflected P-waves. Eight transducers distributed evenly across the receiver can record acoustic waves independently. Each receiver can be considered as belonging to an eight-element arcuate phased array, which allows us to adopt the beamforming method. To evaluate the feasibility of reflector azimuth measurements and the effectiveness of beamforming in azimuth acoustic data, an experimental simulation was conducted in a deep lake. Experimental results reveal that the reflector azimuth can be easily determined with the maximum amplitude value of reflected P-waves. Furthermore, the relationship between the amplitude value of beamformed reflection and azimuth suggests a higher measuring accuracy of azimuth. The results also show that the azimuths of double reflectors arranged opposite to each other can be obtained. The consistency between measured and actual values reveals the reliability of data processing. This work shows a promising prospect in the downhole application of determining the reflector azimuth using this tool in the future.",2,2,2
Other topics ,,"Liu, Jin-Feng; Feng, Jun-Ying; Yang, Shi-Zhong; Gang, Hong-Ze; Mu, Bo-Zhong",The recovery of viscosity of HPAM solution in presence of high concentration sulfide ions,Partially hydrolyzed polyacrylamide; Viscosity; Mechanism; Sulfide ion; Amide group,PARTIALLY HYDROLYZED POLYACRYLAMIDE; ENHANCED OIL-RECOVERY; WATER; TEMPERATURE; ACRYLAMIDE; MECHANISM; SYSTEM,"Partially hydrolyzed polyacrylamide (HPAM) is widely used as a viscosity-enhancing agent in oil recovery. However, significant viscosity loss has been reported for HPAM solutions in the presence of S2-. Surprisingly, in this study, we found that this loss could be recovered by adding more S2-. To address this issue, the rheological behavior, hydrodynamic radius, and chemical structure of HPAM were investigated simultaneously using rheometry, dynamic light scattering (DLS), Fourier-transform infrared (FT-IR) spectroscopy, and 1H nuclear magnetic resonance (NMR) spectroscopy. The viscosity of the HPAM solution dropped sharply in the presence of trace S2- (<10 mg/L), then partially recovered as S2- concentration increased from 10 to 400 mg/L, and finally plateaued at higher concentrations. Also, the change in viscosity with increase of S2- concentration was found to be in consistent with that in hydrodynamic radius of HPAM in aqueous solutions. Furthermore, FT-IR and 1H NMR spectra suggest that the amide amino groups were chemically altered by S2-, changing the chemical environment of the methyne proton. Interaction between amide groups and the trace S2- reduced the hydrodynamic radius and destroyed the HPAM network structure, thus reducing viscosity. In contrast, with increase in S2- concentration, more and more S2- ""linked"" to amide groups via interactions between them, resulting in the enhanced electrostatic repulsion between these S2-. Consequently, the repulsion made the HPAM molecule more stretched and the network fluffier, helping to recover the viscosity loss. Herein, the whole picture and mechanism of S2--induced viscosity changes in an HPAM solution are evaluated for the first time.",2,2,1
Other topics ,,"Noorian, Yaser; Moussavi-Harami, Reza; Mahboubi, Asadollah; Kadkhodaie, Ali; Omidpour, Armin","Assessment of heterogeneities of the Asmari reservoir along the Bibi Hakimeh anticline using petrophysical and sedimentological attributes: Southeast of Dezful Embayment, SW Iran",,SEQUENCE STRATIGRAPHIC FRAMEWORK; OLIGOCENE-LOWER-MIOCENE; CAPILLARY-PRESSURE; OIL-FIELD; FLOW UNITS; ZAGROS; PERMEABILITY; EVOLUTION; FACIES; PREDICTION,,2,3,0
Other topics ,,"Almeida, Forlan; Davoli, Alessandra; Schiozer, Denis Jose",Reducing uncertainties of reservoir properties in an automatized process coupled with geological modeling considering scalar and spatial uncertain attributes,Uncertainty reduction; Geological modeling,HISTORY; SIMULATION; FIELD,"The current work introduces an automatized process coupled with geological modeling to reduce uncertainty in reservoir properties. The method assimilates dynamic data of wells interactively, and applies the deviations to constrain uncertainties. The methodology deals with scalar (e.g. rock compressibility) and spatial (e.g. porosity) attributes at same time, employing specialized uncertainty reduction procedures. The procedure reduces the uncertainty of scalar attributes through Iterative Discrete Latin HyperCube method (IDLHC). To reduce uncertainties of spatial attributes, we worked on an extension of a regionalized co-simulation (co-DSS) method. The main contributions regard the proposition of update, at same time, both kinds of uncertainties (spatial and scalar); the definition of sequential rules, that simplify the process execution and avoiding subjectivities on the coupling of the geological modeling on data assimilation, as well as the automation of the process. The procedure was validated under a siliciclastic black-oil benchmark field (UNISIM-I-M), established based on Namorado Field, Campos Basin, Brazil. The procedure reduced the range of uncertainty of the scalar attributes, centralizing final PDFs with the values presented in the reference model, without collapse to a particular level, as well as preserved the geological consistency throughout data assimilation, obtaining porosity responses in agreement with the reference porosity distribution. The potential of the procedure is supported by the consistent production forecast observed in the outcomes.",2,2,0
Other topics ,,"Zhou, Xingkun; Sun, Yuqing; Duan, Menglan; Li, Wenhua",Numerical investigation on crack identification using natural frequencies and mode shapes of a drilling riser during deployment and retrieval,Crack identification; Drilling riser; Natural frequency; Modal shape; Deployment and retrieval,VIBRATION; CURVATURE; BEAM,"Deployment and retrieval of drilling risers are among the most highly stressed marine operations processes, and allowable imperfections or missed-inspection cracks are likely to expand into limited defects, making crack identification essential during the deployment and retrieval of risers. This study's main objective is to investigate the performances of natural frequencies and modal shapes on crack identification in a drilling riser during installation and retrieval. First, a computation code is programmed to extract the natural frequencies and modal shapes of the intact and cracked risers, and its validity is verified by two numerical methods, i.e., precise integration method and differential transformation method in the literature. Second, the crack-identification ability of natural frequencies versus crack depth and riser-suspension length is studied in detail. An approach using the normalized fourth derivative of modal shapes is developed for crack identification compared with the traditional modal-curvature and modal-curvature difference approaches. Finally, the cracks near the middle span and both ends of the risers are identified, respectively, during the deployment. From the research on crack identification during installation, several conclusions and suggestions are drawn to provide some valuable references for the safety of drilling and production operations.",2,2,0
Other topics ,,"Peter, Ameh; Jin, Xiaoqiang; Sheng, Yong; Fan, Xianfeng; Yang, Dongmin",Static fatigue of saline rocks under different CO2 phase conditions,,SUPERCRITICAL CO2; MECHANICAL-PROPERTIES; GEOLOGICAL STORAGE; INJECTION; PRESSURE; STRESS; CREEP; WATER; TIME; SEQUESTRATION,"Static fatigue tests were conducted on core samples saturated with different phase CO2 to evaluate the fatigue rate and bulk modulus under constant but stepped stress increment. There was re-appearance of primary fatigue at higher stress in all the samples. In the brine saturated sample, for a 4 MPa deviatoric stress increase, there was about 89% increase in primary fatigue rate with up to 16% more strain, up to 88% reduction in fatigue rate when fatigue goes from primary to secondary fatigue and a reduction in primary fatigue duration by 39% with a bulk modulus of 1.050 GPa. Also, the secondary fatigue rate in stress conditions that had the initial primary fatigue portion was up to 16% higher than the secondary fatigue rate for stress conditions that do not have a primary fatigue portion. Saturating the rock with different phase CO2-brine caused a significant change in the fatigue behaviour and bulk modulus depending on the phase of the CO2. While the effect of CO2 phase on bulk modulus is most pronounced in the supercritical CO2 phase (decrease of 22%), change in fatigue rate is most pronounced on gaseous CO2 phase (an increase of up to 45%) especially when it is combined with brine (an increase of up to 93%). The results of this study provide new insights into the deformation and response of rock's bulk moduli to different states of CO2-brine that could exist in a CO2 storage site and will be useful for the future site selection and maintenance of the geological storage projects.",2,2,0
Other topics ,,"Amir, Sahar Z.; Sun, Shuyu; Wheeler, Mary F.",A Machine-Learning based generalization for an iterative Hybrid Embedded Fracture scheme,fractured Rocks; Hybrid embedded fracture scheme; HEF; Image processing; Machine learning; Deep learning; Artificial intelligence,PRESSURE-TRANSIENT ANALYSIS; FINITE-ELEMENT; LARGE SPARSE; FLUID-FLOW; MODEL; PERMEABILITY; TRANSPORT; SIMULATIONS; RESERVOIRS; TRANSFORM,"Accurately simulating fractured systems requires treating the fracture's characteristics. Here we describe a novel framework that involves coupling the Hybrid Embedded Fracture (HEF) scheme with Machine Learning. In general, HEF is more accurate than continuum medium schemes and less reliable but more efficient than the Discrete Fracture Networks (DFN) schemes. In our work, the attributes used to estimate the HEF flux exchange parameters are extracted using image processing, Machine-Learning, and Artificial-Intelligence techniques. In addition, we formulate a pure Machine-Learning classifier and Deep-Learning topology design to deal with the extraction of hierarchical fracture features from low-level to high-level based on Neural-Network layers. Computations are visualized using velocity vectors that are controlled by fractures characteristics extracted automatically from the fractured systems images. Their results provide an understanding of the flow behavior and maps of pressure distributions.",1,1,8
Other topics ,,"Ni, Chen; Wang, YuanYuan; Hou, Qingfeng; Li, Xiaoxuan; Zhang, Ying; Wang, Yan; Xu, Yan; Zhao, Yujun",Phase transformation of thermoresponsive surfactant triggered by its concentration and temperature,,WATER; POLY(N-ISOPROPYLACRYLAMIDE); POLYMERIZATION; NANOPARTICLES; EXTRACTION; OIL,,1,1,4
Other topics ,,"Pu Yu; Ma Pengbo; Chen Hongkun; Li Dong; Arici, Muslum",Characterization investigation on pore -resistance relationship of oil contaminants in soil porous structure,,LATTICE BOLTZMANN MODEL; NUMERICAL-SIMULATION; FRACTAL DIMENSIONS; SCALE PREDICTION; HEAT-TRANSFER; MEDIA; FLOW; PERMEABILITY; MASS; DIFFUSIVITY,,1,1,4
Other topics ,,"Zhou, Qian-Zhi; Xu, Xiao-Ming; Xu, Hong; Zheng, Gui-Zhou; Pi, Wei-Ling; Jiang, Yun-Lin; Xu, Xiang-Po; Li, Yan; Wang, Jiang-Hai","Surface microbial geochemistry of the Beihanzhuang Oilfield, northern Jiangsu, China",Microbial indicator; Surface microbial geochemistry (SMG); Microbial reservoir characterization (MRC); Gaseous hydrocarbon-oxidizing bacteria; Live/dead microbe; Oil reservoir,HYDROCARBON MICROSEEPAGE; EXTRACELLULAR DNA; GAS-FIELDS; METHANOTROPHS; BASIN; INDICATORS; BACTERIA; GENES; SOIL,"Surface microbial geochemistry (SMG) is an effective tool to predict the occurrence of oil/gas deposits at the exploration phase. However, for oil/gas fields in the production period, the significance of SMG is always weakened since the existing microbial indicators for reservoir characterization by SMG are limited. In this study, we systematically analyzed the abundances of live and dead methane-oxidizing bacteria (MOBs) and butane-oxidizing bacteria (BOBs) in surface soils/sediments samples from two cores and 85 sampling sites in the Beihanzhuang Oilfield, China, using the culture-independent method. The results have demonstrated that the suitable sampling depth is 50 cm for this area; and the anomalies in the abundances of live and total MOBs/BOBs and their overlapping relation can clearly reflect the change in the horizontal distribution pattern of the subterranean oil reservoirs. A general SMG strategy integrated with novel microbial indicators has further been proposed in practical applications. Our work may provide a new clue for developing other new microbial indicators for SMG and promoting its wider applications.",1,1,4
Other topics ,,"Mikhailova, A. N.; Kayukova, G. P.; Batalin, G. A.; Babayev, V. M.; Vakhin, A. V.",Comparative influence's research of the compound of metals carboxylates on the generation and composition of hydrocarbons from Domanic deposits at steam-thermal effect in CO2 environment,Domanic rock; Organic matter; Hydrocarbons; Kerogen; Hydrothermal catalytic effect; Catalyst,HEAVY OIL; CATALYTIC AQUATHERMOLYSIS; ORGANIC-MATTER; TRANSFORMATION; CONVERSION; ROCKS; SHALE; FE; CU,"The influence of the catalyst - the compound of oil-soluble carboxylates of metals: Fe, Co and Cu - on the properties and generation of hydrocarbons from the Domanic carbonate-siliceous rocks of the coeval sediments of the Semiluki horizon of the Romashkino and Pervomaisky oil fields located in the central and north-eastern part of Tatarstan was investigated. Experiments were carried out at the temperature 300 degrees C, during steam-thermal effect in CO2 environment. Rocks differ in their carbonate and siliceous content, the content of kerogen and dispersed organic matter, group and structural group composition of the selected extracts, which is due to the different conditions of formation of thicknesses. Due to the processes of destruction of high molecular components and insoluble kerogen structure, the presence of metal catalyst in the reaction system increases the yield of extracts from rocks: 12 times in the rock's sample from Romashkino field and 2 times in the rock's sample of Pervomaisky field, in which the content of saturated hydrocarbons increases: 6 and 1.5 times respectively. The features of the structural-group composition and paramagnetic properties of asphaltenes and carbene-carboids, formed in the process of catalytic experiments, due to the different content of kerogen and high-molecular organic matter in the initial rocks are revealed. Peculiarities in the composition and distribution of microelements in the studied rocks before and after catalytic experiments were revealed. A high sorption capacity of the rock to the metals that included in the compound of the used catalysts was identified.",1,1,3
Other topics ,,"Hou, Jian; Han, Ming; Fuseni, Alhasan",Determination of the concentrations of polyacrylamide-type polymers by a modified nitrogen digestion method,Polymer flooding; Polymer concentration; Polyacrylamide-type polymer; Nitrogen digestion; Infrared spectroscopy; Hydrolysis degree,WATER-SOLUBLE POLYMERS; OIL-RECOVERY; ACRYLAMIDE COPOLYMERS; HIGH-TEMPERATURE; KJELDAHL METHOD; STABILITY; TECHNOLOGY; RHEOLOGY,"This paper presents a laboratory study on the effectiveness of the nitrogen digestion method to determine the polymer concentrations for 3 different kinds of polyacrylamide-type polymers including partially hydrolyzed polyacrylamides, sulfonated polyacrylamides, and cationic polyacrylamides. Different from the classic nitrogen-bromination method for determination of polymer concentrations, the nitrogen digestion method is based on the digestion of amide groups in the polymers as free nitrate ions. The experimental results show good correlations between the nitrogen content and polymer concentration for individual polymers in aqueous solution with pH range from 5 to 8. It turns out the error of the correlations ranging from.2.0% to.8.6%. Sodium and calcium ions do not impact the nitrogen content measurement, providing the reliability of the measurement in high salinity environment. The influence of anionic surfactant is negligible, however, quaternary ammonium cationic surfactant and betaine-type surfactants have strong impact on the polymer concentration measurement because of the presence of nitrogen in the surfactant molecular structures. In order to improve correct the accuracy of polymer concentration results caused by the hydrolysis reaction of acrylamide groups that happen in the long time polymer flooding process especially at high temperature, infrared (IR) spectroscopy analysis was introduced to identify the hydrolysis degree based on the absorption peaks at 1568 cm(-1) and 1671 cm(-1), representing acrylamide group and acrylic acid group, respectively. The absorbance ratio (Ra) of the peak intensities was correlated with the hydrolysis degree (HD) as Ra = 1.35-0.590*HD. Consequently, a normalized correlation was set up based on the polymer concentration, nitrogen content and hydrolysis degree to improve the accuracy of polymer concentration measurement.",1,1,3
Other topics ,,"Nielsen, Julie; Poulsen, Kristoffer G.; Christensen, Jan H.; Lassen, Charlotte; Solling, Theis, I",Productivity and oil fingerprinting: Application of analytical chemistry in the assessment of reservoir quality,Oil fingerprinting; Reservoir quality; GC-MS; CHEM-SIC; PCA,SOURCE IDENTIFICATION; PETROLEUM; DIAGENESIS; STERANES; BIODEGRADATION; MATURATION; BIOMARKERS; SEDIMENTS; TERPANES; CHALK,"The ability to understand and possibly even predict the productivity of wells across a field is an important accomplishment in a production setting. In the tight Lower Cretaceous chalk field Valdemar, 5 wells have been observed to produce significantly larger oil volumes compared to nearby wells. This study was conducted to map the inter-well differences in the oil composition to better understand the productivity differences. This was done by analyzing any chemical differences of 21 samples from 16 different wells by GC-MS and principal component analysis of summed extracted ion chromatograms (SICs) using the chemometric analysis of selected ion chromatograms (CHEMSIC) method. The sterane (m/z 217 and m/z 218) and C4 (m/z 234) biomarker SICs were found to have chemically meaningful features described by principal component 1 (PC1). The association between these markers and the relative production was modeled to provide a better understanding of the productivity of the different wells. A correlation between oil saturation and productivity was established in the sense that the more mature and thus less viscous oil seem to have charged certain favorably placed reservoir sections first; these locations coincide with the location of the 5 wells in question.",1,1,2
Other topics ,,"Amani, N.; Vipulanandan, C.; Plank, J.",Monitoring the hydration and strength development in piezoresistive cement admixed with superplasticizer and retarder additives,Non-destructive testing; Admixtures; Electrical properties,POLYCARBOXYLATE SUPERPLASTICIZERS; RESISTIVITY; ADMIXTURES; CONCRETE; IMPACT,"With the addition of conductive fibers cement can be modified to become a piezoresistive material so that it is highly sensitive to the type of additive, curing and the changes in the stress and can be monitored via changes in the electrical resistivity. In this study, the effect of two conventional admixtures, a superplasticizer (acetoneformaldehyde-sulfite (AFS)) and a retarder (sodium lignosulfonate (Na-LS)), on the piezoresistive properties of the cement were investigated. It was found that both polymers which present conductive polyelectrolytes decreased the resistivity of the cement, but captured all the critical parameters during curing and also the cement was piezoresistive and the strength was enhanced with 0.3% AFS and 0.4% Na-LS addition after 2 and 28 days of curing. The non-destructive method can be used for real-time sensing of cement and concrete properties in the field.",1,1,2
Other topics ,,"Almeida Cardoso, Giuseppe Sampaio; Freitas, Tiago; do Rosario, Francisca F.; Cajaiba, Joao",Enhancing the permeability of a carbonate rock core by dissolution/ precipitation treatment with organophosphorus additives evaluated by SEM/EDS and ICP-OES,,CRYSTAL-GROWTH; INHIBITION,,1,1,2
Other topics ,,"Geng, Tong; Zhao, Di; Xu, Jun; Ren, Mannian; Cao, Fahai",Removal of nickel and calcium from crude oil using core-shell materials grafted with N-substituted pyridines,Core-shell material; Pyridine; Metal removal; Electric desalination; Crude oil,HEAVY-METAL IONS; POLYMER; DEMETALLIZATION; VANADIUM,"The existence of calcium and nickel in crude oil causes serious damage to oil processing equipment and reduces the quality of products. These metals are extremely hard to remove as they exist in form of stable oil-soluble complexes. If they could be removed during the electric desalination process, economic benefits will be greatly improved. The current study thus aimed to seek clean and non-corrosive demetallizing agents to chelating calcium and nickel during the electric desalination process of crude oil. Two different N-substituted pyridines based core-shell materials of P2VP@SiO2 (2-vinylpyridine) and P4VP@SiO2 (4-vinylpyridine) were first prepared, and their metal adsorption capacity and selectivity were explored and compared. The structure and mass grafting ratios (GR) of two materials were determined by FT-IR, TGA, elemental analysis (EA), GPC, SEM and TEM. The GR of P2VP@SiO2 and P4VP@SiO2 under different monomer concentrations, reaction temperature and duration were studied. In addition, the effects of various process conditions on nickel and calcium removal rates using the prepared P2VP@SiO2 and P4VP@SiO2 were investigated. It was worth noting that due to the difference in N substitution positions, for the same pyridine functional group, P2VP@SiO2 exhibited more stable adsorption selectivity, while adsorption capacity of P4VP@SiO2 for calcium and nickel is much better than P2VP@SiO2. The calcium and nickel removal rates by P4VP@SiO2 reached 61.3% and 67.2%, respectively. Briefly, P4VP@SiO2 could be used as a highly efficient demetallizing agent for removing calcium and nickel in crude oil, with high metal adsorption capacity.",1,1,2
Other topics ,,"Rodrigues, H. T.; Soedarmo, A.; Pereyra, E.; Sarica, C.",Droplet entrainment measurements under high-pressure two-phase low-liquid loading flow in slightly inclined pipes,Droplet entrainment; Entrainment fraction; Low-liquid loading flow,FILM THICKNESS; ANNULAR-FLOW,"This paper presents new experimental data for droplet entrainment measurements under low-liquid loading two-phase flow. Liquid and gas flow rates are representative of the flow in wet gas/condensate pipelines under stratified and annular flow patterns. The novelty in the experimental conditions are the high-pressure (2.76 MPa), large diameter pipe (0.155 m) and inclination from the horizontal (2 degrees). The used fluids are Isopar-L oil and Nitrogen gas. Data are presented as a function of system pressure, liquid and gas superficial velocities, and dimensionless numbers. Comparisons of the new data with previous models are also provided.",1,1,1
Other topics ,,"Ghafur, Ala A.","The origin, differential diagenesis and microporosity characteristics of carbonate mud across a late Paleogene ramp (Iraqi Kurdistan region)",Carbonate muds; Microporosity; Carbonate ramp; Paleogene; Kurdistan; Iraq,BURIAL DIAGENESIS; PARIS BASIN; LIMESTONES; ARAGONITE; CALCITE; MICROCRYSTALS; NEOMORPHISM; DISSOLUTION; RESERVOIRS; BOUNDARY,"Microporosity is common in many Middle Eastern carbonate reservoirs and various interpretations have been offered to explain its development, especially in Cretaceous reservoirs. In this study outcrops of late Paleogene carbonates of the north-eastern Iraq have been studied to assess the variation of porosity across a carbonate ramp and the factors that control its distribution. The depositional system of this late Paleogene succession was a homoclinal ramp dipping SW. Inner-mid ramp carbonate facies are massive to thick bedded units, mostly composed of packstone to grainstone, characterized by high diversity of benthic foraminifers, red algae, corals, gastropods and bivalves. Outer ramp carbonate facies are thin bedded wackestone to calcimudstone. In terms of matrix-dominated facies two distinct rock fabrics and pore systems have been identified: low porosity inner-mid ramp facies and higher porosity outer ramp facies. The inner-mid ramp carbonates show evidence of neomorphism and recrystallization of matrix mud which forms larger crystal size (average 3-4 mu m) with smaller pore size (0.5 mu m or less) and average porosity (8.7%). The outer ramp mud matrices exhibit the major component of planktic foraminifera and coccolith debris have smaller crystal size (average 1 mu m) with larger pore size (1-2 mu m), the average porosity (13.1%). For the inner-mid ramp matrices carbon and oxygen (C & O) stable isotopic values are negative indicating likely meteoric diagenesis. The relatively low strontium (Sr) and magnesium (Mg) values and high manganese (Mn) implies likely recrystallization and replacement of the marine precursor, probably high Mg-calcite and aragonite. In the outer ramp facies, the presence of coccolith and planktic foraminiferal debris indicates less diagenetic modification; the C & O stable isotopic values show less altered range with very low Mn and relatively high Sr and Mg also supporting less alteration. The textural and geochemical evidence supports an origin from a more stable, likely low Mg-calcite precursor.",1,1,1
Other topics ,,"Teng, Bailu",Simulation model size reduction using volume of investigation by fast marching method,Volume of investigation; Computational efficiency; Fast marching method; Implicit-finite-difference method; Shale/tight formations,UNCONVENTIONAL RESERVOIRS,"The numerical methods have been widely utilized to conduct history matching work in the formations with complex in-situ conditions. Due to the fact that the history matching process normally requires running numerous models to find the best match between the history production data and the simulated production data, it is necessary to improve the computational efficiency of the numerical method in order to reduce the computational time. In this work, the author introduces a dynamic-volume-of-investigation (DVOI) implicit-finite-difference (IMFD) method to increase the computational efficiency of the conventional IMFD method. In the DVOI-IMFD method, the computational efficiency has been improved by reducing the simulation model size using volume of investigation (VOI) by fast marching method (FMM). This proposed DVOI-IMFD method is developed based on the concept of VOI. The VOI initiates at the wellbore and extends to the further region of the reservoir as production proceeds. Beyond the VOI, the pressure disturbance in the reservoir is regarded as negligible. Following this scenario, the author assumes that, at each timestep, the pressure response in the region that is beyond the VOI can be neglected, and we only study the pressure response in the region that is within the VOI to approximately characterize the transient flow behavior in the reservoir. Therefore, this proposed numerical approach is composed of two parts, namely, predicting the VOI at each timestep and applying the IMFD within the VOI. In this work, the DVOI is captured with a boundary tracking technique which is called FMM. The author applies this proposed DVOI-IMFD method to different scenarios and compares the simulation outputs and computational time of the DVOI-IMFD method to those of the conventional IMFD method. The calculated results show that the outputs of this proposed method exhibit negligible difference from those of the conventional IMFD method, whereas the computational speed of this proposed method can be significantly faster than that of the conventional IMFD method.",1,1,1
Other topics ,,"Zhao, Lei; Yan, Yifei; Yan, Xiangzhen",A novel risk analysis approach of casing under complex conditions using copulas,In-situ stresses; Parameter uncertainty; Copula-based framework; Dependency structure; Casing risk analysis; Decision-making,SIGNIFICANT WAVE HEIGHT; EXTREME-VALUE ANALYSIS; FREQUENCY-ANALYSIS; MULTIVARIATE; DEPENDENCE; RELIABILITY; INFERENCE; DROUGHT; MODELS,"Failure accidents of casings, designed obeying traditional design standards that have been amended for many times, are still happening nowadays, and existing reliability analysis methods mostly have not considered the dependence structures of variables, it's badly necessary to seek other methods to compensate these two problems and defects. This study proposes a copula-based risk analysis framework of casing in a casing-formation composite system (CFCS). Firstly, a mechanical analysis model of casing under CFCS is established and verified by the simulation method. Secondly, random data sets of the formation parameters are obtained by using logging data, meanwhile, the acquisition methods of statistical data of casing are also provided. Thirdly, the best uncertainty parameters in the given five copulas are inferred by using Bayesian-based Markov chain Monte Carlo (MCMC) likelihood algorithm, which are compared with those from other algorithms; the optimal copula is determined by the Bayesian-based MCMC-estimated method and the squared Euclidean distance (SED), respectively; the posterior joint probability isolines of the copulas are depicted, and isolines from the optimal copula are compared with that of the empirical copula method; the correlation coefficients of variables in CFCS, relative to performance function value, are sorted in magnitude. Finally, a division method of safety level is adopted, and based on the optimal copula, the risk analysis of casing is conducted with considering the bivariate dependence. The proposed framework can provide unique insights into the risk analysis of casing in CFCS with correlations considered and can also be programmed to use in risk management and decision-making systems of petroleum engineering.",1,1,1
Other topics ,,"Zhang, Zhi; Wang, Jiawei; Luo, Ming; Li, Yanjun; Zhang, Wandong; Wu, Jiang; Li, Wentuo",Effect of instantaneous shut-in on well bore integrity and safety of gas wells,,WATER-HAMMER; COLUMN-SEPARATION; PRESSURE PULSE; PIPELINE; STRESS; FLOW,,1,1,1
Other topics ,,"Shojaei, Seyed Abdollah; Osfouri, Shahriar; Azin, Reza; Dehghani, Seyed Ali Mousavi",Kinetic modeling of asphaltene nano-aggregates formation using dynamic light scattering technique,Kinetic modeling; Coin model; Asphaltene; Dynamic light scattering; Aggregation,SASKATCHEWAN CRUDE OILS; MOLECULAR-SIZE; PRECIPITATION; ASSOCIATION,"Asphaltene is known as a class of polar poly-nuclear aromatic compounds of crude oil which is extracted by its solubility difference in normal heptane and toluene. Precipitation of this hydrocarbon compound by changing in fluid thermodynamic conditions decelerates flow when passing through up-stream and down-stream processes. In order to understand the thermodynamics of the deposition phenomenon, one needs to pay attention to the kinetics of the aggregation of these nano-particles. In this study, the kinetics phenomenon of aggregation of asphaltene clots in toluene is investigated using dynamic light scattering (DLS) technique. The dynamic light scattering results for super dilute solutions showed that at high and low sonication time, the asphaltene is monomeric and polymeric forms, respectively. Moreover, the experiments revealed that the relationship between the amount of sonication energy given to the solutions and the particle size is logarithmic. The DLS spectra obtained from the lower-sonication solutions were decomposed to the four normal distributions using the deconvolution technique, indicating four different clusters in the solution. The ratio of the area of each normal distribution to the area of the spectrum indicates the fraction of the presence of each cluster in the solution. For the lower and the higher concentrations of the asphaltene solution, the percentage of nano-aggregates is between 8%-41% and 4%-51%, respectively. By assuming the asphaltene molecule to be on a coin-shaped plate and forming a pi bond with a minimal coinage overlap, the coin model of asphaltene aggregation kinetics has been developed. The concentration of each nano-aggregates in equilibrium solution is calculated according to the fraction of its presence in the medium and the coin model. Then, these equilibrium concentrations are used to calculate the equilibrium reaction constants. The correlation coefficient between the reaction constants and the diffusion coefficients of the clots in the solutions for all reactions was found to be equal to 0.42. This same value indicates that this coefficient is independent of the concentration of asphaltene in the solution and is dependent on the nature of the solution.",1,1,1
Other topics ,,"Anya, Alexander; Emadi, Hossein; Watson, Marshall",Effect of size and shape of oil well cement test specimen on uniaxial compressive strength measurements,,CONCRETE,"During unconfined compressive strength (UCS) tests of oil well cement, it is not uncommon for standard cubic test specimens to require some processing in order to meet the requirements of end face planarity and parallelism. Also, unique research scenarios may produce cement specimens for which UCS data is required but that deviate slightly from the 50.8 mm cube shape recommended by API for testing UCS of oil well cements. Little has been published with regards to the effect of such minor specimen shape variations on the UCS value measured or on the acceptability of the obtained measurement. Thus, different oil well cement formulations of varying compressive strength were tested for UCS using different specimen shapes and sizes in order to quantify the effect of geometry on the measured UCS. The shapes and sizes tested were chosen to cover the range of sizes that could result due to slight deviations from the API-recommended standard testing geometry. The validity of the UCS measurement for each specimen geometry was also tested for validation using statistical techniques outlined in ASTM C109 and ASTM C670. The results of this study show that there are no discernable direct size effects for the range of sizes tested even though the shape and size strongly affect the reliability or validity of the UCS reading.",1,1,1
Other topics ,,"Bazooyar, Bahamin; Shaahmadi, Fariborz; Jomekian, Abolfazl; Darabkhani, Hamidreza Gohari",Modelling of wax deposition by perturbed hard sphere chain equation of state,Solid-liquid equilibria; Paraffin; WAT; n-alkane; Hydrocarbon,ASPHALT FLOCCULATION; PRECIPITATION; EQUILIBRIA; FLUIDS,"This article presents a model to predict the wax appearance temperature (WAT) and the quantity of wax deposition in eight different n-alkane mixtures using a correlative technique. The perturbed hard sphere chain equation of state (PHSC EoS) was employed in conjunction with the multi-solid model to describe the liquid-liquid and solid-liquid equilibria. The results are compared with experimental data. The results showed that PHSC EoS for some mixture of n-alkanes can perceptibly outperform the sole solid solution theory, improving the modelling of wax deposition quantities and wax appearance temperature by giving predictions closer to experimental values.",1,1,1
