Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Fracture,Natural Fractures,"Fan, Cunhui; Li, Hu; Qin, Qirong; He, Shun; Zhong, Cheng","Geological conditions and exploration potential of shale gas reservoir in Wufeng and Longmaxi Formation of southeastern Sichuan Basin, China",Shale gas; Geological conditions; Tectonic uplift; Preservation conditions; Longmaxi Formation; Southeastern Sichuan Basin,TIGHT SANDSTONE RESERVOIRS; PERMIAN LUCAOGOU FORMATION; ORDOS BASIN; UPPER ORDOVICIAN; TECTONIC FRACTURES; DINGSHAN AREA; SOUTH CHINA; OIL-SHALE; GEOCHEMICAL CHARACTERISTICS; PRESERVATION CONDITIONS,"The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R-o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration.",39,40,8
Fracture,Natural Fractures,"Tan, Peng; Pang, Huiwen; Zhang, Ruxin; Jin, Yan; Zhou, Yingcao; Kao, Jiawei; Fan, Meng",Experimental investigation into hydraulic fracture geometry and proppant migration characteristics for southeastern Sichuan deep shale reservoirs,Hydraulic fracturing; Deep shale; Proppant migration; Bedding plane,PROPAGATION BEHAVIOR; SIMULATION; INITIATION; NETWORK; OPTIMIZATION; MORPHOLOGY; CRITERION; BRITTLE; MODEL; ROCK,"Difficulties in fracture extension and proppants adding were two key factors that affected the stimulated volume of deep shale reservoir. To clarify the mechanism of hydraulic fracture (HF) propagation and proppants migration, several groups of large-scale true tri-axial fracturing tests with an ingenious method of sand adding were performed utilizing deep Longmaxi shale outcrops from southeastern Sichuan. The interaction behavior between vertical HF and bedding plane (BP) was discussed. The results showed that due to the low bonding strength, the BPs could be easily activated even under high vertical stress difference coefficient. Based on the different influenced degrees of BPs, four types of HF geometries in the vertical direction were observed, that is, transverse HF, horizontal HF, step-shaped HF with fissure opening, and multilateral step-shaped HF network. The migration distance of proppants was limited and almost all the proppants were distributed around the wellbore, thus inducing the formation of multiple secondary HFs. When there are natural fractures (NFs) with large aperture around the wellbore, proppants almost entirely distributed along the NFs. The main factor, causing the difficulty of fracture extension and proppants migration, was the complex HF geometry characterized by the multi-branched fractures with slippage of BPs.",33,34,6
Fracture,Natural Fractures,"Mahesar, Aftab Ahmed; Shar, Abdul Majeed; Ali, Muhammad; Tunio, Abdul Haque; Uqailli, Muhammad Aslam; Mohanty, Udit Surya; Akhondzadeh, Hamed; Iglauer, Stefan; Keshavarz, Alireza","Morphological and petro physical estimation of Eocene tight carbonate formation cracking by cryogenic liquid nitrogen; a case study of Lower Indus basin, Pakistan",Tight carbonate rocks; Petro physics; SEM; AFM; Nano indentation; Liquid nitrogen,PORE STRUCTURE; COAL DAMAGE; GLOBAL OIL; EVOLUTION; PERMEABILITY; RESERVOIRS; SALINITY; FREEZE,"Significant amounts of hydrocarbons are contained in tight carbonate rocks like those within the Indus basin of Pakistan, but due to their unconventional nature, their extraction is difficult. This can be completed/conducted by properly characterizing its mineralogical, geochemical and microstructural properties. In this context, Hydraulic fracturing and acidizing are the most common fracture stimulation techniques. However, they suffer significant technical and environmental flaws. Liquid Nitrogen (LN2) fracking is considered as one of the best alternatives compare to hydraulic fracturing or acidizing due to its eco-friendly nature. In fact, after exposer to LN2, super cryogenic feature of the rock causes porosity, permeability and fracture conductivity enhancement due to thermal shock without any environmental consequences. The effect of Liquid Nitrogen fracking on tight carbonate outcrops collected from the Indus basin is investigated in the present study. Scanning Electron Microscopy (SEM) reveals the clear appearance of wide pore fractures with sizes from 4 mu m to 50 mu m, when subjected to liquid Nitrogen (LN2) treatment ranging from 30 to 90 min' duration. Furthermore, SEM and Atomic Force Microscopy (AFM) images also indicate clear pore fractures in tight carbonate rocks along with increased pore connectivity. Moreover, following liquid nitrogen treatment of up to 90 min the permeability of tight carbonate increases by 53% and increases in porosity by 73%. Results from SEM studies suggest that visible fractures occur in the tight carbonate samples with liquid nitrogen treatment because of the freezing temperature (-196 C-square) of Liquid Nitrogen. In addition to this, Nano indentation moduli depict significant decreases in tight carbonate rocks, both before and after exposure to LN2, as a result of increases in liquid rock compressibility. In this regard, a 50 mN force decreased from 50.57 GPa to 24.37 GPa and for a 200 mN force this decreased from 45.77 GPa to 26.67 GPa. This research depicts the significant effect of Liquid Nitrogen freezing on the fracturing of carbonate rocks.",32,32,8
Fracture,Natural Fractures,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Wang, Suifeng; Wang, Tao; Shi, Xiaohong; Dong, Qingxiang; Li, Junyang",Natural fractures in soft coal seams and their effect on hydraulic fracture propagation: A field study,Soft coal seam; Qinshui Basin; Natural fractures; On-site hydraulic fracturing; Hydraulic fractures; Particle flow method,PORE STRUCTURE CHARACTERIZATION; HIGH-RANK COAL; MECHANICAL-PROPERTIES; RESERVOIR PRESSURE; ACOUSTIC-EMISSION; FIB-SEM; METHANE; PERMEABILITY; MODEL; ROCK,"Natural fractures provide direct flow channels for coalbed methane (CBM) production and gas outburst control. However, in soft coal seams, the characteristics of natural fractures and their effect on hydraulic fractures are still unclear. In this study, a spatial system of visible natural fractures was established through underground dissection and measurement of ground joints from a case study of the Xinyuan Coal Mine in the northern Qinshui Basin, China. Our results show that the orientations of the subsurface exogenetic fractures of the coal seams are consistent with the macrostructural joints on the ground surface in the same tectonic setting. The exogenetic fractures of the coal seams have dominant orientations with approximately equal spacing. Next, a field test of a large-scale hydraulic fracturing project with a volume of up to 2000 m(3) was conducted. The on-site observation of the underground coal seams revealed that the propagation orientation of the vertical propped fractures coincides with the predominant orientation of the natural fractures. Even at a high constant injection rate (12 m(3)/min), the corresponding injection pressure was not constant during the propagation of the hydraulic fractures, and this can be attributed to the effect of the depth of the coal seam, internal natural fracture network, and normal fault. Additionally, a two-dimensional (2D) particle flow simulation (PFC2D) showed that the propagation of the hydraulic fracture is controlled by the orientations of the natural fractures and the principal stresses. The orthogonal fracture network showed more sensitivity to joint spacing than the layered fracture network in controlling the hydraulic fractures. Finally, fluid detection of the coalbed demonstrated that the flow range of the fracturing fluid in the natural exogenetic fractures was up to a few hundred meters. The flow direction was consistent with that of the natural fractures. A comprehensive analysis of the natural fractures contributes to the identification of flow channels and helps in the design of hydraulic fracturing engineering in soft coal seams.",20,20,9
Fracture,Natural Fractures,"Xu, Shang; Gou, Qiyang; Hao, Fang; Zhang, Baiqiao; Shu, Zhiguo; Zhang, Yuanyin","Multiscale faults and fractures characterization and their effects on shale gas accumulation in the Jiaoshiba area, Sichuan Basin, China",Shale; Multiscale faults and fractures; Seal conditions; Accumulation mechanism; Jiaoshiba area,SILURIAN LONGMAXI FORMATION; UPPER ORDOVICIAN WUFENG; PORE STRUCTURE; MARINE SHALE; BOREHOLE IMAGE; SCALE PORES; ENRICHMENT; BARNETT; STORAGE; LOGS,"The distribution and development of faults and fractures in organic-rich shales are important factors for the accumulation or loss of shale gas. In this work, merged three-dimensional seismic data, automated fault extraction, imaging logging, rock core examination, micro-CT scans, and field emission scanning electron microscopy were used to precisely characterize the distribution of faults and fractures of the Wufeng-Longmaxi shales from the Zilichang Block, Jiaoshiba area. The effects of faults and fractures on the accumulation and loss of shale gas were analyzed. The results show that the microfractures of shale samples from the JYA well of the Zilichang Block mainly consisted of intergranular, intragranular, and contraction fractures, and the fracture porosity of the samples is approximately 1.24%. These fractures help to increase the storage space of the shale reservoirs and are conducive for shale gas accumulation. In micro-CT scans, the microfractures were linked in a network-like structure and generally had excellent connectivity. Therefore, the microfractures could enhance the seepage capacity of the shale reservoirs and help the shale gas to migrate to hydraulically induced fractures. As a result, the productivity of the shale reservoirs could be dramatically improved. Macroscopic fractures were found to play a key role in the storage of shale gas. Many natural fractures, mainly are faults and open fractures, have developed in the caprock strata that directly overly the main production layers shales. The shale gas direct seal conditions are poor, which is not conducive to shale gas accumulation. Therefore, the Wufeng-Longmaxi shales in the JYA well is a relatively open shale system, with a formation pressure coefficient and gas saturation value of 0.96 and 37%, respectively. The single-well hydraulic fracturing productivity of the JYA well is low, with an absolute open flow value less than 0.5 x 10(4) m(3)/d.",19,19,7
Fracture,Natural Fractures,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Fracture,Natural Fractures,"Huang, Liuke; Liu, Jianjun; Zhang, Fengshou; Fu, Haifeng; Zhu, Haiyan; Damjanac, Branko",3D lattice modeling of hydraulic fracture initiation and near-wellbore propagation for different perforation models,Lattice modeling; Perforation model; Hydraulic fracturing; Breakdown pressure; Fracture complexity; Near-wellbore,NATURAL FRACTURES; FLUID-INJECTION; ORGANIC SHALE; RESERVOIR; HETEROGENEITY; SIMULATION; PARTICLE; SYSTEM,"This work introduces 3D lattice modeling of hydraulic fracturing initiation and near-wellbore propagation for different perforation models, including spiral perforation, oriented perforation and Tristim perforation. For each perforation model, a total of six perforation tunnels are explicitly modeled and the representative intermediate states are chosen to analyze the results. The numerical simulation results show that the perforation tunnels guide the generation of initial microcracks at the roots of the perforation tunnels once the injection starts, however, the subsequent fracture propagation is controlled by the relative locations of perforation tunnels and the stress interference among different perforation tunnels. The spiral perforation gives the highest breakdown pressure while the Tristim perforation gives the lowest. Trans-wellbore fracture surfaces caused by the generation of large amount of microannulus cracks is the main reason of the pressure breakdown. The magnitude of the breakdown pressure is associated with the level of fracture complexity generated before the breakdown. Despite the variation of breakdown pressure for different perforation models, both the initial minimum pressure after the breakdown and the propagation pressure are nearly identical. The study provides a theoretical basis for understanding fracture initiation and near-wellbore tortuosity.",14,18,7
Fracture,Natural Fractures,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Fracture,Natural Fractures,"Yu, Kun; Gan, Yuting; Ju, Yiwen; Shao, Chunjing",Influence of sedimentary environment on the brittleness of coal-bearing shale: Evidence from geochemistry and micropetrology,Sedimentary environment; Shale brittleness; Micropetrology; Trace element; Rare earth elements,WATER-COLUMN ANOXIA; PB-NB-GA; HUAINAN COALFIELD; HUAIBEI COALFIELD; ORGANIC-MATTER; PERMIAN COALS; MARINE SHALE; CHINA IMPLICATIONS; NATURAL FRACTURES; BARNETT SHALE,"The brittleness of shale is an important index to evaluate the fracture system and reformability of a shale reservoir. This study provides geochemical and micropetrological parameters as proxies for the paleohydrodynamics, redox condition, paleosalinity, and paleoclimate of transitional coal-bearing shale in the Huainan coalfield, eastern China. Thus, combining these data with organic geochemistry parameters, this study aims to investigate the most important factors controlling shale brittleness during the sedimentary process. The results indicate that various important physical and chemical factors (sedimentary facies, hydrodynamics, redox condition, salinity, and climate) of the paleoenvironment have exerted an intense influence on shale brittleness involving complex mechanisms. Rare earth element indexes suggest that marine facies are conducive to the enrichment of carbonate minerals and quartz, thereby improving the brittleness of shale. Micropetrologyical evidence indicates that with an increase of hydrodynamic force, a large number of terrestrial materials are introduced, leading to increased clay mineral content and significantly reducing the brittleness of shale. U/Th, V/Cr, and Ni/Co ratios and Pyrite indexes suggest that reducing water condition accounts for the enrichment of pyrite and the preservation of biogenic quartz. Thus, this increases the content of brittle minerals, while an oxidative environment significantly decreases the brittleness of shale. B/Ga ratios indicate that higher salinity promotes the dissolution of CO2, leading to precipitation of carbonate minerals and thus increasing the content of brittle minerals in shale, which is supported by the salinity characteristics obtained by the B content. In addition, Ba content indicates that a warm climate (humid) is the best condition for the growth of marine life and the development of carbonate minerals, which promotes the enrichment of brittle minerals obviously. While a hot climate (dry) results in the import of more terrestrial clay minerals in the provenance, thereby inhibiting shale brittleness.",14,14,2
Fracture,Natural Fractures,"Xie, Jing; Gao, Mingzhong; Zhang, Ru; Peng, Gaoyou; Lu, Tong; Wang, Fei",Experimental investigation on the anisotropic fractal characteristics of the rock fracture surface and its application on the fluid flow description,Rock fracture surface; Fractal dimension; Fluid flow; Anisotropic characteristics,ROUGH FRACTURE; HYDRAULIC CONDUCTIVITY; PERMEABILITY MODEL; SINGLE; DIMENSION; RESERVOIR; STRENGTH; APERTURE; LENGTH,"Based on the anisotropic fractal characteristics of natural fracture surfaces, a fractal fluid flow model was developed. Three-dimensional printed fracture models were built using the morphological information of an actual tensile and shear fracture surface of a rock. The impacts of the fractal dimension on the fluid flow characteristics were investigated. The results demonstrated that the concentration distribution of the undulating height of tensile fracture was larger than that of shear fracture. The fractal dimension of fracture lines with different directional sections ranges from 1.01 to 1.03, which results in the fluid flow anisotropy of fracture surfaces. As predicted by the theoretical model, the fluid flows along the tensile fracture surface and the shear fracture surface in different directions are 0.7-1.2 times and 0.9-1.1 times the average flow rates, respectively. With increasing pressure head, the Reynolds number linearly increased, and the Euler number first rapidly decreased and then slowly decreased.",13,13,10
Fracture,Natural Fractures,"Ju, Wei; Niu, Xiaobing; Feng, Shengbin; You, Yuan; Xu, Ke; Wang, Geoff; Xu, Haoran","Present-day in-situ stress field within the Yanchang Formation tight oil reservoir of Ordos Basin, central China",In-situ stress field; Tight oil reservoir; Yanchang formation; Stress regime; Natural fracture; Ordos basin,SEDIMENTARY-ROCKS; LOW-PERMEABILITY; TECTONIC STRESS; STATE; AREA; EXPLORATION; FRACTURES; PATTERN; REGION; ORIENTATIONS,"The present-day in-situ stress field has many important and practical applications during the exploration and development of hydrocarbon resources. The Ordos Basin is a significant petroliferous basin in China, within which, the Yanchang Formation serves as the most significant tight oil reservoir. However, an overview of previous studies indicates that little was known as to the present-day stress state in the Yanchang Formation. Therefore, the present-day stress field in the Yanchang Formation tight oil reservoir of the Ordos Basin is systematically analyzed in this study. The orientation of horizontal maximum principal stress (S-Hmax) within the Yanchang Formation of Ordos Basin ranges between north-northeast-south-southwest-trending (NNE-SSW) and east-northeast-west-southwest-trending (ENE-WSW) based on interpretations of borehole breakouts and drilling-induced fractures from borehole imaging logs. The S-Hmax orientation shows various tendencies in different wells, which may result from differential development in lithology, natural fracture and bedding plane over various regions. The estimated magnitudes of vertical stress (S-v), S-Hmax and horizontal minimum principal stress (S-hmin) in the studied wells indicate that the normal faulting stress regime is dominant within the Yanchang Formation. In addition, the geomechanical assessments of wellbore stability and natural fracture reactivation are also performed. Natural fractures in the Yanchang Formation Chang 7 tight oil reservoir of Ordos Basin are developed striking mainly in the northeast-southwest-trending (NE-SW) and west-northwest-east-southeast-trending (WNW-ESE). Among them, those fractures with NE-SW-trending strikes are more conductive with reference to the present-day stress state, contributing more to tight oil production in the Ordos Basin. In addition, within the Yanchang Formation, if horizontal wells are drilled towards the NNE-SSW-trending to ENE-WSW-trending, they are more likely to have wellbore instability issues. The results in this study provide important geological information for tight oil production in the Yanchang Formation of Ordos Basin.",13,14,3
Fracture,Natural Fractures,"Aljuboori, Faisal Awad; Lee, Jang Hyun; Elraies, Khaled A.; Stephen, Karl D.",The effectiveness of low salinity waterflooding in naturally fractured reservoirs,Low salinity (LoSal) waterflooding; Naturally fractured reservoirs (NFR's); Wettability alteration; Residual oil reduction; Qamchuqa reservoir,OIL-RECOVERY; BRINE COMPOSITION; MAUDDUD FORMATION; WATER INJECTION; WETTABILITY; FLOW; SIMULATION; SANDSTONE; FIELD,"Low Salinity (LoSal) waterflooding is a technique which promises to improve and enhance oil recovery. The method has been studied widely in the laboratories using various core plug samples of sandstones and carbonates. Most of the experimental outcomes have demonstrated the possibility of recovery increment in conventional reservoirs. Meanwhile, it is rare to find a discussion in these experiments about the effectiveness of LoSal waterflooding in naturally fractured reservoirs. In this paper, we investigate the potential benefits in fractured reservoirs using simulations. It is often reported from coreflood experiments that LoSal injection has the ability to alter the rock wettability and reduce residual oil saturations through chemical and physical interactions between the rock-oil-water system. Based on the published work, we have calculated relative permeability curves to represent the flow in regions flooded with LoSal water. This includes a qualitative representation of uncertainty. In this sense, the relative permeabilities are a proxy for any physical and chemical mechanisms which are not explicitly represented. The newly generated flow curves were applied to simulate LoSal waterflooding using a fine-scale model and a field scale model based on a fractured reservoir from the Middle East. The simulation results underline the benefits of LoSal whereby the oil recovery from fractured reservoirs can be increased. An additional benefit is the control of water production. The fine-scale modelling has provided an in-depth analysis and accurate estimation of the oil recovery without modelling artefacts or limitations, where an increment of (12-14)% of the Stock Tank Oil Initially In Place (STOIIP) were obtained under secondary and tertiary recovery scheme, respectively. The investigated scenarios demonstrated a sensitivity to the newly generated flow curves and how they affect the ultimate oil recovery. However, for the field scale model, a higher oil production rate has maintained during LoSal waterflooding up to 32 K BPD by the end of year fourteen compared with 25 K BPD in case of high salinity scenario, besides a reduction in the produced water by 35.7%. Therefore, the effectiveness of LoSal brine required a longer time frame to observe the improvements in the oil displacement or sweep efficiency.",13,13,2
Fracture,Natural Fractures,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Fracture,Natural Fractures,"Ren, Wenxi; Lau, Hon Chung",Analytical modeling and probabilistic evaluation of gas production from a hydraulically fractured shale reservoir using a quad-linear flow model,Shale gas; Secondary fractures; Analytical model; Global sensitivity analysis; Probabilistic assessment,PRESSURE-TRANSIENT ANALYSIS; TIGHT OIL-RESERVOIRS; HORIZONTAL WELLS; SENSITIVITY-ANALYSIS; NATURAL FRACTURES; COMPREHENSIVE MODEL; BARNETT SHALE; TRANSPORT; MULTIPLE; PERFORMANCE,"During hydraulic fracturing, secondary fractures are created around hydraulic fractures and serve as important channels connecting the shale matrix and the hydraulic fractures. We developed an analytical model to simulate shale gas production from a multi-stage fractured horizontal well. The analytical model is based on the trilinear flow model, but it is free from the assumption that the length of secondary fractures is equal to the half-distance between hydraulic fractures. This analytical model captures the fundamental characteristics of a hydraulically fractured shale reservoir by incorporating transient gas flow in the matrix, secondary fractures, and hydraulic fractures. Because this model describes four linear flow systems (unstimulated reservoir volume, matrix in the stimulated reservoir volume, secondary fracture, and hydraulic fracture), it is called the quad-linear flow model. Production data from two shale gas wells were used to validate the model. Moreover, using the variance-based method and quasi-Monte Carlo simulation, we developed a stochastic framework to perform a probabilistic assessment of shale gas production. We also conducted a global sensitivity study with nine uncertainty parameters to identify important parameters and their interactions that affect well productivity. The results indicate that the existence of dense secondary fractures (the distance between secondary fractures is small) results in higher initial production rate and ultimate recovery, but a sharper decline in production rate. Increasing the length of the secondary fractures can more effectively enhance gas production in the presence of dense secondary fractures. Moreover, the benefits of dense secondary fractures are mostly limited to a high porosity shale reservoir.",12,12,3
Fracture,Natural Fractures,"Zeng, Jie; Li, Wai; Liu, Jishan; Leong, Yee-Kwong; Elsworth, Derek; Tian, Jianwei; Guo, Jianchun; Zeng, Fanhua",Analytical solutions for multi-stage fractured shale gas reservoirs with damaged fractures and stimulated reservoir volumes,Shale gas reservoir; SRV; Fracture damage,LINEAR FLOW MODEL; HORIZONTAL WELLS; PERMEABILITY; ADSORPTION; TRANSPORT; MECHANISMS; NANOPORES; IMPACT; FACE,"After performing hydraulic fracturing in shale reservoirs, the hydraulic fractures and their adjacent rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures; (2) partially propped fractures with unpropped or poorly propped sections at the middle or tail of fractures; (3) fracture face damage; and (4) multiple damage cases. The classical fracture skin factors are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple damage and partially propped fractures. In this article, a new analytical model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs. The matrix model is a spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly envelops the matrix. The reservoir-fracture flow model is a ten-region linear flow model which can handle fracture damage mechanisms. Specifically, the inner reservoir region is treated as an SRV where the secondary fracture permeability obeys a power-law decreasing trend due to the attenuate stimulation intensity. This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of a published linear flow model. New type curves are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Different damage mechanisms all control specific flow regimes but the fracture face damage shows the slightest influence. In the multiple fracture damage case, some typical flow regimes can be easily identified except those induced by the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.",12,12,3
Fracture,Natural Fractures,"Gu, Yang; Ding, Wenlong; Tian, Qianning; Xu, Sheng; Zhang, Wei; Zhang, Bairen; Jiao, Baocheng","Developmental characteristics and dominant factors of natural fractures in lower Silurian marine organic-rich shale reservoirs: A case study of the Longmaxi formation in the Fenggang block, southern China",The longmaxi shale; Natural fractures; Developmental characteristics; Dominant factors; South China,CAMBRIAN NIUTITANG FORMATION; NORTHERN GUIZHOU PROVINCE; FORT-WORTH BASIN; BOHAI BAY BASIN; BARNETT SHALE; CENGONG BLOCK; QUANTITATIVE PREDICTION; LOGGING IDENTIFICATION; MIGRATION PATHWAYS; GAS-STORAGE,"Natural fractures are an important storage space and main seepage channel of shale gas reservoirs, controlling the permeability of shale gas reservoirs and the migration, enrichment, preservation conditions and single-well productivity of shale gas. The successful production of shale gas has shown that the development of natural fractures in shale is beneficial, and a high degree of natural fracture development can allow a large-scale fracture network to form in the process of hydraulic fracturing, which can effectively improve the shale reservoir conditions. The development of fractures in shale reservoirs not only effectively improves the permeability of shale reservoirs but also increases the gas content, improving the productivity of shale reservoirs. Therefore, the degree of shale fracture development is the key to the production of shale gas reservoirs. Through the outcrop, shale core, thin section and scanning electron microscopy observations of the Longmaxi shale in the Fenggang block of Guizhou Province and the experimental data analysis of the corresponding samples, the fracture characteristics are statistically analyzed, and the fracture development characteristics and dominant factors are discussed in depth. The study area is located in the complex tectonic area of southern China, which experienced a strong tectonic deformation and a high degree of fracture development. The multiscale characterization of Longmaxi shale fractures indicates the following: the fractures observable in the field are mainly regional structural fractures, fold-related fractures, fault-related fractures and bedding fractures; additionally, the statistical analysis of core fractures shows that the structural fractures, including high-angle shear fractures, tension-shear fractures, and low-angle slip fractures are dominant and that most of them are filled with calcite; the micro-fractures are mainly intragranular fractures and intergranular fractures, and the fracture aperture is 0.01-2 mu m. The degree of fracture development is controlled by structural factors, lithology, mineral composition and content, TOC, rock mechanical properties, paleoenvironment and diagenesis, and the structural factors are the most influential. The gentle transition zone of a fold limb is a favorable position for shale gas structure preservation. Fractures significantly impact the formation of seepage channels and storage space and the connection of isolated micropores, so the degree of fracture development has a positive relationship with the total and analytical gas contents.",11,13,8
Fracture,Natural Fractures,"Chen, Hongquan; Onishi, Tsubasa; Olalotiti-Lawal, Feyi; Datta-Gupta, Akhil",Streamline tracing and applications in embedded discrete fracture models,Fractured reservoir; Streamline tracing; Embedded discrete fracture models; Flow diagnostics; Water flood optimization,FLOW DIAGNOSTICS; SHALE FORMATION; PATH LINES; BLACK-OIL; SIMULATION; RESERVOIR; PRESSURE,"Fractures play important role in unconventional resources by influencing the fluid flow pattern underground. Streamline-based flow diagnostic is important to the history matching or operational optimization process of fractured reservoirs. This paper presents a robust streamline tracing framework for use in the Embedded Discrete Fracture Models (EDFM) and several applications including flow visualization, flow diagnostics, and rate allocation optimization. The proposed streamline tracing framework is based on a boundary layer method that can honor the flux communications between the matrix and fractures or between fracture and fracture. The proposed method is benchmarked with a semi-analytical solution and its robustness is illustrated by a series of numerical examples encompassing different levels of geologic and geometrical complexity. Streamlines in complex fracture networks provide flow diagnostics such as sweep efficiency and connectivity of wells and fractures. The streamlines are then utilized to develop a workflow for rate allocation optimization for waterflood in naturally fractured reservoirs. We apply a streamline-based gradient free algorithm whereby both injection and production rates are adjusted under realistic operational constraints to a field scale fractured reservoir. This approach only requires a few forward simulations and therefore offers significant advantage in terms of computational efficiency. It is confirmed that the optimized schedule provides improvements in oil recovery and sweep efficiency compared to the base scenario with uniform injection and production rates.",11,11,1
Fracture,Natural Fractures,"Liu, Yongzan; Liu, Lijun; Leung, Juliana Y.; Moridis, George J.",Sequentially coupled flow and geomechanical simulation with a discrete fracture model for analyzing fracturing fluid recovery and distribution in fractured ultra-low permeability gas reservoirs,Coupled flow and geomechanics; Flowback; Fracturing-fluid distribution; Tight/shale gas; Fracture geometry,TRANSIENT-BEHAVIOR; WATER-FLOWBACK; TIGHT-GAS; SHALE; WELLS; PERFORMANCE; MECHANISMS; IMPACT,"More accurate characterization and prediction of the in-situ distribution of fracturing fluid in fractured reservoirs are needed for enhancing well productivity. In this study, an implicit-sequentially coupled flow/geomechanics simulator incorporating an efficient discrete fracture model is developed to model fluid distribution and recovery performance of ultra-low permeability gas reservoirs. The finite-volume and finite-element methods are used for space discretization of the flow and geomechanics equations, respectively, while the backward Euler method is employed for time discretization. The flow and geomechanics equations are solved sequentially based on fixed-stress splitting. An efficient discrete-fracture model is used to explicitly model the fractured system. Flexible unstructured gridding is employed to model arbitrarily-oriented fractures. The interrelations among pore volume, permeability and geomechanical conditions are considered dynamically using two-way coupled flow and geomechanics computations. The geometry of fracture (networks) due to hydraulic fracturing has significant impacts on the fracturing fluid recovery efficiency and ensuing fluid distribution. Under the same injection volume, the fracturing fluid recovery is higher when the fracture geometry is planar. Fluid recovery is relatively lower whenever natural fractures are activated during fracturing treatments; flowback time is also shortened when complex fracture network with enlarged fracture interface is present. Fracturing fluid in hydraulic fractures may leak off into the natural fractures and subsequently imbibes into the surrounding matrix due to capillarity effects. The fracturing fluid recovery and in-situ fluid distribution are sensitive to the shut-in duration and fracture closure behavior. This study analyzes the coupled flow-geomechanical responses of fractured gas reservoirs during the post-fracturing periods. Understanding the fate of the fracturing fluid can provide insights on, to some extent, the stimulated fracture volume, size of the water invasion zone, and efficiency of the fracturing design. The simulation predictions can also provide more accurate initial reservoir conditions (e.g. distributions of different phases and pressure) for long-term well performance estimation.",10,10,5
Fracture,Natural Fractures,"Wei, Shiming; Jin, Yan; Xia, Yang; Lin, Botao",The flowback and production analysis in sub-saturated fractured shale reservoirs,Sub-saturated shale reservoirs; Flowback; Production; Gas-water flow; Discrete fractures,DISCRETE-FRACTURE; 2-PHASE FLOW; GAS-FLOW; HYDRAULIC-FRACTURE; TRIPLE-CONTINUUM; NUMERICAL-METHOD; HORIZONTAL WELL; POROUS-MEDIA; MODEL; SIMULATION,"The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced ""skin factor"" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model.",10,10,3
Fracture,Natural Fractures,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Fracture,Natural Fractures,"Zhang, Yanjun; Ge, Hongkui; Shen, Yinghao; Jia, Leilei; Wang, Jianbo",Evaluating the potential for oil recovery by imbibition and time-delay effect in tight reservoirs during shut-in,Potential evaluation; Oil recovery by imbibition; NMR; Time-delay effect; Shut-in,FORMATION DAMAGE; GAS-RESERVOIRS; SHALE; FLOW; ADSORPTION; SIMULATION; WELL,"When stimulated only by natural energy, tight oil reservoirs have low production efficiency. Improving the potential for oil recovery by imbibition is essential to enhancing oil production. Shut-in is an effective way to make good use of the potential for oil recovery by imbibition. In this study, imbibition experiments and nuclear magnetic resonance (NMR) testing were combined to reveal the characteristics of spontaneous imbibition and the T-2 value of the oil recovery potential by imbibition in tight oil reservoirs. The main factors affecting the potential for oil recovery by imbibition were studied. We also discussed the relationship between clay minerals and the potential for oil recovery by imbibition, especially the time-delay effect of imbibition displacement. A modified model based on the static balance time for spontaneous imbibition was proposed to calculate the field shut-in time. The results show that the static spontaneous imbibition balance time of tight oil reservoirs are significantly different in various zones. The oil recovery by imbibition has an obvious time-delay effect and it could put the oil in non-movable pores under natural conditions to use. Internal conditions like microscopic pore structure and the type of clay minerals affect the oil recovery by imbibition on small pores (T-2 < 100 ms). External conditions like reservoir temperature, pressure, and bedding affect oil recovery by imbibition in small and large pores. The clay minerals expand after the interaction between fracturing fluids and rock. Meanwhile, oil is discharged with compression of those pore space. To optimize the shut-in time of a tight reservoir, these effects of clay behavior can suggest good practices in hydraulic fracturing.",9,9,4
Fracture,Natural Fractures,"Zhang, Qitao; Zhu, Weiyao; Liu, Wenchao; Yue, Ming; Song, Hongqing",Numerical simulation of fractured vertical well in low-permeable oil reservoir with proppant distribution in hydraulic fracture,Proppant distribution; Effective fracture length; Vertical well; Threshold pressure gradient; Moving boundary; Flow field,TIP SCREEN-OUT; TRANSPORT; FLOW; FLUID; MODEL; KGD; LAW,"In this paper, numerical simulations of fractured vertical well in low-permeable oil reservoir are carried out and two issues: threshold pressure gradient (TPG) in reservoir matrix and proppant distribution in hydraulic fractures are focused on. A physical definition of effective fracture length (EFL) is presented to evaluate the fracture effectiveness due to uneven proppant distribution. In terms of numerical processing for TPG, based on the subsurface Darcy's flow module in COMSOL Multiphysics, an effective numerical simulation method is adopted by substituting the gravitational acceleration vector in Darcy's law (Liu et al., 2019b). The simulation results show that, proppant distribution has great influence on fracture effectiveness. Unappealing proppant distribution can reduce effective fracture length by 49.6%, which is negative for low-permeable oil reservoir development. TPG in reservoir matrix mainly affects the moving boundary and pressure-disturbed area in reservoir. When TPG in matrix reduces from 0.02 MPa/m to 0 MPa/m, the distance of moving boundary at 300 days could increase for almost double and pressure-disturbed area enlarged drastically for around 74%. Furthermore, a heterogenous low-permeable oil with secondary fracture networks is designed to study the joint effect of TPG and proppant distribution. If we neglect these two factors, cumulative oil rate will be greatly overestimated by 38.6% at 1000 days. At the same time, the existence of natural fractures could also affect the streamline distribution in low-permeable oil reservoir and contribute to fluid flow in reservoir.",8,9,6
Fracture,Natural Fractures,"Yue, Ming; Zhang, Qitao; Zhu, Weiyao; Zhang, Liaoyuan; Song, Hongqing; Li, Jianhui",Effects of proppant distribution in fracture networks on horizontal well performance,Hydraulic fracturing; Fracture network; Proppant distribution; Fracture conductivity; Well performance,TIP SCREEN-OUT; HYDRAULIC FRACTURE; NUMERICAL-SIMULATION; TRANSPORT; MODEL; FLOW; SUSPENSIONS; RESERVOIR; SLURRY; KGD,"In this paper, we presented a coupled 3D finite element method model for the simulation of proppant transport in fracture networks and its effects on horizontal well performance. We used a mixture model, which have advantages to deal with two-phase flow containing a dispersed phase like solid particles, to simulate the proppant transport process in fracture networks. Then a tight oil reservoir model was established to evaluate the effect of the proppant distribution on the horizontal well performance. The effects of several factors, such as the proppant physical properties and injection parameters, were analyzed. The calculated results show that, in the fracture network, proppant accumulates at the intersections of cracks. Height of the proppant packed bed in natural fracture was about 30% smaller than that in the main hydraulic fracture, and the communication between hydraulic fractures leads to a larger proppant dune and higher conductivity. Besides, in a tight oil reservoir, the proppant distribution has a significant influence on the well performance. When the reservoir permeability is reduced to 0.05 mD, the productivity index fold of increase calculated including the proppant uneven distribution can be 47.7% larger than that calculated with idealized proppant distribution. Furthermore, the proppant physical properties and injection parameters are found to be correlated with the fracture network conductivity. Based on this analysis, optimum proppant injection conditions can be identified.",8,8,5
Fracture,Natural Fractures,"Karthikeyan, G.; Chand, Jagadish; Chatterjee, Rima","Impact of geomechanics in coal bed methane development and production, Barakar coals in central India",Coal permeability; Wellbore stability; Critically stressed fractures; Sohagpur coalfield,IN-SITU STRESS; KRISHNA-GODAVARI BASIN; PORE PRESSURE; FLUID-FLOW; PERMEABILITY; GAS; STRAIN; ORIENTATION; PREDICTION; RESERVOIRS,"Geomechanics plays a critical role in the different stages of coal bed methane (CBM) operations, starting from its development through production to its abandonment as in Sohagpur field of central India. In general, higher gas production has been observed from the coal seams in low-stress regimes compared to high-stress regimes; however, during the CBM development planning, stress information has been overlooked. The need for inclined and horizontal wellbores in coal seams has increased due to their many-fold rise in production when compared to vertical wells with a minimum surface footprint. However, these non-vertical wells have wellbore instability issues leading to high nonproductive time (NPT) during drilling and completion operations. Prolong challenges exist in achieving the desired half-length from hydraulic fracturing (HF) stimulation due to the limited understanding of the stress contrast between target coal and bounding lithology. The permeability of the coal reservoir varies greatly during depletion due to the combined effects of effective stress and matrix shrinkage. These effects directly impact productivity and hence, require a detailed understanding of how permeability varies during production life. In many instances, production from coal seams is complicated and unpredictable because of the influence of stress induced natural fractures. A geomechanical earth model is focused on understanding and mitigating the aforementioned challenges. In addition to coal thickness and gas content, stress-permeability maps are prepared to assist in the development program to prioritize wells in lower and moderate stress areas. Wellbore stability analysis has been carried out using calibrated stress and strength profiles along with other rock mechanical inputs to successfully drill high angle wells. This analysis indicates that with a slightly higher mud weight, high angle and horizontal wells can be drilled successfully. Hydraulic fracturing design incorporating the available stress contrast can help in achieving the desired fracture parameters without height growth. The coal permeability model suggests that during depletion, coal permeability is expected to increase by about 1.2-3.5 times with a positive impact on productivity. Critically stressed fracture analysis has been carried out on mapped fractures, which suggest that about 48% of the natural fractures are in a stressed state. Presence of these natural fractures has a positive (faster dewatering) as well as a negative (external water) impact on productivity at different places in the study area.",8,8,2
Fracture,Natural Fractures,"Zhao, Peng; Xie, Lingzhi; Ge, Qi; Zhang, Yao; Liu, Jun; He, Bo",Numerical study of the effect of natural fractures on shale hydraulic fracturing based on the continuum approach,Hydraulic fracturing simulation; Anisotropic strength criterion; Discontinuities; Continuum method; Fracturing geometry; Complexity and scale,STIMULATED RESERVOIR VOLUME; PROPAGATION; SIMULATION; MODEL; STRESS; FLOW; GAS; PERMEABILITY; DEFORMATION; MEDIA,"Because of the complexity of shale reservoirs and multiple physical coupling processes, numerical implementation remains a challenge in engineering applications. Unlike conventional reservoirs, shale reservoirs always contain two main discontinuities: bedding interface and natural fractures. The existence of these discontinuities is the key reason a fracture network is formed. Therefore, the numerical model should contain both bedding interface and natural fractures. In this paper, the fracturing propagation process is described based on continuum theory. In contrast to other research, an anisotmpic strength criterion is adopted to consider the anisotropic properties of shale, including the failure of both shale matrix and discontinuities. The criterion is described by the Mohr-Coulomb model combined with tensile failure. When fractures are generated in the shale rock mass, the stiffness and permeability of the fractured rock are homogenized in an element, and volume fracturing is represented by the deformation of three orthogonal fractures in the rock element. Simultaneously, the anisotropic permeability is also enhanced. Hence, based on this continuum approach and finite element method, a three-dimensional model for shale hydraulic fracturing simulation is presented. This model fully considers the direct coupling of fluid flow and rock deformation during hydraulic fracturing. To verify the anisotropic strength criterion, a shale compression test is conducted. Through a comparison of the numerical and experimental results, the applied criterion can describe the shale compressive strength anisotropy. In addition, the KGD analytical model is also adopted to verify the performance of the developed model for hydraulic fracturing. Finally, several cases of shale hydraulic fracturing are simulated, and the results show the geometry of the fracture region under different conditions. Furthermore, the impacts of three factors on hydraulic fracturing geometry are considered, including natural fractures, spacing of perforations and differential in situ stress. The influence of these factors on the complexity and scale of the fracturing region is also discussed.",7,7,7
Fracture,Natural Fractures,"Wei, Shiming; Jin, Yan; Xia, Yang",Predict the mud loss in natural fractured vuggy reservoir using discrete fracture and discrete vug network model,Naturally fractured reservoirs; Discrete fractures; Discrete vugs; Mud loss,FINITE-ELEMENT-METHOD; 2-PHASE FLOW; SIMULATION; FLUID; CONTINUUM; MEDIA,"In carbonate reservoirs, the leakage path is complex and the law of mud loss is not clear, which brings difficulties to the implementation of plugging measures. Carbonate reservoir is a naturally fractured vuggy media. One of the key scientific problems is that the fluid mass transfer among matrix pores, natural fractures and vugs is not well understood. In this paper, a discrete fracture and discrete vug model is presented to study the law of mud loss in the naturally fractured reservoir wherein natural fractures and vugs developed. The model solved the fluid flow in the discrete fracture and vug network, consisting of 1) Darcy flow in lowly permeable rock matrix and highly permeable natural fractures; 2) free flow in macro vugs. A physically-based boundary is applied to ensure the mass continuity on interfaces between vugs and matrix pores, vugs and natural fractures. A good agreement with analytical results for Poiseuille flow in a porous/free connected media is achieved. Two numerical examples using the commercial software COMSOL provide validation of the new model. When simulating the mud loss process, we find that as soon as vugs are connected to wellbore through natural fractures, total loss is observed. The size and number of vugs play prominent roles in increasing mud loss rate and accumulated mud loss. The numerical results show that the discrete fracture and discrete vug model provides a reliable way to model realistic fluid flow in fractured vuggy porous media. The model in this paper can not only simulate the mud loss process, but also the production process of carbonate reservoirs.",7,7,4
Fracture,Horizontal Wells,"Song, Xuanyi; Liu, Yuetian; Xue, Liang; Wang, Jun; Zhang, Jingzhe; Wang, Junqiang; Jiang, Long; Cheng, Ziyan",Time-series well performance prediction based on Long Short-Term Memory (LSTM) neural network model,Deep learning; LSTM; Time sequence data; PSO; Production forecasting,PARTICLE SWARM OPTIMIZATION; ALGORITHM; DESIGN; WIND,"Oil production forecasting is one of the most critical issues during the exploitation phase of the oilfield. The limitations of traditional approaches make time-series production prediction still challenging. With the development of artificial intelligence, high-performance algorithms make reliable production prediction possible from the data perspective. This study proposes a Long Short-Term Memory (LSTM) neural network based model to infer the production of fractured horizontal wells in a volcanic reservoir, which addresses the limitations of traditional method and shows accurate predictions. The LSTM neural network enables to capture the dependencies of the oil rate time sequence data and incorporate the production constraints. Particle Swarm Optimization algorithm (PSO) is employed to optimize the essential configuration of the LSTM model. For evaluation purpose, two case studies are carried out with the production dynamics from synthetic model and from the Xinjiang oilfield, China. Towards a fair evaluation, the performance of the proposed approach is compared with traditional neural networks, time-series forecasting approaches, and conventional decline curves. The experiment results show that the proposed LSTM model outperforms other approaches.",70,73,35
Fracture,Horizontal Wells,"He, Youwei; Qin, Jiazheng; Cheng, Shiqing; Chen, Jianwen",Estimation of fracture production and water breakthrough locations of multi-stage fractured horizontal wells combining pressure-transient analysis and electrical resistance tomography,Multi-stage fractured horizontal wells; Water breakthrough location; Pressure-transient analysis; Electrical resistance tomography; Well performance evaluation,MODEL; FLOW; PERFORMANCE,"The production of multi-stage fractured horizontal wells (MFHWs) decline fast, and water cut quickly increase after short producing period. How to evaluate well performance and estimate the water breakthrough segments become significant for improving oil recovery. The production logging test (PLT) enables to obtain the production profile along horizontal wellbore, however, it's difficult and expensive to carry out PLT for the MFHW. This work presents a new method to estimate production of hydraulic fractures and determine the water-breakthrough locations by combining pressure-transient analysis (PTA) and electrical-resistance tomography (ERT). This paper presents a PTA model of an MFHW which considers the nonuniform properties of fractures, including unequal fracture conductivity, nonuniform production distribution, asymmetric fractures, and arbitrary locations. The proposed model has been verified with the numerical PTA model in KAPPA Ecrin Saphir software. The type curves are developed and the impact of well and fracture properties on pressure and pressure derivative are also analyzed in detail. When the distance between fractures with high production (FHP) increases or number of FHP decreases, the early-radial flow can be obviously observed, and the duration of this regime depends on the interference among fractures. We define a parameter (N*) to describe the number of FHP, and the N* is determined by properties of hydraulic fractures. N* equals to N (total number of hydraulic fractures) if factures are symmetrically and uniformly distributed along wellbore and have equal production and conductivity. N* approximately equals to the number of producing fractures when all producing factures uniformly distribute along wellbore and have equal production, conductivity, and length. The developed PTA model is used to interpret production of different fractures by matching BHP data. The use of ERT enables to track water front, further estimate the water-breakthrough segments and reduce the non-uniqueness of PTA interpretation. The proposed approach is used to evaluate the well performance of MFHWs from Changqing Oil field, and interpretation results obtained in this work match with the results obtained by PLT.",29,29,1
Fracture,Horizontal Wells,"Wu, Zhongwei; Dong, Li; Cui, Chuanzhi; Cheng, Xiangzhi; Wang, Zhen",A numerical model for fractured horizontal well and production characteristics: Comprehensive consideration of the fracturing fluid injection and flowback,Fracturing horizontal well; Production characteristic; Flowback; Fracturing fluid injection; Reservoir damage caused by fracturing fluid,STIMULATED RESERVOIR VOLUME; THRESHOLD PRESSURE-GRADIENT; TIGHT-OIL; SEMIANALYTICAL MODEL; GAS; BEHAVIOR,"Currently, many investigations on fractured well productivity are conducted. However, all this productivity studies are conducted based on the initial pressure and fluid distribution. In this work, taking the reservoir damage caused by fracturing fluid and the effect of fracturing fluid injection on pressure and saturation into consideration, a flow model of multistage fractured horizontal well is built, which is composed of fracturing fluid injection model and fracturing fluid flowback and production model. Numerical solving method is utilized to solve the model and model verification are presented through comparing with the test results of 12 fractured well. The effects of fracture fluid injection rate and fracturing fluid viscosity on pressure and saturation at the end of fracturing fluid injection are analyzed. And the effects of the reservoir oil viscosity, porosity, permeability, heterogeneous and reservoir damage on flowback and production characteristic are analyzed. The results show: (1) The distances of saturation and pressure variation area from the fracture are respectively 10 m and 20 m after the fracturing fluid injection is finished. When the fracturing fluid viscosity increases from 10 mPa s to 30 mPa s, the distance of pressure variation area from the fracture decrease. But the pressure and saturation near the hydraulic fracture increases. When the injection rate increases from 0.28 m(3)/min to 28 m(3)/min, the fracture length increases and the distances of pressure and saturation variation area from the fracture increase. The pressure near the fracture with a high injection rate is larger than that with a small injection rate. (2) With the development of reservoir, the water flow rate and water cut decreases, and the oil flow rate increases firstly and then decreases. When the reservoir oil viscosity increases from 1.5 mPa s to 2.5 mPa s, water cut increases. The maximum oil flow rate decreases from 16.4 to 6.2 m(3)/d. With the increase of reservoir permeability, the water cut decrease. When the reservoir porosity increases, the oil flow rate, water flow rate and cumulative fluid volume increase. While, the water cut decreases with the increase of reservoir porosity. When the residual resistance factor (RRF) increases from 1 to 1.08, the oil flow rate of when the RRF equals 1 is slight larger than that of when the RRF equals 1.08. The reservoir damage has slight effect on the water flow rate and water cut. (3) The development of heterogeneous reservoir is poorer than that of homogeneous reservoir when the development conditions are the same. This work provides a more accurate method to investigate the flowback and production characteristics of fractured well.",20,20,6
Fracture,Horizontal Wells,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Fracture,Horizontal Wells,"Cheng, Linsong; Wang, Deqiang; Cao, Renyi; Xia, Rufeng",The influence of hydraulic fractures on oil recovery by water flooding processes in tight oil reservoirs: An experimental and numerical approach,Tight oil; Hydraulic fracture; Water flooding; Water breakthrough; Core flood experiment,HORIZONTAL WELLS; SHALE; FLOW; GAS; STORAGE; EOR,"The use of multi-fractured horizontal wells has helped to develop tight oil reservoirs, but, if oil depletion occurs, the estimated ultimate recovery is low. Water flooding can be regarded as an easily applied method for improving oil recovery. This study aimed to optimize the scale of the stimulated reservoir volume (SRV) by conducting an experiment to verify the water injection capacity of the Chang 7 Formation, which is situated within in a typical tight oilfield. A one-dimensional long core displacement experiment was designed based on injecting formation water into a tight matrix core and fractured cores with different fracture lengths. Results were then verified and analyzed using core flood simulation and targeted field tests, and they clarified the feasibility of injecting water into a tight oil formation when the injection well is fractured, or when fractures exist near the injection well. It was also verified that although fractures increase the equivalent permeability in the fractured core and promote pressure propagation, they can also lead to rapid water breakthrough if they communicate with the producer well. It is thus considered that optimization of the SRV extent would enhance the recovery of oil and decrease the risk of water breakthrough.",16,15,3
Fracture,Horizontal Wells,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Fracture,Horizontal Wells,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Fracture,Horizontal Wells,"Zhang, Jiyuan; Feng, Qihong; Zhang, Xianmin; Hu, Qiujia; Wen, Shengming; Chen, Dong; Zhai, Yuyang; Yan, Xia","Multi-fractured horizontal well for improved coalbed methane production in eastern Ordos basin, China: Field observations and numerical simulations",Coalbed methane; Multi-fractured horizontal well; Numerical simulation; Improved recovery; Producibility comparison,RATE-TRANSIENT ANALYSIS; PERMEABILITY CHANGES; RESERVOIR SIMULATION; PREDICTION; EVOLUTION; SEAM; PERFORMANCE,"Eastern margin of Ordos basin has been an active commercial coalbed methane (CBM) production area in China, where coal seams are typically characterized with thin layers, low permeability and high gas content. Hydraulically fractured vertical wells (HFVWs) are the primary means for recovery of CBM in this area, which however are usually subject to low gas production and unpromising economics. Although the multi-fractured horizontal well (MFHW) has proven as an effective solution for producing hydrocarbon resources from both tight and shale reservoirs, its applicability in efficient development of CBM reservoirs remains yet unclear. This paper presents a pilot field application of MFHW to improve CBM recovery in eastern Ordos basin. A horizontal well stimulated with 6 stages of hydraulic fractures was observed to significantly outperform HFVWs in terms of depressurization efficiency, gas production and ultimate recovery factor. Peak gas rate of the MFHW is more than five times higher than an HFVW. History matches of the MFHW and representative HFVWs were conducted to obtain key reservoir properties that are subsequently used for production predictions. Numerical simulation predicts that cumulative gas production for the MFHW is 3-15 times as that for each of the HFVWs during a production duration of 15 years. A total of 500 stochastic geological scenarios for the study area were simulated to analyze the effect of geological parameters on the superiority of an MFHW over a group of four HFVWs (which are at equivalent well construction outlays) in terms of cumulative gas production. A correlation was then developed using the alternating conditional expectation (ACE) regression method, resulting in a linear relationship between an indicator of the superiority with permeability and desorption pressure in a log-log coordinate system. This correlation can be potentially used as a criterion for fast determination of the optimal completion option in the target CBM seams. The regression results also show that the superiority of an MFHW over HFVWs is especially highlighted in thin coal seams with low permeability and low gas content. Finally, the effect of the size and spacing of stimulated area (SA) on MFHW producibility was analyzed, showing that increasing the spacing between SAs is an economically viable option when the budget for fracturing operations is limited.",13,13,10
Fracture,Horizontal Wells,"Zhang, Ruxin; Hou, Bing; Tan, Peng; Muhadasi, Yeerfulati; Fu, Weineng; Dong, Xiaomu; Chen, Mian",Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing,Fracture propagation behavior; Temporary plugging agent; Fracture diversion pattern; Horizontal stress difference; 3D scanning,NUMERICAL-SIMULATION; INITIATION,"The exploitation of shale oil and gas has become commercial in the Sichuan basin, China. However, initial fracture closure will result in low production. Therefore, temporary plugging fracturing technology is proposed to create new fractures in alternate directions using a temporary plugging agent that blocks initial fractures, which will lead to a complex fracture morphology. The mechanism of temporary plugging and fracture propagation behavior remains ambiguous, even with many successful operations. Hence, five shale outcrops are used to conduct large-size true tri-axial temporary plugging fracturing simulation experiments to study the issues mentioned above. The effects of horizontal stress difference and temporary plugging agent amount on plugging effectiveness as well as fracture propagation behavior are discussed. The results reveal that the initial fractures are sealed successfully by a water soluble temporary plugging agent. Two plugging positions, fracture heel and tip, result in three main fracture diversion patterns: fracture diversion at the old fracture heel, fracture diversion inside the old fracture, and a new fracture induced at a new position. Based on the fracturing pressure curve, fracturing pressure in the second fracturing is higher than that of the first fracturing, which indicates effective plugging and fracture diversion. A large horizontal stress difference has prevented fracture diversion, and led to a small diversion angle. However, it has improved the induced fracture propagation length. Moreover, the temporary plugging agent amount determines the plugging position and fracture diversion pattern. Fracture diversion inside existing fractures is a result of a small amount sealing at the fracture tip. The other two patterns are created by a large amount of plugging at the fracture heel. Therefore, in order to achieve successful plugging effectiveness, it is necessary to conduct more experiments to optimize operation parameters according to the specific horizontal in-stress state.",13,13,6
Fracture,Horizontal Wells,"Ju, Wei; Niu, Xiaobing; Feng, Shengbin; You, Yuan; Xu, Ke; Wang, Geoff; Xu, Haoran","Present-day in-situ stress field within the Yanchang Formation tight oil reservoir of Ordos Basin, central China",In-situ stress field; Tight oil reservoir; Yanchang formation; Stress regime; Natural fracture; Ordos basin,SEDIMENTARY-ROCKS; LOW-PERMEABILITY; TECTONIC STRESS; STATE; AREA; EXPLORATION; FRACTURES; PATTERN; REGION; ORIENTATIONS,"The present-day in-situ stress field has many important and practical applications during the exploration and development of hydrocarbon resources. The Ordos Basin is a significant petroliferous basin in China, within which, the Yanchang Formation serves as the most significant tight oil reservoir. However, an overview of previous studies indicates that little was known as to the present-day stress state in the Yanchang Formation. Therefore, the present-day stress field in the Yanchang Formation tight oil reservoir of the Ordos Basin is systematically analyzed in this study. The orientation of horizontal maximum principal stress (S-Hmax) within the Yanchang Formation of Ordos Basin ranges between north-northeast-south-southwest-trending (NNE-SSW) and east-northeast-west-southwest-trending (ENE-WSW) based on interpretations of borehole breakouts and drilling-induced fractures from borehole imaging logs. The S-Hmax orientation shows various tendencies in different wells, which may result from differential development in lithology, natural fracture and bedding plane over various regions. The estimated magnitudes of vertical stress (S-v), S-Hmax and horizontal minimum principal stress (S-hmin) in the studied wells indicate that the normal faulting stress regime is dominant within the Yanchang Formation. In addition, the geomechanical assessments of wellbore stability and natural fracture reactivation are also performed. Natural fractures in the Yanchang Formation Chang 7 tight oil reservoir of Ordos Basin are developed striking mainly in the northeast-southwest-trending (NE-SW) and west-northwest-east-southeast-trending (WNW-ESE). Among them, those fractures with NE-SW-trending strikes are more conductive with reference to the present-day stress state, contributing more to tight oil production in the Ordos Basin. In addition, within the Yanchang Formation, if horizontal wells are drilled towards the NNE-SSW-trending to ENE-WSW-trending, they are more likely to have wellbore instability issues. The results in this study provide important geological information for tight oil production in the Yanchang Formation of Ordos Basin.",13,14,3
Fracture,Horizontal Wells,"Du, Xin; Li, Qingyu; Lu, Zhiwei; Li, Peichao; Xian, Yuxi; Xu, Yandong; Li, Dongmei; Lu, Detang",Pressure transient analysis for multi-vug composite fractured vuggy carbonate reservoirs,,SHALE GAS-RESERVOIR; WELL TEST MODEL; HORIZONTAL WELL; FLOW BEHAVIOR; SINGLE-PHASE; PERFORMANCE; SIMULATION; VOLUME,,12,12,10
Fracture,Horizontal Wells,"Tariq, Zeeshan; Mahmoud, Mohamed; Abdulraheem, Abdulazeez; Al-Nakhli, Ayman; BaTaweel, Mohammed",An experimental study to reduce the breakdown pressure of the unconventional carbonate rock by cyclic injection of thermochemical fluids,Unconventional formation; Breakdown pressure; Thermochemical; Cyclic fracturing; Multiple fractures,HYDRAULIC FRACTURE PROPAGATION; SIMULATION; RESERVOIR; OIL,"Commercial production from unconventional reservoirs needs massive fracturing operations. Therefore, long horizontal wells are drilled, and multi-stage fractures are created to achieve the desirable production rates from these reservoirs. One common and major problem in most of the unconventional reservoirs is the high breakdown pressure due to the reservoir tightness. When fracturing these types of rocks, the hydraulic fracturing operation becomes much more challenging and difficult. In some scenarios reaches to the maximum pumping capacity without generating any fractures. In this study, a new approach to reduce the breakdown pressure of tight rocks is introduced and compared with the conventional method of fracturing. The new method incorporates the injection of thermochemical fluid in a series of cycles to create micro- and macro-fractures. The cyclic experiments performed in this study were concluded with the recording of breakdown pressure in each case. The post-treatment analysis using medical Computerized Tomography (CT) showed that multiple fractures were created due to the pressure pulse created in the thermochemical reaction. Results showed that the breakdown pressure of the rock decreases with the increasing number of cycles. The proposed method of cyclic thermochemical fracturing reduced the breakdown pressure by 33% in one-cycle, 41% in two-cycles, 53.5% in three-cycles, and 69% in four-cycles, when compared with conventional method of fracturing. An empirical relationship is also presented between the number of cycles of thermochemical fluid injection and the breakdown pressure of the rock.",12,12,5
Fracture,Horizontal Wells,"Shi, Xian; Zhang, Weidong; Xu, Hongxing; Xiao, Caiyun; Jiang, Shu",Experimental study of hydraulic fracture initiation and propagation in unconsolidated sand with the injection of temporary plugging agent,Unconsolidated sand; Plugging agent; Hydraulic fracturing; Acoustic emission; Fracture initiation,VERTICAL WELL; GAS,"High fluid leak-off rate and low pressurization rate are great challenges for hydraulic fracturing in unconsolidated sands. In this paper, the design of an injection plugging agent as a pad for fracture initiation aid in unconsolidated sands is presented. We have carried out tri-axial hydraulic fracturing tests, focusing on super-high- and high-permeability unconsolidated sands with AE (acoustic emission) monitoring. Powdered oil-soluble materials are used as temporary plugging agents. The laboratory tests demonstrated that three types of fracture geometry, multiple fracture, bi-wing fracture and single-wing fracture, are created. Furthermore, there are continuous AE energy signals with the increase of plugging agent injection, which is a good match with the fluctuated pressure. Moreover, multiple peak fracture points can be observed due to intense grains interaction. In addition, the breakdown pressure has positive relationships with the pump rate and concentration of injection of plugging agents. Multiple fractures only exist for super-high-permeability unconsolidated sands with high pumping rate and low plugging agent concentration, which is primarily due to the plugging agent seal for both hydraulic fracture and the rock matrix. A low injection rate with low plugging agent concentration led to single-wing fracture for high-permeability unconsolidated sands, whereas a high injection rate with high plugging agent concentration led to single-wing fracture for low-permeability unconsolidated sands. Low plugging agent concentration is beneficial for aiding hydraulic fracture propagation along the maximum horizontal stress direction. In addition, the high-pump-rate and low-plugging-agent-concentration scenario and low-pump-rate and highplugging-agent-concentration scenario have a greater chance of creating bi-wing fracture for super-high-permeability unconsolidated sands, whereas low pump rate and high plugging agent concentration are beneficial for bi-wing fracture for high-permeability unconsolidated sands. Local tortuous fracture path indicate tensile and fracture both exist during unconsolidated sands fracturing. With respect to sand control and large contact area, these treatments should be the better fracturing scenario for unconsolidated sand fracturing design with injection of a plugging agent. The findings of this study can help for better understanding of the fracturing mechanism and optimizing treatment parameters in unconsolidated sands fracturing.",12,11,4
Fracture,Horizontal Wells,"Zhang, Fengyuan; Emami-Meybodi, Hamid",Flowback fracture closure of multi-fractured horizontal wells in shale gas reservoirs,Flowback; Multiphase flow; Production data analysis; Fracture closure; Shale reservoirs; Multi-fractured horizontal wells,EARLY-TIME PRODUCTION; MODELING 2-PHASE FLOWBACK; MATERIAL BALANCE EQUATION; RATE-TRANSIENT ANALYSIS; ANALYZING LINEAR FLOW; TIGHT GAS; SEMIANALYTICAL MODEL; LOW PERMEABILITY; BEHAVIOR,"In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties using production data. This paper presents two multiphase flowback models for gas and water phase under boundary dominated flow (BDF) condition by considering gas influx from matrix. In addition, a workflow is proposed to quantitatively evaluate hydraulic fracture closure and fracture properties using both water-phase and gas-phase flowback data. A material balance equation (MBE) is derived to obtain average pressure in the fracture by calculating gas influx from matrix under variable bottomhole pressure (BHP) condition based on Duhamel's principle. The flowback models, average pressure calculation method, and workflow are validated against numerical simulations and applied to an MFHW drilled in Marcellus Shale. The results show that the developed models are capable of predicting fracture properties, and MBE could accurately calculate average pressure in the fracture. Furthermore, the proposed workflow provides quantitative insights into the performance of stimulation jobs by accurately predicting fracture half-length, fracture permeability, and permeability modulus using flowback data. By reconciling flowback analysis with long-term production data analysis, a significant decrease in fracture properties due to fracture closure is observed in the Marcellus MFHW.",12,12,3
Fracture,Horizontal Wells,"Ren, Wenxi; Lau, Hon Chung",Analytical modeling and probabilistic evaluation of gas production from a hydraulically fractured shale reservoir using a quad-linear flow model,Shale gas; Secondary fractures; Analytical model; Global sensitivity analysis; Probabilistic assessment,PRESSURE-TRANSIENT ANALYSIS; TIGHT OIL-RESERVOIRS; HORIZONTAL WELLS; SENSITIVITY-ANALYSIS; NATURAL FRACTURES; COMPREHENSIVE MODEL; BARNETT SHALE; TRANSPORT; MULTIPLE; PERFORMANCE,"During hydraulic fracturing, secondary fractures are created around hydraulic fractures and serve as important channels connecting the shale matrix and the hydraulic fractures. We developed an analytical model to simulate shale gas production from a multi-stage fractured horizontal well. The analytical model is based on the trilinear flow model, but it is free from the assumption that the length of secondary fractures is equal to the half-distance between hydraulic fractures. This analytical model captures the fundamental characteristics of a hydraulically fractured shale reservoir by incorporating transient gas flow in the matrix, secondary fractures, and hydraulic fractures. Because this model describes four linear flow systems (unstimulated reservoir volume, matrix in the stimulated reservoir volume, secondary fracture, and hydraulic fracture), it is called the quad-linear flow model. Production data from two shale gas wells were used to validate the model. Moreover, using the variance-based method and quasi-Monte Carlo simulation, we developed a stochastic framework to perform a probabilistic assessment of shale gas production. We also conducted a global sensitivity study with nine uncertainty parameters to identify important parameters and their interactions that affect well productivity. The results indicate that the existence of dense secondary fractures (the distance between secondary fractures is small) results in higher initial production rate and ultimate recovery, but a sharper decline in production rate. Increasing the length of the secondary fractures can more effectively enhance gas production in the presence of dense secondary fractures. Moreover, the benefits of dense secondary fractures are mostly limited to a high porosity shale reservoir.",12,12,3
Fracture,Horizontal Wells,"Zeng, Jie; Li, Wai; Liu, Jishan; Leong, Yee-Kwong; Elsworth, Derek; Tian, Jianwei; Guo, Jianchun; Zeng, Fanhua",Analytical solutions for multi-stage fractured shale gas reservoirs with damaged fractures and stimulated reservoir volumes,Shale gas reservoir; SRV; Fracture damage,LINEAR FLOW MODEL; HORIZONTAL WELLS; PERMEABILITY; ADSORPTION; TRANSPORT; MECHANISMS; NANOPORES; IMPACT; FACE,"After performing hydraulic fracturing in shale reservoirs, the hydraulic fractures and their adjacent rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures; (2) partially propped fractures with unpropped or poorly propped sections at the middle or tail of fractures; (3) fracture face damage; and (4) multiple damage cases. The classical fracture skin factors are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple damage and partially propped fractures. In this article, a new analytical model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs. The matrix model is a spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly envelops the matrix. The reservoir-fracture flow model is a ten-region linear flow model which can handle fracture damage mechanisms. Specifically, the inner reservoir region is treated as an SRV where the secondary fracture permeability obeys a power-law decreasing trend due to the attenuate stimulation intensity. This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of a published linear flow model. New type curves are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Different damage mechanisms all control specific flow regimes but the fracture face damage shows the slightest influence. In the multiple fracture damage case, some typical flow regimes can be easily identified except those induced by the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.",12,12,3
Fracture,Horizontal Wells,Wang Xue-wu; Xiao Pufu; Yang Zheng-ming; Liu Xue-wei; Xia Zhi-zeng; Wang Li-qiang,Laboratory and field-scale parameter optimization of CO2 huff-n-puff with the staged-fracturing horizontal well in tight oil reservoirs,Tight oil reservoirs; Horizontal well; Fracture; CO2 huff-n-puff; Production mechanism; Parameters optimization,RECOVERY,"With the help of large-scale physical simulation experiment technology, the physical simulation experiments of the CO2 huff-n-puff with the staged-fracturing horizontal well could be acheived. We studied the production process of CO2 huff-n-puff and influence of different parameters affect oil recovery during the CO2 huff-n-puff procedure, ultimately, the operation parameters were optimized by numerical simulation. The results show that CO2 can quickly enter the deep formation through the horizontal well and the fracture during the huff period and staged-fracturing horizontal well can greatly increase the contact area between CO2 and crude oil, which improves the efficiency of extraction, dissolution, reduction of viscosity between CO2 and crude oil. During the puff period, the horizontal well and fractures can reduce the flow resistance effectively, so as to improve the flow capacity of crude oil. After 3 cycles of CO2 huff and puff, the oil recovery can be enhanced by 11.13%-21.39% compared with that obtained by elastic flooding, which indicates that the exploitation method of CO2 huff-n-puff can improve the development effects of tight oil reservoirs. CO2 huff-n-puff injection parameters are optimized, the results show that the optimum time of injection is 1 year, the optimum soaking time is 30d, and the optimal injection pore volume is 0.18HCPV. This research can provide a certain technical support for effective development of tight oil reservoirs.",11,12,3
Fracture,Horizontal Wells,"Wei, Shiming; Jin, Yan; Xia, Yang; Lin, Botao",The flowback and production analysis in sub-saturated fractured shale reservoirs,Sub-saturated shale reservoirs; Flowback; Production; Gas-water flow; Discrete fractures,DISCRETE-FRACTURE; 2-PHASE FLOW; GAS-FLOW; HYDRAULIC-FRACTURE; TRIPLE-CONTINUUM; NUMERICAL-METHOD; HORIZONTAL WELL; POROUS-MEDIA; MODEL; SIMULATION,"The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced ""skin factor"" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model.",10,10,3
Fracture,Horizontal Wells,"Zhao, Yulong; Lu, Guang; Zhang, Liehui; Wei, Yunsheng; Guo, Jingjing; Chang, Cheng",Numerical simulation of shale gas reservoirs considering discrete fracture network using a coupled multiple transport mechanisms and geomechanics model,Shale gas; Multistage fractured horizontal well; Multiple migration mechanisms; Geomechanics; Discrete fracture network,APPARENT PERMEABILITY; HORIZONTAL WELL; COMPOSITE MODEL; FLOW; MATRIX; COAL; DESORPTION; NANOPORES; STRESS; ADSORPTION,"Shale has typical characteristics of multi-scale space for gas storage and migration. It is suitable for description by a triple medium model composed of double continuous medium and discrete fracture model, and need to consider multiple migration mechanisms. Besides, during gas production, effective stress and desorption will cause the deformation of shale, leading to the dynamic changes in porosity and permeability. In this paper, a fully coupled model was established to evaluate the shale gas production dynamics, including the governing equation of shale deformation and the governing equation of gas migration in the matrix, micro-fractures, and hydraulic fractures, respectively. All processes are coupled by the dynamic models of porosity and permeability for matrix and micro-fractures, and by the gas exchange between different systems. The fully coupled model was solved by the finite element method through the PDE solver software named COMSOL Multiphysics. The rationality of this fully coupled model is verified by the production data of Barnett shale. The validated model was applied to study the effects of adsorption and geomechanics parameters on dynamic changes of porosity and permeability, and gas production. Moreover, the impact of primary fracture geometry and secondary fracture distribution parameters on production were also analyzed. Simulation results show that the adsorption parameters have essential effects on both gas flow and production; that the geomechanics parameters have important influences on the evolution of porosity and permeability; that optimizing the distribution and development of hydraulic fracture and secondary fracture is beneficial to the efficient development of shale gas.",9,9,9
Fracture,Horizontal Wells,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Fracture,Horizontal Wells,"Yue, Ming; Zhang, Qitao; Zhu, Weiyao; Zhang, Liaoyuan; Song, Hongqing; Li, Jianhui",Effects of proppant distribution in fracture networks on horizontal well performance,Hydraulic fracturing; Fracture network; Proppant distribution; Fracture conductivity; Well performance,TIP SCREEN-OUT; HYDRAULIC FRACTURE; NUMERICAL-SIMULATION; TRANSPORT; MODEL; FLOW; SUSPENSIONS; RESERVOIR; SLURRY; KGD,"In this paper, we presented a coupled 3D finite element method model for the simulation of proppant transport in fracture networks and its effects on horizontal well performance. We used a mixture model, which have advantages to deal with two-phase flow containing a dispersed phase like solid particles, to simulate the proppant transport process in fracture networks. Then a tight oil reservoir model was established to evaluate the effect of the proppant distribution on the horizontal well performance. The effects of several factors, such as the proppant physical properties and injection parameters, were analyzed. The calculated results show that, in the fracture network, proppant accumulates at the intersections of cracks. Height of the proppant packed bed in natural fracture was about 30% smaller than that in the main hydraulic fracture, and the communication between hydraulic fractures leads to a larger proppant dune and higher conductivity. Besides, in a tight oil reservoir, the proppant distribution has a significant influence on the well performance. When the reservoir permeability is reduced to 0.05 mD, the productivity index fold of increase calculated including the proppant uneven distribution can be 47.7% larger than that calculated with idealized proppant distribution. Furthermore, the proppant physical properties and injection parameters are found to be correlated with the fracture network conductivity. Based on this analysis, optimum proppant injection conditions can be identified.",8,8,5
Fracture,Horizontal Wells,"Chen, Beibei; Xu, Bin; Li, Biao; Kong, Mingwei; Wang, Wanbin; Chen, Huasheng",Understanding the performance of hydraulically fractured wells in the laumontite-rich tight glutenite formation,Hydraulic fracturing; Reservoir dilation; Tight glutenite formation; Laumontite-rich reservoir rock,CAJON-PASS; MODEL; PERMEABILITY; ROCK; DEHYDRATION; SANDSTONES; ZEOLITES; STRENGTH; TESTS; FAULT,"Massive hydraulic fracturing treatments have been used to produce hydrocarbons from tight glutenite oil reservoirs through both vertical and horizontal wells. Some tight glutenite reservoirs are rich in laumontite. Field experiences indicate that the performance of hydraulically fractured wells on this type of laumontite-rich tight glutenite reservoir typically resulted in low oil productivity and quickly declining oil rates. To understand the poor well performance of these laumontite-rich tight oil wells, extensive laboratory and numerical simulation studies have been conducted to explore the major controlling factors. Laboratory results indicate that the laumontite-rich glutenite reservoir rock has the following characteristics: 1) reservoir permeability is sensitive to stress conditions; 2) reservoir rock has low mechanical strength; and 3) reservoir rock has a low elastic modulus. These geomechanical deformation characteristics strongly affect the well productivity on the laumontite-rich formations. During the hydraulic fracturing and well production phases, the reservoir rock near the main hydraulic fracture can be compacted significantly to reduce rock porosity and permeability. As a result, the fluid flow capacity from the reservoir rock into the hydraulic fracture is reduced. By using laboratory testing data, fully coupled flow-deformation finite element simulations were conducted to study the impact of rock compaction/dilation on well productivity. Based on the numerical simulations, a new hydraulic fracturing scheme was proposed, and a field pilot test was conducted on one vertical well in the study area. Promising field oil production rates were achieved. This paper presents our understanding of the laboratory data, numerical simulation, and field pilot tests results. The new hydraulic fracturing scheme was based on the rock dilation near the main hydraulic fracture. The result indicates that rock dilation, if proactively utilized, can enhance the fluid deliverability from the reservoir into the main hydraulic fracture and boost well productivity.",8,8,3
Fracture,Horizontal Wells,"Karthikeyan, G.; Chand, Jagadish; Chatterjee, Rima","Impact of geomechanics in coal bed methane development and production, Barakar coals in central India",Coal permeability; Wellbore stability; Critically stressed fractures; Sohagpur coalfield,IN-SITU STRESS; KRISHNA-GODAVARI BASIN; PORE PRESSURE; FLUID-FLOW; PERMEABILITY; GAS; STRAIN; ORIENTATION; PREDICTION; RESERVOIRS,"Geomechanics plays a critical role in the different stages of coal bed methane (CBM) operations, starting from its development through production to its abandonment as in Sohagpur field of central India. In general, higher gas production has been observed from the coal seams in low-stress regimes compared to high-stress regimes; however, during the CBM development planning, stress information has been overlooked. The need for inclined and horizontal wellbores in coal seams has increased due to their many-fold rise in production when compared to vertical wells with a minimum surface footprint. However, these non-vertical wells have wellbore instability issues leading to high nonproductive time (NPT) during drilling and completion operations. Prolong challenges exist in achieving the desired half-length from hydraulic fracturing (HF) stimulation due to the limited understanding of the stress contrast between target coal and bounding lithology. The permeability of the coal reservoir varies greatly during depletion due to the combined effects of effective stress and matrix shrinkage. These effects directly impact productivity and hence, require a detailed understanding of how permeability varies during production life. In many instances, production from coal seams is complicated and unpredictable because of the influence of stress induced natural fractures. A geomechanical earth model is focused on understanding and mitigating the aforementioned challenges. In addition to coal thickness and gas content, stress-permeability maps are prepared to assist in the development program to prioritize wells in lower and moderate stress areas. Wellbore stability analysis has been carried out using calibrated stress and strength profiles along with other rock mechanical inputs to successfully drill high angle wells. This analysis indicates that with a slightly higher mud weight, high angle and horizontal wells can be drilled successfully. Hydraulic fracturing design incorporating the available stress contrast can help in achieving the desired fracture parameters without height growth. The coal permeability model suggests that during depletion, coal permeability is expected to increase by about 1.2-3.5 times with a positive impact on productivity. Critically stressed fracture analysis has been carried out on mapped fractures, which suggest that about 48% of the natural fractures are in a stressed state. Presence of these natural fractures has a positive (faster dewatering) as well as a negative (external water) impact on productivity at different places in the study area.",8,8,2
Fracture,Horizontal Wells,"Sun, Ruofan; Hu, Jinghong; Zhang, Yuan; Li, Zhiping",A semi-analytical model for investigating the productivity of fractured horizontal wells in tight oil reservoirs with micro-fractures,Micro-fractures; Fractured horizontal wells; Well productivity; Tight oil reservoirs; Sensitivity analysis,PRESSURE-TRANSIENT ANALYSIS; GAS-PRODUCTION; LINEAR FLOW; MICROFRACTURES; SHALE; PERMEABILITY; PERFORMANCE; PREDICTION; BASIN,"Combining horizontal drilling with hydraulic fracturing has become a well-established technique to improve well productivity in tight oil reservoirs. The existence of micro-fractures in these reservoirs affects the fluid flow process as well as the productivity. However, current models for evaluating the well performance of fractured horizontal wells containing micro-fractures lack accuracy. Hence, the objective of this study is to build an efficient model to analyze well productivity, considering the effects of micro-fractures. A novel flow model for multi-fractured horizontal wells was established, considering the effect of micro-fractures on the fluid flow. Subsequently, we built a reservoir model based on the typical fracture and fluid properties of a tight oil block in the Daqing oil field, China. Good agreement between the prediction results and field data was obtained, indicating that the effect of micro-fractures on well productivity cannot be neglected. Further study reveals that micro-fractures essentially function as a joint connecting reservoir matrix and have a persistent impact on well productivity. Micro-fractures can promote well productivity; however, if the value of micro-fracture permeability increases, this promotional effect will slow down. Well productivity can be considerably improved as an increase in micro-fracture percentage. Finally, a series of sensitivity studies were conducted to identify the effects of critical parameters on well productivity. Results show that reservoir permeability significantly influences well productivity, followed by reservoir effective thickness, micro-fracture percentage, fracture number, hydraulic fracture half-length. Pressure sensitivity coefficient, threshold pressure gradient and micro-fracture permeability have the least effect on well productivity. This work provides a sophisticated and efficient tool to evaluate the productivity of multi-fractured horizontal wells in tight oil reservoirs with micro-fractures.",7,7,5
Fracture,Fracture Network,"Song, Xuanyi; Liu, Yuetian; Xue, Liang; Wang, Jun; Zhang, Jingzhe; Wang, Junqiang; Jiang, Long; Cheng, Ziyan",Time-series well performance prediction based on Long Short-Term Memory (LSTM) neural network model,Deep learning; LSTM; Time sequence data; PSO; Production forecasting,PARTICLE SWARM OPTIMIZATION; ALGORITHM; DESIGN; WIND,"Oil production forecasting is one of the most critical issues during the exploitation phase of the oilfield. The limitations of traditional approaches make time-series production prediction still challenging. With the development of artificial intelligence, high-performance algorithms make reliable production prediction possible from the data perspective. This study proposes a Long Short-Term Memory (LSTM) neural network based model to infer the production of fractured horizontal wells in a volcanic reservoir, which addresses the limitations of traditional method and shows accurate predictions. The LSTM neural network enables to capture the dependencies of the oil rate time sequence data and incorporate the production constraints. Particle Swarm Optimization algorithm (PSO) is employed to optimize the essential configuration of the LSTM model. For evaluation purpose, two case studies are carried out with the production dynamics from synthetic model and from the Xinjiang oilfield, China. Towards a fair evaluation, the performance of the proposed approach is compared with traditional neural networks, time-series forecasting approaches, and conventional decline curves. The experiment results show that the proposed LSTM model outperforms other approaches.",70,73,35
Fracture,Fracture Network,"Tan, Peng; Pang, Huiwen; Zhang, Ruxin; Jin, Yan; Zhou, Yingcao; Kao, Jiawei; Fan, Meng",Experimental investigation into hydraulic fracture geometry and proppant migration characteristics for southeastern Sichuan deep shale reservoirs,Hydraulic fracturing; Deep shale; Proppant migration; Bedding plane,PROPAGATION BEHAVIOR; SIMULATION; INITIATION; NETWORK; OPTIMIZATION; MORPHOLOGY; CRITERION; BRITTLE; MODEL; ROCK,"Difficulties in fracture extension and proppants adding were two key factors that affected the stimulated volume of deep shale reservoir. To clarify the mechanism of hydraulic fracture (HF) propagation and proppants migration, several groups of large-scale true tri-axial fracturing tests with an ingenious method of sand adding were performed utilizing deep Longmaxi shale outcrops from southeastern Sichuan. The interaction behavior between vertical HF and bedding plane (BP) was discussed. The results showed that due to the low bonding strength, the BPs could be easily activated even under high vertical stress difference coefficient. Based on the different influenced degrees of BPs, four types of HF geometries in the vertical direction were observed, that is, transverse HF, horizontal HF, step-shaped HF with fissure opening, and multilateral step-shaped HF network. The migration distance of proppants was limited and almost all the proppants were distributed around the wellbore, thus inducing the formation of multiple secondary HFs. When there are natural fractures (NFs) with large aperture around the wellbore, proppants almost entirely distributed along the NFs. The main factor, causing the difficulty of fracture extension and proppants migration, was the complex HF geometry characterized by the multi-branched fractures with slippage of BPs.",33,34,6
Fracture,Fracture Network,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Wang, Suifeng; Wang, Tao; Shi, Xiaohong; Dong, Qingxiang; Li, Junyang",Natural fractures in soft coal seams and their effect on hydraulic fracture propagation: A field study,Soft coal seam; Qinshui Basin; Natural fractures; On-site hydraulic fracturing; Hydraulic fractures; Particle flow method,PORE STRUCTURE CHARACTERIZATION; HIGH-RANK COAL; MECHANICAL-PROPERTIES; RESERVOIR PRESSURE; ACOUSTIC-EMISSION; FIB-SEM; METHANE; PERMEABILITY; MODEL; ROCK,"Natural fractures provide direct flow channels for coalbed methane (CBM) production and gas outburst control. However, in soft coal seams, the characteristics of natural fractures and their effect on hydraulic fractures are still unclear. In this study, a spatial system of visible natural fractures was established through underground dissection and measurement of ground joints from a case study of the Xinyuan Coal Mine in the northern Qinshui Basin, China. Our results show that the orientations of the subsurface exogenetic fractures of the coal seams are consistent with the macrostructural joints on the ground surface in the same tectonic setting. The exogenetic fractures of the coal seams have dominant orientations with approximately equal spacing. Next, a field test of a large-scale hydraulic fracturing project with a volume of up to 2000 m(3) was conducted. The on-site observation of the underground coal seams revealed that the propagation orientation of the vertical propped fractures coincides with the predominant orientation of the natural fractures. Even at a high constant injection rate (12 m(3)/min), the corresponding injection pressure was not constant during the propagation of the hydraulic fractures, and this can be attributed to the effect of the depth of the coal seam, internal natural fracture network, and normal fault. Additionally, a two-dimensional (2D) particle flow simulation (PFC2D) showed that the propagation of the hydraulic fracture is controlled by the orientations of the natural fractures and the principal stresses. The orthogonal fracture network showed more sensitivity to joint spacing than the layered fracture network in controlling the hydraulic fractures. Finally, fluid detection of the coalbed demonstrated that the flow range of the fracturing fluid in the natural exogenetic fractures was up to a few hundred meters. The flow direction was consistent with that of the natural fractures. A comprehensive analysis of the natural fractures contributes to the identification of flow channels and helps in the design of hydraulic fracturing engineering in soft coal seams.",20,20,9
Fracture,Fracture Network,"Wang, Fuyong; Cheng, Hui",A fractal permeability model for 2D complex tortuous fractured porous media,Fracture; Permeability; Tortuosity; Porous media; Fractal,CARBONATE ROCK; FLUID-FLOW; NETWORKS,"The complex fracture networks are of significance to petroleum production in unconventional reservoirs, but effectively predicting its permeability is challenging due to the complex distribution and geometry of fracture networks. This paper proposes a new permeability model for 2D complex tortuous fractured porous media based on fractal theory, and two important characteristics of fractures, i.e. branching and tortuosity are considered in the developed permeability model. In this paper, the fractured porous media is assumed to be made up of a bundle of tortuous fractal-like tree fracture networks. First, the modified cubic law for describing flow rate in a fracture with fractal distribution of tortuosity is derived. Secondly, the fractal-like tree fracture network is used to represent the distribution of complex fracture networks, and then flow rate in a tortuous fractal-like tree fracture network is derived. After that, with the assumption of the fractal scaling law between fracture number and fracture apertures, the total flow rate in a bundle of tortuous fractal-like tree fracture networks is given and then the analytical expression for permeability of 2D complex tortuous fractured porous media is derived. Finally, the model reliability is verified with a case study and the key parameters influencing permeability of 2D fracture porous media are investigated with sensitivity study. The research results show that the fractal dimension of aperture distribution D-f, tortuosity fractal dimension D-T, branch level m and fracture length ratio gamma have significant influence on fracture network permeability; the effects of branch angle theta and the straight length of the zero-level fracture l(0) on fracture network permeability are insignificant.",17,18,5
Fracture,Fracture Network,"Rao, Xiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Liu, Hao; Du, Xulin",A modified projection-based embedded discrete fracture model (pEDFM) for practical and accurate numerical simulation of fractured reservoir,Embedded discrete fracture model; Projection-based embedded discrete fracture model; Complex fracture network; Numerical simulation; Flow barriers,MULTIPHASE FLOW; POROUS-MEDIA; NETWORKS; EDFM; OIL,"pEDFM is a new numerical model which is proposed in the last three years to handle the flow simulation with complex fracture networks. Previous works show that classical EDFM has a good performance only for production or injection simulation of multistage fractured well, but pEDFM can effectively handle more general cases than EDFM. Although pEDFM has been validated by by some works, this paper points out that there are still some limitations in previous pEDFM need to be resolved, lying on lack of a practical method to select projected faces, the proficiency in the transmissibility formula of f-m connections, and poor performances in some cases. Then, corresponding modifications are presented to resolve these limitations, and these modifications include A practical algorithm called ""micro-translation method"" to select projected-faces combinations, the physical transmissibility formula of additional fracture-matrix (f-m) connections and an extended pEDFM framework by considering additional fracture-fracture (f-f) connections. Some test cases are implemented to illustrate the necessity and validity of these modifications. Besides, two examples are implemented to illustrate the robustness of the modified pEDFM workflow for practical application of a fractured reservoir.",16,18,2
Fracture,Fracture Network,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Fracture,Fracture Network,"Dias, Luciana Olivia; Bom, Clecio R.; Faria, Elisangela L.; Valentin, Manuel Blanco; Correia, Maury Duarte; de Albuquerque, Marcio P.; de Albuquerque, Marcelo P.; Coelho, Juliana M.",Automatic detection of fractures and breakouts patterns in acoustic borehole image logs using fast-region convolutional neural networks,Borehole; Image; Deep learning; Breakouts; Geological fractures; Classification,MECHANICS,"Borehole acoustic image logs present meaningful information about some petrophysical properties of a reservoir. The identification of these features, in addition to several supplementary data are very important to achieve a valid characterization of the reservoir itself. Among the different patterns that image logs could show, it can be mentioned fractures and breakouts occurrences, which are very important for the experts in the field. These occurrences usually appear on borehole acoustic image logs. Its study can provide some insights about petrophysical properties of the reservoir, such as the mechanical stresses borne by the geology of the site, and this, for example, can be linked to the dynamics of the fluids retained inside the reservoir itself (i.e., hydrocarbon, gas or water). Usually, the workflow used to identify these structures requires experts to manually identify them. In this work, we propose a novel methodology for automatic detection in Borehole acoustic image logs of such structures using a single Fast Region-based Convolutional Neural Network (fast-RCNN), which could easily be incorporated into the analysis workflow carried out by petrophysicists, contributing to the characterization process. Due to the high number of samples that this type of neural network require, we trained our algorithm simulating pattern breakouts and fractures and after we test it in real and simulated images. Our model reported the area under the Receiver Operating Characteristic curve (AUC) of 98% and 90% for detecting fractures and breakouts, respectively, in simulated data. The algorithms commonly reported in the literature to identify fractures and breakouts, only achieve around 81% and 73% of AUC, respectively. Finally, for real images, the fast-RCNN detected efficiently the fractures and parts of breakouts. Thus, our data suggest that deep learning can improve significantly the accuracy on automatic detection of geological formations in acoustic borehole image logs. Available repository at Fast-Rcnn-Geo.",13,14,3
Fracture,Fracture Network,"Gu, Yang; Ding, Wenlong; Tian, Qianning; Xu, Sheng; Zhang, Wei; Zhang, Bairen; Jiao, Baocheng","Developmental characteristics and dominant factors of natural fractures in lower Silurian marine organic-rich shale reservoirs: A case study of the Longmaxi formation in the Fenggang block, southern China",The longmaxi shale; Natural fractures; Developmental characteristics; Dominant factors; South China,CAMBRIAN NIUTITANG FORMATION; NORTHERN GUIZHOU PROVINCE; FORT-WORTH BASIN; BOHAI BAY BASIN; BARNETT SHALE; CENGONG BLOCK; QUANTITATIVE PREDICTION; LOGGING IDENTIFICATION; MIGRATION PATHWAYS; GAS-STORAGE,"Natural fractures are an important storage space and main seepage channel of shale gas reservoirs, controlling the permeability of shale gas reservoirs and the migration, enrichment, preservation conditions and single-well productivity of shale gas. The successful production of shale gas has shown that the development of natural fractures in shale is beneficial, and a high degree of natural fracture development can allow a large-scale fracture network to form in the process of hydraulic fracturing, which can effectively improve the shale reservoir conditions. The development of fractures in shale reservoirs not only effectively improves the permeability of shale reservoirs but also increases the gas content, improving the productivity of shale reservoirs. Therefore, the degree of shale fracture development is the key to the production of shale gas reservoirs. Through the outcrop, shale core, thin section and scanning electron microscopy observations of the Longmaxi shale in the Fenggang block of Guizhou Province and the experimental data analysis of the corresponding samples, the fracture characteristics are statistically analyzed, and the fracture development characteristics and dominant factors are discussed in depth. The study area is located in the complex tectonic area of southern China, which experienced a strong tectonic deformation and a high degree of fracture development. The multiscale characterization of Longmaxi shale fractures indicates the following: the fractures observable in the field are mainly regional structural fractures, fold-related fractures, fault-related fractures and bedding fractures; additionally, the statistical analysis of core fractures shows that the structural fractures, including high-angle shear fractures, tension-shear fractures, and low-angle slip fractures are dominant and that most of them are filled with calcite; the micro-fractures are mainly intragranular fractures and intergranular fractures, and the fracture aperture is 0.01-2 mu m. The degree of fracture development is controlled by structural factors, lithology, mineral composition and content, TOC, rock mechanical properties, paleoenvironment and diagenesis, and the structural factors are the most influential. The gentle transition zone of a fold limb is a favorable position for shale gas structure preservation. Fractures significantly impact the formation of seepage channels and storage space and the connection of isolated micropores, so the degree of fracture development has a positive relationship with the total and analytical gas contents.",11,13,8
Fracture,Fracture Network,"Chen, Hongquan; Onishi, Tsubasa; Olalotiti-Lawal, Feyi; Datta-Gupta, Akhil",Streamline tracing and applications in embedded discrete fracture models,Fractured reservoir; Streamline tracing; Embedded discrete fracture models; Flow diagnostics; Water flood optimization,FLOW DIAGNOSTICS; SHALE FORMATION; PATH LINES; BLACK-OIL; SIMULATION; RESERVOIR; PRESSURE,"Fractures play important role in unconventional resources by influencing the fluid flow pattern underground. Streamline-based flow diagnostic is important to the history matching or operational optimization process of fractured reservoirs. This paper presents a robust streamline tracing framework for use in the Embedded Discrete Fracture Models (EDFM) and several applications including flow visualization, flow diagnostics, and rate allocation optimization. The proposed streamline tracing framework is based on a boundary layer method that can honor the flux communications between the matrix and fractures or between fracture and fracture. The proposed method is benchmarked with a semi-analytical solution and its robustness is illustrated by a series of numerical examples encompassing different levels of geologic and geometrical complexity. Streamlines in complex fracture networks provide flow diagnostics such as sweep efficiency and connectivity of wells and fractures. The streamlines are then utilized to develop a workflow for rate allocation optimization for waterflood in naturally fractured reservoirs. We apply a streamline-based gradient free algorithm whereby both injection and production rates are adjusted under realistic operational constraints to a field scale fractured reservoir. This approach only requires a few forward simulations and therefore offers significant advantage in terms of computational efficiency. It is confirmed that the optimized schedule provides improvements in oil recovery and sweep efficiency compared to the base scenario with uniform injection and production rates.",11,11,1
Fracture,Fracture Network,"Du, Shuheng","Characteristics and the formation mechanism of the heterogeneous microfractures in the tight oil reservoir of Ordos Basin, China",Microfracture; Formation mechanism; Tight oil; Sandstone; Characterization,SANDSTONE RESERVOIR; FRACTURE NETWORK; PERMEABILITY; INSPIRATION; SIMULATION; ANISOTROPY; MODELS; SHALE; FLOW,"This study aims to investigate the characteristics and the formation mechanism of the heterogeneous microfractures in the upper Triassic Yanchang Formation tight oil reservoir of Ordos Basin, China with some new perspectives. In this paper, we define two sets of parameters describing the size and geometry of microfractures by using Feret diameter calculation and Legendre ellipse fitting. Then the unidirectional fracture zone and multidirectional fracture zone are also be defined. Results of the microfractures characterization show that when the lengths of microfractures are less than 600 mu m (and the widths are less than 90 mu m), the above two set of data show a good linear positive correlation, but when the lengths of microfractures continue to increase, the widths of microfractures begin to deviate from the linear relationship and gradually diverge. This indicates that the lengths and widths of microfractures are not strictly and steadily correlated, but their correlation has a threshold value. If the lengths of microfractures increase due to the change of internal or external stress, when the length value is higher than a certain value, the opening process of microfractures will begin to lose stability, and the widths will change gradually irregularly. Once the compaction process reach a certain extent, some of the microfractures opened previously will be temporarily closed, which will greatly promote the process of pressure-solution, and thus increase the microfracture tortuosity. The length, width, solidity and boundary tortuosity of microfractures could be used to distinguish two zones include the multi-directional fracture zone from the unidirectional fracture zone. The conclusion would provide the important scientific basis for the EOR applications of tight oil.",11,11,1
Fracture,Fracture Network,"Lin, Botao; Guo, Jiancheng; Liu, Xing; Xiang, Jianhua; Zhong, Hua",Prediction of flowback ratio and production in Sichuan shale gas reservoirs and their relationships with stimulated reservoir volume,Flowback ratio; Productivity; Shale gas reservoir; Neural network; Stimulated reservoir volume,WATER; IMBIBITION,"Good flowback management in shale gas reservoirs not only preserves the conductivity of the flow paths created by the fracture network but also assists the subsequent production by minimizing the damage of the fracturing fluid to the fluid-sensitive formation. However, a quantitative prediction of its behavior and impact on the productivity of a reservoir is not available yet. This study proposed a mathematical approach to predict the flowback behavior concerning flow back ratio (FBR), and the productivity represented by first-month production (PROD), of the Changning-Weiyuan shale gas reserve in Sichuan basin, southwest China. First, a BP (Back Propagation) neural network model was established to filter out the controlling factors given the actual FBRs and the geological and engineering characteristics of seventy-six sample wells. Secondly, a correlation was generated between the FBR, the geological index g, and the engineering index e by non-linear fitting. In subsequence, the PROD was predicted based on the field recorded FBR and the comprehensive index c that combines the influences of both geological and engineering parameters. Finally, the stimulated reservoir volumes (SRVs) of twelve wells were estimated using the K-means clustering and Delaunay triangulation to assess their impact on the FBR and PROD data. It was found that the associated FBR and PROD diagrams can provide accurate predictions for the sixteen additional wells. Meanwhile, there exists an optimum FBR range of 20-40% for the shale gas region of concern where the productivity of the formation can be maximized. It is also observed that the FBR and PROD fail to display any specific trend with the value of the SRV magnitude. In general, the proposed approach can be used in shale gas reservoirs to examine the favorable FBR and guide the engineering designs to enhance production if adequate reservoir data are accessible.",10,10,6
Fracture,Fracture Network,"Liu, Yongzan; Liu, Lijun; Leung, Juliana Y.; Moridis, George J.",Sequentially coupled flow and geomechanical simulation with a discrete fracture model for analyzing fracturing fluid recovery and distribution in fractured ultra-low permeability gas reservoirs,Coupled flow and geomechanics; Flowback; Fracturing-fluid distribution; Tight/shale gas; Fracture geometry,TRANSIENT-BEHAVIOR; WATER-FLOWBACK; TIGHT-GAS; SHALE; WELLS; PERFORMANCE; MECHANISMS; IMPACT,"More accurate characterization and prediction of the in-situ distribution of fracturing fluid in fractured reservoirs are needed for enhancing well productivity. In this study, an implicit-sequentially coupled flow/geomechanics simulator incorporating an efficient discrete fracture model is developed to model fluid distribution and recovery performance of ultra-low permeability gas reservoirs. The finite-volume and finite-element methods are used for space discretization of the flow and geomechanics equations, respectively, while the backward Euler method is employed for time discretization. The flow and geomechanics equations are solved sequentially based on fixed-stress splitting. An efficient discrete-fracture model is used to explicitly model the fractured system. Flexible unstructured gridding is employed to model arbitrarily-oriented fractures. The interrelations among pore volume, permeability and geomechanical conditions are considered dynamically using two-way coupled flow and geomechanics computations. The geometry of fracture (networks) due to hydraulic fracturing has significant impacts on the fracturing fluid recovery efficiency and ensuing fluid distribution. Under the same injection volume, the fracturing fluid recovery is higher when the fracture geometry is planar. Fluid recovery is relatively lower whenever natural fractures are activated during fracturing treatments; flowback time is also shortened when complex fracture network with enlarged fracture interface is present. Fracturing fluid in hydraulic fractures may leak off into the natural fractures and subsequently imbibes into the surrounding matrix due to capillarity effects. The fracturing fluid recovery and in-situ fluid distribution are sensitive to the shut-in duration and fracture closure behavior. This study analyzes the coupled flow-geomechanical responses of fractured gas reservoirs during the post-fracturing periods. Understanding the fate of the fracturing fluid can provide insights on, to some extent, the stimulated fracture volume, size of the water invasion zone, and efficiency of the fracturing design. The simulation predictions can also provide more accurate initial reservoir conditions (e.g. distributions of different phases and pressure) for long-term well performance estimation.",10,10,5
Fracture,Fracture Network,"Wei, Shiming; Jin, Yan; Xia, Yang; Lin, Botao",The flowback and production analysis in sub-saturated fractured shale reservoirs,Sub-saturated shale reservoirs; Flowback; Production; Gas-water flow; Discrete fractures,DISCRETE-FRACTURE; 2-PHASE FLOW; GAS-FLOW; HYDRAULIC-FRACTURE; TRIPLE-CONTINUUM; NUMERICAL-METHOD; HORIZONTAL WELL; POROUS-MEDIA; MODEL; SIMULATION,"The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced ""skin factor"" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model.",10,10,3
Fracture,Fracture Network,"Zhao, Yulong; Lu, Guang; Zhang, Liehui; Wei, Yunsheng; Guo, Jingjing; Chang, Cheng",Numerical simulation of shale gas reservoirs considering discrete fracture network using a coupled multiple transport mechanisms and geomechanics model,Shale gas; Multistage fractured horizontal well; Multiple migration mechanisms; Geomechanics; Discrete fracture network,APPARENT PERMEABILITY; HORIZONTAL WELL; COMPOSITE MODEL; FLOW; MATRIX; COAL; DESORPTION; NANOPORES; STRESS; ADSORPTION,"Shale has typical characteristics of multi-scale space for gas storage and migration. It is suitable for description by a triple medium model composed of double continuous medium and discrete fracture model, and need to consider multiple migration mechanisms. Besides, during gas production, effective stress and desorption will cause the deformation of shale, leading to the dynamic changes in porosity and permeability. In this paper, a fully coupled model was established to evaluate the shale gas production dynamics, including the governing equation of shale deformation and the governing equation of gas migration in the matrix, micro-fractures, and hydraulic fractures, respectively. All processes are coupled by the dynamic models of porosity and permeability for matrix and micro-fractures, and by the gas exchange between different systems. The fully coupled model was solved by the finite element method through the PDE solver software named COMSOL Multiphysics. The rationality of this fully coupled model is verified by the production data of Barnett shale. The validated model was applied to study the effects of adsorption and geomechanics parameters on dynamic changes of porosity and permeability, and gas production. Moreover, the impact of primary fracture geometry and secondary fracture distribution parameters on production were also analyzed. Simulation results show that the adsorption parameters have essential effects on both gas flow and production; that the geomechanics parameters have important influences on the evolution of porosity and permeability; that optimizing the distribution and development of hydraulic fracture and secondary fracture is beneficial to the efficient development of shale gas.",9,9,9
Fracture,Fracture Network,"Muojeke, Somadina; Venkatesan, Ramachandran; Khan, Faisal",Supervised data-driven approach to early kick detection during drilling operation,Artificial neural network; Downhole monitoring; Early kick detection; Supervised learning,ARTIFICIAL NEURAL-NETWORKS; DEVELOPING LEADING INDICATORS; PREDICTING RATE; WELL; PENETRATION; MODELS,"The margin between pore pressure and fracture gradient in new offshore discoveries continues to get narrower. This poses greater risks and higher cost of ensuring safety of lives, facilities and the environment. The 2010 Macondo blowout has fueled increased interests in monitoring downhole parameter for early kick detection. Early detection of kick is important part of the process safety. It provides opportunity to activate safety measures. This work investigates the simplest supervised learning-based kick detection system to ensure higher reliability using experimental data. It combines an Artificial Neural Network (ANN), binary classifier and downhole monitoring of drilling flow parameters to build data-driven kick detection models. Data was generated from experiment that monitors downhole parameters when kick occurs. Recorded parameters such as mud flow-out rate, conductivity, density and downhole pressure are combined to build the model capable of detecting kick events. Abnormal pressure and flow regimes in the wellbore provide early warnings and was shown to be more significant parameters than others, however relying on them alone could increase susceptibility to a false alarm. The model has been tested on data from two different laboratory scale drilling simulator.",9,9,0
Fracture,Fracture Network,"Zhai, Hongyu; Chang, Xu; Wang, Yibo; Lei, Xinglin; Xue, Ziqiu",Analysis of acoustic emission events induced during stress unloading of a hydraulic fractured Longmaxi shale sample,,MOMENT TENSORS; MECHANICAL-PROPERTIES; SICHUAN BASIN; ROCKS; EVOLUTION; FAILURE; COAL,"In shale-gas exploitation, hydraulic fracturing technology is essential to successfully create complex fracture networks in formations. To investigate the dynamic fracturing process, we performed a hydraulic fracturing experiment on a Longmaxi shale sample in the laboratory. After hydrofracturing, hundreds of induced acoustic emission (AE) events were recorded during the stress unloading procedure. At the same time, the high-pressure water stored in the sample fracture network was also discharged. The fracture network inside the fractured sample was studied using medical X-ray computed tomography (CT) scanning technology. Then, the locations and characteristics of the shale failure were analyzed by localizing and inversing the source mechanism of the AE events. Furthermore, the inversion results were verified by comparing with the scanned internal cracks images. According to the source mechanism inversion result, the induced AE events mainly stemmed from the dilatation or compression of fractures and the shear slip of shale along the fracture plane. Finally, the influence of formation attenuation error (underestimated or overestimated attenuation value) on source mechanism inversion results were quantitatively analyzed. It was confirmed that the shear component of the AE event was more sensitive than the volume component to medium attenuation change, especially when the attenuation value was overestimated.",8,9,10
Fracture,Fracture Network,"Zhang, Qitao; Zhu, Weiyao; Liu, Wenchao; Yue, Ming; Song, Hongqing",Numerical simulation of fractured vertical well in low-permeable oil reservoir with proppant distribution in hydraulic fracture,Proppant distribution; Effective fracture length; Vertical well; Threshold pressure gradient; Moving boundary; Flow field,TIP SCREEN-OUT; TRANSPORT; FLOW; FLUID; MODEL; KGD; LAW,"In this paper, numerical simulations of fractured vertical well in low-permeable oil reservoir are carried out and two issues: threshold pressure gradient (TPG) in reservoir matrix and proppant distribution in hydraulic fractures are focused on. A physical definition of effective fracture length (EFL) is presented to evaluate the fracture effectiveness due to uneven proppant distribution. In terms of numerical processing for TPG, based on the subsurface Darcy's flow module in COMSOL Multiphysics, an effective numerical simulation method is adopted by substituting the gravitational acceleration vector in Darcy's law (Liu et al., 2019b). The simulation results show that, proppant distribution has great influence on fracture effectiveness. Unappealing proppant distribution can reduce effective fracture length by 49.6%, which is negative for low-permeable oil reservoir development. TPG in reservoir matrix mainly affects the moving boundary and pressure-disturbed area in reservoir. When TPG in matrix reduces from 0.02 MPa/m to 0 MPa/m, the distance of moving boundary at 300 days could increase for almost double and pressure-disturbed area enlarged drastically for around 74%. Furthermore, a heterogenous low-permeable oil with secondary fracture networks is designed to study the joint effect of TPG and proppant distribution. If we neglect these two factors, cumulative oil rate will be greatly overestimated by 38.6% at 1000 days. At the same time, the existence of natural fractures could also affect the streamline distribution in low-permeable oil reservoir and contribute to fluid flow in reservoir.",8,9,6
Fracture,Fracture Network,"Yue, Ming; Zhang, Qitao; Zhu, Weiyao; Zhang, Liaoyuan; Song, Hongqing; Li, Jianhui",Effects of proppant distribution in fracture networks on horizontal well performance,Hydraulic fracturing; Fracture network; Proppant distribution; Fracture conductivity; Well performance,TIP SCREEN-OUT; HYDRAULIC FRACTURE; NUMERICAL-SIMULATION; TRANSPORT; MODEL; FLOW; SUSPENSIONS; RESERVOIR; SLURRY; KGD,"In this paper, we presented a coupled 3D finite element method model for the simulation of proppant transport in fracture networks and its effects on horizontal well performance. We used a mixture model, which have advantages to deal with two-phase flow containing a dispersed phase like solid particles, to simulate the proppant transport process in fracture networks. Then a tight oil reservoir model was established to evaluate the effect of the proppant distribution on the horizontal well performance. The effects of several factors, such as the proppant physical properties and injection parameters, were analyzed. The calculated results show that, in the fracture network, proppant accumulates at the intersections of cracks. Height of the proppant packed bed in natural fracture was about 30% smaller than that in the main hydraulic fracture, and the communication between hydraulic fractures leads to a larger proppant dune and higher conductivity. Besides, in a tight oil reservoir, the proppant distribution has a significant influence on the well performance. When the reservoir permeability is reduced to 0.05 mD, the productivity index fold of increase calculated including the proppant uneven distribution can be 47.7% larger than that calculated with idealized proppant distribution. Furthermore, the proppant physical properties and injection parameters are found to be correlated with the fracture network conductivity. Based on this analysis, optimum proppant injection conditions can be identified.",8,8,5
Fracture,Fracture Network,"Berawala, Dhruvit S.; Andersen, Pal O.",Numerical investigation of Non-Darcy flow regime transitions in shale gas production,Shale gas production; Non-Darcy flow; Forchheimer equation; Fracture-matrix flow; Apparent permeability,APPARENT PERMEABILITY; STRESS-DEPENDENCE; MODEL; RESERVOIRS; ADSORPTION; IMBIBITION; DIFFUSION; TRANSPORT; NANOPORES; EVOLUTION,"Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable. The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure depletion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir isotherm and is a key production mechanism. This model is implemented in Matlab using Marcellus shale data. Scaling the model shows that recovery of gas depends on two dimensionless number that incorporates geometry relations, time scales of flow, intrinsic parameters of the porous media, non-Darcy constants, adsorption and boundary conditions. The dimensionless numbers define respectively if 1) the fracture or matrix limit the gas production rate 2) if non-Darcy flow is significant in the fracture or matrix. When one of the media limit production, the non-Darcy flow in the other medium has reduced importance and can be excluded from the model. Non-Darcy flow is important if it limits flow in the medium limiting the production. By checking the magnitude of the selected dimensionless numbers, the modelling approach can be determined in advance and significant computational time can be saved. The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.",8,8,4
Fracture,Fracture Network,"Xie, Jing; Gao, Mingzhong; Zhang, Ru; Liu, Junjun; Lu, Tong; Wang, Mingyao",Gas flow characteristics of coal samples with different levels of fracture network complexity under triaxial loading and unloading conditions,Prefractured coal sample; Gas flow characteristics; Permeability evolution; Loading and loading-unloading tests,PERMEABILITY EVOLUTION; STRESS; DEFORMATION; MODEL,"Research on the characteristics of gas flow in coal rocks is fundamentally important for coalbed methane exploitation. Laboratory tests of prefractured coal samples may be a practical means of simulating the fractured media encountered in actual engineering applications. In this study, coal samples were mechanically prefractured, and the complexity of the prefractured structures was described quantitatively. Several gas flow experiments were conducted on these samples under loading and loading-unloading conditions. The experimental results were analyzed in terms of the Klinkenberg effect, the evolution mechanisms of coal rock damage, the coal permeability and the permeability enhancement rate (PER). The main results suggest that the Klinkenberg effect gradually weakens as the fracture complexity indices increase. The prefractured coal samples clearly exhibited a deformation capacity under both loading and loading-unloading conditions, with significant transient instability leading to failure and volume expansion. Under conventional triaxial stress conditions, the permeability of the prefractured coal samples typically evolved via an initial rapid decrease followed by a rebound and a slow increase. The permeability was clearly enhanced during this evolution process. The final permeabilities of fractured coal samples with complexity indices of 0.600, 0.565, 0.549 and 0.522 increased by factors of 2.98, 6.79, 7.54 and 53.33, respectively, over that of a nonprefractured coal sample. Therefore, the more complex a fractured coal sample is, the less distinct the permeability enhancement is. The evolution mechanism of coal permeability under loading-unloading conditions was analyzed based on the porosity-damage relationship and a PER calculation model. The onset of damage corresponded to the onset of the volume change and permeability enhancement.",7,9,11
Fracture,Fracture Network,"Zhao, Peng; Xie, Lingzhi; Ge, Qi; Zhang, Yao; Liu, Jun; He, Bo",Numerical study of the effect of natural fractures on shale hydraulic fracturing based on the continuum approach,Hydraulic fracturing simulation; Anisotropic strength criterion; Discontinuities; Continuum method; Fracturing geometry; Complexity and scale,STIMULATED RESERVOIR VOLUME; PROPAGATION; SIMULATION; MODEL; STRESS; FLOW; GAS; PERMEABILITY; DEFORMATION; MEDIA,"Because of the complexity of shale reservoirs and multiple physical coupling processes, numerical implementation remains a challenge in engineering applications. Unlike conventional reservoirs, shale reservoirs always contain two main discontinuities: bedding interface and natural fractures. The existence of these discontinuities is the key reason a fracture network is formed. Therefore, the numerical model should contain both bedding interface and natural fractures. In this paper, the fracturing propagation process is described based on continuum theory. In contrast to other research, an anisotmpic strength criterion is adopted to consider the anisotropic properties of shale, including the failure of both shale matrix and discontinuities. The criterion is described by the Mohr-Coulomb model combined with tensile failure. When fractures are generated in the shale rock mass, the stiffness and permeability of the fractured rock are homogenized in an element, and volume fracturing is represented by the deformation of three orthogonal fractures in the rock element. Simultaneously, the anisotropic permeability is also enhanced. Hence, based on this continuum approach and finite element method, a three-dimensional model for shale hydraulic fracturing simulation is presented. This model fully considers the direct coupling of fluid flow and rock deformation during hydraulic fracturing. To verify the anisotropic strength criterion, a shale compression test is conducted. Through a comparison of the numerical and experimental results, the applied criterion can describe the shale compressive strength anisotropy. In addition, the KGD analytical model is also adopted to verify the performance of the developed model for hydraulic fracturing. Finally, several cases of shale hydraulic fracturing are simulated, and the results show the geometry of the fracture region under different conditions. Furthermore, the impacts of three factors on hydraulic fracturing geometry are considered, including natural fractures, spacing of perforations and differential in situ stress. The influence of these factors on the complexity and scale of the fracturing region is also discussed.",7,7,7
Fracture,Fracture Network,"Wei, Shiming; Jin, Yan; Xia, Yang",Predict the mud loss in natural fractured vuggy reservoir using discrete fracture and discrete vug network model,Naturally fractured reservoirs; Discrete fractures; Discrete vugs; Mud loss,FINITE-ELEMENT-METHOD; 2-PHASE FLOW; SIMULATION; FLUID; CONTINUUM; MEDIA,"In carbonate reservoirs, the leakage path is complex and the law of mud loss is not clear, which brings difficulties to the implementation of plugging measures. Carbonate reservoir is a naturally fractured vuggy media. One of the key scientific problems is that the fluid mass transfer among matrix pores, natural fractures and vugs is not well understood. In this paper, a discrete fracture and discrete vug model is presented to study the law of mud loss in the naturally fractured reservoir wherein natural fractures and vugs developed. The model solved the fluid flow in the discrete fracture and vug network, consisting of 1) Darcy flow in lowly permeable rock matrix and highly permeable natural fractures; 2) free flow in macro vugs. A physically-based boundary is applied to ensure the mass continuity on interfaces between vugs and matrix pores, vugs and natural fractures. A good agreement with analytical results for Poiseuille flow in a porous/free connected media is achieved. Two numerical examples using the commercial software COMSOL provide validation of the new model. When simulating the mud loss process, we find that as soon as vugs are connected to wellbore through natural fractures, total loss is observed. The size and number of vugs play prominent roles in increasing mud loss rate and accumulated mud loss. The numerical results show that the discrete fracture and discrete vug model provides a reliable way to model realistic fluid flow in fractured vuggy porous media. The model in this paper can not only simulate the mud loss process, but also the production process of carbonate reservoirs.",7,7,4
Fracture,Tight Oil Reservoirs,"Mahesar, Aftab Ahmed; Shar, Abdul Majeed; Ali, Muhammad; Tunio, Abdul Haque; Uqailli, Muhammad Aslam; Mohanty, Udit Surya; Akhondzadeh, Hamed; Iglauer, Stefan; Keshavarz, Alireza","Morphological and petro physical estimation of Eocene tight carbonate formation cracking by cryogenic liquid nitrogen; a case study of Lower Indus basin, Pakistan",Tight carbonate rocks; Petro physics; SEM; AFM; Nano indentation; Liquid nitrogen,PORE STRUCTURE; COAL DAMAGE; GLOBAL OIL; EVOLUTION; PERMEABILITY; RESERVOIRS; SALINITY; FREEZE,"Significant amounts of hydrocarbons are contained in tight carbonate rocks like those within the Indus basin of Pakistan, but due to their unconventional nature, their extraction is difficult. This can be completed/conducted by properly characterizing its mineralogical, geochemical and microstructural properties. In this context, Hydraulic fracturing and acidizing are the most common fracture stimulation techniques. However, they suffer significant technical and environmental flaws. Liquid Nitrogen (LN2) fracking is considered as one of the best alternatives compare to hydraulic fracturing or acidizing due to its eco-friendly nature. In fact, after exposer to LN2, super cryogenic feature of the rock causes porosity, permeability and fracture conductivity enhancement due to thermal shock without any environmental consequences. The effect of Liquid Nitrogen fracking on tight carbonate outcrops collected from the Indus basin is investigated in the present study. Scanning Electron Microscopy (SEM) reveals the clear appearance of wide pore fractures with sizes from 4 mu m to 50 mu m, when subjected to liquid Nitrogen (LN2) treatment ranging from 30 to 90 min' duration. Furthermore, SEM and Atomic Force Microscopy (AFM) images also indicate clear pore fractures in tight carbonate rocks along with increased pore connectivity. Moreover, following liquid nitrogen treatment of up to 90 min the permeability of tight carbonate increases by 53% and increases in porosity by 73%. Results from SEM studies suggest that visible fractures occur in the tight carbonate samples with liquid nitrogen treatment because of the freezing temperature (-196 C-square) of Liquid Nitrogen. In addition to this, Nano indentation moduli depict significant decreases in tight carbonate rocks, both before and after exposure to LN2, as a result of increases in liquid rock compressibility. In this regard, a 50 mN force decreased from 50.57 GPa to 24.37 GPa and for a 200 mN force this decreased from 45.77 GPa to 26.67 GPa. This research depicts the significant effect of Liquid Nitrogen freezing on the fracturing of carbonate rocks.",32,32,8
Fracture,Tight Oil Reservoirs,"Cheng, Linsong; Wang, Deqiang; Cao, Renyi; Xia, Rufeng",The influence of hydraulic fractures on oil recovery by water flooding processes in tight oil reservoirs: An experimental and numerical approach,Tight oil; Hydraulic fracture; Water flooding; Water breakthrough; Core flood experiment,HORIZONTAL WELLS; SHALE; FLOW; GAS; STORAGE; EOR,"The use of multi-fractured horizontal wells has helped to develop tight oil reservoirs, but, if oil depletion occurs, the estimated ultimate recovery is low. Water flooding can be regarded as an easily applied method for improving oil recovery. This study aimed to optimize the scale of the stimulated reservoir volume (SRV) by conducting an experiment to verify the water injection capacity of the Chang 7 Formation, which is situated within in a typical tight oilfield. A one-dimensional long core displacement experiment was designed based on injecting formation water into a tight matrix core and fractured cores with different fracture lengths. Results were then verified and analyzed using core flood simulation and targeted field tests, and they clarified the feasibility of injecting water into a tight oil formation when the injection well is fractured, or when fractures exist near the injection well. It was also verified that although fractures increase the equivalent permeability in the fractured core and promote pressure propagation, they can also lead to rapid water breakthrough if they communicate with the producer well. It is thus considered that optimization of the SRV extent would enhance the recovery of oil and decrease the risk of water breakthrough.",16,15,3
Fracture,Tight Oil Reservoirs,"Zhang, Juan; Zhang, Hui Xiao; Ma, Li Yan; Liu, Yi; Zhang, Liang",Performance evaluation and mechanism with different CO2 flooding modes in tight oil reservoir with fractures,CO2 injection; Flooding mechanism; Fractures; Tight reservoir; Miscible pressure,GAS; GENERATION; INJECTION; RECOVERY; EOR,"Due to the abundant reserves in tight reservoirs and the large amounts of residual oil after implementing common enhanced oil recovery methods, profitable methods with a high oil recovery such as CO2 flooding are urgently needed. Although CO2 flooding has attracted much attention and obtained good results in China and abroad, it has the critical problem of a low sweep efficiency, especially in tight reservoirs that develop with hydraulic fractures. In this study, the minimum miscible pressure of oil and CO2 was measured as 17.8 MPa, higher than the original formation pressure. Subsequently, the minimum miscible pressure was matched by means of numerical simulation, and the method of adding intermediate components to the injection CO2 was studied to reduce the miscible pressure in the study area. Afterwards, fractures were added to the geological model to study the mechanism of gas channeling under different CO2 injection modes. The continuous CO2 injection (CGI) mode requires the largest gas injection volume, which is easily affected by fractures and production pressure differences to form irregular gas channeling. Soaking alternating gas injection (SAG) can effectively supplement the formation pressure through periodic well switching, gas channeling delay, and radial gas flooding pattern formation. Water alternating CO2 (WAG) flooding can delay gas channeling, and the rhombus or square gas flooding pattern is formed due to the influence of the well pattern and well spacing. Foam flooding can better mitigate gas channeling but has a poor displacement effect. Through comparison of the various gas injection modes, it is concluded that WAG is the best CO2 flooding mode in the research area, and the cumulative increase in oil over 20 years can reach 390,466 t. The outcome of this work is important to CO2 flooding in tight reservoirs with fractures. The CO2 flooding mechanism in tight reservoir with fractures was examined.",14,14,12
Fracture,Tight Oil Reservoirs,"Wijaya, Nur; Sheng, James J.",Mitigating near-fracture blockage and enhancing oil recovery in tight reservoirs by adding surfactants in hydraulic fracturing fluid,Surfactant; Water blockage; Invasion fluid; Flowback; Interfacial tension; Wettability alteration,CALCIUM ALGINATE BEADS; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; WATER BLOCKING; IFT REDUCTION; FLOW; GAS,"Flowback after hydraulic fracturing consistently shows a significantly poor load recovery of the fracturing fluid. The unrecovered fluid creates a blockage at the matrix-fracture interface in the reservoir, which hinders the optimum hydrocarbon production. Surfactant, added into the fracturing fluid, is believed to minimize this blockage by reducing the oil-water interfacial tension (IFT) and altering the rock wettability. Although many lab and field data have shown the surfactant benefits, there is a lack of mechanistic analysis on how surfactant more effectively removes such blockage. Therefore, this paper presents a mechanistic study of water blockage removal by surfactant. Interfacial tension (IFT) reduction and wettability alteration effect are modeled to represent the main effects induced due to the surfactant addition. Our numerical model is extensively calibrated with computed tomography (CT) scans and pressure drop data during coreflood experiments. Our model shows that surfactant addition into the fracturing fluid results in a better water blockage removal than fracturing water alone, because surfactant results not only in a shallower invasion depth, but also a much milder blockage within the shallower invasion depth itself. Furthermore, our model also discovers that the restoration of hydrocarbon permeability by surfactant could demonstrate a time-dependent behavior, based on the interplaying effects among IFT reduction, fracture clean-up state, and the wettability of the matrix-fracture interface. Overall, by presenting the mechanistic analysis, this study serves as a crucial step toward the optimization of surfactant formulation for fracturing fluid and EOR applications in tight reservoirs.",14,14,8
Fracture,Tight Oil Reservoirs,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Fracture,Tight Oil Reservoirs,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Fracture,Tight Oil Reservoirs,"Xiao, Qianhua; Yang, Zhengming; Wang, Zhiyuan; Qi, Zhilin; Wang, Xuewu; Xiong, Shengchun",A full-scale characterization method and application for pore-throat radius distribution in tight oil reservoirs,Tight oil reservoir; Full-scale characterization method; Pore-throat radius distribution; Content of nanoscale pores,HYDROCARBON; CHINA; EXPLORATION; ADSORPTION; SHALE; FLOW,"A pore-throat radius full-scale distribution is defined according to the molecular size of formation fluid and the lower limit of pore-throat radius distribution, in order to study the integratedcharacteristics of micro-nano pore-throat systems in tight oil reservoirs. In this study, we established a new full-scale characterization method for pore-throats through contrasting experimental data of high-pressure mercury injection and low-temperature nitrogen adsorption, optimizing the valid data intervals of the full-scale pore-throat radius distribution. Then, the data of full-scale pore-throat radius distribution is checked and corrected based on the experimental data of NMR and centrifugation. Finally, the mesopore data is derived from low-temperature nitrogen adsorption and the macropore data is derived from high-pressure mercury injection. Moreover, the steps to characterize full-scale pore-throats include one unified dimension, one data optimization, two interpolations, one connection, one data test and one data correction. The full-scale characterization of pore-throat radius distribution in tight oil reservoirs of Daqing, Changqing, Sichuan and Dagang shows that the pore-throats of tight sandstones are mainly distributed in the submicron-nano-scale, and 50% of permeability is contributed by submicron pores. Therefore, it is challenging to effectively develop the tight oil reservoirs with permeability less than 0.08 mD in Daqing and lower than 0.03 mD in Changqing. For tight carbonate matrix, pore-throats are mainly distributed in the nanoscale space, and the permeability is mainly contributed by macropores or fractures, so the developmental degree of fractures and other factors shall be considered for estimating the development limit.",13,13,8
Fracture,Tight Oil Reservoirs,"Ju, Wei; Niu, Xiaobing; Feng, Shengbin; You, Yuan; Xu, Ke; Wang, Geoff; Xu, Haoran","Present-day in-situ stress field within the Yanchang Formation tight oil reservoir of Ordos Basin, central China",In-situ stress field; Tight oil reservoir; Yanchang formation; Stress regime; Natural fracture; Ordos basin,SEDIMENTARY-ROCKS; LOW-PERMEABILITY; TECTONIC STRESS; STATE; AREA; EXPLORATION; FRACTURES; PATTERN; REGION; ORIENTATIONS,"The present-day in-situ stress field has many important and practical applications during the exploration and development of hydrocarbon resources. The Ordos Basin is a significant petroliferous basin in China, within which, the Yanchang Formation serves as the most significant tight oil reservoir. However, an overview of previous studies indicates that little was known as to the present-day stress state in the Yanchang Formation. Therefore, the present-day stress field in the Yanchang Formation tight oil reservoir of the Ordos Basin is systematically analyzed in this study. The orientation of horizontal maximum principal stress (S-Hmax) within the Yanchang Formation of Ordos Basin ranges between north-northeast-south-southwest-trending (NNE-SSW) and east-northeast-west-southwest-trending (ENE-WSW) based on interpretations of borehole breakouts and drilling-induced fractures from borehole imaging logs. The S-Hmax orientation shows various tendencies in different wells, which may result from differential development in lithology, natural fracture and bedding plane over various regions. The estimated magnitudes of vertical stress (S-v), S-Hmax and horizontal minimum principal stress (S-hmin) in the studied wells indicate that the normal faulting stress regime is dominant within the Yanchang Formation. In addition, the geomechanical assessments of wellbore stability and natural fracture reactivation are also performed. Natural fractures in the Yanchang Formation Chang 7 tight oil reservoir of Ordos Basin are developed striking mainly in the northeast-southwest-trending (NE-SW) and west-northwest-east-southeast-trending (WNW-ESE). Among them, those fractures with NE-SW-trending strikes are more conductive with reference to the present-day stress state, contributing more to tight oil production in the Ordos Basin. In addition, within the Yanchang Formation, if horizontal wells are drilled towards the NNE-SSW-trending to ENE-WSW-trending, they are more likely to have wellbore instability issues. The results in this study provide important geological information for tight oil production in the Yanchang Formation of Ordos Basin.",13,14,3
Fracture,Tight Oil Reservoirs,"Tariq, Zeeshan; Mahmoud, Mohamed; Abdulraheem, Abdulazeez; Al-Nakhli, Ayman; BaTaweel, Mohammed",An experimental study to reduce the breakdown pressure of the unconventional carbonate rock by cyclic injection of thermochemical fluids,Unconventional formation; Breakdown pressure; Thermochemical; Cyclic fracturing; Multiple fractures,HYDRAULIC FRACTURE PROPAGATION; SIMULATION; RESERVOIR; OIL,"Commercial production from unconventional reservoirs needs massive fracturing operations. Therefore, long horizontal wells are drilled, and multi-stage fractures are created to achieve the desirable production rates from these reservoirs. One common and major problem in most of the unconventional reservoirs is the high breakdown pressure due to the reservoir tightness. When fracturing these types of rocks, the hydraulic fracturing operation becomes much more challenging and difficult. In some scenarios reaches to the maximum pumping capacity without generating any fractures. In this study, a new approach to reduce the breakdown pressure of tight rocks is introduced and compared with the conventional method of fracturing. The new method incorporates the injection of thermochemical fluid in a series of cycles to create micro- and macro-fractures. The cyclic experiments performed in this study were concluded with the recording of breakdown pressure in each case. The post-treatment analysis using medical Computerized Tomography (CT) showed that multiple fractures were created due to the pressure pulse created in the thermochemical reaction. Results showed that the breakdown pressure of the rock decreases with the increasing number of cycles. The proposed method of cyclic thermochemical fracturing reduced the breakdown pressure by 33% in one-cycle, 41% in two-cycles, 53.5% in three-cycles, and 69% in four-cycles, when compared with conventional method of fracturing. An empirical relationship is also presented between the number of cycles of thermochemical fluid injection and the breakdown pressure of the rock.",12,12,5
Fracture,Tight Oil Reservoirs,Wang Xue-wu; Xiao Pufu; Yang Zheng-ming; Liu Xue-wei; Xia Zhi-zeng; Wang Li-qiang,Laboratory and field-scale parameter optimization of CO2 huff-n-puff with the staged-fracturing horizontal well in tight oil reservoirs,Tight oil reservoirs; Horizontal well; Fracture; CO2 huff-n-puff; Production mechanism; Parameters optimization,RECOVERY,"With the help of large-scale physical simulation experiment technology, the physical simulation experiments of the CO2 huff-n-puff with the staged-fracturing horizontal well could be acheived. We studied the production process of CO2 huff-n-puff and influence of different parameters affect oil recovery during the CO2 huff-n-puff procedure, ultimately, the operation parameters were optimized by numerical simulation. The results show that CO2 can quickly enter the deep formation through the horizontal well and the fracture during the huff period and staged-fracturing horizontal well can greatly increase the contact area between CO2 and crude oil, which improves the efficiency of extraction, dissolution, reduction of viscosity between CO2 and crude oil. During the puff period, the horizontal well and fractures can reduce the flow resistance effectively, so as to improve the flow capacity of crude oil. After 3 cycles of CO2 huff and puff, the oil recovery can be enhanced by 11.13%-21.39% compared with that obtained by elastic flooding, which indicates that the exploitation method of CO2 huff-n-puff can improve the development effects of tight oil reservoirs. CO2 huff-n-puff injection parameters are optimized, the results show that the optimum time of injection is 1 year, the optimum soaking time is 30d, and the optimal injection pore volume is 0.18HCPV. This research can provide a certain technical support for effective development of tight oil reservoirs.",11,12,3
Fracture,Tight Oil Reservoirs,"Du, Shuheng","Characteristics and the formation mechanism of the heterogeneous microfractures in the tight oil reservoir of Ordos Basin, China",Microfracture; Formation mechanism; Tight oil; Sandstone; Characterization,SANDSTONE RESERVOIR; FRACTURE NETWORK; PERMEABILITY; INSPIRATION; SIMULATION; ANISOTROPY; MODELS; SHALE; FLOW,"This study aims to investigate the characteristics and the formation mechanism of the heterogeneous microfractures in the upper Triassic Yanchang Formation tight oil reservoir of Ordos Basin, China with some new perspectives. In this paper, we define two sets of parameters describing the size and geometry of microfractures by using Feret diameter calculation and Legendre ellipse fitting. Then the unidirectional fracture zone and multidirectional fracture zone are also be defined. Results of the microfractures characterization show that when the lengths of microfractures are less than 600 mu m (and the widths are less than 90 mu m), the above two set of data show a good linear positive correlation, but when the lengths of microfractures continue to increase, the widths of microfractures begin to deviate from the linear relationship and gradually diverge. This indicates that the lengths and widths of microfractures are not strictly and steadily correlated, but their correlation has a threshold value. If the lengths of microfractures increase due to the change of internal or external stress, when the length value is higher than a certain value, the opening process of microfractures will begin to lose stability, and the widths will change gradually irregularly. Once the compaction process reach a certain extent, some of the microfractures opened previously will be temporarily closed, which will greatly promote the process of pressure-solution, and thus increase the microfracture tortuosity. The length, width, solidity and boundary tortuosity of microfractures could be used to distinguish two zones include the multi-directional fracture zone from the unidirectional fracture zone. The conclusion would provide the important scientific basis for the EOR applications of tight oil.",11,11,1
Fracture,Tight Oil Reservoirs,"Chen, Hailong; Li, Haifeng; Li, Zhaomin; Li, Songyan; Wang, Yujun; Wang, Jian; Li, Binfei",Effects of matrix permeability and fracture on production characteristics and residual oil distribution during flue gas flooding in low permeability/tight reservoirs,Flue gas flooding; Matrix permeability; Fracture; Residual oil distribution; Gas channeling point,HUFF-N-PUFF; HEAVY OIL; CO2; RECOVERY; TIGHT; STEAM; STORAGE; FOAM; INJECTION; DRIVE,"The effects of matrix permeability and fracture on production characteristics and residual oil distribution of flue gas flooding in low permeability/tight conditions are analyzed systematically by laboratory physical simulation experiments and low-field nuclear magnetic resonance (LFNMR) system. T2 spectra results show that the crude oil is mainly distributed in the corresponding macropores of 100-1000 ms before and after the flue gas injection, and the crude oil in macropores is produced in large quantities after the flue gas injection in both fracture and fracture-free low permeability/tight cores. Additionally, oil production performance indicates that matrix permeability has a remarkable effect in fracture-free low permeability/tight cores. T2 spectra combined with slice scanned images show the migration from the macropores to the medium and fine pores is more obvious in the core with high matrix permeability and the final residual oil distribution is more uniform compared to those of the core with low matrix permeability. Matrix permeability is inversely proportional to the gas channeling point and it has a linear relationships with the gas channeling point in a log-log plot in fracture-free low permeability/tight cores. Besides, fracture can significantly reduce the effect of matrix permeability on oil recovery. The presence of fracture weakens the migration of crude oil in low permeability/tight fracture cores, and the residual oil spreads throughout the core. Fracture plays a dominating role in the gas channeling points for different permeability cores.",9,9,15
Fracture,Tight Oil Reservoirs,"Zhang, Yanjun; Ge, Hongkui; Shen, Yinghao; Jia, Leilei; Wang, Jianbo",Evaluating the potential for oil recovery by imbibition and time-delay effect in tight reservoirs during shut-in,Potential evaluation; Oil recovery by imbibition; NMR; Time-delay effect; Shut-in,FORMATION DAMAGE; GAS-RESERVOIRS; SHALE; FLOW; ADSORPTION; SIMULATION; WELL,"When stimulated only by natural energy, tight oil reservoirs have low production efficiency. Improving the potential for oil recovery by imbibition is essential to enhancing oil production. Shut-in is an effective way to make good use of the potential for oil recovery by imbibition. In this study, imbibition experiments and nuclear magnetic resonance (NMR) testing were combined to reveal the characteristics of spontaneous imbibition and the T-2 value of the oil recovery potential by imbibition in tight oil reservoirs. The main factors affecting the potential for oil recovery by imbibition were studied. We also discussed the relationship between clay minerals and the potential for oil recovery by imbibition, especially the time-delay effect of imbibition displacement. A modified model based on the static balance time for spontaneous imbibition was proposed to calculate the field shut-in time. The results show that the static spontaneous imbibition balance time of tight oil reservoirs are significantly different in various zones. The oil recovery by imbibition has an obvious time-delay effect and it could put the oil in non-movable pores under natural conditions to use. Internal conditions like microscopic pore structure and the type of clay minerals affect the oil recovery by imbibition on small pores (T-2 < 100 ms). External conditions like reservoir temperature, pressure, and bedding affect oil recovery by imbibition in small and large pores. The clay minerals expand after the interaction between fracturing fluids and rock. Meanwhile, oil is discharged with compression of those pore space. To optimize the shut-in time of a tight reservoir, these effects of clay behavior can suggest good practices in hydraulic fracturing.",9,9,4
Fracture,Tight Oil Reservoirs,"Ye, Tao; Niu, Chengmin; Wei, Ajuan","Characteristics and genetic mechanism of large granitic buried-hill reservoir, a case study from PengLai oil field of Bohai Bay Basin, north China",,WEATHERING CRUST; TIGHT SANDSTONES; JUNGGAR BASIN; ZHENJING AREA; BONGOR BASIN; FAULT ZONE; BASEMENT; ROCK; FRACTURES; MIGRATION,"In recent years, a major breakthrough has been made in granite hydrocarbon exploration in the Bohai Bay Basin. With the proven reserves of more than 2 x 10(8)t, the Penglai (PL) oilfield is the largest granite oilfield discovered in China. Although the reservoir scale is large, the reservoir heterogeneity is also strong, which brings challenges to its exploration and evaluation. Based on the data of cores, thin sections, whole rock and physical property, the reservoir characteristics and control factors of reservoir-forming in the study area are discussed through the fault analysis and the recovery of tectonic uplift history. The results show that the lithology of PL structure are mainly Mesozoic intrusive granite and Proterozoic mica quartz schist, which develops reservoirs related to the weathered crust and internal fractures. Due to the influence of weathering intensity and fault activity, the porous reservoirs in weathered glutenite zone, pore-fractured reservoirs in weathered fracture zone and fractured reservoirs in the inner fracture zone were distributed orderly from top to bottom vertically. The scale of the high quality reservoir on the plane is controlled by lithology, faults, weathering and buried depth. Granite is the main reservoir-forming lithology for more brittle and less resistant to weathering than mica quartz schist, which forms a special phenomenon that the granite in saddle is rich for hydrocarbon while the mica quartz schist in high position is poor for hydrocarbon accumulation. The northwest Miaoxi fault is the main controlling-fault in the study area, and there is an obvious negative correlation between reservoir thickness and distance from this fault. The long-term uplift of Cenozoic provides conditions for strong weathering, while the shallow burial in the late stage provides effective protection for weathered crust reservoirs. The coupling of the above conditions is the main reason of large scale reservoir development in the study area, and among them, the long-term uplift is the key factor for reservoir-forming.",9,10,3
Fracture,Tight Oil Reservoirs,"Yue, Ming; Zhang, Qitao; Zhu, Weiyao; Zhang, Liaoyuan; Song, Hongqing; Li, Jianhui",Effects of proppant distribution in fracture networks on horizontal well performance,Hydraulic fracturing; Fracture network; Proppant distribution; Fracture conductivity; Well performance,TIP SCREEN-OUT; HYDRAULIC FRACTURE; NUMERICAL-SIMULATION; TRANSPORT; MODEL; FLOW; SUSPENSIONS; RESERVOIR; SLURRY; KGD,"In this paper, we presented a coupled 3D finite element method model for the simulation of proppant transport in fracture networks and its effects on horizontal well performance. We used a mixture model, which have advantages to deal with two-phase flow containing a dispersed phase like solid particles, to simulate the proppant transport process in fracture networks. Then a tight oil reservoir model was established to evaluate the effect of the proppant distribution on the horizontal well performance. The effects of several factors, such as the proppant physical properties and injection parameters, were analyzed. The calculated results show that, in the fracture network, proppant accumulates at the intersections of cracks. Height of the proppant packed bed in natural fracture was about 30% smaller than that in the main hydraulic fracture, and the communication between hydraulic fractures leads to a larger proppant dune and higher conductivity. Besides, in a tight oil reservoir, the proppant distribution has a significant influence on the well performance. When the reservoir permeability is reduced to 0.05 mD, the productivity index fold of increase calculated including the proppant uneven distribution can be 47.7% larger than that calculated with idealized proppant distribution. Furthermore, the proppant physical properties and injection parameters are found to be correlated with the fracture network conductivity. Based on this analysis, optimum proppant injection conditions can be identified.",8,8,5
Fracture,Tight Oil Reservoirs,"Chen, Beibei; Xu, Bin; Li, Biao; Kong, Mingwei; Wang, Wanbin; Chen, Huasheng",Understanding the performance of hydraulically fractured wells in the laumontite-rich tight glutenite formation,Hydraulic fracturing; Reservoir dilation; Tight glutenite formation; Laumontite-rich reservoir rock,CAJON-PASS; MODEL; PERMEABILITY; ROCK; DEHYDRATION; SANDSTONES; ZEOLITES; STRENGTH; TESTS; FAULT,"Massive hydraulic fracturing treatments have been used to produce hydrocarbons from tight glutenite oil reservoirs through both vertical and horizontal wells. Some tight glutenite reservoirs are rich in laumontite. Field experiences indicate that the performance of hydraulically fractured wells on this type of laumontite-rich tight glutenite reservoir typically resulted in low oil productivity and quickly declining oil rates. To understand the poor well performance of these laumontite-rich tight oil wells, extensive laboratory and numerical simulation studies have been conducted to explore the major controlling factors. Laboratory results indicate that the laumontite-rich glutenite reservoir rock has the following characteristics: 1) reservoir permeability is sensitive to stress conditions; 2) reservoir rock has low mechanical strength; and 3) reservoir rock has a low elastic modulus. These geomechanical deformation characteristics strongly affect the well productivity on the laumontite-rich formations. During the hydraulic fracturing and well production phases, the reservoir rock near the main hydraulic fracture can be compacted significantly to reduce rock porosity and permeability. As a result, the fluid flow capacity from the reservoir rock into the hydraulic fracture is reduced. By using laboratory testing data, fully coupled flow-deformation finite element simulations were conducted to study the impact of rock compaction/dilation on well productivity. Based on the numerical simulations, a new hydraulic fracturing scheme was proposed, and a field pilot test was conducted on one vertical well in the study area. Promising field oil production rates were achieved. This paper presents our understanding of the laboratory data, numerical simulation, and field pilot tests results. The new hydraulic fracturing scheme was based on the rock dilation near the main hydraulic fracture. The result indicates that rock dilation, if proactively utilized, can enhance the fluid deliverability from the reservoir into the main hydraulic fracture and boost well productivity.",8,8,3
Fracture,Tight Oil Reservoirs,"Wijaya, Nur; Sheng, James J.",Optimum surfactant criteria for controlling invasion-induced water blockage in tight water-wet cores,Surfactant; Hydraulic fracturing; Flowback; Water blockage; Interfacial tension; Wettability alteration,ENHANCED SPONTANEOUS IMBIBITION; CALCIUM ALGINATE BEADS; WETTABILITY ALTERATION; IFT REDUCTION; OIL-RECOVERY; GAS SHALES; RESERVOIRS; FLOW; MECHANISMS; ADSORPTION,"Flowback after hydraulic fracturing shows a poor recovery of the fracturing fluid. The unrecovered fluid is believed to invade the matrix and creates a formation damage called water blockage, which affects the optimum oil production from the reservoir. Surfactant is often added into the fracturing fluid, because it can improve the recovery of the fracturing fluid, and hence minimum water blockage. This objective is achieved by the surfactant's interfacial tension (IFT) reduction and wettability alteration capabilities. This study investigates the optimum surfactant criteria, in terms of the IFT and wettability, to minimize the water blockage. From the perspective of regained oil relative permeability, our history-matched core-scale model reveals that the optimum criteria depend on the matrix capillarity. In conventional reservoirs, the optimum criteria are to select surfactants which offer ultralow IFT (even as low as 0.001 mN/m) and maintain the waterwetness of the rock. However, in tight reservoirs, the optimum criteria are surfactants which strongly alter the rock wettability to oil-wet, while the IFT requirement is more flexible (i.e., from 15 down to 0.001 mN/m). The contradicting optimum criteria can be explained by the relative dominance between relative permeability and capillary pressure. This study emphasizes that the optimum surfactant criteria for conventional reservoirs are not necessarily the same as those for tight reservoirs.",8,8,2
Fracture,Tight Oil Reservoirs,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Fracture,Tight Oil Reservoirs,"Sun, Ruofan; Hu, Jinghong; Zhang, Yuan; Li, Zhiping",A semi-analytical model for investigating the productivity of fractured horizontal wells in tight oil reservoirs with micro-fractures,Micro-fractures; Fractured horizontal wells; Well productivity; Tight oil reservoirs; Sensitivity analysis,PRESSURE-TRANSIENT ANALYSIS; GAS-PRODUCTION; LINEAR FLOW; MICROFRACTURES; SHALE; PERMEABILITY; PERFORMANCE; PREDICTION; BASIN,"Combining horizontal drilling with hydraulic fracturing has become a well-established technique to improve well productivity in tight oil reservoirs. The existence of micro-fractures in these reservoirs affects the fluid flow process as well as the productivity. However, current models for evaluating the well performance of fractured horizontal wells containing micro-fractures lack accuracy. Hence, the objective of this study is to build an efficient model to analyze well productivity, considering the effects of micro-fractures. A novel flow model for multi-fractured horizontal wells was established, considering the effect of micro-fractures on the fluid flow. Subsequently, we built a reservoir model based on the typical fracture and fluid properties of a tight oil block in the Daqing oil field, China. Good agreement between the prediction results and field data was obtained, indicating that the effect of micro-fractures on well productivity cannot be neglected. Further study reveals that micro-fractures essentially function as a joint connecting reservoir matrix and have a persistent impact on well productivity. Micro-fractures can promote well productivity; however, if the value of micro-fracture permeability increases, this promotional effect will slow down. Well productivity can be considerably improved as an increase in micro-fracture percentage. Finally, a series of sensitivity studies were conducted to identify the effects of critical parameters on well productivity. Results show that reservoir permeability significantly influences well productivity, followed by reservoir effective thickness, micro-fracture percentage, fracture number, hydraulic fracture half-length. Pressure sensitivity coefficient, threshold pressure gradient and micro-fracture permeability have the least effect on well productivity. This work provides a sophisticated and efficient tool to evaluate the productivity of multi-fractured horizontal wells in tight oil reservoirs with micro-fractures.",7,7,5
Fracture,Mechanical Properties,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Wang, Suifeng; Wang, Tao; Shi, Xiaohong; Dong, Qingxiang; Li, Junyang",Natural fractures in soft coal seams and their effect on hydraulic fracture propagation: A field study,Soft coal seam; Qinshui Basin; Natural fractures; On-site hydraulic fracturing; Hydraulic fractures; Particle flow method,PORE STRUCTURE CHARACTERIZATION; HIGH-RANK COAL; MECHANICAL-PROPERTIES; RESERVOIR PRESSURE; ACOUSTIC-EMISSION; FIB-SEM; METHANE; PERMEABILITY; MODEL; ROCK,"Natural fractures provide direct flow channels for coalbed methane (CBM) production and gas outburst control. However, in soft coal seams, the characteristics of natural fractures and their effect on hydraulic fractures are still unclear. In this study, a spatial system of visible natural fractures was established through underground dissection and measurement of ground joints from a case study of the Xinyuan Coal Mine in the northern Qinshui Basin, China. Our results show that the orientations of the subsurface exogenetic fractures of the coal seams are consistent with the macrostructural joints on the ground surface in the same tectonic setting. The exogenetic fractures of the coal seams have dominant orientations with approximately equal spacing. Next, a field test of a large-scale hydraulic fracturing project with a volume of up to 2000 m(3) was conducted. The on-site observation of the underground coal seams revealed that the propagation orientation of the vertical propped fractures coincides with the predominant orientation of the natural fractures. Even at a high constant injection rate (12 m(3)/min), the corresponding injection pressure was not constant during the propagation of the hydraulic fractures, and this can be attributed to the effect of the depth of the coal seam, internal natural fracture network, and normal fault. Additionally, a two-dimensional (2D) particle flow simulation (PFC2D) showed that the propagation of the hydraulic fracture is controlled by the orientations of the natural fractures and the principal stresses. The orthogonal fracture network showed more sensitivity to joint spacing than the layered fracture network in controlling the hydraulic fractures. Finally, fluid detection of the coalbed demonstrated that the flow range of the fracturing fluid in the natural exogenetic fractures was up to a few hundred meters. The flow direction was consistent with that of the natural fractures. A comprehensive analysis of the natural fractures contributes to the identification of flow channels and helps in the design of hydraulic fracturing engineering in soft coal seams.",20,20,9
Fracture,Mechanical Properties,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Fracture,Mechanical Properties,"Gupta, Ishank; Sondergeld, Carl; Rai, Chandra",Fracture toughness in shales using nano-indentation,Fracture toughness; Nano-indentation; Shale anisotropy; Water weakening,,"Fracture toughness property is often ignored but has a significant impact on the hydraulic fracture design, i.e. length and height. It represents the resistance of the rock to hydraulic fracturing and is a direct indicator of rock fracability. It is difficult to measure fracture toughness in shales using current experimental procedures designed for conventional rocks largely due to mechanical and chemical instability in shales. This study measures fracture toughness in shales using nano-indentation. Nano-indentation can, in fact, be used to derive both tensile and shear dominated fracture toughness. The observations in the study show that while crack-length method derived fracture toughness is close to Mode I (tensile) fracture toughness, energy-method based fracture toughness is closer to Mode II (shear) fracture toughness. Fracture toughness was calculated for 67 samples in different shale formations namely Marcellus, Wolfcamp, Woodford and Eagle Ford. The results show that mineralogy had a strong control on fracture toughness. Fracture toughness decreases with increasing porosity, TOC (Total Organic Carbon) and clay content. The fracture toughness also shows strong anisotropy with fracture toughness measured parallel to the bedding planes being generally 33% higher than the corresponding values measured normal to the bedding planes. The fracture toughness shows a direct correlation with other mechanical properties like Young's modulus, hardness and brittleness. Typically, samples with fracture toughness values greater than 3 MPa m(0.5) were found to be brittle based on Young's modulus and Poisson's ratio cross plots. Evaluation of fluid effects on fracture toughness shows that it decreases by 10-37% due to spontaneous imbibition with low salinity brines. This could help understand the impact of hydraulic fracturing fluid on fracture propagation and stimulated reservoir volume (SRV) creation.",14,15,5
Fracture,Mechanical Properties,"He, Huan; Senetakis, Kostas",A micromechanical study of shale rock-proppant composite interface,Shale rock; Quartz sand; Interface friction; Hydraulic fracturing; Proppant,GRAIN-SCALE MECHANICS; GUM AQUEOUS-SOLUTION; FRACTURE CONDUCTIVITY; QUARTZ SAND; BEHAVIOR; CONTACT; SHEARING; PARTICLE,"The micromechanical properties of shale rock-sand type of composite interface were investigated by performing laboratory tests with a custom-built loading apparatus. This type of interface is of significant interest in petroleum engineering in the process of hydraulic fracturing using proppants. Two different types of quartz sands of different particle shapes were used as proppant simulants and they were sheared against rough and smooth surfaces of shale. It was shown that sand grain type and surface roughness of shale affected the contact stiffness in the normal and tangential directions because of their influence on the induced contact stresses. Based on the micromechanical shearing tests, it was found that the coefficient of friction, the initial tangential stiffness and the microslip displacement were positively correlated with the magnitude of normal load. Although clear surface damage/plowing of the shale surface caused by shearing was observed and captured by interferometry images, the effect of loading history was found to be small. Shearing tests on wet and dry shale surfaces did not show that much difference in results, but immersion of shale in water prior to shearing affected the initial tangential stiffness and coefficient of friction at certain normal loads. Smoothening of the surface had an influence on friction as long as limited plowing was triggered in the low range of normal loads, so that the influence of surface roughness of the shale would diminish at higher normal loads where plowing mechanism dominated the interface response.",14,14,5
Fracture,Mechanical Properties,"Dias, Luciana Olivia; Bom, Clecio R.; Faria, Elisangela L.; Valentin, Manuel Blanco; Correia, Maury Duarte; de Albuquerque, Marcio P.; de Albuquerque, Marcelo P.; Coelho, Juliana M.",Automatic detection of fractures and breakouts patterns in acoustic borehole image logs using fast-region convolutional neural networks,Borehole; Image; Deep learning; Breakouts; Geological fractures; Classification,MECHANICS,"Borehole acoustic image logs present meaningful information about some petrophysical properties of a reservoir. The identification of these features, in addition to several supplementary data are very important to achieve a valid characterization of the reservoir itself. Among the different patterns that image logs could show, it can be mentioned fractures and breakouts occurrences, which are very important for the experts in the field. These occurrences usually appear on borehole acoustic image logs. Its study can provide some insights about petrophysical properties of the reservoir, such as the mechanical stresses borne by the geology of the site, and this, for example, can be linked to the dynamics of the fluids retained inside the reservoir itself (i.e., hydrocarbon, gas or water). Usually, the workflow used to identify these structures requires experts to manually identify them. In this work, we propose a novel methodology for automatic detection in Borehole acoustic image logs of such structures using a single Fast Region-based Convolutional Neural Network (fast-RCNN), which could easily be incorporated into the analysis workflow carried out by petrophysicists, contributing to the characterization process. Due to the high number of samples that this type of neural network require, we trained our algorithm simulating pattern breakouts and fractures and after we test it in real and simulated images. Our model reported the area under the Receiver Operating Characteristic curve (AUC) of 98% and 90% for detecting fractures and breakouts, respectively, in simulated data. The algorithms commonly reported in the literature to identify fractures and breakouts, only achieve around 81% and 73% of AUC, respectively. Finally, for real images, the fast-RCNN detected efficiently the fractures and parts of breakouts. Thus, our data suggest that deep learning can improve significantly the accuracy on automatic detection of geological formations in acoustic borehole image logs. Available repository at Fast-Rcnn-Geo.",13,14,3
Fracture,Mechanical Properties,"Zeng, Jie; Li, Wai; Liu, Jishan; Leong, Yee-Kwong; Elsworth, Derek; Tian, Jianwei; Guo, Jianchun; Zeng, Fanhua",Analytical solutions for multi-stage fractured shale gas reservoirs with damaged fractures and stimulated reservoir volumes,Shale gas reservoir; SRV; Fracture damage,LINEAR FLOW MODEL; HORIZONTAL WELLS; PERMEABILITY; ADSORPTION; TRANSPORT; MECHANISMS; NANOPORES; IMPACT; FACE,"After performing hydraulic fracturing in shale reservoirs, the hydraulic fractures and their adjacent rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures; (2) partially propped fractures with unpropped or poorly propped sections at the middle or tail of fractures; (3) fracture face damage; and (4) multiple damage cases. The classical fracture skin factors are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple damage and partially propped fractures. In this article, a new analytical model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs. The matrix model is a spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly envelops the matrix. The reservoir-fracture flow model is a ten-region linear flow model which can handle fracture damage mechanisms. Specifically, the inner reservoir region is treated as an SRV where the secondary fracture permeability obeys a power-law decreasing trend due to the attenuate stimulation intensity. This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of a published linear flow model. New type curves are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Different damage mechanisms all control specific flow regimes but the fracture face damage shows the slightest influence. In the multiple fracture damage case, some typical flow regimes can be easily identified except those induced by the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.",12,12,3
Fracture,Mechanical Properties,"Wen, Tao; Tang, Huiming; Wang, Yankun",Brittleness evaluation based on the energy evolution throughout the failure process of rocks,Failure process; Brittleness; Energy evolution; Dissipation energy; Stress-strain curve,INDEX ESTIMATION; SHALE; SANDSTONE; STRESS; STABILITY; STRENGTH; MODEL; DEFORMATION; CRITERIA; COAL,"Brittleness is an important mechanical property of rock masses and a key index used in various engineering practices particularly to evaluate hydraulic fracturing, rock fragmentation and rock burst. However, rock brittleness is a concept remaining to be determined since there are no unique standards available. In this study, two methods to determine the brittleness index are proposed by considering the pre-peak failure energy and post-peak fracture energy, which are regarded as key factors in determining whether brittle failure of rock occurs. By taking the Longmaxi Formation shale as an example, the energy evolution laws of shales under different confinements are first analyzed, and the evaluation methods are then examined and applied to these rocks. The results show that these brittleness indexes for shales are capable of describing the transition from absolute plasticity to absolute brittleness. The applicability and performance of the proposed indexes are further validated against large uniaxial and triaxial compression test datasets for different rock types. Application of these brittleness indexes to the tested rock types clearly demonstrate that the two indexes have opposite variation trends with rising confining pressure. Compared with the previous evaluation methods, the rationality of the methods proposed in this study is also verified. These results indicate the proposed brittleness indexes can reflect the brittle characteristics of the rock and the whole process of deformation and failure of the rock. Accordingly, these methods seem to offer reliable evaluations of the brittleness of rock in various engineering practices, although further validation is necessary.",11,11,15
Fracture,Mechanical Properties,"Gu, Yang; Ding, Wenlong; Tian, Qianning; Xu, Sheng; Zhang, Wei; Zhang, Bairen; Jiao, Baocheng","Developmental characteristics and dominant factors of natural fractures in lower Silurian marine organic-rich shale reservoirs: A case study of the Longmaxi formation in the Fenggang block, southern China",The longmaxi shale; Natural fractures; Developmental characteristics; Dominant factors; South China,CAMBRIAN NIUTITANG FORMATION; NORTHERN GUIZHOU PROVINCE; FORT-WORTH BASIN; BOHAI BAY BASIN; BARNETT SHALE; CENGONG BLOCK; QUANTITATIVE PREDICTION; LOGGING IDENTIFICATION; MIGRATION PATHWAYS; GAS-STORAGE,"Natural fractures are an important storage space and main seepage channel of shale gas reservoirs, controlling the permeability of shale gas reservoirs and the migration, enrichment, preservation conditions and single-well productivity of shale gas. The successful production of shale gas has shown that the development of natural fractures in shale is beneficial, and a high degree of natural fracture development can allow a large-scale fracture network to form in the process of hydraulic fracturing, which can effectively improve the shale reservoir conditions. The development of fractures in shale reservoirs not only effectively improves the permeability of shale reservoirs but also increases the gas content, improving the productivity of shale reservoirs. Therefore, the degree of shale fracture development is the key to the production of shale gas reservoirs. Through the outcrop, shale core, thin section and scanning electron microscopy observations of the Longmaxi shale in the Fenggang block of Guizhou Province and the experimental data analysis of the corresponding samples, the fracture characteristics are statistically analyzed, and the fracture development characteristics and dominant factors are discussed in depth. The study area is located in the complex tectonic area of southern China, which experienced a strong tectonic deformation and a high degree of fracture development. The multiscale characterization of Longmaxi shale fractures indicates the following: the fractures observable in the field are mainly regional structural fractures, fold-related fractures, fault-related fractures and bedding fractures; additionally, the statistical analysis of core fractures shows that the structural fractures, including high-angle shear fractures, tension-shear fractures, and low-angle slip fractures are dominant and that most of them are filled with calcite; the micro-fractures are mainly intragranular fractures and intergranular fractures, and the fracture aperture is 0.01-2 mu m. The degree of fracture development is controlled by structural factors, lithology, mineral composition and content, TOC, rock mechanical properties, paleoenvironment and diagenesis, and the structural factors are the most influential. The gentle transition zone of a fold limb is a favorable position for shale gas structure preservation. Fractures significantly impact the formation of seepage channels and storage space and the connection of isolated micropores, so the degree of fracture development has a positive relationship with the total and analytical gas contents.",11,13,8
Fracture,Mechanical Properties,"Zhang, Yifei; Niu, Suyun; Du, Zhongming; Hao, Jin; Yang, Jijin",Dynamic fracture evolution of tight sandstone under uniaxial compression in high resolution 3D X-ray microscopy,Tight sandstone; 3D XRM; Uniaxial compression; Fracture evolution,COMPUTED-TOMOGRAPHY; CRACK-PROPAGATION; ACOUSTIC-EMISSION; BRITTLE-FRACTURE; STRESS; ROCK; DAMAGE; DEEP; RESERVOIR; STRENGTH,"Stress-induced fracture evolution in tight sandstone reservoir is of great significance in hydraulic fracturing treatment and borehole stability. The meso scale fracture mechanism needs to be well understood. In this work, the smaller-sized tight sandstone specimens (4 mm in diameter and 8 mm in height) from Bashijiqike formation were studied under uniaxial compression in high resolution three dimensional (3D) X-ray microscopy (XRM). Using high-resolution XRM, 2D slices and 3D digital cores with real pore structure characteristics were reconstructed at different stages of uniaxial compression. During the uniaxial loading process, porosity and diameter distribution of the voids were obtained to analyze the progressive deformation of rock, and then the complexity and heterogeneity of the cracks were quantified by applying fractal analysis. The results show that the fracture evolution of tight sandstone at meso scale could be divided into compaction stage, linear elastic behavior stage, non-linear deformation stage and residual deformation stage. The mineral composition and meso structure of tight sandstone have significant effects to its mechanical properties, fracture pattern and crack morphology under uniaxial compression. The propagation direction of secondary cracks tends to parallel to the direction of axial stress, revealed by higher resolution of region of interest (ROI) imaging.",11,10,1
Fracture,Mechanical Properties,"Li, Yanliang; Peng, Jianming; Bo, Kun; Huang, Chaoyang; Zhang, Yanjun; Zhang, Pengyu",Analysis on the mechanical properties of granite rock near the wellbore after percussive drilling and AWJ perforation,Percussive drilling; AWJ perforation; Impact fractures; Mechanical properties; Critical distance,HIGH-TEMPERATURE; FLUIDIC HAMMER; FRACTURE; INDENTATION; MICROSTRUCTURE; PENETRATION; SIMULATION,"Rock properties near the wellbore are particularly important for the development of geothermal wells, but few people have studied them. The mechanical properties of granite rock near the wellbore after percussive drilling and abrasive water jet (AWJ) perforation are analyzed and studied in this paper. The variation of P-wave velocity, stress-strain curve, tensile strength, uniaxial compressive strength, peak strain, elastic modulus, microscopic appearances of fractures with the distance from the wellbore is studied. The purpose is to provide theoretical and technical support for fracturing and perforation in geothermal resource development. The experimental results indicate that percussive drilling can generate a large number of impact fractures near the wellbore, which can reduce the mechanical properties of granite rock near the wellbore. Compared with the granite after conventional rotary drilling, the p-wave, tensile strength, compressive strength and elastic modulus of granite after percussive drilling can be reduced by 87.3%, 55.10%, 38.32%, 66.67%, respectively. In addition, we find that AWJ perforation can only produce a few fractures, that is to say, its effect on the mechanical properties of rock is not significant. The percussive drilling effect on the mechanical properties is much more intense than AWJ perforation. Percussive drilling can affect the wellbore in a range of 1.2-1.5 times the diameter of the wellbore, while AWJ perforation can affect the wellbore in a range of 0.4-0.6 times the diameter of the wellbore. On the other hand, although AWJ perforation cannot change the mechanical properties of granite rock near the wellbore significantly, the secondary fractures produced by AWJ perforation can connect the impact fractures produced by percussive drilling, forming crushed zones. It demonstrates that the assistant technique of percussive drilling can be a potential solution for the stimulation enhancement of geothermal resources.",10,10,10
Fracture,Mechanical Properties,"Voltolini, Marco; Ajo-Franklin, Jonathan",Evolution of propped fractures in shales: The microscale controlling factors as revealed by in situ X-Ray microtomography,Proppant; Fractures; Tight oil and gas shales; X-ray microtomography; Permeability,GAS; CONDUCTIVITY; CHALLENGES,"The behavior of proppant at the microscale during fracture closure in oil and gas shales is not yet well understood. In this context, we used a combination of dynamic synchrotron X-ray micro computed tomography with morphometric analysis and flow modeling to provide new insight into the dominant physical processes acting at the microscale during fracture closure, and understand their impact on hydraulic properties of the fracture. The roles of three variables have been investigated in proppant monolayers: i) Shale mineralogy and microstructure; ii) Shale bedding orientation with respect to the fracture plane; iii) Proppant characteristics. Unsurprisingly, all three variables have an impact on the permeability evolution during closure and their extent has been quantified via Stokes flow simulations. For the fracture geometry considered, proppant rearrangement during loading is the leading cause of permeability loss. The mechanical strength of proppant and shale becomes important at the later stages of the fracture closure. Bedding orientation has an impact on the mechanical response of the proppantshale contact areas. The more regular morphology and higher mechanical strength of ceramic proppant allows to maintain a better permeability throughout the whole fracture evolution cycle when compared to quartz sand. This combined analysis approach allowed us to understand and quantify the processes involved during the closure of a propped fracture and to directly link them to the evolution of morphology and hydraulic properties. A better understanding of the contributions of these processes could ultimately help in the design and optimization of proppants, enabling more efficient extraction of hydrocarbons from unconventional systems.",10,10,2
Fracture,Mechanical Properties,"Zhang, Hao; Zhong, Ying; Zhang, Jiang; Zhang, Yongchun; Kuang, Jianchao; Yang, Bin",Experimental research on deterioration of mechanical properties of carbonate rocks under acidified conditions,Carbonate reservoirs; Acid fracturing; Reaction rate constant; Activation energy; Mechanical properties,LABORATORY EVALUATION; REACTION-KINETICS; ACID REACTION; PORE-SCALE; DISSOLUTION; RESERVOIR; MODEL; STIMULATION; COEFFICIENT; PROPAGATION,"Understanding the relationship among the individual factors (i.e., carbonate rock types, acid rock reaction kinetics, deterioration of rock mechanical properties) can provide practical guidelines that can be used for the design and optimization of acid fracturing operation. A comprehensively experimental study was conducted to investigate the acid rock reaction kinetics of carbonate rocks under acidified conditions, and how the acid rock reaction would influence the carbonate rock mechanical properties. In addition, the deterioration mechanism of the carbonate rock mechanical properties is determined by the qualitative analysis of casting thin section images. Results show that the limestone rock is more susceptible to acid dissolution than limy dolomite rock under the same acidified conditions. The limestone rock has relatively large reaction rate constant and low activation energy, however, it is reverse in limy dolomite rock. As a result, the mechanical properties of rocks with relatively low cementation strength could be highly or lowly weakened. The reduction (in percentage, %) in mechanical properties of the limestone rocks with relatively high cementation strength is greater than that of the limy dolomite rocks with relatively high cementation strength. Casting thin section images show that the cementation and fillings of limestone and limy dolomite rocks are calcite and calcite-dolomite, respectively. The non-uniform (i.e., superficial and local deep) and uniform etched pattern (i.e., superficial and symmetrical) occur on the end surface of limestone and limy dolomite, respectively. Consequently, the mechanical properties of relatively high cemented limestone rocks are more significantly reduced than that of relatively high cemented limy dolomite rocks. This work is of great practical guidelines for the design and optimization of acid fracturing operations, as well as the efficient stimulation of carbonate reservoirs.",9,9,4
Fracture,Mechanical Properties,"Ye, Tao; Niu, Chengmin; Wei, Ajuan","Characteristics and genetic mechanism of large granitic buried-hill reservoir, a case study from PengLai oil field of Bohai Bay Basin, north China",,WEATHERING CRUST; TIGHT SANDSTONES; JUNGGAR BASIN; ZHENJING AREA; BONGOR BASIN; FAULT ZONE; BASEMENT; ROCK; FRACTURES; MIGRATION,"In recent years, a major breakthrough has been made in granite hydrocarbon exploration in the Bohai Bay Basin. With the proven reserves of more than 2 x 10(8)t, the Penglai (PL) oilfield is the largest granite oilfield discovered in China. Although the reservoir scale is large, the reservoir heterogeneity is also strong, which brings challenges to its exploration and evaluation. Based on the data of cores, thin sections, whole rock and physical property, the reservoir characteristics and control factors of reservoir-forming in the study area are discussed through the fault analysis and the recovery of tectonic uplift history. The results show that the lithology of PL structure are mainly Mesozoic intrusive granite and Proterozoic mica quartz schist, which develops reservoirs related to the weathered crust and internal fractures. Due to the influence of weathering intensity and fault activity, the porous reservoirs in weathered glutenite zone, pore-fractured reservoirs in weathered fracture zone and fractured reservoirs in the inner fracture zone were distributed orderly from top to bottom vertically. The scale of the high quality reservoir on the plane is controlled by lithology, faults, weathering and buried depth. Granite is the main reservoir-forming lithology for more brittle and less resistant to weathering than mica quartz schist, which forms a special phenomenon that the granite in saddle is rich for hydrocarbon while the mica quartz schist in high position is poor for hydrocarbon accumulation. The northwest Miaoxi fault is the main controlling-fault in the study area, and there is an obvious negative correlation between reservoir thickness and distance from this fault. The long-term uplift of Cenozoic provides conditions for strong weathering, while the shallow burial in the late stage provides effective protection for weathered crust reservoirs. The coupling of the above conditions is the main reason of large scale reservoir development in the study area, and among them, the long-term uplift is the key factor for reservoir-forming.",9,10,3
Fracture,Mechanical Properties,"Zhai, Hongyu; Chang, Xu; Wang, Yibo; Lei, Xinglin; Xue, Ziqiu",Analysis of acoustic emission events induced during stress unloading of a hydraulic fractured Longmaxi shale sample,,MOMENT TENSORS; MECHANICAL-PROPERTIES; SICHUAN BASIN; ROCKS; EVOLUTION; FAILURE; COAL,"In shale-gas exploitation, hydraulic fracturing technology is essential to successfully create complex fracture networks in formations. To investigate the dynamic fracturing process, we performed a hydraulic fracturing experiment on a Longmaxi shale sample in the laboratory. After hydrofracturing, hundreds of induced acoustic emission (AE) events were recorded during the stress unloading procedure. At the same time, the high-pressure water stored in the sample fracture network was also discharged. The fracture network inside the fractured sample was studied using medical X-ray computed tomography (CT) scanning technology. Then, the locations and characteristics of the shale failure were analyzed by localizing and inversing the source mechanism of the AE events. Furthermore, the inversion results were verified by comparing with the scanned internal cracks images. According to the source mechanism inversion result, the induced AE events mainly stemmed from the dilatation or compression of fractures and the shear slip of shale along the fracture plane. Finally, the influence of formation attenuation error (underestimated or overestimated attenuation value) on source mechanism inversion results were quantitatively analyzed. It was confirmed that the shear component of the AE event was more sensitive than the volume component to medium attenuation change, especially when the attenuation value was overestimated.",8,9,10
Fracture,Mechanical Properties,Deng Kuanhai; Yuan Yue; Hao Yi; Li Zhonghui; Lin Yuanhua,Experimental study on the integrity of casing-cement sheath in shale gas wells under pressure and temperature cycle loading,Casing-cement sheath; Full-scale integrity test; Temperature cycle loading; Pressure cycle loading; Interface mechanical properties; Multistage hydraulic fracturing,ZONAL ISOLATION; FAILURE; MODEL,"During large-scale multistage hydraulic fracturing in shale-gas wells, the cement sheath loses its integrity easily because of repeated temperature and pressure variations in the wellbore. This is likely to form a potential leak path, subsequently leading to the loss of zonal isolation and sustained casing pressure. To prevent such barrier failures, it is crucial to investigate and understand the failure mechanism of cement sheath. In this study, an experimental apparatus and evaluation method of the sealing integrity and mechanical integrity for casing-cement sheath under temperatures and pressures cycle loading have been presented in this paper by which sixteen groups of full-scale integrity tests of general and high-strength cement sheath have been conducted under temperature ranging from 30 to 150 degrees C and pressure ranging from 0 to 70 MPa cycling loading. The anti-channeling/sealing performance and interface mechanical behavior of casing-cement sheath are measured and characterized respectively under different loading-unloading methods. The cycle numbers required for sealing integrity failure of cement sheath under different cyclic temperatures and pressures have been obtained. The interface mechanical properties (cementing force, friction force, shearing strength and lateral bonding strength) of cement sheath have been obtained, and effects of alternating temperatures and pressures on those mechanical properties and late integrity have been analyzed. Research results can provide a very important reference for the fracturing design of shale-gas wells.",8,8,6
Fracture,Mechanical Properties,"Mehrabianfar, Parviz; Malmir, Pourya; Soulgani, Bahram Soltani; Hashemi, Abdolnabi",Study on the optimization of the performance of preformed particle gel (PPG) on the isolation of high permeable zone,Preformed particle gel (PPG); Water diversion; Fractured reservoir; Glass micromodel; Water control,WATER PRODUCTION COST; CONFORMANCE-CONTROL; TRANSPORT,"Unwanted water production is a critical problem in fractured reservoirs. Corrosion of facilities and reduction of oil relative permeability are some of the consequences of high water production. Preformed particle gel (PPG) injection is one of the conformance control methods, which initiated in 2007, has been used to control water production and increase sweep efficiency. There are several parameters which affect the performance of PPG such as stability at reservoir condition, salinity of makeup solution and PPG particle size and concentration. Although the study of the application of PPG in fracture plugging attracted a lot of attention in recent years, there are limited studies to investigate the effect of PPG physical properties on its application in water production control. In this study, the application of a super absorbent polymer on fracture plugging has been investigated. The results of swelling tests indicated that this type of PPG had significant high resistance even at high temperatures and wide range of salinities. In addition, the results of rheology tests showed that the PPG solution was stable even at high salinity and high shear rate condition. In order to study the mechanism of improvement of sweep efficiency through PPG injection, visual investigation using glass etched micromodel was performed. The results showed that the main mechanism for PPG treatment is water diversion into the low permeability zone as the consequence of fracture plugging. Also, core flooding tests were performed to check the performance of PPG in a heterogeneous carbonate porous media. According to the results, PPG was able to reduce the permeability, and this permeability reduction is related to swelling ratio which is controlled by makeup solution salinity. The results of this study revealed the potential of super absorbent polymers as preformed particle gel in unwanted water production through fracture plugging.",8,8,4
Fracture,Mechanical Properties,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Fracture,Mechanical Properties,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Fracture,Mechanical Properties,"Jiu, Bo; Huang, Wenhui; Mu, Nana; He, Mingqian","Effect of hydrothermal fluids on the ultra-deep Ordovician carbonate rocks in Tarim Basin, China",Tarim basin; Hydrothermal transformation; Carbonate rock; Migration mode; Fluid properties,THERMOCHEMICAL SULFATE REDUCTION; RARE-EARTH-ELEMENTS; NW CHINA; DOLOMITE RESERVOIRS; TAZHONG AREA; GEOCHEMICAL CHARACTERISTICS; CALCITE DISSOLUTION; FORMATION MECHANISM; BURIAL DISSOLUTION; FIBROUS CALCITE,"Carbonate rocks of Ordovician formations make up many important reservoirs in Tarim Basin. This study focuses on the formation mechanism and evolution model of Ordovician hydrothermal reformed carbonate reservoirs in the Yubei area of Tarim Basin. The observations of core samples, thin sections and cathode luminescence images shows that the carbonate rocks were subjected to multiple stages of karstification and hydrothermal cementation. The results of fluorescence observations and fluid inclusions indicate that the study area was affected by two periods of hydrothermal migration during the late Hercynian period and late Himalayan period. Controlled by the freshwater and hydrothermal fluids, the delta C-13 and delta O-18 of the fracture fillings are distributed from -1.8 parts per thousand to -0.8 parts per thousand and from -13.6 parts per thousand to -10.1 parts per thousand, respectively, with delta Eu>1 and high Mn and Fe. According to the distribution characteristics of trace elements and metallic elements, the two phases of hydrothermal fluid were rich in SiO2, Ho, and Tm. H2S produced by thermochemical sulfate reduction (TSR) changes the pH of the formation-hydrothermal fluids to acidic values. The hydrothermal fluid was converted to weakly alkaline by the reversible reaction between CO32- and HCO32-, building a silica-calcite-filled karst-fracture reservoir. Eventually, this paper establish a schematic diagram of hydrothermal migration along a single fracture and reveal the evolution mode of the study area.",7,7,5
Fracture,Effective Stress,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Wang, Suifeng; Wang, Tao; Shi, Xiaohong; Dong, Qingxiang; Li, Junyang",Natural fractures in soft coal seams and their effect on hydraulic fracture propagation: A field study,Soft coal seam; Qinshui Basin; Natural fractures; On-site hydraulic fracturing; Hydraulic fractures; Particle flow method,PORE STRUCTURE CHARACTERIZATION; HIGH-RANK COAL; MECHANICAL-PROPERTIES; RESERVOIR PRESSURE; ACOUSTIC-EMISSION; FIB-SEM; METHANE; PERMEABILITY; MODEL; ROCK,"Natural fractures provide direct flow channels for coalbed methane (CBM) production and gas outburst control. However, in soft coal seams, the characteristics of natural fractures and their effect on hydraulic fractures are still unclear. In this study, a spatial system of visible natural fractures was established through underground dissection and measurement of ground joints from a case study of the Xinyuan Coal Mine in the northern Qinshui Basin, China. Our results show that the orientations of the subsurface exogenetic fractures of the coal seams are consistent with the macrostructural joints on the ground surface in the same tectonic setting. The exogenetic fractures of the coal seams have dominant orientations with approximately equal spacing. Next, a field test of a large-scale hydraulic fracturing project with a volume of up to 2000 m(3) was conducted. The on-site observation of the underground coal seams revealed that the propagation orientation of the vertical propped fractures coincides with the predominant orientation of the natural fractures. Even at a high constant injection rate (12 m(3)/min), the corresponding injection pressure was not constant during the propagation of the hydraulic fractures, and this can be attributed to the effect of the depth of the coal seam, internal natural fracture network, and normal fault. Additionally, a two-dimensional (2D) particle flow simulation (PFC2D) showed that the propagation of the hydraulic fracture is controlled by the orientations of the natural fractures and the principal stresses. The orthogonal fracture network showed more sensitivity to joint spacing than the layered fracture network in controlling the hydraulic fractures. Finally, fluid detection of the coalbed demonstrated that the flow range of the fracturing fluid in the natural exogenetic fractures was up to a few hundred meters. The flow direction was consistent with that of the natural fractures. A comprehensive analysis of the natural fractures contributes to the identification of flow channels and helps in the design of hydraulic fracturing engineering in soft coal seams.",20,20,9
Fracture,Effective Stress,"Chen, Jiangzhan; Li, Xibing; Cao, Han; Huang, Linqi",Experimental investigation of the influence of pulsating hydraulic fracturing on pre-existing fractures propagation in coal,Coalbed methane; Pulsating hydraulic fracturing; Pre-existing fracture; Fracture propagation; Multi-mode injection; Fatigue damage,HAMMER WAVE ATTENUATION; METHANE DEVELOPMENT; STRESS DISTURBANCE; PERMEABILITY; MECHANISM; OPPORTUNITIES; SIMULATION; CHALLENGES; RESERVOIRS; EVOLUTION,"This study aims to investigate the propagation behavior of pre-existing fractures in a coalbed methane (CBM) reservoir during pulsating hydraulic fracturing (PHF). An innovative test system capable of true triaxial loading and multi-mode PHF was developed to conduct PHF on pre-existing fracture specimens of synthetic coal. The fluid pressure, strain around the pre-existing fracture, and propagation morphology of the pre-existing fractures were measured to analyze the influences of the coupling action between the pulsating parameters and the confining stress on pre-existing fracture propagation and fatigue damage of the coal. The results show that the evolution of fluid pressure under PHF can be divided into four periods: slow growth, rapid rise, steady drop, and decline. In the steady drop period, the intermittent fluid injection causes alternating pressure pulsation in the pre-existing fractures and cyclical strain fluctuation around the pre-existing fractures, leading to an abrupt propagation. With the increase in confining stress, the propagation morphology changes from single to cross direction exhibiting a ""T"" shape. Under flow-control injection mode, the frequency and amplitude of the pulsating pressure significantly influence the fatigue damage of coal, stimulating fracture propagation. With the increase in pulsating frequency, the pulsating amplitude decreases gradually, and the pre-existing fracture propagation rate and the pressure drop rate both increase first and then decrease; thus, an optimal pulsating frequency can be chosen to accelerate fracture propagation. Furthermore, the pulsating pressure has weakening effects on the coal around the pre-existing fractures, thus enriching the seepage channels around the primary fracture. Based on this work, a PHF method integrated with multi-mode injection is proposed to achieve the control of hydraulic fractures and perform efficient fracturing of CBM reservoirs.",17,18,13
Fracture,Effective Stress,"Kang, Zhiqin; Zhao, Yangsheng; Yang, Dong; Tian, Lijun; Li, Xiang",A pilot investigation of pyrolysis from oil and gas extraction from oil shale by in-situ superheated steam injection,Oil shale; In-situ pyrolysis; Superheated steam injection; Experimental investigation; Oil-recovery rate,COMPREHENSIVE UTILIZATION; NUMERICAL-SIMULATION; THERMAL-CRACKING; HIGH-TEMPERATURE; ORGANIC-MATTER; X-RAY; TECHNOLOGY; COMBUSTION; PERMEABILITY; EVOLUTION,"Oil shale is a critical strategic energy with huge reserve. The research and development of an economically feasible in-situ retorting technology for oil and gas extraction from oil shale is of great significance. Thus, this paper experimentally studied the large oil-shale samples pyrolysis by in-situ superheated steam injection (MTI) implemented from 2014 to 2016. The structure of the large-scale in-situ pyrolysis test system, the experimental procedure, and the results are presented here. The steam fracturing-connection was used during the initial stage, and the pressure of the superheated steam for fracturing was similar to 2 times higher than the strata stress. The variation of temperature and pressure during pyrolysis was controlled by the variation in steam seepage. The operating steam pressure during pyrolysis was lower than 1/4 of the strata stress. The energy utilization of the superheated steam for the pyrolysis reaction was 42.7%. The average temperature of the fluid that was discharged from the production wells was around 170 degrees C, which can be recycled to achieve a heat-utilization coefficient of 13.19% in commercial operations. The oil-recovery rate in the pyrolysis area exceeded 95%, and the overall oil-recovery rate reached up to 70.7% of the tested large oil-shale samples. The gas production rate and the effective energy rate of the injected steam are correlated with an exponential function. Our pilot tests indicate that the in-situ retorting technology of oil shale by MTI shows great potential for commercial operation in oil-shale formation.",15,18,10
Fracture,Effective Stress,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Fracture,Effective Stress,"He, Huan; Senetakis, Kostas",A micromechanical study of shale rock-proppant composite interface,Shale rock; Quartz sand; Interface friction; Hydraulic fracturing; Proppant,GRAIN-SCALE MECHANICS; GUM AQUEOUS-SOLUTION; FRACTURE CONDUCTIVITY; QUARTZ SAND; BEHAVIOR; CONTACT; SHEARING; PARTICLE,"The micromechanical properties of shale rock-sand type of composite interface were investigated by performing laboratory tests with a custom-built loading apparatus. This type of interface is of significant interest in petroleum engineering in the process of hydraulic fracturing using proppants. Two different types of quartz sands of different particle shapes were used as proppant simulants and they were sheared against rough and smooth surfaces of shale. It was shown that sand grain type and surface roughness of shale affected the contact stiffness in the normal and tangential directions because of their influence on the induced contact stresses. Based on the micromechanical shearing tests, it was found that the coefficient of friction, the initial tangential stiffness and the microslip displacement were positively correlated with the magnitude of normal load. Although clear surface damage/plowing of the shale surface caused by shearing was observed and captured by interferometry images, the effect of loading history was found to be small. Shearing tests on wet and dry shale surfaces did not show that much difference in results, but immersion of shale in water prior to shearing affected the initial tangential stiffness and coefficient of friction at certain normal loads. Smoothening of the surface had an influence on friction as long as limited plowing was triggered in the low range of normal loads, so that the influence of surface roughness of the shale would diminish at higher normal loads where plowing mechanism dominated the interface response.",14,14,5
Fracture,Effective Stress,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Fracture,Effective Stress,"Zhang, Ruxin; Hou, Bing; Tan, Peng; Muhadasi, Yeerfulati; Fu, Weineng; Dong, Xiaomu; Chen, Mian",Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing,Fracture propagation behavior; Temporary plugging agent; Fracture diversion pattern; Horizontal stress difference; 3D scanning,NUMERICAL-SIMULATION; INITIATION,"The exploitation of shale oil and gas has become commercial in the Sichuan basin, China. However, initial fracture closure will result in low production. Therefore, temporary plugging fracturing technology is proposed to create new fractures in alternate directions using a temporary plugging agent that blocks initial fractures, which will lead to a complex fracture morphology. The mechanism of temporary plugging and fracture propagation behavior remains ambiguous, even with many successful operations. Hence, five shale outcrops are used to conduct large-size true tri-axial temporary plugging fracturing simulation experiments to study the issues mentioned above. The effects of horizontal stress difference and temporary plugging agent amount on plugging effectiveness as well as fracture propagation behavior are discussed. The results reveal that the initial fractures are sealed successfully by a water soluble temporary plugging agent. Two plugging positions, fracture heel and tip, result in three main fracture diversion patterns: fracture diversion at the old fracture heel, fracture diversion inside the old fracture, and a new fracture induced at a new position. Based on the fracturing pressure curve, fracturing pressure in the second fracturing is higher than that of the first fracturing, which indicates effective plugging and fracture diversion. A large horizontal stress difference has prevented fracture diversion, and led to a small diversion angle. However, it has improved the induced fracture propagation length. Moreover, the temporary plugging agent amount determines the plugging position and fracture diversion pattern. Fracture diversion inside existing fractures is a result of a small amount sealing at the fracture tip. The other two patterns are created by a large amount of plugging at the fracture heel. Therefore, in order to achieve successful plugging effectiveness, it is necessary to conduct more experiments to optimize operation parameters according to the specific horizontal in-stress state.",13,13,6
Fracture,Effective Stress,"Fan, Ming; Chen, Cheng",Numerical simulation of the migration and deposition of fine particles in a proppant-supported fracture,Fine particle deposition; Deposition coefficient; Proppant; Hydraulic fractures; Discrete element method; Lattice Boltzmann,LATTICE BOLTZMANN MODEL; BED FILTRATION; STIMULATION; EVOLUTION; TRANSPORT; SYSTEM; FLOWS,"Many hydrocarbon-bearing geologic formations, especially shales, contain high clay contents. During hydrocarbon production, pore pressure reduces and the effective stress of the rock matrix increases, which may lead to formation failure and consequently fine particles production within the formation fluids. Invasion of fine particles into proppant assemblies in a hydraulic fracture can clog the pore spaces between proppant particles and consequently lead to loss of fracture permeability and conductivity. Although fine particle migration and clogging in a proppant-supported hydraulic fracture is critical to effective production of hydrocarbons, the role of effective stress, proppant particle size, and proppant size distribution is still unclear. In this study, a discrete element method-lattice Boltzmann (DEM-LB) numerical framework was developed to study the mechanisms that regulate the migration and deposition of fine particles in a proppant-supported fracture, which is subjected to a closure pressure. Specifically, DEM was used to generate proppant assemblies and to simulate effective stress increase and the resultant proppant particle compaction. The DEM-simulated pore structure of the compacted proppant assembly was then extracted and imported into the LB simulator as internal boundary conditions of fluid flow modeling. Fine particle transport in the pore spaces was numerically simulated based on the LB-simulated pore flow field, and three transport mechanisms that regulate fine particle migration, including interception collection, Brownian motion, and gravitational settling, were accounted for. The numerical results of pore-scale particle tracking and deposition were fitted using a continuum-scale fine particle deposition model to determine the macroscopic deposition coefficient, as well as how fine particle size, proppant size heterogeneity, and effective stress influence the macroscopic deposition coefficient. Good agreement between numerically-simulated and correlation-predicted deposition coefficients was observed. The simulation results confirmed the non-monotonic change of fine particle deposition coefficient as a function of fine particle size. This study indicates that proppant assemblies having the same mean proppant diameter but a more heterogeneous proppant diameter distribution (i.e., a wider distribution of proppant diameter) favors fine particle migration through the pore space under low to moderate closure stresses. The developed simulation framework can be used to effectively model the migration and deposition of fine particles having varying sizes at the pore scale.",11,11,7
Fracture,Effective Stress,"Li, Jia; Qiu Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian",Coupled CFD-DEM analysis of parameters on bridging in the fracture during lost circulation,Lost circulation; Bridging mechanism; Solid-liquid flow; Critical bridging concentration; CFD-DEM,WELLBORE STABILITY; FLOW; SIMULATION; DESIGN,"As an important preventive and remedial application of lost circulation, the optimization of lost circulation materials (LCMs) has become a crucial problem. In order to optimize the design of LCMs, the mechanism of bridging was studied. Based on the theory of solid-liquid flow, a coupled Computational Fluid Dynamics (CFD) - Discrete Element Method (DEM) model was introduced to accurately simulate the dynamic bridging process of plugging particles. The criterion of critical bridging concentration was developed to quantitatively evaluate the effects of Young's modulus, particle density, particle size distribution (PSD), friction coefficient, fracture geometry, lost circulation velocity and fluid yield stress on bridging capacity. The results show that the plugging zone will become more stable with the increase of particle angularity, Young's modulus, density of LCMs, lost circulation velocity and the decrease of fluid yield stress. The friction failure is easier to occur, because the stability of plugging zone is more sensitive to the friction between particle and fracture surface. The critical bridging concentration is more sensitive to the ratio of inlet size to outlet size (R-io) with a higher ratio of outlet size to particle size (R-o). For a small outlet size (R-o <= 2.5), the bridging state can be observed obviously because the large particles are dominant. When the outlet size is larger (R-o > 3), the stable plugging zone is hard to form because the dense state increases the risk of friction failure. The hindering effect of gravity on the trajectory of particles will be more significant when the fracture extension direction is perpendicular to the gravity direction.",11,12,4
Fracture,Effective Stress,"Zhang, Yifei; Niu, Suyun; Du, Zhongming; Hao, Jin; Yang, Jijin",Dynamic fracture evolution of tight sandstone under uniaxial compression in high resolution 3D X-ray microscopy,Tight sandstone; 3D XRM; Uniaxial compression; Fracture evolution,COMPUTED-TOMOGRAPHY; CRACK-PROPAGATION; ACOUSTIC-EMISSION; BRITTLE-FRACTURE; STRESS; ROCK; DAMAGE; DEEP; RESERVOIR; STRENGTH,"Stress-induced fracture evolution in tight sandstone reservoir is of great significance in hydraulic fracturing treatment and borehole stability. The meso scale fracture mechanism needs to be well understood. In this work, the smaller-sized tight sandstone specimens (4 mm in diameter and 8 mm in height) from Bashijiqike formation were studied under uniaxial compression in high resolution three dimensional (3D) X-ray microscopy (XRM). Using high-resolution XRM, 2D slices and 3D digital cores with real pore structure characteristics were reconstructed at different stages of uniaxial compression. During the uniaxial loading process, porosity and diameter distribution of the voids were obtained to analyze the progressive deformation of rock, and then the complexity and heterogeneity of the cracks were quantified by applying fractal analysis. The results show that the fracture evolution of tight sandstone at meso scale could be divided into compaction stage, linear elastic behavior stage, non-linear deformation stage and residual deformation stage. The mineral composition and meso structure of tight sandstone have significant effects to its mechanical properties, fracture pattern and crack morphology under uniaxial compression. The propagation direction of secondary cracks tends to parallel to the direction of axial stress, revealed by higher resolution of region of interest (ROI) imaging.",11,10,1
Fracture,Effective Stress,"Wijaya, Nur; Sheng, James J.",Probabilistic forecasting and economic evaluation of pressure-drawdown effect in unconventional oil reservoirs under uncertainty of water blockage severity,Pressure drawdown; Stress-dependent permeability; Water blockage; History matching; Stimulated reservoir volume; Net present value,HORN RIVER SHALE; DEPENDENT PERMEABILITY; FRACTURE PERMEABILITY; GAS-WELL; STRESS; MODEL,"Applying mild pressure drawdown during early-time oil production from unconventional reservoirs is believed to be beneficial for the ultimate oil recovery because it prevents early fracture conductivity loss and mitigates water blockage. However, previous studies demonstrate mixed results - some studies report mild drawdown as beneficial for the oil recovery, whereas others detrimental. This paper investigates water blockage severity and stress-dependent permeability (SDP) as two of the main reasons for the mixed perceptions. To introduce the uncertainty of water blockage severity, this study builds five distinct reservoir solution models of different levels of water blockage severity to perform probabilistic forecasting. All of the models are validated using the same field production data. Meanwhile, to introduce the uncertainty of SDP, this study used a parametric analysis based on numerous SDP experimental data. The results demonstrate that the mild drawdown tends to result in a higher oil recovery when the reservoir permeability is barely stress-sensitive or when the water blockage is severe. We have also shown that this claim can straighten out the mixed conclusions among some previous papers. However, although the mild drawdown can be beneficial in terms of oil recovery, it can more likely be detrimental in terms of NPV, unless the reservoirs are severely water-blocked. This occurs because such reservoirs tend to generate additional oil recovery soon with a small water production volume.",10,11,0
Fracture,Effective Stress,"Zhao, Yulong; Lu, Guang; Zhang, Liehui; Wei, Yunsheng; Guo, Jingjing; Chang, Cheng",Numerical simulation of shale gas reservoirs considering discrete fracture network using a coupled multiple transport mechanisms and geomechanics model,Shale gas; Multistage fractured horizontal well; Multiple migration mechanisms; Geomechanics; Discrete fracture network,APPARENT PERMEABILITY; HORIZONTAL WELL; COMPOSITE MODEL; FLOW; MATRIX; COAL; DESORPTION; NANOPORES; STRESS; ADSORPTION,"Shale has typical characteristics of multi-scale space for gas storage and migration. It is suitable for description by a triple medium model composed of double continuous medium and discrete fracture model, and need to consider multiple migration mechanisms. Besides, during gas production, effective stress and desorption will cause the deformation of shale, leading to the dynamic changes in porosity and permeability. In this paper, a fully coupled model was established to evaluate the shale gas production dynamics, including the governing equation of shale deformation and the governing equation of gas migration in the matrix, micro-fractures, and hydraulic fractures, respectively. All processes are coupled by the dynamic models of porosity and permeability for matrix and micro-fractures, and by the gas exchange between different systems. The fully coupled model was solved by the finite element method through the PDE solver software named COMSOL Multiphysics. The rationality of this fully coupled model is verified by the production data of Barnett shale. The validated model was applied to study the effects of adsorption and geomechanics parameters on dynamic changes of porosity and permeability, and gas production. Moreover, the impact of primary fracture geometry and secondary fracture distribution parameters on production were also analyzed. Simulation results show that the adsorption parameters have essential effects on both gas flow and production; that the geomechanics parameters have important influences on the evolution of porosity and permeability; that optimizing the distribution and development of hydraulic fracture and secondary fracture is beneficial to the efficient development of shale gas.",9,9,9
Fracture,Effective Stress,"Duan, Y. T.; Li, X.; Ranjith, P. G.; Wu, Y. F.",An investigation of the evolution of the internal structures and failure modes of Longmaxi shale using novel X-ray microscopy,X-ray microscopy; Longmaxi shale; Void evolution; Crack connectivity; Meso-scale mineral; Intergranular fracture,PARTIALLY SATURATED SAND; CRACKING PROCESS; CT; LOCALIZATION; ROCKS,"An accurate description of the evolution of the internal structure of shale during loading and fracturing is important to understand the failure mechanisms that are related to shale-gas migration. The aim of this work was to investigate and characterize the void evolution and failure of Longmaxi shale quantitatively under uniaxial tests, and analyze the relationship between the distribution of the meso-scale (voxel-scale) minerals and the failure mode. Novel X-ray microscopy combined with an in-situ microtest device was used and three groups of shale specimens were tested under uniaxial conditions with different scanning stresses. Some three-dimensional stereograms of different loading forces and an entire force-displacement curve were obtained for each in-situ test. Based on the results, an evolution of the void distribution was characterized and divided into four stages: weakened damage, linear, damage evolution and stable development, and accelerated damage development. The degree of development of the final cracks was distinguished by the crack volume, equivalent aperture width and connectivity rate. The structure evolution and failure mode of shale were described quantitatively by the void changes and the crack characteristics. Three phenomena of intergranular fracture, transgranular fracture and arrest cracks were observed at a meso-scale to explain the effect of mineral distribution on the crack pattern. These quantitative results can provide a guide for the design in shale fracturing engineering and some references for numerical analysis.",9,9,6
Fracture,Effective Stress,"Karthikeyan, G.; Chand, Jagadish; Chatterjee, Rima","Impact of geomechanics in coal bed methane development and production, Barakar coals in central India",Coal permeability; Wellbore stability; Critically stressed fractures; Sohagpur coalfield,IN-SITU STRESS; KRISHNA-GODAVARI BASIN; PORE PRESSURE; FLUID-FLOW; PERMEABILITY; GAS; STRAIN; ORIENTATION; PREDICTION; RESERVOIRS,"Geomechanics plays a critical role in the different stages of coal bed methane (CBM) operations, starting from its development through production to its abandonment as in Sohagpur field of central India. In general, higher gas production has been observed from the coal seams in low-stress regimes compared to high-stress regimes; however, during the CBM development planning, stress information has been overlooked. The need for inclined and horizontal wellbores in coal seams has increased due to their many-fold rise in production when compared to vertical wells with a minimum surface footprint. However, these non-vertical wells have wellbore instability issues leading to high nonproductive time (NPT) during drilling and completion operations. Prolong challenges exist in achieving the desired half-length from hydraulic fracturing (HF) stimulation due to the limited understanding of the stress contrast between target coal and bounding lithology. The permeability of the coal reservoir varies greatly during depletion due to the combined effects of effective stress and matrix shrinkage. These effects directly impact productivity and hence, require a detailed understanding of how permeability varies during production life. In many instances, production from coal seams is complicated and unpredictable because of the influence of stress induced natural fractures. A geomechanical earth model is focused on understanding and mitigating the aforementioned challenges. In addition to coal thickness and gas content, stress-permeability maps are prepared to assist in the development program to prioritize wells in lower and moderate stress areas. Wellbore stability analysis has been carried out using calibrated stress and strength profiles along with other rock mechanical inputs to successfully drill high angle wells. This analysis indicates that with a slightly higher mud weight, high angle and horizontal wells can be drilled successfully. Hydraulic fracturing design incorporating the available stress contrast can help in achieving the desired fracture parameters without height growth. The coal permeability model suggests that during depletion, coal permeability is expected to increase by about 1.2-3.5 times with a positive impact on productivity. Critically stressed fracture analysis has been carried out on mapped fractures, which suggest that about 48% of the natural fractures are in a stressed state. Presence of these natural fractures has a positive (faster dewatering) as well as a negative (external water) impact on productivity at different places in the study area.",8,8,2
Fracture,Effective Stress,"Xie, Jing; Gao, Mingzhong; Zhang, Ru; Liu, Junjun; Lu, Tong; Wang, Mingyao",Gas flow characteristics of coal samples with different levels of fracture network complexity under triaxial loading and unloading conditions,Prefractured coal sample; Gas flow characteristics; Permeability evolution; Loading and loading-unloading tests,PERMEABILITY EVOLUTION; STRESS; DEFORMATION; MODEL,"Research on the characteristics of gas flow in coal rocks is fundamentally important for coalbed methane exploitation. Laboratory tests of prefractured coal samples may be a practical means of simulating the fractured media encountered in actual engineering applications. In this study, coal samples were mechanically prefractured, and the complexity of the prefractured structures was described quantitatively. Several gas flow experiments were conducted on these samples under loading and loading-unloading conditions. The experimental results were analyzed in terms of the Klinkenberg effect, the evolution mechanisms of coal rock damage, the coal permeability and the permeability enhancement rate (PER). The main results suggest that the Klinkenberg effect gradually weakens as the fracture complexity indices increase. The prefractured coal samples clearly exhibited a deformation capacity under both loading and loading-unloading conditions, with significant transient instability leading to failure and volume expansion. Under conventional triaxial stress conditions, the permeability of the prefractured coal samples typically evolved via an initial rapid decrease followed by a rebound and a slow increase. The permeability was clearly enhanced during this evolution process. The final permeabilities of fractured coal samples with complexity indices of 0.600, 0.565, 0.549 and 0.522 increased by factors of 2.98, 6.79, 7.54 and 53.33, respectively, over that of a nonprefractured coal sample. Therefore, the more complex a fractured coal sample is, the less distinct the permeability enhancement is. The evolution mechanism of coal permeability under loading-unloading conditions was analyzed based on the porosity-damage relationship and a PER calculation model. The onset of damage corresponded to the onset of the volume change and permeability enhancement.",7,9,11
Fracture,Effective Stress,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Fracture,Effective Stress,"Zhao, Peng; Xie, Lingzhi; Ge, Qi; Zhang, Yao; Liu, Jun; He, Bo",Numerical study of the effect of natural fractures on shale hydraulic fracturing based on the continuum approach,Hydraulic fracturing simulation; Anisotropic strength criterion; Discontinuities; Continuum method; Fracturing geometry; Complexity and scale,STIMULATED RESERVOIR VOLUME; PROPAGATION; SIMULATION; MODEL; STRESS; FLOW; GAS; PERMEABILITY; DEFORMATION; MEDIA,"Because of the complexity of shale reservoirs and multiple physical coupling processes, numerical implementation remains a challenge in engineering applications. Unlike conventional reservoirs, shale reservoirs always contain two main discontinuities: bedding interface and natural fractures. The existence of these discontinuities is the key reason a fracture network is formed. Therefore, the numerical model should contain both bedding interface and natural fractures. In this paper, the fracturing propagation process is described based on continuum theory. In contrast to other research, an anisotmpic strength criterion is adopted to consider the anisotropic properties of shale, including the failure of both shale matrix and discontinuities. The criterion is described by the Mohr-Coulomb model combined with tensile failure. When fractures are generated in the shale rock mass, the stiffness and permeability of the fractured rock are homogenized in an element, and volume fracturing is represented by the deformation of three orthogonal fractures in the rock element. Simultaneously, the anisotropic permeability is also enhanced. Hence, based on this continuum approach and finite element method, a three-dimensional model for shale hydraulic fracturing simulation is presented. This model fully considers the direct coupling of fluid flow and rock deformation during hydraulic fracturing. To verify the anisotropic strength criterion, a shale compression test is conducted. Through a comparison of the numerical and experimental results, the applied criterion can describe the shale compressive strength anisotropy. In addition, the KGD analytical model is also adopted to verify the performance of the developed model for hydraulic fracturing. Finally, several cases of shale hydraulic fracturing are simulated, and the results show the geometry of the fracture region under different conditions. Furthermore, the impacts of three factors on hydraulic fracturing geometry are considered, including natural fractures, spacing of perforations and differential in situ stress. The influence of these factors on the complexity and scale of the fracturing region is also discussed.",7,7,7
Fracture,Effective Stress,"Shao, Jiaxin; You, Lijun; Kang, Yili; Gao, Xinping; Chen, Mingjun; Meng, Sen; Zhang, Nan",Experimental study on stress sensitivity of underground gas storage,Underground gas storage; Effective stress; Pressure gradient; Stress sensitivity; Effective stress action time,TRANSPORT BEHAVIOR; PERMEABILITY; MULTISCALE; MECHANISM; BASIN,"The increase in effective stress and effective stress action time reduces the permeability of rock fractures. XG underground gas storage systems are constructed in carbonate formations. Fractures constitute the main seepage channel of pore-fracture carbonate formation. Alternating stress during multi-cycle injection-production of underground gas storage causes the fractures to open and close periodically. This leads to stress sensitivity of the formation and reduces the permeability of rock fractures. In this work, typical rock samples of carbonate formation in XG underground gas storage were selected as the research object, and stress sensitivity experiments, gas speed sensitivity experiments and stress sensitivity experiments considering effective stress action time were carried out. The rock sample permeability during the experiment was measured. The fracture walls of rock samples before and after the stress sensitivity experiments and stress sensitivity experiment considering the effective stress action time were analyzed by SEM. The influence mechanism of effective stress and effective stress action time on permeability of underground gas storage was explored. Stress sensitivity coefficient method was used to evaluate stress sensitivity. The results show that the stress sensitivity of fracture and matrix samples considering effective stress action time was enhanced compared with stress sensitivity experiments. With the increase in effective stress action time, the elastic-plastic deformation of rock increased the breaking of microconvex bodies on the fracture wall. Moreover, micro-fractures were generated to reduce rock strength. The breaking of micro-convex bodies and the generation of micro-fractures strengthened the stress sensitivity of rocks. Moreover, fine migration caused by excessive injection-production pressure gradient also increased the stress sensitivity.",7,7,5
Fracture,Carbonate Rocks,"Mahesar, Aftab Ahmed; Shar, Abdul Majeed; Ali, Muhammad; Tunio, Abdul Haque; Uqailli, Muhammad Aslam; Mohanty, Udit Surya; Akhondzadeh, Hamed; Iglauer, Stefan; Keshavarz, Alireza","Morphological and petro physical estimation of Eocene tight carbonate formation cracking by cryogenic liquid nitrogen; a case study of Lower Indus basin, Pakistan",Tight carbonate rocks; Petro physics; SEM; AFM; Nano indentation; Liquid nitrogen,PORE STRUCTURE; COAL DAMAGE; GLOBAL OIL; EVOLUTION; PERMEABILITY; RESERVOIRS; SALINITY; FREEZE,"Significant amounts of hydrocarbons are contained in tight carbonate rocks like those within the Indus basin of Pakistan, but due to their unconventional nature, their extraction is difficult. This can be completed/conducted by properly characterizing its mineralogical, geochemical and microstructural properties. In this context, Hydraulic fracturing and acidizing are the most common fracture stimulation techniques. However, they suffer significant technical and environmental flaws. Liquid Nitrogen (LN2) fracking is considered as one of the best alternatives compare to hydraulic fracturing or acidizing due to its eco-friendly nature. In fact, after exposer to LN2, super cryogenic feature of the rock causes porosity, permeability and fracture conductivity enhancement due to thermal shock without any environmental consequences. The effect of Liquid Nitrogen fracking on tight carbonate outcrops collected from the Indus basin is investigated in the present study. Scanning Electron Microscopy (SEM) reveals the clear appearance of wide pore fractures with sizes from 4 mu m to 50 mu m, when subjected to liquid Nitrogen (LN2) treatment ranging from 30 to 90 min' duration. Furthermore, SEM and Atomic Force Microscopy (AFM) images also indicate clear pore fractures in tight carbonate rocks along with increased pore connectivity. Moreover, following liquid nitrogen treatment of up to 90 min the permeability of tight carbonate increases by 53% and increases in porosity by 73%. Results from SEM studies suggest that visible fractures occur in the tight carbonate samples with liquid nitrogen treatment because of the freezing temperature (-196 C-square) of Liquid Nitrogen. In addition to this, Nano indentation moduli depict significant decreases in tight carbonate rocks, both before and after exposure to LN2, as a result of increases in liquid rock compressibility. In this regard, a 50 mN force decreased from 50.57 GPa to 24.37 GPa and for a 200 mN force this decreased from 45.77 GPa to 26.67 GPa. This research depicts the significant effect of Liquid Nitrogen freezing on the fracturing of carbonate rocks.",32,32,8
Fracture,Carbonate Rocks,"Wang, Fuyong; Cheng, Hui",A fractal permeability model for 2D complex tortuous fractured porous media,Fracture; Permeability; Tortuosity; Porous media; Fractal,CARBONATE ROCK; FLUID-FLOW; NETWORKS,"The complex fracture networks are of significance to petroleum production in unconventional reservoirs, but effectively predicting its permeability is challenging due to the complex distribution and geometry of fracture networks. This paper proposes a new permeability model for 2D complex tortuous fractured porous media based on fractal theory, and two important characteristics of fractures, i.e. branching and tortuosity are considered in the developed permeability model. In this paper, the fractured porous media is assumed to be made up of a bundle of tortuous fractal-like tree fracture networks. First, the modified cubic law for describing flow rate in a fracture with fractal distribution of tortuosity is derived. Secondly, the fractal-like tree fracture network is used to represent the distribution of complex fracture networks, and then flow rate in a tortuous fractal-like tree fracture network is derived. After that, with the assumption of the fractal scaling law between fracture number and fracture apertures, the total flow rate in a bundle of tortuous fractal-like tree fracture networks is given and then the analytical expression for permeability of 2D complex tortuous fractured porous media is derived. Finally, the model reliability is verified with a case study and the key parameters influencing permeability of 2D fracture porous media are investigated with sensitivity study. The research results show that the fractal dimension of aperture distribution D-f, tortuosity fractal dimension D-T, branch level m and fracture length ratio gamma have significant influence on fracture network permeability; the effects of branch angle theta and the straight length of the zero-level fracture l(0) on fracture network permeability are insignificant.",17,18,5
Fracture,Carbonate Rocks,"Gupta, Ishank; Sondergeld, Carl; Rai, Chandra",Fracture toughness in shales using nano-indentation,Fracture toughness; Nano-indentation; Shale anisotropy; Water weakening,,"Fracture toughness property is often ignored but has a significant impact on the hydraulic fracture design, i.e. length and height. It represents the resistance of the rock to hydraulic fracturing and is a direct indicator of rock fracability. It is difficult to measure fracture toughness in shales using current experimental procedures designed for conventional rocks largely due to mechanical and chemical instability in shales. This study measures fracture toughness in shales using nano-indentation. Nano-indentation can, in fact, be used to derive both tensile and shear dominated fracture toughness. The observations in the study show that while crack-length method derived fracture toughness is close to Mode I (tensile) fracture toughness, energy-method based fracture toughness is closer to Mode II (shear) fracture toughness. Fracture toughness was calculated for 67 samples in different shale formations namely Marcellus, Wolfcamp, Woodford and Eagle Ford. The results show that mineralogy had a strong control on fracture toughness. Fracture toughness decreases with increasing porosity, TOC (Total Organic Carbon) and clay content. The fracture toughness also shows strong anisotropy with fracture toughness measured parallel to the bedding planes being generally 33% higher than the corresponding values measured normal to the bedding planes. The fracture toughness shows a direct correlation with other mechanical properties like Young's modulus, hardness and brittleness. Typically, samples with fracture toughness values greater than 3 MPa m(0.5) were found to be brittle based on Young's modulus and Poisson's ratio cross plots. Evaluation of fluid effects on fracture toughness shows that it decreases by 10-37% due to spontaneous imbibition with low salinity brines. This could help understand the impact of hydraulic fracturing fluid on fracture propagation and stimulated reservoir volume (SRV) creation.",14,15,5
Fracture,Carbonate Rocks,"Aljuboori, Faisal Awad; Lee, Jang Hyun; Elraies, Khaled A.; Stephen, Karl D.",The effectiveness of low salinity waterflooding in naturally fractured reservoirs,Low salinity (LoSal) waterflooding; Naturally fractured reservoirs (NFR's); Wettability alteration; Residual oil reduction; Qamchuqa reservoir,OIL-RECOVERY; BRINE COMPOSITION; MAUDDUD FORMATION; WATER INJECTION; WETTABILITY; FLOW; SIMULATION; SANDSTONE; FIELD,"Low Salinity (LoSal) waterflooding is a technique which promises to improve and enhance oil recovery. The method has been studied widely in the laboratories using various core plug samples of sandstones and carbonates. Most of the experimental outcomes have demonstrated the possibility of recovery increment in conventional reservoirs. Meanwhile, it is rare to find a discussion in these experiments about the effectiveness of LoSal waterflooding in naturally fractured reservoirs. In this paper, we investigate the potential benefits in fractured reservoirs using simulations. It is often reported from coreflood experiments that LoSal injection has the ability to alter the rock wettability and reduce residual oil saturations through chemical and physical interactions between the rock-oil-water system. Based on the published work, we have calculated relative permeability curves to represent the flow in regions flooded with LoSal water. This includes a qualitative representation of uncertainty. In this sense, the relative permeabilities are a proxy for any physical and chemical mechanisms which are not explicitly represented. The newly generated flow curves were applied to simulate LoSal waterflooding using a fine-scale model and a field scale model based on a fractured reservoir from the Middle East. The simulation results underline the benefits of LoSal whereby the oil recovery from fractured reservoirs can be increased. An additional benefit is the control of water production. The fine-scale modelling has provided an in-depth analysis and accurate estimation of the oil recovery without modelling artefacts or limitations, where an increment of (12-14)% of the Stock Tank Oil Initially In Place (STOIIP) were obtained under secondary and tertiary recovery scheme, respectively. The investigated scenarios demonstrated a sensitivity to the newly generated flow curves and how they affect the ultimate oil recovery. However, for the field scale model, a higher oil production rate has maintained during LoSal waterflooding up to 32 K BPD by the end of year fourteen compared with 25 K BPD in case of high salinity scenario, besides a reduction in the produced water by 35.7%. Therefore, the effectiveness of LoSal brine required a longer time frame to observe the improvements in the oil displacement or sweep efficiency.",13,13,2
Fracture,Carbonate Rocks,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Fracture,Carbonate Rocks,Kao Jiawei; Jin Yan; Zhang Kunpeng; Ren Pengju,Experimental investigation on the characteristics of acid-etched fractures in acid fracturing by an improved true tri-axial equipment,Acid fracturing; Carbonate; Acid-etched fracture; Alternate injection; Surface etching; Fracture morphology,BALL DRILLING-FLUIDS; PROPAGATION BEHAVIOR; MODEL; MECHANISM; GROWTH; SHALE,"The propagation characteristics and influencing factors of hydraulic fractures can be analyzed through fracturing experiments. However, there are almost no fracturing experiments in which acid fluids were considered, for the acid resistance of the equipment is always imperfect. In this paper, a physical modeling experimental equipment for acid fracturing was designed and introduced, in which corrosion protection and alternate injection were realized. The carbonate rock for acid fracturing experiment was collected from Sichuan Basin, China, which was tight with a little cavity developed. Acid fracturing experiments, in which HCL, guanidine gum and guanidine gum with an acid fluid were used as the fracturing fluids, were conducted to analyze the characteristic of acid-etched fractures. The results showed that Acid fluid etched the fracture surface, especially in the near-wellbore area; Acid fluid would open microfractures and pores easily, and leaked into these spaces, which decreased the propagation distance of the primary acid-etched fracture; High viscosity guanidine gum was first injected and then with low viscosity acid fluid, then the latter one was transported to distal area by viscous fingering, which would lead to a better fracturing effect; Due to the acid-rock reaction, the morphology of acid-etched fracture was obviously different from hydraulic fracture, and two kinds of acid-etched fracture morphology were proposed according to the sequence of acid fluid and guanidine gum. In this paper, the characteristics of acid-etched fractures were investigated by four groups of acid fracturing experiments, which could provide a reference to optimize acid fracturing effect.",12,13,9
Fracture,Carbonate Rocks,"Tariq, Zeeshan; Mahmoud, Mohamed; Abdulraheem, Abdulazeez; Al-Nakhli, Ayman; BaTaweel, Mohammed",An experimental study to reduce the breakdown pressure of the unconventional carbonate rock by cyclic injection of thermochemical fluids,Unconventional formation; Breakdown pressure; Thermochemical; Cyclic fracturing; Multiple fractures,HYDRAULIC FRACTURE PROPAGATION; SIMULATION; RESERVOIR; OIL,"Commercial production from unconventional reservoirs needs massive fracturing operations. Therefore, long horizontal wells are drilled, and multi-stage fractures are created to achieve the desirable production rates from these reservoirs. One common and major problem in most of the unconventional reservoirs is the high breakdown pressure due to the reservoir tightness. When fracturing these types of rocks, the hydraulic fracturing operation becomes much more challenging and difficult. In some scenarios reaches to the maximum pumping capacity without generating any fractures. In this study, a new approach to reduce the breakdown pressure of tight rocks is introduced and compared with the conventional method of fracturing. The new method incorporates the injection of thermochemical fluid in a series of cycles to create micro- and macro-fractures. The cyclic experiments performed in this study were concluded with the recording of breakdown pressure in each case. The post-treatment analysis using medical Computerized Tomography (CT) showed that multiple fractures were created due to the pressure pulse created in the thermochemical reaction. Results showed that the breakdown pressure of the rock decreases with the increasing number of cycles. The proposed method of cyclic thermochemical fracturing reduced the breakdown pressure by 33% in one-cycle, 41% in two-cycles, 53.5% in three-cycles, and 69% in four-cycles, when compared with conventional method of fracturing. An empirical relationship is also presented between the number of cycles of thermochemical fluid injection and the breakdown pressure of the rock.",12,12,5
Fracture,Carbonate Rocks,"Zhang, Hao; Zhong, Ying; Zhang, Jiang; Zhang, Yongchun; Kuang, Jianchao; Yang, Bin",Experimental research on deterioration of mechanical properties of carbonate rocks under acidified conditions,Carbonate reservoirs; Acid fracturing; Reaction rate constant; Activation energy; Mechanical properties,LABORATORY EVALUATION; REACTION-KINETICS; ACID REACTION; PORE-SCALE; DISSOLUTION; RESERVOIR; MODEL; STIMULATION; COEFFICIENT; PROPAGATION,"Understanding the relationship among the individual factors (i.e., carbonate rock types, acid rock reaction kinetics, deterioration of rock mechanical properties) can provide practical guidelines that can be used for the design and optimization of acid fracturing operation. A comprehensively experimental study was conducted to investigate the acid rock reaction kinetics of carbonate rocks under acidified conditions, and how the acid rock reaction would influence the carbonate rock mechanical properties. In addition, the deterioration mechanism of the carbonate rock mechanical properties is determined by the qualitative analysis of casting thin section images. Results show that the limestone rock is more susceptible to acid dissolution than limy dolomite rock under the same acidified conditions. The limestone rock has relatively large reaction rate constant and low activation energy, however, it is reverse in limy dolomite rock. As a result, the mechanical properties of rocks with relatively low cementation strength could be highly or lowly weakened. The reduction (in percentage, %) in mechanical properties of the limestone rocks with relatively high cementation strength is greater than that of the limy dolomite rocks with relatively high cementation strength. Casting thin section images show that the cementation and fillings of limestone and limy dolomite rocks are calcite and calcite-dolomite, respectively. The non-uniform (i.e., superficial and local deep) and uniform etched pattern (i.e., superficial and symmetrical) occur on the end surface of limestone and limy dolomite, respectively. Consequently, the mechanical properties of relatively high cemented limestone rocks are more significantly reduced than that of relatively high cemented limy dolomite rocks. This work is of great practical guidelines for the design and optimization of acid fracturing operations, as well as the efficient stimulation of carbonate reservoirs.",9,9,4
Fracture,Carbonate Rocks,"Abalkhail, Nassir; Liyanage, Pathma Jith; Upamali, Karasinghe A. N.; Pope, Gary A.; Mohanty, Kishore K.",Alkaline-surfactant-polymer formulation development for a HTHS carbonate reservoir,Surfactant flooding; Enhanced oil recovery; Carbonate reservoir; High temperature; High salinity,MICROEMULSION PHASE; OIL,"There are many HTHS (high temperature, high salinity) carbonate reservoirs where temperature (>80 degrees C) and salinity (>30,000 ppm) are high. The goal of this study was to develop an alkaline-surfactant-polymer (ASP) formulation for a high temperature (similar to 100 degrees C), high salinity (similar to 60,000 ppm) giant carbonate reservoir with low surfactant retention, an essential requirement for low chemical cost. Phase behavior tests were conducted with anionic surfactants, alkali, co-solvents, brine, and crude oil to identify chemical formulations with ultra-low IFT under reservoir conditions. Corefloods were first conducted in outcrop carbonate cores and then in reservoir cores. The effluent was analyzed for oil, surfactant, pH, salinity and viscosity. Surfactant adsorption on carbonate surfaces decreases at high pH. Ammonia and a new organic alkali ethoxylated diisopropylamine (DIPA-10EO) were studied for this application since there is both anhydrite and dolomite in the formation. Sodium carbonate cannot be used as the alkali in rocks containing anhydrite, and sodium hydroxide cannot be used as the alkali in rocks containing dolomite. Ultralow IFT (similar to 0.001 mN/m) was achieved with several ASP formulations using the reservoir oil. The first three core floods in Indiana limestone yielded excellent tertiary oil recoveries of 85.2, 89.5 and 91.8%, and very low surfactant retentions of 0.06, 0.02, and 0.11 mg/g-rock, respectively. The reservoir coreflood resulted in 93.6% tertiary oil recovery and a final oil saturation of 1.2%. The surfactant retention was 0.083 mg/g-rock. The chemical formulation developed here is applicable to this high permeability, non-fractured, HTHS carbonate reservoir. Future research should address other carbonate reservoir issues such as fractures and low permeability.",9,9,1
Fracture,Carbonate Rocks,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Fracture,Carbonate Rocks,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Fracture,Carbonate Rocks,"Shao, Jiaxin; You, Lijun; Kang, Yili; Gao, Xinping; Chen, Mingjun; Meng, Sen; Zhang, Nan",Experimental study on stress sensitivity of underground gas storage,Underground gas storage; Effective stress; Pressure gradient; Stress sensitivity; Effective stress action time,TRANSPORT BEHAVIOR; PERMEABILITY; MULTISCALE; MECHANISM; BASIN,"The increase in effective stress and effective stress action time reduces the permeability of rock fractures. XG underground gas storage systems are constructed in carbonate formations. Fractures constitute the main seepage channel of pore-fracture carbonate formation. Alternating stress during multi-cycle injection-production of underground gas storage causes the fractures to open and close periodically. This leads to stress sensitivity of the formation and reduces the permeability of rock fractures. In this work, typical rock samples of carbonate formation in XG underground gas storage were selected as the research object, and stress sensitivity experiments, gas speed sensitivity experiments and stress sensitivity experiments considering effective stress action time were carried out. The rock sample permeability during the experiment was measured. The fracture walls of rock samples before and after the stress sensitivity experiments and stress sensitivity experiment considering the effective stress action time were analyzed by SEM. The influence mechanism of effective stress and effective stress action time on permeability of underground gas storage was explored. Stress sensitivity coefficient method was used to evaluate stress sensitivity. The results show that the stress sensitivity of fracture and matrix samples considering effective stress action time was enhanced compared with stress sensitivity experiments. With the increase in effective stress action time, the elastic-plastic deformation of rock increased the breaking of microconvex bodies on the fracture wall. Moreover, micro-fractures were generated to reduce rock strength. The breaking of micro-convex bodies and the generation of micro-fractures strengthened the stress sensitivity of rocks. Moreover, fine migration caused by excessive injection-production pressure gradient also increased the stress sensitivity.",7,7,5
Fracture,Carbonate Rocks,"Jiu, Bo; Huang, Wenhui; Mu, Nana; He, Mingqian","Effect of hydrothermal fluids on the ultra-deep Ordovician carbonate rocks in Tarim Basin, China",Tarim basin; Hydrothermal transformation; Carbonate rock; Migration mode; Fluid properties,THERMOCHEMICAL SULFATE REDUCTION; RARE-EARTH-ELEMENTS; NW CHINA; DOLOMITE RESERVOIRS; TAZHONG AREA; GEOCHEMICAL CHARACTERISTICS; CALCITE DISSOLUTION; FORMATION MECHANISM; BURIAL DISSOLUTION; FIBROUS CALCITE,"Carbonate rocks of Ordovician formations make up many important reservoirs in Tarim Basin. This study focuses on the formation mechanism and evolution model of Ordovician hydrothermal reformed carbonate reservoirs in the Yubei area of Tarim Basin. The observations of core samples, thin sections and cathode luminescence images shows that the carbonate rocks were subjected to multiple stages of karstification and hydrothermal cementation. The results of fluorescence observations and fluid inclusions indicate that the study area was affected by two periods of hydrothermal migration during the late Hercynian period and late Himalayan period. Controlled by the freshwater and hydrothermal fluids, the delta C-13 and delta O-18 of the fracture fillings are distributed from -1.8 parts per thousand to -0.8 parts per thousand and from -13.6 parts per thousand to -10.1 parts per thousand, respectively, with delta Eu>1 and high Mn and Fe. According to the distribution characteristics of trace elements and metallic elements, the two phases of hydrothermal fluid were rich in SiO2, Ho, and Tm. H2S produced by thermochemical sulfate reduction (TSR) changes the pH of the formation-hydrothermal fluids to acidic values. The hydrothermal fluid was converted to weakly alkaline by the reversible reaction between CO32- and HCO32-, building a silica-calcite-filled karst-fracture reservoir. Eventually, this paper establish a schematic diagram of hydrothermal migration along a single fracture and reveal the evolution mode of the study area.",7,7,5
Fracture,Carbonate Rocks,"Wei, Shiming; Jin, Yan; Xia, Yang",Predict the mud loss in natural fractured vuggy reservoir using discrete fracture and discrete vug network model,Naturally fractured reservoirs; Discrete fractures; Discrete vugs; Mud loss,FINITE-ELEMENT-METHOD; 2-PHASE FLOW; SIMULATION; FLUID; CONTINUUM; MEDIA,"In carbonate reservoirs, the leakage path is complex and the law of mud loss is not clear, which brings difficulties to the implementation of plugging measures. Carbonate reservoir is a naturally fractured vuggy media. One of the key scientific problems is that the fluid mass transfer among matrix pores, natural fractures and vugs is not well understood. In this paper, a discrete fracture and discrete vug model is presented to study the law of mud loss in the naturally fractured reservoir wherein natural fractures and vugs developed. The model solved the fluid flow in the discrete fracture and vug network, consisting of 1) Darcy flow in lowly permeable rock matrix and highly permeable natural fractures; 2) free flow in macro vugs. A physically-based boundary is applied to ensure the mass continuity on interfaces between vugs and matrix pores, vugs and natural fractures. A good agreement with analytical results for Poiseuille flow in a porous/free connected media is achieved. Two numerical examples using the commercial software COMSOL provide validation of the new model. When simulating the mud loss process, we find that as soon as vugs are connected to wellbore through natural fractures, total loss is observed. The size and number of vugs play prominent roles in increasing mud loss rate and accumulated mud loss. The numerical results show that the discrete fracture and discrete vug model provides a reliable way to model realistic fluid flow in fractured vuggy porous media. The model in this paper can not only simulate the mud loss process, but also the production process of carbonate reservoirs.",7,7,4
Fracture,Proppant,"Tan, Peng; Pang, Huiwen; Zhang, Ruxin; Jin, Yan; Zhou, Yingcao; Kao, Jiawei; Fan, Meng",Experimental investigation into hydraulic fracture geometry and proppant migration characteristics for southeastern Sichuan deep shale reservoirs,Hydraulic fracturing; Deep shale; Proppant migration; Bedding plane,PROPAGATION BEHAVIOR; SIMULATION; INITIATION; NETWORK; OPTIMIZATION; MORPHOLOGY; CRITERION; BRITTLE; MODEL; ROCK,"Difficulties in fracture extension and proppants adding were two key factors that affected the stimulated volume of deep shale reservoir. To clarify the mechanism of hydraulic fracture (HF) propagation and proppants migration, several groups of large-scale true tri-axial fracturing tests with an ingenious method of sand adding were performed utilizing deep Longmaxi shale outcrops from southeastern Sichuan. The interaction behavior between vertical HF and bedding plane (BP) was discussed. The results showed that due to the low bonding strength, the BPs could be easily activated even under high vertical stress difference coefficient. Based on the different influenced degrees of BPs, four types of HF geometries in the vertical direction were observed, that is, transverse HF, horizontal HF, step-shaped HF with fissure opening, and multilateral step-shaped HF network. The migration distance of proppants was limited and almost all the proppants were distributed around the wellbore, thus inducing the formation of multiple secondary HFs. When there are natural fractures (NFs) with large aperture around the wellbore, proppants almost entirely distributed along the NFs. The main factor, causing the difficulty of fracture extension and proppants migration, was the complex HF geometry characterized by the multi-branched fractures with slippage of BPs.",33,34,6
Fracture,Proppant,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Fracture,Proppant,"He, Huan; Senetakis, Kostas",A micromechanical study of shale rock-proppant composite interface,Shale rock; Quartz sand; Interface friction; Hydraulic fracturing; Proppant,GRAIN-SCALE MECHANICS; GUM AQUEOUS-SOLUTION; FRACTURE CONDUCTIVITY; QUARTZ SAND; BEHAVIOR; CONTACT; SHEARING; PARTICLE,"The micromechanical properties of shale rock-sand type of composite interface were investigated by performing laboratory tests with a custom-built loading apparatus. This type of interface is of significant interest in petroleum engineering in the process of hydraulic fracturing using proppants. Two different types of quartz sands of different particle shapes were used as proppant simulants and they were sheared against rough and smooth surfaces of shale. It was shown that sand grain type and surface roughness of shale affected the contact stiffness in the normal and tangential directions because of their influence on the induced contact stresses. Based on the micromechanical shearing tests, it was found that the coefficient of friction, the initial tangential stiffness and the microslip displacement were positively correlated with the magnitude of normal load. Although clear surface damage/plowing of the shale surface caused by shearing was observed and captured by interferometry images, the effect of loading history was found to be small. Shearing tests on wet and dry shale surfaces did not show that much difference in results, but immersion of shale in water prior to shearing affected the initial tangential stiffness and coefficient of friction at certain normal loads. Smoothening of the surface had an influence on friction as long as limited plowing was triggered in the low range of normal loads, so that the influence of surface roughness of the shale would diminish at higher normal loads where plowing mechanism dominated the interface response.",14,14,5
Fracture,Proppant,"Fan, Ming; Chen, Cheng",Numerical simulation of the migration and deposition of fine particles in a proppant-supported fracture,Fine particle deposition; Deposition coefficient; Proppant; Hydraulic fractures; Discrete element method; Lattice Boltzmann,LATTICE BOLTZMANN MODEL; BED FILTRATION; STIMULATION; EVOLUTION; TRANSPORT; SYSTEM; FLOWS,"Many hydrocarbon-bearing geologic formations, especially shales, contain high clay contents. During hydrocarbon production, pore pressure reduces and the effective stress of the rock matrix increases, which may lead to formation failure and consequently fine particles production within the formation fluids. Invasion of fine particles into proppant assemblies in a hydraulic fracture can clog the pore spaces between proppant particles and consequently lead to loss of fracture permeability and conductivity. Although fine particle migration and clogging in a proppant-supported hydraulic fracture is critical to effective production of hydrocarbons, the role of effective stress, proppant particle size, and proppant size distribution is still unclear. In this study, a discrete element method-lattice Boltzmann (DEM-LB) numerical framework was developed to study the mechanisms that regulate the migration and deposition of fine particles in a proppant-supported fracture, which is subjected to a closure pressure. Specifically, DEM was used to generate proppant assemblies and to simulate effective stress increase and the resultant proppant particle compaction. The DEM-simulated pore structure of the compacted proppant assembly was then extracted and imported into the LB simulator as internal boundary conditions of fluid flow modeling. Fine particle transport in the pore spaces was numerically simulated based on the LB-simulated pore flow field, and three transport mechanisms that regulate fine particle migration, including interception collection, Brownian motion, and gravitational settling, were accounted for. The numerical results of pore-scale particle tracking and deposition were fitted using a continuum-scale fine particle deposition model to determine the macroscopic deposition coefficient, as well as how fine particle size, proppant size heterogeneity, and effective stress influence the macroscopic deposition coefficient. Good agreement between numerically-simulated and correlation-predicted deposition coefficients was observed. The simulation results confirmed the non-monotonic change of fine particle deposition coefficient as a function of fine particle size. This study indicates that proppant assemblies having the same mean proppant diameter but a more heterogeneous proppant diameter distribution (i.e., a wider distribution of proppant diameter) favors fine particle migration through the pore space under low to moderate closure stresses. The developed simulation framework can be used to effectively model the migration and deposition of fine particles having varying sizes at the pore scale.",11,11,7
Fracture,Proppant,"Wang, Jie; Huang, Yixiao; Zhang, Yan; Zhou, Fujian; Yao, Erdong; Wang, Rui",Study of Fracturing Fluid on Gel Breaking Performance and Damage to fracture conductivity,Gel breaking of fracturing fluid; Fracturing fluid residue; Proppant crush; Proppant embedding; Conductivity,FLOW; BEHAVIOR; MODEL,"As a thickening agent commonly used in hydraulic fracturing, guar gum has the advantage of low price and excellent performance. However, the gel breaking mechanism of fracturing fluid under high temperature and high pressure environment and the damage mechanism to the reservoir needs further study. The current criteria for judging gel breaking is based on the viscosity of the solution being less than 5 mPa s, however it's not always true that the gel breaks even if the viscosity of the fluid is low. To solve this problem, it's recommended in this paper to analyze the gel breaking performance of fracturing fluid by measuring the median molecular particle size and the residue content together with the viscosity of fracturing fluid. Moreover, the effects of the gel breaker on the crushing and formation embedding of the proppant, the adsorption and retention mechanism of the residue in the induced fracture and their influence on the conductivity are investigated. Studies show that the gel breaking performance of guar gum fracturing fluid is affected by the amount of gel breaker and temperature. Adding extra amount of gel breaker and imposing high temperatures do not effectively reduce the median molecular particle size of the fracturing fluid. The detrimental effect of the gel breaker and it's residue to the fracture conductivity is mainly reflected in three aspects: increased crush rate of the proppant due to soaking in the gel breaker, exacerbated embedding of the proppant into formation due to interaction of the fluid and the formation and the reduced pore diameter of the formation due to residue of the fracturing fluid. It's observed that the detrimental effect of the gel breaker on the conductivity of the fracture is mostly in the area with a high closing pressure of 50 MPa or above. This study provides a reference of tight sandstone reservoirs hydraulic stimulation and fracturing fluid formation damage for high temperature and high pressure oilfields like Tarim oilfield.",10,11,14
Fracture,Proppant,"Voltolini, Marco; Ajo-Franklin, Jonathan",Evolution of propped fractures in shales: The microscale controlling factors as revealed by in situ X-Ray microtomography,Proppant; Fractures; Tight oil and gas shales; X-ray microtomography; Permeability,GAS; CONDUCTIVITY; CHALLENGES,"The behavior of proppant at the microscale during fracture closure in oil and gas shales is not yet well understood. In this context, we used a combination of dynamic synchrotron X-ray micro computed tomography with morphometric analysis and flow modeling to provide new insight into the dominant physical processes acting at the microscale during fracture closure, and understand their impact on hydraulic properties of the fracture. The roles of three variables have been investigated in proppant monolayers: i) Shale mineralogy and microstructure; ii) Shale bedding orientation with respect to the fracture plane; iii) Proppant characteristics. Unsurprisingly, all three variables have an impact on the permeability evolution during closure and their extent has been quantified via Stokes flow simulations. For the fracture geometry considered, proppant rearrangement during loading is the leading cause of permeability loss. The mechanical strength of proppant and shale becomes important at the later stages of the fracture closure. Bedding orientation has an impact on the mechanical response of the proppantshale contact areas. The more regular morphology and higher mechanical strength of ceramic proppant allows to maintain a better permeability throughout the whole fracture evolution cycle when compared to quartz sand. This combined analysis approach allowed us to understand and quantify the processes involved during the closure of a propped fracture and to directly link them to the evolution of morphology and hydraulic properties. A better understanding of the contributions of these processes could ultimately help in the design and optimization of proppants, enabling more efficient extraction of hydrocarbons from unconventional systems.",10,10,2
Fracture,Proppant,"Wei, Gongjue; Babadagli, Tayfun; Huang, Hai; Hou, Lei; Li, Huazhou",A visual experimental study: Resin-coated ceramic proppants transport within rough vertical models,Hydraulic fracture; Surface roughness; Proppant transport; Coated ceramic proppant,HYDRAULIC FRACTURES; CONDUCTIVITY; OPTIMIZATION; RESERVOIRS; HEIGHT; FLOW,"Resin-coated ceramic proppants have a thin layer of resin coating on a ceramic body. In this study, we performed experiments to investigate the transport and settling behavior of resin-coated ceramic proppant in three rough vertical fracture models that are replications of different rocks. We studied the effects of the influential factors on the transport behavior of the proppant, including the location of the injection point; proppant, fracturing fluid, and fracture model types; injection rate; particle size; and fracture aperture. Resin-coated ceramic proppant occupied a large area of the fracture when the slurry was injected through the top injection point compared to when it was injected through the bottom injection point. Moreover, the resin-coated ceramic proppant covered a larger area of the fracture than silica sand owing to its higher density. The relative coverage of proppant carried by slickwater was also lower than that of proppant carried by tap water. The larger particle size and additional collisions between the particles and the rough surface of the fracture enabled 20-40 mesh resin-coated ceramic particles to cover more area, compared to 30-50 mesh resin-coated ceramic particles, in the fracture models. When slurry mixed with proppant was injected into fractures with smaller apertures, more collisions occurred between the proppant particles and the fracture surface, slowing the movement of the resin-coated ceramic particles and producing a higher chance of proppant settling and accumulating. Of the three fracture models, the highest relative coverage of resin-coated ceramic proppant was obtained in a replication of coarse-grained white marble, while the lowest relative coverage of resin-coated ceramic proppant was obtained in a replication of beige limestone with abundant coarse fossil shells.",9,9,8
Fracture,Proppant,"Li, Ning; Zhang, Shicheng; Ma, Xinfang; Zou, Yushi; Li, Sihai; Zhang, Zhaopeng",Thermal effect on the evolution of hydraulic fracture conductivity: An experimental study of enhanced geothermal system,Geothermal energy; Hot dry rock; Micro-indentation; Thermal softening; Fracture conductivity,HOT DRY ROCK; ACOUSTIC-EMISSION RESPONSE; MECHANICAL-BEHAVIOR; HIGH-TEMPERATURE; HEAT EXTRACTION; ELASTIC-MODULUS; GRANITE; PROPPANT; INDENTATION; GROWTH,"This paper aimed to investigate the thermal effect on the evolution of hydraulic fracture conductivity during heat extraction. Meanwhile, the degradation mechanisms of fracture conductivity were analyzed in terms of the mechanical damage of fracture surfaces. Experimental results of micro-indentation tests on the studies granite show the existence of a threshold value of temperature. The Young's modulus and hardness of fracture surface significantly decreased when the thermal treatment levels were higher than 300 degrees C. Similarly, the degradation of fracture conductivity was limited (<10%) before 300 degrees C and then significantly deteriorated at 400 degrees C and 500 degrees C. Moreover, cyclic thermal treatment tended to aggregate the mechanical damages of fracture surfaces further. At the thermal treatment level of 300 degrees C, obvious thermal softening of fracture surfaces and degradation of fracture conductivity were observed only when the number of cycles was larger than 10, while both of these two phenomena became more severe with the increasing of the number of cycles at the thermal treatment level of 400 degrees C. The evolution of fracture conductivity can be accounted for by the temperature-related integrity of fracture surfaces and proppant pack. It was indicated that the thermal softening of fracture surface tended to enhance the proppant embedding, which might be beneficial for the alleviation of proppant crushing.",9,9,7
Fracture,Proppant,"Zhang, Qitao; Zhu, Weiyao; Liu, Wenchao; Yue, Ming; Song, Hongqing",Numerical simulation of fractured vertical well in low-permeable oil reservoir with proppant distribution in hydraulic fracture,Proppant distribution; Effective fracture length; Vertical well; Threshold pressure gradient; Moving boundary; Flow field,TIP SCREEN-OUT; TRANSPORT; FLOW; FLUID; MODEL; KGD; LAW,"In this paper, numerical simulations of fractured vertical well in low-permeable oil reservoir are carried out and two issues: threshold pressure gradient (TPG) in reservoir matrix and proppant distribution in hydraulic fractures are focused on. A physical definition of effective fracture length (EFL) is presented to evaluate the fracture effectiveness due to uneven proppant distribution. In terms of numerical processing for TPG, based on the subsurface Darcy's flow module in COMSOL Multiphysics, an effective numerical simulation method is adopted by substituting the gravitational acceleration vector in Darcy's law (Liu et al., 2019b). The simulation results show that, proppant distribution has great influence on fracture effectiveness. Unappealing proppant distribution can reduce effective fracture length by 49.6%, which is negative for low-permeable oil reservoir development. TPG in reservoir matrix mainly affects the moving boundary and pressure-disturbed area in reservoir. When TPG in matrix reduces from 0.02 MPa/m to 0 MPa/m, the distance of moving boundary at 300 days could increase for almost double and pressure-disturbed area enlarged drastically for around 74%. Furthermore, a heterogenous low-permeable oil with secondary fracture networks is designed to study the joint effect of TPG and proppant distribution. If we neglect these two factors, cumulative oil rate will be greatly overestimated by 38.6% at 1000 days. At the same time, the existence of natural fractures could also affect the streamline distribution in low-permeable oil reservoir and contribute to fluid flow in reservoir.",8,9,6
Fracture,Proppant,"Yue, Ming; Zhang, Qitao; Zhu, Weiyao; Zhang, Liaoyuan; Song, Hongqing; Li, Jianhui",Effects of proppant distribution in fracture networks on horizontal well performance,Hydraulic fracturing; Fracture network; Proppant distribution; Fracture conductivity; Well performance,TIP SCREEN-OUT; HYDRAULIC FRACTURE; NUMERICAL-SIMULATION; TRANSPORT; MODEL; FLOW; SUSPENSIONS; RESERVOIR; SLURRY; KGD,"In this paper, we presented a coupled 3D finite element method model for the simulation of proppant transport in fracture networks and its effects on horizontal well performance. We used a mixture model, which have advantages to deal with two-phase flow containing a dispersed phase like solid particles, to simulate the proppant transport process in fracture networks. Then a tight oil reservoir model was established to evaluate the effect of the proppant distribution on the horizontal well performance. The effects of several factors, such as the proppant physical properties and injection parameters, were analyzed. The calculated results show that, in the fracture network, proppant accumulates at the intersections of cracks. Height of the proppant packed bed in natural fracture was about 30% smaller than that in the main hydraulic fracture, and the communication between hydraulic fractures leads to a larger proppant dune and higher conductivity. Besides, in a tight oil reservoir, the proppant distribution has a significant influence on the well performance. When the reservoir permeability is reduced to 0.05 mD, the productivity index fold of increase calculated including the proppant uneven distribution can be 47.7% larger than that calculated with idealized proppant distribution. Furthermore, the proppant physical properties and injection parameters are found to be correlated with the fracture network conductivity. Based on this analysis, optimum proppant injection conditions can be identified.",8,8,5
Fracture,Brittleness,"Tan, Peng; Pang, Huiwen; Zhang, Ruxin; Jin, Yan; Zhou, Yingcao; Kao, Jiawei; Fan, Meng",Experimental investigation into hydraulic fracture geometry and proppant migration characteristics for southeastern Sichuan deep shale reservoirs,Hydraulic fracturing; Deep shale; Proppant migration; Bedding plane,PROPAGATION BEHAVIOR; SIMULATION; INITIATION; NETWORK; OPTIMIZATION; MORPHOLOGY; CRITERION; BRITTLE; MODEL; ROCK,"Difficulties in fracture extension and proppants adding were two key factors that affected the stimulated volume of deep shale reservoir. To clarify the mechanism of hydraulic fracture (HF) propagation and proppants migration, several groups of large-scale true tri-axial fracturing tests with an ingenious method of sand adding were performed utilizing deep Longmaxi shale outcrops from southeastern Sichuan. The interaction behavior between vertical HF and bedding plane (BP) was discussed. The results showed that due to the low bonding strength, the BPs could be easily activated even under high vertical stress difference coefficient. Based on the different influenced degrees of BPs, four types of HF geometries in the vertical direction were observed, that is, transverse HF, horizontal HF, step-shaped HF with fissure opening, and multilateral step-shaped HF network. The migration distance of proppants was limited and almost all the proppants were distributed around the wellbore, thus inducing the formation of multiple secondary HFs. When there are natural fractures (NFs) with large aperture around the wellbore, proppants almost entirely distributed along the NFs. The main factor, causing the difficulty of fracture extension and proppants migration, was the complex HF geometry characterized by the multi-branched fractures with slippage of BPs.",33,34,6
Fracture,Brittleness,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Fracture,Brittleness,"Gupta, Ishank; Sondergeld, Carl; Rai, Chandra",Fracture toughness in shales using nano-indentation,Fracture toughness; Nano-indentation; Shale anisotropy; Water weakening,,"Fracture toughness property is often ignored but has a significant impact on the hydraulic fracture design, i.e. length and height. It represents the resistance of the rock to hydraulic fracturing and is a direct indicator of rock fracability. It is difficult to measure fracture toughness in shales using current experimental procedures designed for conventional rocks largely due to mechanical and chemical instability in shales. This study measures fracture toughness in shales using nano-indentation. Nano-indentation can, in fact, be used to derive both tensile and shear dominated fracture toughness. The observations in the study show that while crack-length method derived fracture toughness is close to Mode I (tensile) fracture toughness, energy-method based fracture toughness is closer to Mode II (shear) fracture toughness. Fracture toughness was calculated for 67 samples in different shale formations namely Marcellus, Wolfcamp, Woodford and Eagle Ford. The results show that mineralogy had a strong control on fracture toughness. Fracture toughness decreases with increasing porosity, TOC (Total Organic Carbon) and clay content. The fracture toughness also shows strong anisotropy with fracture toughness measured parallel to the bedding planes being generally 33% higher than the corresponding values measured normal to the bedding planes. The fracture toughness shows a direct correlation with other mechanical properties like Young's modulus, hardness and brittleness. Typically, samples with fracture toughness values greater than 3 MPa m(0.5) were found to be brittle based on Young's modulus and Poisson's ratio cross plots. Evaluation of fluid effects on fracture toughness shows that it decreases by 10-37% due to spontaneous imbibition with low salinity brines. This could help understand the impact of hydraulic fracturing fluid on fracture propagation and stimulated reservoir volume (SRV) creation.",14,15,5
Fracture,Brittleness,"Yu, Kun; Gan, Yuting; Ju, Yiwen; Shao, Chunjing",Influence of sedimentary environment on the brittleness of coal-bearing shale: Evidence from geochemistry and micropetrology,Sedimentary environment; Shale brittleness; Micropetrology; Trace element; Rare earth elements,WATER-COLUMN ANOXIA; PB-NB-GA; HUAINAN COALFIELD; HUAIBEI COALFIELD; ORGANIC-MATTER; PERMIAN COALS; MARINE SHALE; CHINA IMPLICATIONS; NATURAL FRACTURES; BARNETT SHALE,"The brittleness of shale is an important index to evaluate the fracture system and reformability of a shale reservoir. This study provides geochemical and micropetrological parameters as proxies for the paleohydrodynamics, redox condition, paleosalinity, and paleoclimate of transitional coal-bearing shale in the Huainan coalfield, eastern China. Thus, combining these data with organic geochemistry parameters, this study aims to investigate the most important factors controlling shale brittleness during the sedimentary process. The results indicate that various important physical and chemical factors (sedimentary facies, hydrodynamics, redox condition, salinity, and climate) of the paleoenvironment have exerted an intense influence on shale brittleness involving complex mechanisms. Rare earth element indexes suggest that marine facies are conducive to the enrichment of carbonate minerals and quartz, thereby improving the brittleness of shale. Micropetrologyical evidence indicates that with an increase of hydrodynamic force, a large number of terrestrial materials are introduced, leading to increased clay mineral content and significantly reducing the brittleness of shale. U/Th, V/Cr, and Ni/Co ratios and Pyrite indexes suggest that reducing water condition accounts for the enrichment of pyrite and the preservation of biogenic quartz. Thus, this increases the content of brittle minerals, while an oxidative environment significantly decreases the brittleness of shale. B/Ga ratios indicate that higher salinity promotes the dissolution of CO2, leading to precipitation of carbonate minerals and thus increasing the content of brittle minerals in shale, which is supported by the salinity characteristics obtained by the B content. In addition, Ba content indicates that a warm climate (humid) is the best condition for the growth of marine life and the development of carbonate minerals, which promotes the enrichment of brittle minerals obviously. While a hot climate (dry) results in the import of more terrestrial clay minerals in the provenance, thereby inhibiting shale brittleness.",14,14,2
Fracture,Brittleness,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Fracture,Brittleness,"Wen, Tao; Tang, Huiming; Wang, Yankun",Brittleness evaluation based on the energy evolution throughout the failure process of rocks,Failure process; Brittleness; Energy evolution; Dissipation energy; Stress-strain curve,INDEX ESTIMATION; SHALE; SANDSTONE; STRESS; STABILITY; STRENGTH; MODEL; DEFORMATION; CRITERIA; COAL,"Brittleness is an important mechanical property of rock masses and a key index used in various engineering practices particularly to evaluate hydraulic fracturing, rock fragmentation and rock burst. However, rock brittleness is a concept remaining to be determined since there are no unique standards available. In this study, two methods to determine the brittleness index are proposed by considering the pre-peak failure energy and post-peak fracture energy, which are regarded as key factors in determining whether brittle failure of rock occurs. By taking the Longmaxi Formation shale as an example, the energy evolution laws of shales under different confinements are first analyzed, and the evaluation methods are then examined and applied to these rocks. The results show that these brittleness indexes for shales are capable of describing the transition from absolute plasticity to absolute brittleness. The applicability and performance of the proposed indexes are further validated against large uniaxial and triaxial compression test datasets for different rock types. Application of these brittleness indexes to the tested rock types clearly demonstrate that the two indexes have opposite variation trends with rising confining pressure. Compared with the previous evaluation methods, the rationality of the methods proposed in this study is also verified. These results indicate the proposed brittleness indexes can reflect the brittle characteristics of the rock and the whole process of deformation and failure of the rock. Accordingly, these methods seem to offer reliable evaluations of the brittleness of rock in various engineering practices, although further validation is necessary.",11,11,15
Fracture,Brittleness,"Ye, Tao; Niu, Chengmin; Wei, Ajuan","Characteristics and genetic mechanism of large granitic buried-hill reservoir, a case study from PengLai oil field of Bohai Bay Basin, north China",,WEATHERING CRUST; TIGHT SANDSTONES; JUNGGAR BASIN; ZHENJING AREA; BONGOR BASIN; FAULT ZONE; BASEMENT; ROCK; FRACTURES; MIGRATION,"In recent years, a major breakthrough has been made in granite hydrocarbon exploration in the Bohai Bay Basin. With the proven reserves of more than 2 x 10(8)t, the Penglai (PL) oilfield is the largest granite oilfield discovered in China. Although the reservoir scale is large, the reservoir heterogeneity is also strong, which brings challenges to its exploration and evaluation. Based on the data of cores, thin sections, whole rock and physical property, the reservoir characteristics and control factors of reservoir-forming in the study area are discussed through the fault analysis and the recovery of tectonic uplift history. The results show that the lithology of PL structure are mainly Mesozoic intrusive granite and Proterozoic mica quartz schist, which develops reservoirs related to the weathered crust and internal fractures. Due to the influence of weathering intensity and fault activity, the porous reservoirs in weathered glutenite zone, pore-fractured reservoirs in weathered fracture zone and fractured reservoirs in the inner fracture zone were distributed orderly from top to bottom vertically. The scale of the high quality reservoir on the plane is controlled by lithology, faults, weathering and buried depth. Granite is the main reservoir-forming lithology for more brittle and less resistant to weathering than mica quartz schist, which forms a special phenomenon that the granite in saddle is rich for hydrocarbon while the mica quartz schist in high position is poor for hydrocarbon accumulation. The northwest Miaoxi fault is the main controlling-fault in the study area, and there is an obvious negative correlation between reservoir thickness and distance from this fault. The long-term uplift of Cenozoic provides conditions for strong weathering, while the shallow burial in the late stage provides effective protection for weathered crust reservoirs. The coupling of the above conditions is the main reason of large scale reservoir development in the study area, and among them, the long-term uplift is the key factor for reservoir-forming.",9,10,3
Fracture,Brittleness,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Fracture,Acid,"Mahesar, Aftab Ahmed; Shar, Abdul Majeed; Ali, Muhammad; Tunio, Abdul Haque; Uqailli, Muhammad Aslam; Mohanty, Udit Surya; Akhondzadeh, Hamed; Iglauer, Stefan; Keshavarz, Alireza","Morphological and petro physical estimation of Eocene tight carbonate formation cracking by cryogenic liquid nitrogen; a case study of Lower Indus basin, Pakistan",Tight carbonate rocks; Petro physics; SEM; AFM; Nano indentation; Liquid nitrogen,PORE STRUCTURE; COAL DAMAGE; GLOBAL OIL; EVOLUTION; PERMEABILITY; RESERVOIRS; SALINITY; FREEZE,"Significant amounts of hydrocarbons are contained in tight carbonate rocks like those within the Indus basin of Pakistan, but due to their unconventional nature, their extraction is difficult. This can be completed/conducted by properly characterizing its mineralogical, geochemical and microstructural properties. In this context, Hydraulic fracturing and acidizing are the most common fracture stimulation techniques. However, they suffer significant technical and environmental flaws. Liquid Nitrogen (LN2) fracking is considered as one of the best alternatives compare to hydraulic fracturing or acidizing due to its eco-friendly nature. In fact, after exposer to LN2, super cryogenic feature of the rock causes porosity, permeability and fracture conductivity enhancement due to thermal shock without any environmental consequences. The effect of Liquid Nitrogen fracking on tight carbonate outcrops collected from the Indus basin is investigated in the present study. Scanning Electron Microscopy (SEM) reveals the clear appearance of wide pore fractures with sizes from 4 mu m to 50 mu m, when subjected to liquid Nitrogen (LN2) treatment ranging from 30 to 90 min' duration. Furthermore, SEM and Atomic Force Microscopy (AFM) images also indicate clear pore fractures in tight carbonate rocks along with increased pore connectivity. Moreover, following liquid nitrogen treatment of up to 90 min the permeability of tight carbonate increases by 53% and increases in porosity by 73%. Results from SEM studies suggest that visible fractures occur in the tight carbonate samples with liquid nitrogen treatment because of the freezing temperature (-196 C-square) of Liquid Nitrogen. In addition to this, Nano indentation moduli depict significant decreases in tight carbonate rocks, both before and after exposure to LN2, as a result of increases in liquid rock compressibility. In this regard, a 50 mN force decreased from 50.57 GPa to 24.37 GPa and for a 200 mN force this decreased from 45.77 GPa to 26.67 GPa. This research depicts the significant effect of Liquid Nitrogen freezing on the fracturing of carbonate rocks.",32,32,8
Fracture,Acid,"Aljawad, Murtada Saleh; Schwalbert, Mateus Palharini; Zhu, Ding; Hill, Alfred Daniel",Improving acid fracture design in dolomite formations utilizing a fully integrated acid fracture model,Acid; Fracture; Productivity; Dolomite; Stimulation; Modeling,,"Acid reactivity with dolomite is more sensitive to temperature as compared to calcite formations, resulting in different dissolution profile. Acid fracture fluids are heated inside the fracture, as it flows away from the wellbore, due to the reservoir heat flux. This causes a sharp increase in dolomite reactivity, resulting in a bell-shaped conductivity profile along the fracture half-length. The productivity of such conductivity distributions will be wrongly estimated if a single average conductivity value is used. In the present research, a reservoir simulator that includes variable fracture conductivity was coupled with an integrated acid fracture model. Also, design guidelines for acid fractures in dolomite formations have been proposed. Case studies are presented, showing that in conventional acid fracture designs, the maximum dissolution in dolomite usually occurs away from the wellbore. This negatively affects productivity, as maximum conductivity is desired near the wellbore. This effect is especially significant for fracturing candidate wells in higher permeability reservoirs. This study shows that in good permeability formations, productivity can be improved by acid fractures designed at a lower injection rate. In cases where the desired injection rate is not sufficient to propagate the fracture, good productivity can be obtained by using two acid stages with different injection rates. A higher injection rate is employed to create the desired fracture dimensions, and a smaller rate used to obtain good conductivity in the near-wellbore region. In low permeability reservoirs, it is desirable to alternate injections of retarded acid systems with pad fluid to create longer acid penetration distances. The results show that, in certain conditions, designs following the proposed guidelines can result in substantial productivity improvement compared to the conventional approach.",14,14,1
Fracture,Acid,Kao Jiawei; Jin Yan; Zhang Kunpeng; Ren Pengju,Experimental investigation on the characteristics of acid-etched fractures in acid fracturing by an improved true tri-axial equipment,Acid fracturing; Carbonate; Acid-etched fracture; Alternate injection; Surface etching; Fracture morphology,BALL DRILLING-FLUIDS; PROPAGATION BEHAVIOR; MODEL; MECHANISM; GROWTH; SHALE,"The propagation characteristics and influencing factors of hydraulic fractures can be analyzed through fracturing experiments. However, there are almost no fracturing experiments in which acid fluids were considered, for the acid resistance of the equipment is always imperfect. In this paper, a physical modeling experimental equipment for acid fracturing was designed and introduced, in which corrosion protection and alternate injection were realized. The carbonate rock for acid fracturing experiment was collected from Sichuan Basin, China, which was tight with a little cavity developed. Acid fracturing experiments, in which HCL, guanidine gum and guanidine gum with an acid fluid were used as the fracturing fluids, were conducted to analyze the characteristic of acid-etched fractures. The results showed that Acid fluid etched the fracture surface, especially in the near-wellbore area; Acid fluid would open microfractures and pores easily, and leaked into these spaces, which decreased the propagation distance of the primary acid-etched fracture; High viscosity guanidine gum was first injected and then with low viscosity acid fluid, then the latter one was transported to distal area by viscous fingering, which would lead to a better fracturing effect; Due to the acid-rock reaction, the morphology of acid-etched fracture was obviously different from hydraulic fracture, and two kinds of acid-etched fracture morphology were proposed according to the sequence of acid fluid and guanidine gum. In this paper, the characteristics of acid-etched fractures were investigated by four groups of acid fracturing experiments, which could provide a reference to optimize acid fracturing effect.",12,13,9
Fracture,Acid,"Zhang, Lufeng; Zhou, Fujian; Feng, Wei; Pournik, Maysam; Li, Zhun; Li, Xiuhui",Experimental study on plugging behavior of degradable fibers and particulates within acid-etched fracture,Temporary plugging; Degradable fibers and particulates; Diverting acid fracturing; 3D printing,SANDSTONE; MECHANISM; DESIGN; WATER,"As proven from field practices in North America and Northwest China, temporary plugging and diverting acid fracturing is an indispensable technology to enhance stimulation effect and hydrocarbon production of complex carbonate reservoirs. It's well-known that the key to the success of this technology lies in creating a temporary plugging within the previously created fractures. Consequently, many scholars have conducted laboratory experiments to investigate the plugging behavior of fibers and particulates. However, the current devices nearly have certain limitations in simulating temporary plugging experiments. Aiming at this problem, this paper introduced the fracture temporary plugging evaluation system with large fracture size, and high-pressure resistance, which can meet the requirement of temporary plugging experiment. In addition, 3D printing technology was used to reproduce the roughness of acid-etched fracture surface, improving the experimental accuracy. Based on the device, a series of experiments were performed to study the effect of carrier fluids type, the injection rate, the fracture width, and the fracture morphology on plugging behavior of fibers and particulates. Experimental results show that the plugging effect of HPG fracturing fluid is better than that of slick water. Moreover, the effect of temporary plugging deteriorates with the decrease of injection rate, which can be attributed to the fact that high injection rate increases the probability of bridging and plugging. When it comes to the fracture width, only fibers have favorable plugging effect under the condition of 2 mm fracture width. However, a single type of temporary plugging agent (only fibers or particulates) cannot achieve effective plugging under the condition of 4 mm fracture width. The combination of fibers and particulates can obtain favorable plugging effect. When the fracture width increases to 6 mm, it's difficult to obtain favorable plugging effect if the diameter of particulates is less than 50% of fracture width. Hence, it is recommended to add big particulates whose diameters are at least 50% of the fracture width to improve the plugging effect. Moreover, the fracture surface morphology affects the formation time of temporary plugging, but does not affect whether temporary plugging is formed or not. This study deepens the understanding the plugging behavior of fibers and particulates within acid-etched fracture and provides fundamental for field treatment design.",11,13,8
Fracture,Acid,"Zhang, Hao; Zhong, Ying; Zhang, Jiang; Zhang, Yongchun; Kuang, Jianchao; Yang, Bin",Experimental research on deterioration of mechanical properties of carbonate rocks under acidified conditions,Carbonate reservoirs; Acid fracturing; Reaction rate constant; Activation energy; Mechanical properties,LABORATORY EVALUATION; REACTION-KINETICS; ACID REACTION; PORE-SCALE; DISSOLUTION; RESERVOIR; MODEL; STIMULATION; COEFFICIENT; PROPAGATION,"Understanding the relationship among the individual factors (i.e., carbonate rock types, acid rock reaction kinetics, deterioration of rock mechanical properties) can provide practical guidelines that can be used for the design and optimization of acid fracturing operation. A comprehensively experimental study was conducted to investigate the acid rock reaction kinetics of carbonate rocks under acidified conditions, and how the acid rock reaction would influence the carbonate rock mechanical properties. In addition, the deterioration mechanism of the carbonate rock mechanical properties is determined by the qualitative analysis of casting thin section images. Results show that the limestone rock is more susceptible to acid dissolution than limy dolomite rock under the same acidified conditions. The limestone rock has relatively large reaction rate constant and low activation energy, however, it is reverse in limy dolomite rock. As a result, the mechanical properties of rocks with relatively low cementation strength could be highly or lowly weakened. The reduction (in percentage, %) in mechanical properties of the limestone rocks with relatively high cementation strength is greater than that of the limy dolomite rocks with relatively high cementation strength. Casting thin section images show that the cementation and fillings of limestone and limy dolomite rocks are calcite and calcite-dolomite, respectively. The non-uniform (i.e., superficial and local deep) and uniform etched pattern (i.e., superficial and symmetrical) occur on the end surface of limestone and limy dolomite, respectively. Consequently, the mechanical properties of relatively high cemented limestone rocks are more significantly reduced than that of relatively high cemented limy dolomite rocks. This work is of great practical guidelines for the design and optimization of acid fracturing operations, as well as the efficient stimulation of carbonate reservoirs.",9,9,4
Fracture,Acid,"Shi, Wenyang; Yao, Yuedong; Cheng, Shiqing; Shi, Zhiliang","Pressure transient analysis of acid fracturing stimulated well in multilayered fractured carbonate reservoirs: A field case in Western Sichuan Basin, China",Multilayered reservoir; Formation crossflow; Fractured carbonate reservoir; Acid fracturing stimulated well; Pressure transient analysis,BEHAVIOR,"In this paper, we propose a novel analytical model to characterize the bottom-hole pressure (BHP) behavior of acid fracturing stimulated wells in the multilayered fractured carbonate reservoirs. The inter-porosity flow between fracture and matrix, and the crossflow in acid fracturing stimulated zone and unstimulated zone are simultaneously captured. The Bessel functions, Laplace transform, and inversion algorithm are deployed to solve the acid fracturing stimulated model for multilayered fractured carbonate reservoir. Nine flow regimes are identified in the type curves. Compared with current acid fracturing stimulation models for fractured carbonate reservoir, this model has additionally inner crossflow and outer crossflow regimes. Results show that the crossflow obviously affects the concave characteristics in the middle flow stage. The bigger the crossflow coefficient is, the earlier the crossflow regime appears. The pressure derivative value for outer radial flow is found as 0.5 times of the high-permeability layer (HLP) mobility ratio, which provides us a straightforward indication for the determination of acid fracturing stimulation degree. Finally, a field case from the Western Sichuan Basin carbonate reservoir are discussed in detail to validate the capabilities of our model.",8,10,0
Fracture,Acid,"Jiu, Bo; Huang, Wenhui; Mu, Nana; He, Mingqian","Effect of hydrothermal fluids on the ultra-deep Ordovician carbonate rocks in Tarim Basin, China",Tarim basin; Hydrothermal transformation; Carbonate rock; Migration mode; Fluid properties,THERMOCHEMICAL SULFATE REDUCTION; RARE-EARTH-ELEMENTS; NW CHINA; DOLOMITE RESERVOIRS; TAZHONG AREA; GEOCHEMICAL CHARACTERISTICS; CALCITE DISSOLUTION; FORMATION MECHANISM; BURIAL DISSOLUTION; FIBROUS CALCITE,"Carbonate rocks of Ordovician formations make up many important reservoirs in Tarim Basin. This study focuses on the formation mechanism and evolution model of Ordovician hydrothermal reformed carbonate reservoirs in the Yubei area of Tarim Basin. The observations of core samples, thin sections and cathode luminescence images shows that the carbonate rocks were subjected to multiple stages of karstification and hydrothermal cementation. The results of fluorescence observations and fluid inclusions indicate that the study area was affected by two periods of hydrothermal migration during the late Hercynian period and late Himalayan period. Controlled by the freshwater and hydrothermal fluids, the delta C-13 and delta O-18 of the fracture fillings are distributed from -1.8 parts per thousand to -0.8 parts per thousand and from -13.6 parts per thousand to -10.1 parts per thousand, respectively, with delta Eu>1 and high Mn and Fe. According to the distribution characteristics of trace elements and metallic elements, the two phases of hydrothermal fluid were rich in SiO2, Ho, and Tm. H2S produced by thermochemical sulfate reduction (TSR) changes the pH of the formation-hydrothermal fluids to acidic values. The hydrothermal fluid was converted to weakly alkaline by the reversible reaction between CO32- and HCO32-, building a silica-calcite-filled karst-fracture reservoir. Eventually, this paper establish a schematic diagram of hydrothermal migration along a single fracture and reveal the evolution mode of the study area.",7,7,5
Fracture,Stress Sensitivity,"Lyu, Shuaifeng; Wang, Shengwei; Chen, Xiaojun; Wang, Suifeng; Wang, Tao; Shi, Xiaohong; Dong, Qingxiang; Li, Junyang",Natural fractures in soft coal seams and their effect on hydraulic fracture propagation: A field study,Soft coal seam; Qinshui Basin; Natural fractures; On-site hydraulic fracturing; Hydraulic fractures; Particle flow method,PORE STRUCTURE CHARACTERIZATION; HIGH-RANK COAL; MECHANICAL-PROPERTIES; RESERVOIR PRESSURE; ACOUSTIC-EMISSION; FIB-SEM; METHANE; PERMEABILITY; MODEL; ROCK,"Natural fractures provide direct flow channels for coalbed methane (CBM) production and gas outburst control. However, in soft coal seams, the characteristics of natural fractures and their effect on hydraulic fractures are still unclear. In this study, a spatial system of visible natural fractures was established through underground dissection and measurement of ground joints from a case study of the Xinyuan Coal Mine in the northern Qinshui Basin, China. Our results show that the orientations of the subsurface exogenetic fractures of the coal seams are consistent with the macrostructural joints on the ground surface in the same tectonic setting. The exogenetic fractures of the coal seams have dominant orientations with approximately equal spacing. Next, a field test of a large-scale hydraulic fracturing project with a volume of up to 2000 m(3) was conducted. The on-site observation of the underground coal seams revealed that the propagation orientation of the vertical propped fractures coincides with the predominant orientation of the natural fractures. Even at a high constant injection rate (12 m(3)/min), the corresponding injection pressure was not constant during the propagation of the hydraulic fractures, and this can be attributed to the effect of the depth of the coal seam, internal natural fracture network, and normal fault. Additionally, a two-dimensional (2D) particle flow simulation (PFC2D) showed that the propagation of the hydraulic fracture is controlled by the orientations of the natural fractures and the principal stresses. The orthogonal fracture network showed more sensitivity to joint spacing than the layered fracture network in controlling the hydraulic fractures. Finally, fluid detection of the coalbed demonstrated that the flow range of the fracturing fluid in the natural exogenetic fractures was up to a few hundred meters. The flow direction was consistent with that of the natural fractures. A comprehensive analysis of the natural fractures contributes to the identification of flow channels and helps in the design of hydraulic fracturing engineering in soft coal seams.",20,20,9
Fracture,Stress Sensitivity,"Li, Jia; Qiu Zhengsong; Zhong, Hanyi; Zhao, Xin; Huang, Weian",Coupled CFD-DEM analysis of parameters on bridging in the fracture during lost circulation,Lost circulation; Bridging mechanism; Solid-liquid flow; Critical bridging concentration; CFD-DEM,WELLBORE STABILITY; FLOW; SIMULATION; DESIGN,"As an important preventive and remedial application of lost circulation, the optimization of lost circulation materials (LCMs) has become a crucial problem. In order to optimize the design of LCMs, the mechanism of bridging was studied. Based on the theory of solid-liquid flow, a coupled Computational Fluid Dynamics (CFD) - Discrete Element Method (DEM) model was introduced to accurately simulate the dynamic bridging process of plugging particles. The criterion of critical bridging concentration was developed to quantitatively evaluate the effects of Young's modulus, particle density, particle size distribution (PSD), friction coefficient, fracture geometry, lost circulation velocity and fluid yield stress on bridging capacity. The results show that the plugging zone will become more stable with the increase of particle angularity, Young's modulus, density of LCMs, lost circulation velocity and the decrease of fluid yield stress. The friction failure is easier to occur, because the stability of plugging zone is more sensitive to the friction between particle and fracture surface. The critical bridging concentration is more sensitive to the ratio of inlet size to outlet size (R-io) with a higher ratio of outlet size to particle size (R-o). For a small outlet size (R-o <= 2.5), the bridging state can be observed obviously because the large particles are dominant. When the outlet size is larger (R-o > 3), the stable plugging zone is hard to form because the dense state increases the risk of friction failure. The hindering effect of gravity on the trajectory of particles will be more significant when the fracture extension direction is perpendicular to the gravity direction.",11,12,4
Fracture,Stress Sensitivity,"Zhai, Hongyu; Chang, Xu; Wang, Yibo; Lei, Xinglin; Xue, Ziqiu",Analysis of acoustic emission events induced during stress unloading of a hydraulic fractured Longmaxi shale sample,,MOMENT TENSORS; MECHANICAL-PROPERTIES; SICHUAN BASIN; ROCKS; EVOLUTION; FAILURE; COAL,"In shale-gas exploitation, hydraulic fracturing technology is essential to successfully create complex fracture networks in formations. To investigate the dynamic fracturing process, we performed a hydraulic fracturing experiment on a Longmaxi shale sample in the laboratory. After hydrofracturing, hundreds of induced acoustic emission (AE) events were recorded during the stress unloading procedure. At the same time, the high-pressure water stored in the sample fracture network was also discharged. The fracture network inside the fractured sample was studied using medical X-ray computed tomography (CT) scanning technology. Then, the locations and characteristics of the shale failure were analyzed by localizing and inversing the source mechanism of the AE events. Furthermore, the inversion results were verified by comparing with the scanned internal cracks images. According to the source mechanism inversion result, the induced AE events mainly stemmed from the dilatation or compression of fractures and the shear slip of shale along the fracture plane. Finally, the influence of formation attenuation error (underestimated or overestimated attenuation value) on source mechanism inversion results were quantitatively analyzed. It was confirmed that the shear component of the AE event was more sensitive than the volume component to medium attenuation change, especially when the attenuation value was overestimated.",8,9,10
Fracture,Stress Sensitivity,"Chen, Beibei; Xu, Bin; Li, Biao; Kong, Mingwei; Wang, Wanbin; Chen, Huasheng",Understanding the performance of hydraulically fractured wells in the laumontite-rich tight glutenite formation,Hydraulic fracturing; Reservoir dilation; Tight glutenite formation; Laumontite-rich reservoir rock,CAJON-PASS; MODEL; PERMEABILITY; ROCK; DEHYDRATION; SANDSTONES; ZEOLITES; STRENGTH; TESTS; FAULT,"Massive hydraulic fracturing treatments have been used to produce hydrocarbons from tight glutenite oil reservoirs through both vertical and horizontal wells. Some tight glutenite reservoirs are rich in laumontite. Field experiences indicate that the performance of hydraulically fractured wells on this type of laumontite-rich tight glutenite reservoir typically resulted in low oil productivity and quickly declining oil rates. To understand the poor well performance of these laumontite-rich tight oil wells, extensive laboratory and numerical simulation studies have been conducted to explore the major controlling factors. Laboratory results indicate that the laumontite-rich glutenite reservoir rock has the following characteristics: 1) reservoir permeability is sensitive to stress conditions; 2) reservoir rock has low mechanical strength; and 3) reservoir rock has a low elastic modulus. These geomechanical deformation characteristics strongly affect the well productivity on the laumontite-rich formations. During the hydraulic fracturing and well production phases, the reservoir rock near the main hydraulic fracture can be compacted significantly to reduce rock porosity and permeability. As a result, the fluid flow capacity from the reservoir rock into the hydraulic fracture is reduced. By using laboratory testing data, fully coupled flow-deformation finite element simulations were conducted to study the impact of rock compaction/dilation on well productivity. Based on the numerical simulations, a new hydraulic fracturing scheme was proposed, and a field pilot test was conducted on one vertical well in the study area. Promising field oil production rates were achieved. This paper presents our understanding of the laboratory data, numerical simulation, and field pilot tests results. The new hydraulic fracturing scheme was based on the rock dilation near the main hydraulic fracture. The result indicates that rock dilation, if proactively utilized, can enhance the fluid deliverability from the reservoir into the main hydraulic fracture and boost well productivity.",8,8,3
Fracture,Stress Sensitivity,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Fracture,Stress Sensitivity,"Shao, Jiaxin; You, Lijun; Kang, Yili; Gao, Xinping; Chen, Mingjun; Meng, Sen; Zhang, Nan",Experimental study on stress sensitivity of underground gas storage,Underground gas storage; Effective stress; Pressure gradient; Stress sensitivity; Effective stress action time,TRANSPORT BEHAVIOR; PERMEABILITY; MULTISCALE; MECHANISM; BASIN,"The increase in effective stress and effective stress action time reduces the permeability of rock fractures. XG underground gas storage systems are constructed in carbonate formations. Fractures constitute the main seepage channel of pore-fracture carbonate formation. Alternating stress during multi-cycle injection-production of underground gas storage causes the fractures to open and close periodically. This leads to stress sensitivity of the formation and reduces the permeability of rock fractures. In this work, typical rock samples of carbonate formation in XG underground gas storage were selected as the research object, and stress sensitivity experiments, gas speed sensitivity experiments and stress sensitivity experiments considering effective stress action time were carried out. The rock sample permeability during the experiment was measured. The fracture walls of rock samples before and after the stress sensitivity experiments and stress sensitivity experiment considering the effective stress action time were analyzed by SEM. The influence mechanism of effective stress and effective stress action time on permeability of underground gas storage was explored. Stress sensitivity coefficient method was used to evaluate stress sensitivity. The results show that the stress sensitivity of fracture and matrix samples considering effective stress action time was enhanced compared with stress sensitivity experiments. With the increase in effective stress action time, the elastic-plastic deformation of rock increased the breaking of microconvex bodies on the fracture wall. Moreover, micro-fractures were generated to reduce rock strength. The breaking of micro-convex bodies and the generation of micro-fractures strengthened the stress sensitivity of rocks. Moreover, fine migration caused by excessive injection-production pressure gradient also increased the stress sensitivity.",7,7,5
Fracture,High Temperature,"Yang, Yun; Liu, Shimin",Laboratory study of cryogenic treatment induced pore-scale structural alterations of Illinois coal and their implications on gas sorption and diffusion behaviors,Cryogenic fracturing; CBM stimulation; Diffusion coefficient; Sorption isotherm,WAALS ADSORPTION-ISOTHERMS; NITROGEN FREEZE-THAW; LIQUID-NITROGEN; SURFACE-DIFFUSION; SIZE DISTRIBUTION; STRUCTURE DAMAGE; CARBON-DIOXIDE; METHANE; HYSTERESIS; DESORPTION,"Cryogenic fracturing using liquid nitrogen is a choice for CBM reservoir stimulation. However, the development of cryogenic fracturing is still at its infancy. This work focused on induced pore structural alterations due to cryogenic treatment and their effects on gas sorption and diffusion behaviors. The changes in the pore structure of coal induced by cyclic nitrogen injections were studied by physical adsorption at low temperatures. A micromechanical model is proposed to simulate the microscopic process and predict the degree of deterioration due to low temperature treatments. As a common characteristic of modeled results and experimental results, the total volume of mesopore and macropore increased with cryogenic treatment, but the growth rate of pore volume became much smaller as freezing-thawing were repeated. Pores of different sizes experienced different degrees of deterioration. In the range of micropores, no significant alteration of pore volume occurred with the repetition of freezing and thawing. In the range of mesopores, pore volume increased with the repetition of freezing and thawing. In the range of macropores, pore volume increased after the first cycle of freezing and thawing but decreased after three cycles of freezing and thawing. Because of pore structural alteration, cryogenic treatment enhanced gas transport process as the diffusion coefficients of the freeze-thawed coal samples were increased by 18.76% and 30.18% in the adsorption and desorption process. The effect of cyclic cryogenic treatment on the pore structure of tested coal varied depending on coal properties. For the studied Illinois coal sample, repetitive applications of cryogenic treatment reduced macropore volume and increase mesopore volume. For the tested sample, the diffusion coefficient of the coal sample that underwent three cycles of freezing-thawing was lower than that of the coal sample that underwent a single cycle of freezing and thawing. The outcome of this study provides justification for a post-cryogenic fracturing effect on diffusion improvement and gas production enhancement, especially for high ""sorption time"" CBM reservoirs.",14,14,17
Fracture,High Temperature,"Wang, Jie; Huang, Yixiao; Zhang, Yan; Zhou, Fujian; Yao, Erdong; Wang, Rui",Study of Fracturing Fluid on Gel Breaking Performance and Damage to fracture conductivity,Gel breaking of fracturing fluid; Fracturing fluid residue; Proppant crush; Proppant embedding; Conductivity,FLOW; BEHAVIOR; MODEL,"As a thickening agent commonly used in hydraulic fracturing, guar gum has the advantage of low price and excellent performance. However, the gel breaking mechanism of fracturing fluid under high temperature and high pressure environment and the damage mechanism to the reservoir needs further study. The current criteria for judging gel breaking is based on the viscosity of the solution being less than 5 mPa s, however it's not always true that the gel breaks even if the viscosity of the fluid is low. To solve this problem, it's recommended in this paper to analyze the gel breaking performance of fracturing fluid by measuring the median molecular particle size and the residue content together with the viscosity of fracturing fluid. Moreover, the effects of the gel breaker on the crushing and formation embedding of the proppant, the adsorption and retention mechanism of the residue in the induced fracture and their influence on the conductivity are investigated. Studies show that the gel breaking performance of guar gum fracturing fluid is affected by the amount of gel breaker and temperature. Adding extra amount of gel breaker and imposing high temperatures do not effectively reduce the median molecular particle size of the fracturing fluid. The detrimental effect of the gel breaker and it's residue to the fracture conductivity is mainly reflected in three aspects: increased crush rate of the proppant due to soaking in the gel breaker, exacerbated embedding of the proppant into formation due to interaction of the fluid and the formation and the reduced pore diameter of the formation due to residue of the fracturing fluid. It's observed that the detrimental effect of the gel breaker on the conductivity of the fracture is mostly in the area with a high closing pressure of 50 MPa or above. This study provides a reference of tight sandstone reservoirs hydraulic stimulation and fracturing fluid formation damage for high temperature and high pressure oilfields like Tarim oilfield.",10,11,14
Fracture,High Temperature,"Abalkhail, Nassir; Liyanage, Pathma Jith; Upamali, Karasinghe A. N.; Pope, Gary A.; Mohanty, Kishore K.",Alkaline-surfactant-polymer formulation development for a HTHS carbonate reservoir,Surfactant flooding; Enhanced oil recovery; Carbonate reservoir; High temperature; High salinity,MICROEMULSION PHASE; OIL,"There are many HTHS (high temperature, high salinity) carbonate reservoirs where temperature (>80 degrees C) and salinity (>30,000 ppm) are high. The goal of this study was to develop an alkaline-surfactant-polymer (ASP) formulation for a high temperature (similar to 100 degrees C), high salinity (similar to 60,000 ppm) giant carbonate reservoir with low surfactant retention, an essential requirement for low chemical cost. Phase behavior tests were conducted with anionic surfactants, alkali, co-solvents, brine, and crude oil to identify chemical formulations with ultra-low IFT under reservoir conditions. Corefloods were first conducted in outcrop carbonate cores and then in reservoir cores. The effluent was analyzed for oil, surfactant, pH, salinity and viscosity. Surfactant adsorption on carbonate surfaces decreases at high pH. Ammonia and a new organic alkali ethoxylated diisopropylamine (DIPA-10EO) were studied for this application since there is both anhydrite and dolomite in the formation. Sodium carbonate cannot be used as the alkali in rocks containing anhydrite, and sodium hydroxide cannot be used as the alkali in rocks containing dolomite. Ultralow IFT (similar to 0.001 mN/m) was achieved with several ASP formulations using the reservoir oil. The first three core floods in Indiana limestone yielded excellent tertiary oil recoveries of 85.2, 89.5 and 91.8%, and very low surfactant retentions of 0.06, 0.02, and 0.11 mg/g-rock, respectively. The reservoir coreflood resulted in 93.6% tertiary oil recovery and a final oil saturation of 1.2%. The surfactant retention was 0.083 mg/g-rock. The chemical formulation developed here is applicable to this high permeability, non-fractured, HTHS carbonate reservoir. Future research should address other carbonate reservoir issues such as fractures and low permeability.",9,9,1
Fracture,High Temperature,"Zhang, Zengzeng; Zhao, Dajun; Zhao, Yan; Zhou, Yu; Tang, Qiongqiong; Han, Junpeng",Simulation and experimental study on temperature and stress field of full-sized PDC bits in rock breaking process,Full-sized PDC bits; Temperature field; Stress field; Finite element simulation,THERMAL RESPONSE; CUTTERS; FORCE; WEAR; REDUCTION; FRACTURE; FATIGUE; SURFACE; STATE; MODEL,"The failure rate of polycrystalline diamond compact (PDC) bits mainly depended on the cutting temperature and the force of the cutting teeth. It was of great value to study the distribution of temperature and stress fields on the PDC cutting teeth during rock breaking for exploring the failure mechanism and improving the service life of the bits. In this paper, the finite element was used to simulate the thermal-structural coupling of rock breaking process of the full-sized PDC bits. The simulation results show that the high temperature region of the cutting teeth was offset from the top of the crown to the outside of the cutting teeth during drilling process, and the high temperature region of the cutting teeth was fan-shaped. The failure reason of PDC cutting teeth was analyzed by simulation. The maximum principal stress of PDC cutting teeth existed in the interface between the polycrystalline diamond (PCD) layer and the cemented carbide (WC-Co) substrate, fracture and delamination were concentrated at the top of the cutting teeth crown. The experimental results show that the temperature of cutting teeth when drilling the granite was about 2 times that of the marble and 3 times that of the sandstone under the same conditions. The simulation results were basically consistent with the experimental results, which verified the accuracy of the finite element model simulation analysis method.",8,9,11
Fracture,High Temperature,"Xiong, Chao; Huang, Zhongwei; Yang, Ruiyue; Sheng, Mao; Shi, Huaizhong; Dai, Xianwei; Wu, Xiaoguang; Zhang, Shikun",Comparative analysis cutting characteristics of stinger PDC cutter and conventional PDC cutter,Stinger PDC cutter; Cutting characteristics; Single cutter tests; Rock-breaking mechanism,ROCK; TEMPERATURE; BREAKING; GRANITE; SURFACE; FORCE,"The Stinger PDC cutter has a better performance than the conventional PDC cutter drilling for hard, interbedded and highly abrasive rocks. Although researchers have investigated the cutter's characteristic, such as impact resistance, wear resistance and cutter's life, the cutting behaviors of the Stinger PDC cutter still remains unclear. In this study, the single cutter tests were carried out with a Stinger PDC cutter and a conventional PDC cutter as comparisons. The cutting force, cuttings size, surface topography along the cutting trajectory and microscopic morphology of the fracture surface were compared and analyzed. The results show that the average cutting force of a Stinger PDC cutter is 46.14% lower than that of a conventional PDC cutter. The proportion of large cuttings (r > 2.36 mm) generated in the Stinger PDC cutter test is higher than that in the conventional PDC cutter test. In addition, the energy consumption of breaking rocks by a Stinger PDC cutter is 34.09% lower than that by a conventional PDC cutter. The cutting trajectory in the Stinger PDC cutter test has a ""V"" shape and the surface is relatively rough (Sa = 617.08 mu m), while the conventional PDC cutter produces a ""U"" shape cutting trajectory and the surface is relatively smooth (Sa = 462.18 mu m). Furthermore, the SEM analysis shows that the Stinger PDC cutter breaks granite mainly by tensile stress, which is different with the conventional PDC cutter by shear stress. The key findings of this work will help to reveal the rock-breaking process and mechanism with the Stinger PDC cutters.",8,8,7
Fracture,High Temperature,"Mehrabianfar, Parviz; Malmir, Pourya; Soulgani, Bahram Soltani; Hashemi, Abdolnabi",Study on the optimization of the performance of preformed particle gel (PPG) on the isolation of high permeable zone,Preformed particle gel (PPG); Water diversion; Fractured reservoir; Glass micromodel; Water control,WATER PRODUCTION COST; CONFORMANCE-CONTROL; TRANSPORT,"Unwanted water production is a critical problem in fractured reservoirs. Corrosion of facilities and reduction of oil relative permeability are some of the consequences of high water production. Preformed particle gel (PPG) injection is one of the conformance control methods, which initiated in 2007, has been used to control water production and increase sweep efficiency. There are several parameters which affect the performance of PPG such as stability at reservoir condition, salinity of makeup solution and PPG particle size and concentration. Although the study of the application of PPG in fracture plugging attracted a lot of attention in recent years, there are limited studies to investigate the effect of PPG physical properties on its application in water production control. In this study, the application of a super absorbent polymer on fracture plugging has been investigated. The results of swelling tests indicated that this type of PPG had significant high resistance even at high temperatures and wide range of salinities. In addition, the results of rheology tests showed that the PPG solution was stable even at high salinity and high shear rate condition. In order to study the mechanism of improvement of sweep efficiency through PPG injection, visual investigation using glass etched micromodel was performed. The results showed that the main mechanism for PPG treatment is water diversion into the low permeability zone as the consequence of fracture plugging. Also, core flooding tests were performed to check the performance of PPG in a heterogeneous carbonate porous media. According to the results, PPG was able to reduce the permeability, and this permeability reduction is related to swelling ratio which is controlled by makeup solution salinity. The results of this study revealed the potential of super absorbent polymers as preformed particle gel in unwanted water production through fracture plugging.",8,8,4
Fracture,Temporary Plugging,"Zhang, Ruxin; Hou, Bing; Tan, Peng; Muhadasi, Yeerfulati; Fu, Weineng; Dong, Xiaomu; Chen, Mian",Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing,Fracture propagation behavior; Temporary plugging agent; Fracture diversion pattern; Horizontal stress difference; 3D scanning,NUMERICAL-SIMULATION; INITIATION,"The exploitation of shale oil and gas has become commercial in the Sichuan basin, China. However, initial fracture closure will result in low production. Therefore, temporary plugging fracturing technology is proposed to create new fractures in alternate directions using a temporary plugging agent that blocks initial fractures, which will lead to a complex fracture morphology. The mechanism of temporary plugging and fracture propagation behavior remains ambiguous, even with many successful operations. Hence, five shale outcrops are used to conduct large-size true tri-axial temporary plugging fracturing simulation experiments to study the issues mentioned above. The effects of horizontal stress difference and temporary plugging agent amount on plugging effectiveness as well as fracture propagation behavior are discussed. The results reveal that the initial fractures are sealed successfully by a water soluble temporary plugging agent. Two plugging positions, fracture heel and tip, result in three main fracture diversion patterns: fracture diversion at the old fracture heel, fracture diversion inside the old fracture, and a new fracture induced at a new position. Based on the fracturing pressure curve, fracturing pressure in the second fracturing is higher than that of the first fracturing, which indicates effective plugging and fracture diversion. A large horizontal stress difference has prevented fracture diversion, and led to a small diversion angle. However, it has improved the induced fracture propagation length. Moreover, the temporary plugging agent amount determines the plugging position and fracture diversion pattern. Fracture diversion inside existing fractures is a result of a small amount sealing at the fracture tip. The other two patterns are created by a large amount of plugging at the fracture heel. Therefore, in order to achieve successful plugging effectiveness, it is necessary to conduct more experiments to optimize operation parameters according to the specific horizontal in-stress state.",13,13,6
Fracture,Temporary Plugging,"Shi, Xian; Zhang, Weidong; Xu, Hongxing; Xiao, Caiyun; Jiang, Shu",Experimental study of hydraulic fracture initiation and propagation in unconsolidated sand with the injection of temporary plugging agent,Unconsolidated sand; Plugging agent; Hydraulic fracturing; Acoustic emission; Fracture initiation,VERTICAL WELL; GAS,"High fluid leak-off rate and low pressurization rate are great challenges for hydraulic fracturing in unconsolidated sands. In this paper, the design of an injection plugging agent as a pad for fracture initiation aid in unconsolidated sands is presented. We have carried out tri-axial hydraulic fracturing tests, focusing on super-high- and high-permeability unconsolidated sands with AE (acoustic emission) monitoring. Powdered oil-soluble materials are used as temporary plugging agents. The laboratory tests demonstrated that three types of fracture geometry, multiple fracture, bi-wing fracture and single-wing fracture, are created. Furthermore, there are continuous AE energy signals with the increase of plugging agent injection, which is a good match with the fluctuated pressure. Moreover, multiple peak fracture points can be observed due to intense grains interaction. In addition, the breakdown pressure has positive relationships with the pump rate and concentration of injection of plugging agents. Multiple fractures only exist for super-high-permeability unconsolidated sands with high pumping rate and low plugging agent concentration, which is primarily due to the plugging agent seal for both hydraulic fracture and the rock matrix. A low injection rate with low plugging agent concentration led to single-wing fracture for high-permeability unconsolidated sands, whereas a high injection rate with high plugging agent concentration led to single-wing fracture for low-permeability unconsolidated sands. Low plugging agent concentration is beneficial for aiding hydraulic fracture propagation along the maximum horizontal stress direction. In addition, the high-pump-rate and low-plugging-agent-concentration scenario and low-pump-rate and highplugging-agent-concentration scenario have a greater chance of creating bi-wing fracture for super-high-permeability unconsolidated sands, whereas low pump rate and high plugging agent concentration are beneficial for bi-wing fracture for high-permeability unconsolidated sands. Local tortuous fracture path indicate tensile and fracture both exist during unconsolidated sands fracturing. With respect to sand control and large contact area, these treatments should be the better fracturing scenario for unconsolidated sand fracturing design with injection of a plugging agent. The findings of this study can help for better understanding of the fracturing mechanism and optimizing treatment parameters in unconsolidated sands fracturing.",12,11,4
Fracture,Temporary Plugging,"Zhang, Lufeng; Zhou, Fujian; Feng, Wei; Pournik, Maysam; Li, Zhun; Li, Xiuhui",Experimental study on plugging behavior of degradable fibers and particulates within acid-etched fracture,Temporary plugging; Degradable fibers and particulates; Diverting acid fracturing; 3D printing,SANDSTONE; MECHANISM; DESIGN; WATER,"As proven from field practices in North America and Northwest China, temporary plugging and diverting acid fracturing is an indispensable technology to enhance stimulation effect and hydrocarbon production of complex carbonate reservoirs. It's well-known that the key to the success of this technology lies in creating a temporary plugging within the previously created fractures. Consequently, many scholars have conducted laboratory experiments to investigate the plugging behavior of fibers and particulates. However, the current devices nearly have certain limitations in simulating temporary plugging experiments. Aiming at this problem, this paper introduced the fracture temporary plugging evaluation system with large fracture size, and high-pressure resistance, which can meet the requirement of temporary plugging experiment. In addition, 3D printing technology was used to reproduce the roughness of acid-etched fracture surface, improving the experimental accuracy. Based on the device, a series of experiments were performed to study the effect of carrier fluids type, the injection rate, the fracture width, and the fracture morphology on plugging behavior of fibers and particulates. Experimental results show that the plugging effect of HPG fracturing fluid is better than that of slick water. Moreover, the effect of temporary plugging deteriorates with the decrease of injection rate, which can be attributed to the fact that high injection rate increases the probability of bridging and plugging. When it comes to the fracture width, only fibers have favorable plugging effect under the condition of 2 mm fracture width. However, a single type of temporary plugging agent (only fibers or particulates) cannot achieve effective plugging under the condition of 4 mm fracture width. The combination of fibers and particulates can obtain favorable plugging effect. When the fracture width increases to 6 mm, it's difficult to obtain favorable plugging effect if the diameter of particulates is less than 50% of fracture width. Hence, it is recommended to add big particulates whose diameters are at least 50% of the fracture width to improve the plugging effect. Moreover, the fracture surface morphology affects the formation time of temporary plugging, but does not affect whether temporary plugging is formed or not. This study deepens the understanding the plugging behavior of fibers and particulates within acid-etched fracture and provides fundamental for field treatment design.",11,13,8
Fracture,PDC Cutter,"Zhang, Zengzeng; Zhao, Dajun; Zhao, Yan; Zhou, Yu; Tang, Qiongqiong; Han, Junpeng",Simulation and experimental study on temperature and stress field of full-sized PDC bits in rock breaking process,Full-sized PDC bits; Temperature field; Stress field; Finite element simulation,THERMAL RESPONSE; CUTTERS; FORCE; WEAR; REDUCTION; FRACTURE; FATIGUE; SURFACE; STATE; MODEL,"The failure rate of polycrystalline diamond compact (PDC) bits mainly depended on the cutting temperature and the force of the cutting teeth. It was of great value to study the distribution of temperature and stress fields on the PDC cutting teeth during rock breaking for exploring the failure mechanism and improving the service life of the bits. In this paper, the finite element was used to simulate the thermal-structural coupling of rock breaking process of the full-sized PDC bits. The simulation results show that the high temperature region of the cutting teeth was offset from the top of the crown to the outside of the cutting teeth during drilling process, and the high temperature region of the cutting teeth was fan-shaped. The failure reason of PDC cutting teeth was analyzed by simulation. The maximum principal stress of PDC cutting teeth existed in the interface between the polycrystalline diamond (PCD) layer and the cemented carbide (WC-Co) substrate, fracture and delamination were concentrated at the top of the cutting teeth crown. The experimental results show that the temperature of cutting teeth when drilling the granite was about 2 times that of the marble and 3 times that of the sandstone under the same conditions. The simulation results were basically consistent with the experimental results, which verified the accuracy of the finite element model simulation analysis method.",8,9,11
Fracture,PDC Cutter,"Xiong, Chao; Huang, Zhongwei; Yang, Ruiyue; Sheng, Mao; Shi, Huaizhong; Dai, Xianwei; Wu, Xiaoguang; Zhang, Shikun",Comparative analysis cutting characteristics of stinger PDC cutter and conventional PDC cutter,Stinger PDC cutter; Cutting characteristics; Single cutter tests; Rock-breaking mechanism,ROCK; TEMPERATURE; BREAKING; GRANITE; SURFACE; FORCE,"The Stinger PDC cutter has a better performance than the conventional PDC cutter drilling for hard, interbedded and highly abrasive rocks. Although researchers have investigated the cutter's characteristic, such as impact resistance, wear resistance and cutter's life, the cutting behaviors of the Stinger PDC cutter still remains unclear. In this study, the single cutter tests were carried out with a Stinger PDC cutter and a conventional PDC cutter as comparisons. The cutting force, cuttings size, surface topography along the cutting trajectory and microscopic morphology of the fracture surface were compared and analyzed. The results show that the average cutting force of a Stinger PDC cutter is 46.14% lower than that of a conventional PDC cutter. The proportion of large cuttings (r > 2.36 mm) generated in the Stinger PDC cutter test is higher than that in the conventional PDC cutter test. In addition, the energy consumption of breaking rocks by a Stinger PDC cutter is 34.09% lower than that by a conventional PDC cutter. The cutting trajectory in the Stinger PDC cutter test has a ""V"" shape and the surface is relatively rough (Sa = 617.08 mu m), while the conventional PDC cutter produces a ""U"" shape cutting trajectory and the surface is relatively smooth (Sa = 462.18 mu m). Furthermore, the SEM analysis shows that the Stinger PDC cutter breaks granite mainly by tensile stress, which is different with the conventional PDC cutter by shear stress. The key findings of this work will help to reveal the rock-breaking process and mechanism with the Stinger PDC cutters.",8,8,7
Oil Recovery,Interfacial Tension,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Water-oil interfacial tension (IFT) reduction and wettability alteration in surfactant flooding process using extracted saponin from Anabasis Setifera plant,Surfactant flooding; Saponin; Interfacial tension (IFT); Wettability alteration; Chemical enhanced oil recovery; Anabasis Setifera,DISSOLVED CARBON-DIOXIDE; LEAF-DERIVED SURFACTANTS; SMART WATER; POROUS-MEDIA; CO2 FOAM; RECOVERY; IONS; INJECTION; RESERVOIR; EMULSIFICATION,"Surfactants are known as interfacial tension (IFT) reducer additives in enhanced oil recovery (EOR) process. The use of chemical surfactants has always been a challenge due to the high cost of materials and sometimes noncompliance with the environment. Hence, researchers are looking for alternative ways to make them cheap and affordable. Herbal extracts that combine some surfactants, such as saponins, are a new source for replacing with expensive chemical surfactants. In this study, Anabasis Setifera plant was used as a source of natural surfactant supply. Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance ((HNMR)-H-1) and thermal gravimetric analysis (TGA) were performed to characterize and determine the temperature stability, as well as surface tension tests for estimating the critical micelle concentration (CMC) of saponin extracted from Anabasis Setifera. In addition, pendant drop water-oil IFT test, contact angle test, and flooding of surfactant solution at CMC and optimum salinity were performed to study the application of the natural surfactant in EOR process. The effects of NaCl, KCl, CaCl2, MgCl2, FeSO4, K2SO4 and NaHCO3 salts and formation water salinity were investigated at different concentrations on the IFT and contact angle. The results show that the surfactant is more effective than conventional plant extracts and in combination with chemical surfactants and an IFT value of 1.066 mN/m was obtained at CMC. The contact angle tests also show the capability of this surfactant to alter the wettability to a poor water-wetting (a contact angle of 56.51. Ultimately, an oil recovery of 15.4% was obtained by flooding of the surfactant solution at CMC and optimum formation water salinity.",37,37,18
Oil Recovery,Interfacial Tension,"Rahimi, Ali; Honarvar, Bizhan; Safari, Mehdi",The role of salinity and aging time on carbonate reservoir in low salinity seawater and smart seawater flooding,Smart water; IFT reduction; Aging time; Wettability; Low salinity,DYNAMIC INTERFACIAL-TENSION; ENHANCED OIL-RECOVERY; DETERMINING IONS CA2+; WETTABILITY ALTERATION; WATER INJECTION; SPONTANEOUS IMBIBITION; FATTY-ACIDS; IMPACT; ADSORPTION; CALCITE,"Although the terms Low Salinity Sea Water and Smart Sea Water have been used interchangeably as one of Enhanced Oil Recovery methods in recent years, the present study shows that there are some differences between these two. To prove the claim, the role of salinity and aging time on interfacial tension reduction and contact angle alteration of a crude oil/brine/rock system is investigated using both smart sea water and low salinity sea water. Moreover, the governing mechanisms of the IFT variation and wettability alteration are discussed. For this purpose, the seawater solution is diluted with distilled water and at the optimal salinity NaCl, CaCl2, and Na2SO4 salts are added to the solution. Next, the IFT of brine and oil, and the CA of the oil drop are measured on the carbonate surface in the presence of brine. The results showed that IFT between low salinity sea water and oil was decreased with increasing salinity and then increased. In this regard, similar results were observed by adding NaCl, CaCl2, and Na2SO4 to a low salinity seawater (LSSW) solution. Additionally, reducing seawater salinity improved the wettability from oil-wet to neutral wet such that the optimum wettability range was achieved by adding Na2SO4 to the LSSW solution. The effect of aging time in the low salinity sea water solution and smart sea water resulted in a reduction in the interfacial tension and the contact angle, as well as improving the crude oil/brine/rock interface. The mechanisms governing the reduction of the interfacial tension of low salinity sea water and smart sea water were surface excess concentration, salting in effect, and boiling point reduction, while the dominant mechanism for changing the wettability of low salinity water and smart sea water were the pH rise, pseudo-alkaline behavior, double layer increase, carbonate surface dissolution and salting in effect.",29,29,1
Oil Recovery,Interfacial Tension,"Chaturvedi, Krishna Raghav; Sharma, Tushar",Carbonated polymeric nanofluids for enhanced oil recovery from sandstone reservoir,Carbonated water injection; CO2 absorption; Enhanced oil recovery; Nanofluid; Polymeric nanoparticle suspension; Sandstone,WATER INJECTION; DEPLETION FLOCCULATION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSION; SILICA NANOFLUIDS; CO2 SOLUBILITY; NANOPARTICLES; SURFACTANT; STABILITY,"Polymeric nanoparticle (NP) suspensions are colloidal suspensions where NPs (size <= 100 nm) are suspended in the polymer-enhanced base fluid, mainly water. Compared to water or sole polymer solutions, they exhibit superior rheological, mass transfer, and heat tolerance attributes. While the use of polymeric NP suspensions as injection fluids for enhanced oil recovery has been explored in past studies, their use as carrier fluids for CO2-loaded (carbonated) water injection has not been explored to date. Thus, this study explores the use of polymeric NP suspensions prepared using SiO2, ZnO, and TiO2 nanoparticles of varying concentration for CO2 loading and their use as carbonated fluids for enhanced oil recovery from sand-packs mimicking a sandstone reservoir. It was observed that the use of nanoparticles improved CO2 absorption in the base fluid, water by a significant margin (approximate to 8-23%). The inclusion of salt (3 wt% NaCl) induced aggregation in NP suspensions and reduced their CO2 loading capacity. When used for flooding, the carbonated polymeric NP suspensions exhibited superior oil mobilization than their non-carbonated peers resulting in more oil produced even at a higher temperature and salinity (additional 12-20% of OOIP). Increasing temperature reduced the loading (absorption) of CO2 and oil recovery effectiveness of the polymeric NP suspensions while salt majorly impacted oil recovery efficiency under the investigated conditions. Based on the results obtained in this study, the use of 0.1 wt% SiO2 NPs has been recommended as the ideal concentration for use in carbonated water injection.",21,21,3
Oil Recovery,Interfacial Tension,"Wang, Yanwei; Liu, Huiqing; Zhang, Qichen; Chen, Zhangxin; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Pore-scale experimental study on EOR mechanisms of combining thermal and chemical flooding in heavy oil reservoirs,Viscosity reducer; Steam flooding; Foam; Visualized experiments; Mechanisms analysis,CYCLIC STEAM STIMULATION; CRUDE-OIL; VISCOSITY REDUCTION; FOAM-GENERATION; RECOVERY; EMULSIONS; INJECTION; FLOW; ASPHALTENE; RHEOLOGY,"Steam flooding is an important method for the development of heavy oil reservoirs, but steam channeling is an inevitable serious problem in the process of steam injection, which decreases the sweep efficiency of steam and leads to low oil recovery. Viscosity reducer (VR) flooding and nitrogen foam flooding are two effective methods of enhancing heavy oil recovery with satisfactory results. In this paper, a series of experiments were conducted to evaluate the effects of various factors on the performance of the novel viscosity reducer (VR-A). On this basis, A visualized model was adopted to investigate the synergistic development effect of thermal and chemical flooding, which vividly reflected the interaction of chemical agents with crude oil and their migration characteristics in porous media, as well as the mechanisms of enhancing oil recovery on the pore-scale. The results showed that VR-A could achieve excellent viscosity reduction effect on heavy oil under the influence of various factors, which could be combined with thermal flooding to effectively recover heavy oil. As for the pore-scale level, after the VR-A solution was injected, the interfacial tension between the oil and water was decreased, the wettability of the surface of the particle was changed, and two types of oil-in-water emulsions (spherical emulsions and flocculent emulsions) with a lower viscosity were formed, which were easy to flow with the fluid in pores and throats and could temporarily block the high-permeability area. In the process of foam flooding, the phenomena of bubble coalescence and breakup occurred constantly, and bubbles trapped in the porous media could improve the sweep efficiency of the subsequent fluid. The ultimate oil recovery of the development method combining thermal and chemical flooding in the visualized displacement experiment is 76.9%, 39.7% higher than that of pure thermal flooding. This article can provide an effective method to solve the problem of poor steam flooding performance in heavy oil reservoirs.",19,20,8
Oil Recovery,Interfacial Tension,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Syed, Asad Hassan; Sevoo, Thenesh; Kanesen, Kamalarasan","Synergistic influence of nanoparticles and surfactants on interfacial tension reduction, wettability alteration and stabilization of oil-in-water emulsion",Nanoparticles; Surfactants; Interfacial properties; Micro-pores; Dead-end pores; Emulsion,METAL-OXIDE NANOPARTICLES; WALLED CARBON NANOTUBES; SILICON DIOXIDE; FOAM STABILITY; ADSORPTION; RECOVERY; NANOFLUIDS; DISPERSION; SALINITY; BEHAVIOR,"In this study, the synergistic interaction of nanoparticles and surfactants were explored for oil-water interfacial tension (IFT) reduction, alteration of rock wettability, and stabilization of oil-in-water emulsion. The interfacial properties were investigated using drop-shape analyzer (DSA 25) while the pore scale visualization studies were conducted using the etched glass micromodels. The most stable surfactant-stabilized emulsion was formed in presence of cetyltrimethylammonium bromide (CTAB) while the order of increasing emulsion stability in presence of nanoparticles was obtained as follows: carbon nanotubes > copper oxide > silicon dioxide > aluminum oxide > titanium dioxide. Compared to pure nanofluids or surfactant solutions, the nanoparticles-surfactant solutions demonstrated promising tendency for significant reduction in oil-water interfacial tension and alteration of rock wetting properties. Specifically, the carbon nanotubes (CN) based nanofluids, reduced the contact angle of the rock from 68.73 degrees to 65.5 degrees (4.7%) while the Triton X-100 (TX 100) and CN-TX100 solutions reduced the contact angles to 10.65 degrees (84.5%) and 7.0 degrees (89.8%) respectively. The dominant mechanism of resident oil mobilization from the micro and dead-end pores was identified as emulsification-entrainment. A correlation exists between influence of nanoparticles-surfactant solutions on interfacial properties and resident oil mobilization from the micro and dead-end pores. The CN-CTAB solution that was the most effective in mobilization of the resident oil from the micro and dead-end pores significantly reduced the crude oil-water IFT to 0.63 mN/m. The mechanisms of IFT reduction, wetting properties alteration, as well as emulsion stabilization have been identified as the orientation of the particles at the interface and the electrostatic interaction between the nanoparticles and surfactant molecules. These procedures could be exploited to achieve significant reduction in IFT, rock wettability alteration and emulsion stabilization than could be achieved using pure nanofluids or surfactant solutions only.",18,17,8
Oil Recovery,Interfacial Tension,"Wijaya, Nur; Sheng, James J.",Mitigating near-fracture blockage and enhancing oil recovery in tight reservoirs by adding surfactants in hydraulic fracturing fluid,Surfactant; Water blockage; Invasion fluid; Flowback; Interfacial tension; Wettability alteration,CALCIUM ALGINATE BEADS; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; WATER BLOCKING; IFT REDUCTION; FLOW; GAS,"Flowback after hydraulic fracturing consistently shows a significantly poor load recovery of the fracturing fluid. The unrecovered fluid creates a blockage at the matrix-fracture interface in the reservoir, which hinders the optimum hydrocarbon production. Surfactant, added into the fracturing fluid, is believed to minimize this blockage by reducing the oil-water interfacial tension (IFT) and altering the rock wettability. Although many lab and field data have shown the surfactant benefits, there is a lack of mechanistic analysis on how surfactant more effectively removes such blockage. Therefore, this paper presents a mechanistic study of water blockage removal by surfactant. Interfacial tension (IFT) reduction and wettability alteration effect are modeled to represent the main effects induced due to the surfactant addition. Our numerical model is extensively calibrated with computed tomography (CT) scans and pressure drop data during coreflood experiments. Our model shows that surfactant addition into the fracturing fluid results in a better water blockage removal than fracturing water alone, because surfactant results not only in a shallower invasion depth, but also a much milder blockage within the shallower invasion depth itself. Furthermore, our model also discovers that the restoration of hydrocarbon permeability by surfactant could demonstrate a time-dependent behavior, based on the interplaying effects among IFT reduction, fracture clean-up state, and the wettability of the matrix-fracture interface. Overall, by presenting the mechanistic analysis, this study serves as a crucial step toward the optimization of surfactant formulation for fracturing fluid and EOR applications in tight reservoirs.",14,14,8
Oil Recovery,Interfacial Tension,"Mpelwa, Musa; Tang, Shanfa; Jin, Lijun; Hu, Ruizhi; Wang, Changquan; Hu, Yang",The study on the properties of the newly extended Gemini surfactants and their application potentials in the petroleum industry,Chemical EOR; Gemini surfactant; Interfacial tension; Rheological behavior; Corrosion inhibition,ENHANCED OIL-RECOVERY; ULTRALOW INTERFACIAL-TENSION; CORROSION-INHIBITORS; PERFORMANCE; BEHAVIOR; SPACER; TEMPERATURE; ADSORPTION; STEEL,"In this study, the newly extended Gemini surfactants (EGSs) were studied as potential candidates in the petroleum industry applications. The performances of EGSs with respect to variant spacer lengths were studied through surface tension, conductivity, dynamic light scattering (DLS), interfacial tension, rheological behavior, field emission electron microscopy (FESEM), core flooding, and corrosion inhibition measurements. The surface pressure (pi(CMC)), surface efficiency (pC(20)), critical micelle concentration (CMC), maximum surface excess concentration (Gamma(max)), minimum area per molecule of surfactant at the air-water interface (A(min)), average the degree of counterion binding to micelle (beta), Gibb's free energy of micellization (Delta G(mic)), and Gibb's free energy of adsorption (Delta G(ads)) of the EGSs were determined from surface tension and conductivity data. The results showed that the EGSs exhibited more surface activity properties, low CMCs, and spontaneously adsorbed at the air-water interface and micellized in the bulk aqueous phase. The surfactants reduced the oil-water interfacial tension (IFT) to ultralow values (10(-3) mN/m) at low concentration, and it decreased substantively to very ultralow values (10(-4) mN/m) due to the addition of inorganic salts. Also, they exhibited fascinating viscosifying effect and viscoelastic behavior at the experimental temperatures (30 degrees C-60 degrees C). The rheological behaviors were influenced by the formation of entangled micelles in aqueous solutions. Furthermore, through core flooding, EGS1 increased oil recovery by 12.30% which is an interesting incremental recovery. Besides, the EGSs surfactants showed high anticorrosion efficacy on A3 carbon steel in 1 M HCl aqueous solution and the inhibitive action mechanism was revealed to be by creating a protective film on the carbon steel surface through physisorption. Overall, the surface activity, interfacial activity, rheological behaviors, and anticorrosion property were dependent on the length of the spacer group. The surfactants, particularly EGS1 demonstrated a more promising interfacial activity and rheological behavior for enhanced oil recovery (EOR) in heterogeneity reservoirs as well as a remarkable anticorrosion property.",13,13,1
Oil Recovery,Interfacial Tension,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Oil Recovery,Interfacial Tension,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Oil Recovery,Interfacial Tension,"Bruns, Fritjof; Babadagli, Tayfun",Heavy-oil recovery improvement by additives to steam injection: Identifying underlying mechanisms and chemical selection through visual experiments,Steam additives; Surfactants and solvents; Nanofluids and ionic liquids; Gravity and viscous displacement; Visual 2D experiments,,"To mimic the gravity assisted drainage and flooding type, steam displacement tests we performed previously (Bruns and Babadagli, 2017) on cores saturated with 27,000 cP heavy-crude-oil; a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. The majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, anionic surfactant (linear toluene sulfonate), non-ionic surfactants, biodiesel (thermally stable surface active agents), solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at a constant rate and pressure after being vaporized in an oven along with steam; the whole process was recorded with a camera. The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface and were observed to be the main reason for positive contribution of chemicals. Biodiesel exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the linear toluene sulfonate (LTS) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep). Non-ionic surfactants showed different emulsion capabilities and high efficiency in steam/condensate displacement with a higher HLB (hydrophile - lipophile balance) value.",12,12,3
Oil Recovery,Interfacial Tension,"Datta, Poulami; Tiwari, Pankaj; Pandey, Lalit M.",Oil washing proficiency of biosurfactant produced by isolated Bacillus tequilensis MK 729017 from Assam reservoir soil,Biosurfactant production; Optimization; Wetting; Surface tension; Oil washing efficiency; Emulsion,CELL-SURFACE HYDROPHOBICITY; CRUDE-OIL; INTERFACIAL-TENSION; RAPID IDENTIFICATION; RECOVERY; OPTIMIZATION; WETTABILITY; STRAIN; WATER; MEOR,"The present study describes elaborately the isolation of a potential biosurfactant producing and crude oil degrading strains isolated from the reservoir soil of Assam oil reservoir field. The produced biosurfactant was chemically characterized for its applicability for the enhanced oil recovery applications in terms of wetting, interfacial tension (IFT) and oil washing. From the seven isolated strains, Bacillus tequilensis MK 729017 was chosen based on the better surface active properties as it reduced the surface tension to 30 +/- 2 mN/m along with a moderate emulsification index of 66 +/- 2%. The produced biosurfactant was chemically identified to be lipopeptide, surfactin with a lower critical micelle concentration value of 90 mg/L. The carbon source and environmental parameters were optimized for the maximum concentration of the biosurfactant using response surface methodology based on the central composite design (RSM-CCD). The maximum biosurfactant concentration was measured to be 7.46 +/- 0.39 g/L and Y-PS was determined as 0.45. The specific growth rate of the isolate was 0.15 +/- 0.01 h(-1) and Y-XS was estimated as 0.1. The produced biosurfactant was also found to be thermal and colloidal stable. The biosurfactant solutions altered wettability of hydrophobic rock surface from 90 +/- 1 degrees to 26 +/- 1 degrees indicating a better interfacial interaction. The IFT of the produced biosurfactant was found to be 0.32 +/- 0.02 mN/m. The oil washing efficiency (80 +/- 2%) of the produced surfactin was comparable with chemical surfactants and the process involved two-step: initial a faster (surface) washing followed by a slower (internal) washing. The first process was dependent on micelle sizes, while the latter was dependent on water-oil emulsion size. The lower emulsion size of surfactin contributed to a greater internal washing as compared to chemical surfactants.",12,12,2
Oil Recovery,Interfacial Tension,"Arab, Danial; Kantzas, Apostolos; Bryant, Steven L.",Water flooding of oil reservoirs: Effect of oil viscosity and injection velocity on the interplay between capillary and viscous forces,Unconventional heavy oil; Conventional light oil; Water flooding; Instability analysis; Viscous fingering,HEAVY-OIL; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; EXPERIMENTAL-VERIFICATION; INSTABILITY THEORY; WETTABILITY; RECOVERY; DISPLACEMENT; SATURATION; PERMEABILITY,"Water flooding is the most widely applied recovery process in both conventional and heavy oil reservoirs. It is generally accepted that theories explaining water flooding performance in light oil reservoirs are not applicable to heavy oil reservoirs. Nonetheless, there is a lack of a systematic study discussing the underlying mechanisms of water flooding in heavy oil systems. This article presents findings of water flooding experiments and discusses the interplay between viscous and capillary forces as a function of oil viscosity and injection velocity. Experimental data of 178 core floods were used to develop a new dimensionless capillary number, N-Ca = (mu V-w(w)/sigma Cos theta phi)(0.26) (mu(w)/mu(o))(0.50) (K/LD)(0.18), which is useful in predicting water flood performance for a wide range of oil to water viscosity ratio up to 15,000. This scaling parameter along with the Peters and Flock's (Peters and Flock, 1981) instability number were used to map the interplay between capillary and viscous forces. It was found that there is a critical oil to water viscosity ratio (<= 20) below which the flow is stable (having instability numbers below a critical value) and viscous-dominant. In these cases, breakthrough oil recovery monotonically increases with increasing injection velocity. For viscous oils with viscosity of greater than 160 mPa s, flow is identified as pseudo-stable flow with instability numbers above a critical instability number. In these cases, breakthrough oil recovery is almost independent of injection velocity. In intermediate oil to water viscosity ratio of 20-160, breakthrough oil recovery increases with decreasing injection velocity, suggesting the flow regime is capillary-dominant. In these cases, imbibition activated at slower velocities has been identified as the main mechanism responsible for incremental oil recovery. In viscous oil systems (160 < mu(o) < 15,000), late time oil recovery monotonically increases with decreasing injection velocity. This increase in oil recovery is more pronounced in more viscous oil systems suggesting the importance of capillary forces in these systems. Results of this study suggest some new insights on the mechanisms of water flooding as a cost effective non-thermal EOR technique and how this can be very different in light oil systems compared to heavy oil reservoirs.",11,11,5
Oil Recovery,Interfacial Tension,"Das, A.; Nguyen, N.; Farajzadeh, R.; Southwick, J. G.; Vincent-Bonnieu, S.; Khaburi, S.; Al Kindi, A.; Nguyen, Quoc P.","Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs",Enhanced oil recovery; Foam; Microemulsion; Carbonate; High salinity; Low permeability,ADSORPTION; OIL,"Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging. In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 degrees C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.",10,10,7
Oil Recovery,Interfacial Tension,"Jafarbeigi, Ehsan; Kamari, Ehsan; Salimi, Farhad; Mohammadidoust, Akbar",Experimental study of the effects of a novel nanoparticle on enhanced oil recovery in carbonate porous media,Interfacial tension (IFT); Nanofluid flooding; Wettability alteration; Contact angle; Enhanced oil recovery (EOR),WETTABILITY ALTERATION; INTERFACIAL-TENSION; GRAPHENE OXIDE; SILICA NANOPARTICLES; SULFONATED GRAPHENE; WATER INJECTION; NANOFLUID; SALINITY; FUNCTIONALIZATION; ADSORPTION,"One of the effective methods in the process of enhancing the oil recovery from oil reservoirs is the use of nanotechnology. For this purpose, a new nanofluid was used to enhance the oil recovery from the reservoir at the scale of carbonate rocks. Finally, the obtained compound, in the first stage, nano-graphene oxide (NGO) were synthesized using Hummer's method and then they were subjected to surface modifications under new compounds. Finally, the obtained compound was known as (graphene oxide (N-(1-naphthyl) ethylenediamine)) (G-NEA), where G stands for graphene oxide (GO). Also, to determine the morphological characteristics and structure of the synthesized nanoparticles, Field Emission Scanning Electron Microscopy (FESEM), Fourier-transform infrared spectroscopy (FTIR), and Transmission electron microscopy (TEM) were performed. In addition, zeta-potential analysis was performed to investigate the stability of nanofluids at different pHs. In order to investigate the effect of nanofluids on oil recovery, three concentrations (200, 400, and 500 ppm) of G-NEA nanofluids were prepared. Also, the interfacial-tension (IFT) measurement and rock angle measurement in the presence of nanofluid were investigated using a pendant drop and sessile drop method, respectively. The coreflood experiment was performed to evaluate the effect of G-NEA nanofluid on carbonate plugs. The results showed that when the G-NEA nanofluid concentration increased, the IFT value of 19.34 (mN/m) for deionized water to 10.8 (mN/m) for 500 ppm G-NEA and the contact angle decreased from the initial value of 166 degrees to 40 degrees, indicating the tendency of the wettability alteration of the rock to a water-wet conditions. The results of the coreflood experiment showed that at 400 and 500 ppm concentrations, the G-NEA nanofluid enhanced the oil recovery by 23 and 15%, respectively. Therefore, this synthesized nanofluid can have an effective approach to drive the carbonate reservoir rock into a water-wet condition and enhance oil recovery.",9,9,6
Oil Recovery,Interfacial Tension,"Drexler, Santiago; Correia, Elton L.; Jerdy, Ana Carolina; Cavadas, Leandro A.; Couto, Paulo",Effect of CO2 on the dynamic and equilibrium interfacial tension between crude oil and formation brine for a deepwater Pre-salt field,Interfacial tension; CO2 flooding; Pre-salt reservoirs; WAG; Reservoir fluid characterization; Capillary forces; Dynamic IFT,ASPHALTENE; RESIN; SALINITY; SURFACTANT; SYSTEMS; PH,"Interfacial tension (IFT) between oil and brine is key to determine the Capillary Number, which governs capillary forces in the porous medium. As a result, changes in IFT affect the displacement efficiency and the residual oil saturation having direct impact on the Recovery Factor. Fluids in Pre-salt fields (offshore Brazil) have particular characteristics, such as high salinity in the brines, elevated content of asphaltenes and resins in the oils and high CO2 content in the produced gas for some fields. The effect of CO2 on the IFT depends on complex electrostatic and acid-base equilibria, and cannot be predicted by a single fluid property. This work presents the experimental study of the effect of CO2 dissolution on the IFT between a Pre-salt oil with a high total base number (TBN) and non-negligible total acid number (TAN) and a high salinity brine using the pendant drop technique. The oil and its asphaltenic fraction were characterized by Fourier-transform infrared spectroscopy, nuclear magnetic resonance spectroscopy, and elemental analysis identifying characteristic functional groups and indicating both acidic and basic polar functional groups. CO2 dissolution resulted in an IFT increase of 56% evidencing that, despite the high TBN of this oil, basic groups have low surface-activity. Moreover, a study of IFT as a function of pH showed that the maximum IFT was found in strongly acidic environments, but constant IFT values were obtained at neutral and basic pH values. Thus, the interfacial activity is governed by asphaltenes and resins with polar groups of varying acid/base behavior. The presence of CO2 also accelerated the dynamic behavior of IFT reducing the equilibrium time by 70%. This is caused by the reduction of oil viscosity, which impacts the relaxation time and enhances the diffusion of surface-active species towards the interface. The results in this work evidence that the CO2 content should be considered when modeling fluid properties for this type of reservoirs, as it affects the oil-brine IFT. In addition, for this oil with high content of surface-active compounds and non-negligible TAN and TBN, CO2 flooding does not contribute to reduce the IFT. Therefore, the efficiency of this Enhanced Oil Recovery technique in this type of field relies on viscosity reduction, miscible displacement and wettability alteration rather than IFT reduction.",9,10,4
Oil Recovery,Interfacial Tension,"Haq, Bashirul; Liu, Jishan; Liu, Keyu; Al Shehri, Dhafer",The role of biodegradable surfactant in microbial enhanced oil recovery,MEOR; Green surfactant; GEOR,INTERFACIAL-TENSION,"Many aerobic microorganisms can produce bio-surfactants which are capable of effectively reducing interfacial tensions between oil, water and rock. However, there are few publications on the production of bio-surfactants from anaerobic organisms. The combined effect of bio-surfactant, green surfactant and alcohol in the MEOR process, are not well understood yet and require further investigation. This experimental study was conducted to examine the effectiveness of combination of two microbial by-products, bio-surfactant and bio-alcohol, in recovering residual oil within the pores of rock. It also considered whether bio-surfactant capability could be improved by blending it with non-ionic green surfactant. Two formulations of surfactant and co-surfactant mixtures were selected for core-flood experiments based on phase behaviour study and IFT reduction to examine their potential for enhanced oil recovery. In the first formulation, JF-2 bio-surfactant was mixed with butanol; it was found that this formulation did not produce a significant quantity of incremental oil after water flooding. Lastly, a bio-surfactant (anionic) was blended with non-ionic green surfactant alkyl polyglucoside and butanol; this produced about 25% tertiary oil and 64% OIIP.",9,11,3
Oil Recovery,Interfacial Tension,"Kumar, Amit; Mandal, Ajay",Core-scale modelling and numerical simulation of zwitterionic surfactant flooding: Designing of chemical slug for enhanced oil recovery,Enhanced oil recovery; Zwitterionic surfactant; Core flooding; Simulation; CMG-STARS,,"Surfactant flooding is a proven enhanced oil recovery method for the recovery of trapped crude oil from the pores of the reservoir. In the present study, the applicability of a synthesized zwitterionic surfactant as an efficient EOR agent was tested, in terms of its interfacial tension reduction capability, emulsification behavior, and wettability modification behavior. Core flooding experiments conducted in sandstone core with the injection of 0.3 pore volume of chemical slug after water flooding showed 20% of additional oil recovery. The core flooding experiment was simulated using CMG-STARS simulator and history matching of relative permeability curve and its interpolation parameters were done. The validated model closely represented the experimental core flooding with very low error of 6%. The validated model helps in understanding the movement of crude oil and its interaction with the injected surfactant slug in the porous media. The validated model was further used for optimization of injected chemical slug by varying the parameters such as the surfactant concentration in the injected slug, the volume of injected chemical slug, and the injection rate of chemical slug. Each parameter had different effects on the oil recovery efficiency and cumulative oil recovery of more than 90% OOIP was obtained using model with injection of 1 PV of chemical slug containing 100 ppm of surfactant with the injection rate of 0.3 mL/min. The simulation of core flooding helped in optimization of crude oil production by zwitterionic surfactant and its implementation on field scale production by zwitterionic surfactant flooding.",8,8,4
Oil Recovery,Interfacial Tension,"Wijaya, Nur; Sheng, James J.",Optimum surfactant criteria for controlling invasion-induced water blockage in tight water-wet cores,Surfactant; Hydraulic fracturing; Flowback; Water blockage; Interfacial tension; Wettability alteration,ENHANCED SPONTANEOUS IMBIBITION; CALCIUM ALGINATE BEADS; WETTABILITY ALTERATION; IFT REDUCTION; OIL-RECOVERY; GAS SHALES; RESERVOIRS; FLOW; MECHANISMS; ADSORPTION,"Flowback after hydraulic fracturing shows a poor recovery of the fracturing fluid. The unrecovered fluid is believed to invade the matrix and creates a formation damage called water blockage, which affects the optimum oil production from the reservoir. Surfactant is often added into the fracturing fluid, because it can improve the recovery of the fracturing fluid, and hence minimum water blockage. This objective is achieved by the surfactant's interfacial tension (IFT) reduction and wettability alteration capabilities. This study investigates the optimum surfactant criteria, in terms of the IFT and wettability, to minimize the water blockage. From the perspective of regained oil relative permeability, our history-matched core-scale model reveals that the optimum criteria depend on the matrix capillarity. In conventional reservoirs, the optimum criteria are to select surfactants which offer ultralow IFT (even as low as 0.001 mN/m) and maintain the waterwetness of the rock. However, in tight reservoirs, the optimum criteria are surfactants which strongly alter the rock wettability to oil-wet, while the IFT requirement is more flexible (i.e., from 15 down to 0.001 mN/m). The contradicting optimum criteria can be explained by the relative dominance between relative permeability and capillary pressure. This study emphasizes that the optimum surfactant criteria for conventional reservoirs are not necessarily the same as those for tight reservoirs.",8,8,2
Oil Recovery,Interfacial Tension,"Agi, Augustine; Junin, Radzuan; Abdullah, Mohammed Omar; Jaafar, Mohd Zaidi; Arsad, Agus; Sulaiman, Wan Rosli Wan; Norddin, M. N. A. Mohd; Abdurrahman, Muslim; Abbas, Azza; Gbadamosi, Afeez; Azli, Nur Bashirah",Application of polymeric nanofluid in enhancing oil recovery at reservoir condition,EOR; Cissus populnea; IFT; Wettability; Ultrasound; Nanofluid,CRYSTALLINE STARCH NANOPARTICLES; INTERFACIAL-TENSION; SILICA NANOPARTICLE; GEMINI SURFACTANTS; ACID-HYDROLYSIS; TEMPERATURE; STABILITY; BEHAVIOR; ULTRASOUND; RHEOLOGY,"In this study, ascorbic acid was used to synthesize Cissus populnea nanoparticles (CPNP). The synthesized CPNP was isolated and the influence of the process variables on the physical properties were studied. The rheology of the formulated Cissus populnea nanofluid (CPNF) was measured and compared with Cissus populnea (CP) solution and commercial polymer xanthan. Moreover, the interfacial properties of CPNF were studied at various concentrations and temperatures, and the influence of salinity and their interaction with ultrasound was investigated. Sessile drop contact angle method was used to determine the wettability alteration efficiency of CPNF on an initially oil-wet sandstone core surface. Finally, CPNF and CP solutions were evaluated for EOR purposes at typical reservoir condition. The displacement process was scaled to reduce the number of parameters investigated using dimensionless parameters. The synthesis methods were efficient in generating sphere-shaped and elongated nanoparticles (50 nm mean diameter). Experimental results show that an increase in temperature of CP and CPNP yielded increased viscosity of the solutions in stark contrast to xanthan whose solution viscosity declines as the temperature increases. Besides, the CPNF was effective in lowering IFT at oil-water (O/W) interface and altered the wettability of the sandstone cores to water-wetting condition. The novel CPNF increased the oil recovery by 26% and was effective at high-temperature high-pressure (HTHP) reservoir condition. The result shows a transition from capillary dominated flow to gravity dominated flow as decrease in IFT decreased residual oil saturation and increased capillary and Bond number. The energy consumption and cost estimation of the proposed novel polymeric nanofluid shows it is cost-effective than conventional EOR chemicals.",8,8,2
Oil Recovery,Interfacial Tension,"Zhao, Han; Yang, Hongbin; Kang, Xin; Jiang, Haizhuang; Li, Menglan; Kang, Wanli; Sarsenbekuly, Bauyrzhan",Study on the types and formation mechanisms of residual oil after two surfactant imbibition,Imbibition; Surfactant; Micromodel; Residual oil; Interfacial film; Emulsion,POROUS-MEDIA; PORE-SCALE; SNAP-OFF; WATER; EMULSION; RECOVERY; WET; DISPLACEMENT; VISCOELASTICITY; PERFORMANCE,"For investigating the types and formation mechanisms of residual oil after surfactant imbibition, the easyemulsifying surfactant Sodium Dodecylbenzene Sulfonate (SDBS) and ultra-low interfacial tension surfactant Sodium Oleate (SOL) were selected. The visual micromodel was adopted to observe the oil morphologies, while the rheometer and the emulsion stability analyzer were applied to analyze formation mechanisms. According to micro experiments, the main types of residual oil after SDBS imbibition are columnar, cluster, blind-end and small drop residual oil whose structure was small fragmented droplet. As for SOL solution, they are mainly blindend and island residual oil. The formation mechanism of columnar and cluster residual oil is capillary force offsetting, the direction of capillary force forms the blind-end residual oil, while the Marangoni effect and snapoff effect are responsible for island residual oil. The small drop residual oil is from emulsification, which always appears at the intersection of multiple flows. The aromatic groups of SDBS can promote the emulsion more stable by increasing the strength of interfacial film, hence the small drop residual oil only exists after SDBS imbibition.",7,6,8
Oil Recovery,Interfacial Tension,"Kharazi, Mona; Saien, Javad; Yarie, Meysam; Zolfigol, Mohammad Ali","The superior effects of a long chain gemini ionic liquid on the interfacial tension, emulsification and oil displacement of crude oil-water",Gemini ionic liquids; EOR; Interfacial tension; Wettability; Emulsification; Frumkin model,ADSORPTION BEHAVIOR; MICELLE FORMATION; CONTACT-ANGLE; SURFACTANTS; RECOVERY; MICELLIZATION; CATALYST; SPACER,"Gemini ionic liquid (IL) type surfactants, with high interfacial activity and environment friendly nature have revealed desired potentials for enhanced oil recovery (EOR). In this study, a long chain gemini imidazolium IL, namely [C(12)im-C-4-imC(12)]Br-2, was synthesized and its effect on different properties of the crude oil-water system was investigated. Significant changes in the system interfacial tension (IFT), micellization, emulsification and wettability were observed. A drastic reduction in IFT under the IL bulk concentrations of less than 0.2 mol dm(-3) and achieving the ultra-low IFTs to about 8.2 x 10(-3) mN m(-1) (99.97% reduction) were appropriate. Increasing temperature (within 298.2-323.2 K) favored the function of the IL. Moreover, achieving stable emulsion of more than 52% after one week and oil displacement phenomenon at elevated IL concentrations were observed. Comparison of the results with two homolog shorter alkyl chain ILs, revealed the superior impact of the used IL. The Frumkin adsorption isotherm nicely reproduced the IFT data and the corresponding parameters as well as thermodynamic quantities were obtained.",7,7,5
Oil Recovery,Wettability Alteration,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Water-oil interfacial tension (IFT) reduction and wettability alteration in surfactant flooding process using extracted saponin from Anabasis Setifera plant,Surfactant flooding; Saponin; Interfacial tension (IFT); Wettability alteration; Chemical enhanced oil recovery; Anabasis Setifera,DISSOLVED CARBON-DIOXIDE; LEAF-DERIVED SURFACTANTS; SMART WATER; POROUS-MEDIA; CO2 FOAM; RECOVERY; IONS; INJECTION; RESERVOIR; EMULSIFICATION,"Surfactants are known as interfacial tension (IFT) reducer additives in enhanced oil recovery (EOR) process. The use of chemical surfactants has always been a challenge due to the high cost of materials and sometimes noncompliance with the environment. Hence, researchers are looking for alternative ways to make them cheap and affordable. Herbal extracts that combine some surfactants, such as saponins, are a new source for replacing with expensive chemical surfactants. In this study, Anabasis Setifera plant was used as a source of natural surfactant supply. Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance ((HNMR)-H-1) and thermal gravimetric analysis (TGA) were performed to characterize and determine the temperature stability, as well as surface tension tests for estimating the critical micelle concentration (CMC) of saponin extracted from Anabasis Setifera. In addition, pendant drop water-oil IFT test, contact angle test, and flooding of surfactant solution at CMC and optimum salinity were performed to study the application of the natural surfactant in EOR process. The effects of NaCl, KCl, CaCl2, MgCl2, FeSO4, K2SO4 and NaHCO3 salts and formation water salinity were investigated at different concentrations on the IFT and contact angle. The results show that the surfactant is more effective than conventional plant extracts and in combination with chemical surfactants and an IFT value of 1.066 mN/m was obtained at CMC. The contact angle tests also show the capability of this surfactant to alter the wettability to a poor water-wetting (a contact angle of 56.51. Ultimately, an oil recovery of 15.4% was obtained by flooding of the surfactant solution at CMC and optimum formation water salinity.",37,37,18
Oil Recovery,Wettability Alteration,"Rahimi, Ali; Honarvar, Bizhan; Safari, Mehdi",The role of salinity and aging time on carbonate reservoir in low salinity seawater and smart seawater flooding,Smart water; IFT reduction; Aging time; Wettability; Low salinity,DYNAMIC INTERFACIAL-TENSION; ENHANCED OIL-RECOVERY; DETERMINING IONS CA2+; WETTABILITY ALTERATION; WATER INJECTION; SPONTANEOUS IMBIBITION; FATTY-ACIDS; IMPACT; ADSORPTION; CALCITE,"Although the terms Low Salinity Sea Water and Smart Sea Water have been used interchangeably as one of Enhanced Oil Recovery methods in recent years, the present study shows that there are some differences between these two. To prove the claim, the role of salinity and aging time on interfacial tension reduction and contact angle alteration of a crude oil/brine/rock system is investigated using both smart sea water and low salinity sea water. Moreover, the governing mechanisms of the IFT variation and wettability alteration are discussed. For this purpose, the seawater solution is diluted with distilled water and at the optimal salinity NaCl, CaCl2, and Na2SO4 salts are added to the solution. Next, the IFT of brine and oil, and the CA of the oil drop are measured on the carbonate surface in the presence of brine. The results showed that IFT between low salinity sea water and oil was decreased with increasing salinity and then increased. In this regard, similar results were observed by adding NaCl, CaCl2, and Na2SO4 to a low salinity seawater (LSSW) solution. Additionally, reducing seawater salinity improved the wettability from oil-wet to neutral wet such that the optimum wettability range was achieved by adding Na2SO4 to the LSSW solution. The effect of aging time in the low salinity sea water solution and smart sea water resulted in a reduction in the interfacial tension and the contact angle, as well as improving the crude oil/brine/rock interface. The mechanisms governing the reduction of the interfacial tension of low salinity sea water and smart sea water were surface excess concentration, salting in effect, and boiling point reduction, while the dominant mechanism for changing the wettability of low salinity water and smart sea water were the pH rise, pseudo-alkaline behavior, double layer increase, carbonate surface dissolution and salting in effect.",29,29,1
Oil Recovery,Wettability Alteration,"Tale, F.; Kalantariasl, A.; Shabani, A.; Abbasi, S.; Zohoorian, A. H.; Khamehchi, E.",Experimental and simulation study of low salinity brine interactions with carbonate rocks,Low salinity; Dissolution; Precipitation; Ion exchange; Geochemical reactions,IMPROVED OIL-RECOVERY; WETTABILITY ALTERATION; WATER INJECTION; MODEL; IMPACT; HETEROGENEITY; SANDSTONE; DOLOMITE; EXCHANGE; SEAWATER,"Injection of low salinity water is one of the demanding enhanced oil recovery (EOR) methods that gained considerable attentions in the recent years. Among many mechanisms proposed for success of low salinity water injection (LSWI), brine/rock interactions are important with a critical role in carbonate formations that leads to dissolution, precipitation and ion exchange at the rock surface. This study presents experimental and simulation study of brine/rock interactions for thin sections of calcite and dolomite samples with four different brines. Mass difference, pH, and Scanning Electron Microscopy (SEM) were applied to monitor brine/rock interactions. A geochemical package (PHREEQC) was used to simulate geochemical reactions and sensitivity analysis. Good agreement between experimental and simulation results was achieved. SEM images confirmed the interactions at the calcite rock surface for different diluted brines. Among negative species at surface, is less sensitive to salinity changes, thus would not be the reason of surface charge alteration.",22,22,2
Oil Recovery,Wettability Alteration,"Chaturvedi, Krishna Raghav; Sharma, Tushar",Carbonated polymeric nanofluids for enhanced oil recovery from sandstone reservoir,Carbonated water injection; CO2 absorption; Enhanced oil recovery; Nanofluid; Polymeric nanoparticle suspension; Sandstone,WATER INJECTION; DEPLETION FLOCCULATION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSION; SILICA NANOFLUIDS; CO2 SOLUBILITY; NANOPARTICLES; SURFACTANT; STABILITY,"Polymeric nanoparticle (NP) suspensions are colloidal suspensions where NPs (size <= 100 nm) are suspended in the polymer-enhanced base fluid, mainly water. Compared to water or sole polymer solutions, they exhibit superior rheological, mass transfer, and heat tolerance attributes. While the use of polymeric NP suspensions as injection fluids for enhanced oil recovery has been explored in past studies, their use as carrier fluids for CO2-loaded (carbonated) water injection has not been explored to date. Thus, this study explores the use of polymeric NP suspensions prepared using SiO2, ZnO, and TiO2 nanoparticles of varying concentration for CO2 loading and their use as carbonated fluids for enhanced oil recovery from sand-packs mimicking a sandstone reservoir. It was observed that the use of nanoparticles improved CO2 absorption in the base fluid, water by a significant margin (approximate to 8-23%). The inclusion of salt (3 wt% NaCl) induced aggregation in NP suspensions and reduced their CO2 loading capacity. When used for flooding, the carbonated polymeric NP suspensions exhibited superior oil mobilization than their non-carbonated peers resulting in more oil produced even at a higher temperature and salinity (additional 12-20% of OOIP). Increasing temperature reduced the loading (absorption) of CO2 and oil recovery effectiveness of the polymeric NP suspensions while salt majorly impacted oil recovery efficiency under the investigated conditions. Based on the results obtained in this study, the use of 0.1 wt% SiO2 NPs has been recommended as the ideal concentration for use in carbonated water injection.",21,21,3
Oil Recovery,Wettability Alteration,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Syed, Asad Hassan; Sevoo, Thenesh; Kanesen, Kamalarasan","Synergistic influence of nanoparticles and surfactants on interfacial tension reduction, wettability alteration and stabilization of oil-in-water emulsion",Nanoparticles; Surfactants; Interfacial properties; Micro-pores; Dead-end pores; Emulsion,METAL-OXIDE NANOPARTICLES; WALLED CARBON NANOTUBES; SILICON DIOXIDE; FOAM STABILITY; ADSORPTION; RECOVERY; NANOFLUIDS; DISPERSION; SALINITY; BEHAVIOR,"In this study, the synergistic interaction of nanoparticles and surfactants were explored for oil-water interfacial tension (IFT) reduction, alteration of rock wettability, and stabilization of oil-in-water emulsion. The interfacial properties were investigated using drop-shape analyzer (DSA 25) while the pore scale visualization studies were conducted using the etched glass micromodels. The most stable surfactant-stabilized emulsion was formed in presence of cetyltrimethylammonium bromide (CTAB) while the order of increasing emulsion stability in presence of nanoparticles was obtained as follows: carbon nanotubes > copper oxide > silicon dioxide > aluminum oxide > titanium dioxide. Compared to pure nanofluids or surfactant solutions, the nanoparticles-surfactant solutions demonstrated promising tendency for significant reduction in oil-water interfacial tension and alteration of rock wetting properties. Specifically, the carbon nanotubes (CN) based nanofluids, reduced the contact angle of the rock from 68.73 degrees to 65.5 degrees (4.7%) while the Triton X-100 (TX 100) and CN-TX100 solutions reduced the contact angles to 10.65 degrees (84.5%) and 7.0 degrees (89.8%) respectively. The dominant mechanism of resident oil mobilization from the micro and dead-end pores was identified as emulsification-entrainment. A correlation exists between influence of nanoparticles-surfactant solutions on interfacial properties and resident oil mobilization from the micro and dead-end pores. The CN-CTAB solution that was the most effective in mobilization of the resident oil from the micro and dead-end pores significantly reduced the crude oil-water IFT to 0.63 mN/m. The mechanisms of IFT reduction, wetting properties alteration, as well as emulsion stabilization have been identified as the orientation of the particles at the interface and the electrostatic interaction between the nanoparticles and surfactant molecules. These procedures could be exploited to achieve significant reduction in IFT, rock wettability alteration and emulsion stabilization than could be achieved using pure nanofluids or surfactant solutions only.",18,17,8
Oil Recovery,Wettability Alteration,"Kumar, Ravi Shankar; Chaturvedi, Krishna Raghav; Iglauer, Stefan; Trivedi, Japan; Sharma, Tushar","Impact of anionic surfactant on stability, viscoelastic moduli, and oil recovery of silica nanofluid in saline environment",EOR; Nanofluid; Nanoparticle; Rheology; Salinity; SDS,PARTIALLY HYDROLYZED POLYACRYLAMIDE; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; CHARGED NANOPARTICLES; THERMAL-CONDUCTIVITY; DISPERSION STABILITY; AQUEOUS-SOLUTIONS; IONIC-STRENGTH; POLYMER FLOOD; BEHAVIOR,"Controlling nanofluid stability in saline environment has been a long-standing challenge as salt ions screen-out the surface charge of the nanoparticles (NPs), rendering them unstable. This study thus reports the use of an anionic surfactant (sodium dodecylsulfate, SDS), as co-stabilizer, that not only controls the effect of salt, but also dramatically improves nanofluid stability by controlling the agglomeration rate. Silica NPs of 0.5 wt%, SDS with concentration >= critical micelles concentration (CMC), and polymer polyacrylamide (PAM) of 1000 ppm were used while the concentration of NaCl was explored up to 5 wt%. The dispersion stability of nanofluid without salt (NaCl) was found to be similar to 4 weeks which further increased to similar to 7 weeks with increasing SDS concentration. With increasing SDS (>CMC), a reduction in NP agglomeration was observed that delayed the NP settlement. The effect of salinity was also investigated for flow properties of nanofluids and, an unstable rheological response (transition from viscoelastic to viscous) was observed with increasing NaCl concentration. However, SDS (>CMC) made nanofluid rheologically stable up to saline environment of 3 wt%, an optimum salinity was identified. SDS role on nanofluid stabilization in saline environment is also generalized for enhanced oil recovery (EOR) applications in a porous media enriched with varying salinity. With increasing salinity, the cumulative oil recovery from sand-pack reduced and reached to minimum level of 48% original oil in place (OOIP) at 3 wt% NaCl which was 58% OOIP without salinity. Oil recovery re-established to 55% OOIP in presence of increasing SDS concentration, which is remarkable for nanofluid applicability in saline environment where conventional methods typically show challenges. Even in the presence of 4 wt% NaCl, the synergy between surfactant and nanofluid enabled an improvement in oil recovery and subdued surfactant adsorption in both unconsolidated and consolidated porous media, paving future way for field implementation.",18,18,4
Oil Recovery,Wettability Alteration,"Takeya, Miku; Ubaidah, Amir; Shimokawara, Mai; Okano, Hirofumi; Nawa, Toyoharu; Elakneswaran, Yogarajah","Crude oil/brine/rock interface in low salinity waterflooding: Experiments, triple-layer surface complexation model, and DLVO theory",Zeta potential; Surface complexation model; Wettability alteration; Surface charge; EOR,POTENTIAL DETERMINING IONS; ENHANCED OIL-RECOVERY; WETTABILITY ALTERATION; ELECTROKINETIC PROPERTIES; STRUCTURAL APPROACH; MODIFIED WATER; SMART WATER; ADSORPTION; SANDSTONE; IMPACT,"The determination of the electrokinetic properties of crude oil/brine and rock/brine interfaces is necessary to understand and evaluate the low salinity waterflooding (LSWF) effect on wettability alteration and enhanced oil recovery (EOR). The interface properties and characteristics of oil and rock minerals significantly affect LSWF and must be elucidated in detail. Herein, the interaction of crude oil, brine, and rock was studied to elucidate the LSWF effect in carbonate and sandstone reservoirs. A triple-layer surface complexation model was proposed to describe the calcite/brine and kaolinite/brine interfaces and was verified with zeta potential experiments at various pH and calcium, magnesium, and sulphate concentrations. Furthermore, the surface complexation model prediction of zeta potential agreed well with the measured data for the suspension in seawater, formation water, and associated dilutions. The predicted surface potential of crude oil, calcite, and kaolinite was used in Derjaguin-Landau-Verwey-Overbeek (DLVO) theory to estimate the total disjoining pressure as attractive/repulsive forces. The interaction between crude oil and calcite/kaolinite on seawater dilution and in the presence of sulphate in the diluted solution for calcite was evaluated via disjoining pressure. Moreover, the importance of electrokinetic properties on attractive/repulsive forces and the mechanisms for wettability alteration in crude oil-brine-kaolinite due to LSWF as well as in oil-brine-calcite because of sulphate addition are discussed.",18,18,3
Oil Recovery,Wettability Alteration,"Wijaya, Nur; Sheng, James J.",Mitigating near-fracture blockage and enhancing oil recovery in tight reservoirs by adding surfactants in hydraulic fracturing fluid,Surfactant; Water blockage; Invasion fluid; Flowback; Interfacial tension; Wettability alteration,CALCIUM ALGINATE BEADS; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; WATER BLOCKING; IFT REDUCTION; FLOW; GAS,"Flowback after hydraulic fracturing consistently shows a significantly poor load recovery of the fracturing fluid. The unrecovered fluid creates a blockage at the matrix-fracture interface in the reservoir, which hinders the optimum hydrocarbon production. Surfactant, added into the fracturing fluid, is believed to minimize this blockage by reducing the oil-water interfacial tension (IFT) and altering the rock wettability. Although many lab and field data have shown the surfactant benefits, there is a lack of mechanistic analysis on how surfactant more effectively removes such blockage. Therefore, this paper presents a mechanistic study of water blockage removal by surfactant. Interfacial tension (IFT) reduction and wettability alteration effect are modeled to represent the main effects induced due to the surfactant addition. Our numerical model is extensively calibrated with computed tomography (CT) scans and pressure drop data during coreflood experiments. Our model shows that surfactant addition into the fracturing fluid results in a better water blockage removal than fracturing water alone, because surfactant results not only in a shallower invasion depth, but also a much milder blockage within the shallower invasion depth itself. Furthermore, our model also discovers that the restoration of hydrocarbon permeability by surfactant could demonstrate a time-dependent behavior, based on the interplaying effects among IFT reduction, fracture clean-up state, and the wettability of the matrix-fracture interface. Overall, by presenting the mechanistic analysis, this study serves as a crucial step toward the optimization of surfactant formulation for fracturing fluid and EOR applications in tight reservoirs.",14,14,8
Oil Recovery,Wettability Alteration,"Shaik, I. K.; Song, J.; Biswal, S. L.; Hirasaki, G. J.; Bikkina, P. K.; Aichele, C. P.",Effect of brine type and ionic strength on the wettability alteration of naphthenic-acid-adsorbed calcite surfaces,Low salinity; Carbonate reservoir; Enhanced oil recovery; Contact angle; Calcite surface; Naphthenic acid,DROP BUBBLE SIZE; OIL-RECOVERY; CONTACT ANGLES; FATTY-ACIDS; SPONTANEOUS IMBIBITION; BENZOIC-ACID; SESSILE-DROP; SULFATE-IONS; SMART WATER; ADSORPTION,"Low-salinity/smart waterflooding is a technique, used in oil reservoirs, where the salinity and/or ionic composition of the injection water is tuned to improve oil recovery. It has been observed by many researchers that low-salinity waterflooding can enhance oil recovery by altering the wettability of carbonate rock surfaces from oil-wet to water-wet. Though wettability alteration is generally agreed to be the main mechanism for the improved oil recovery, the contributing parameters and necessary conditions for wettability alteration are not clearly understood. Hence, it is essential to decouple the effects of salinity, ionic composition, and oil composition on wettability alteration of the solid surface. In this work, we systematically investigated smart-water induced wettability alteration of naphthenic-acid-adsorbed oil-wet calcite surfaces. Well-characterized model systems were used to understand the effects of individual monovalent and divalent ions (Na+, Cl-, Mg2+ and SO42-), and salinity on the calcite surface wettability. Contact angle measurements were performed on smooth Iceland Spar calcite surfaces that were aged at 120 degrees C in 5M NaCl brine, acid number 1.5 model oil, and single-electrolyte-based brine solutions of different salinity and ionic composition. The extent of wettability alteration was assessed based on ACA values, which are more relevant during waterflooding, using a goniometer customized for obtaining multiple advancing and receding contact angles along the surface by the tilting plate method. The results indicate that, for 0.164 M ionic strength (equivalent to 4-times diluted seawater concentration) brine solutions, the wettability of calcite surfaces was changed from oil-wet state to water-wet state irrespective of the salt type. The lowest advancing contact angle (ACA) values (20 degrees-30 degrees range) were obtained for 0.164 M ionic strength NaCl and Na2SO4 solutions, indicating the presence of SO42- ions or reduction in NaCl concentration act in favor of wettability alteration towards water-wet. At this ionic strength, the relative merit of divalent SO42 ions over monovalent Cl ions was not observed. Upon comparison of ACA values for 0.164 M ionic strength Na2SO4 and MgSO4 (SO42 ion is common) solutions, we concluded that the extent of wettability alteration is lower in the presence of Mg2+ ions. A similar conclusion was made by comparing ACA values for 0.164 M ionic strength NaCl and MgCl2 solutions (Cl ion is common). The calcite surfaces aged in 0.656 M (equivalent to seawater concentration) NaCl solution demonstrated intermediate-wet state indicating the extent of wettability alteration towards water-wet state increases with a decrease in salinity.",14,14,1
Oil Recovery,Wettability Alteration,"Aljuboori, Faisal Awad; Lee, Jang Hyun; Elraies, Khaled A.; Stephen, Karl D.",The effectiveness of low salinity waterflooding in naturally fractured reservoirs,Low salinity (LoSal) waterflooding; Naturally fractured reservoirs (NFR's); Wettability alteration; Residual oil reduction; Qamchuqa reservoir,OIL-RECOVERY; BRINE COMPOSITION; MAUDDUD FORMATION; WATER INJECTION; WETTABILITY; FLOW; SIMULATION; SANDSTONE; FIELD,"Low Salinity (LoSal) waterflooding is a technique which promises to improve and enhance oil recovery. The method has been studied widely in the laboratories using various core plug samples of sandstones and carbonates. Most of the experimental outcomes have demonstrated the possibility of recovery increment in conventional reservoirs. Meanwhile, it is rare to find a discussion in these experiments about the effectiveness of LoSal waterflooding in naturally fractured reservoirs. In this paper, we investigate the potential benefits in fractured reservoirs using simulations. It is often reported from coreflood experiments that LoSal injection has the ability to alter the rock wettability and reduce residual oil saturations through chemical and physical interactions between the rock-oil-water system. Based on the published work, we have calculated relative permeability curves to represent the flow in regions flooded with LoSal water. This includes a qualitative representation of uncertainty. In this sense, the relative permeabilities are a proxy for any physical and chemical mechanisms which are not explicitly represented. The newly generated flow curves were applied to simulate LoSal waterflooding using a fine-scale model and a field scale model based on a fractured reservoir from the Middle East. The simulation results underline the benefits of LoSal whereby the oil recovery from fractured reservoirs can be increased. An additional benefit is the control of water production. The fine-scale modelling has provided an in-depth analysis and accurate estimation of the oil recovery without modelling artefacts or limitations, where an increment of (12-14)% of the Stock Tank Oil Initially In Place (STOIIP) were obtained under secondary and tertiary recovery scheme, respectively. The investigated scenarios demonstrated a sensitivity to the newly generated flow curves and how they affect the ultimate oil recovery. However, for the field scale model, a higher oil production rate has maintained during LoSal waterflooding up to 32 K BPD by the end of year fourteen compared with 25 K BPD in case of high salinity scenario, besides a reduction in the produced water by 35.7%. Therefore, the effectiveness of LoSal brine required a longer time frame to observe the improvements in the oil displacement or sweep efficiency.",13,13,2
Oil Recovery,Wettability Alteration,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Oil Recovery,Wettability Alteration,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Oil Recovery,Wettability Alteration,"Datta, Poulami; Tiwari, Pankaj; Pandey, Lalit M.",Oil washing proficiency of biosurfactant produced by isolated Bacillus tequilensis MK 729017 from Assam reservoir soil,Biosurfactant production; Optimization; Wetting; Surface tension; Oil washing efficiency; Emulsion,CELL-SURFACE HYDROPHOBICITY; CRUDE-OIL; INTERFACIAL-TENSION; RAPID IDENTIFICATION; RECOVERY; OPTIMIZATION; WETTABILITY; STRAIN; WATER; MEOR,"The present study describes elaborately the isolation of a potential biosurfactant producing and crude oil degrading strains isolated from the reservoir soil of Assam oil reservoir field. The produced biosurfactant was chemically characterized for its applicability for the enhanced oil recovery applications in terms of wetting, interfacial tension (IFT) and oil washing. From the seven isolated strains, Bacillus tequilensis MK 729017 was chosen based on the better surface active properties as it reduced the surface tension to 30 +/- 2 mN/m along with a moderate emulsification index of 66 +/- 2%. The produced biosurfactant was chemically identified to be lipopeptide, surfactin with a lower critical micelle concentration value of 90 mg/L. The carbon source and environmental parameters were optimized for the maximum concentration of the biosurfactant using response surface methodology based on the central composite design (RSM-CCD). The maximum biosurfactant concentration was measured to be 7.46 +/- 0.39 g/L and Y-PS was determined as 0.45. The specific growth rate of the isolate was 0.15 +/- 0.01 h(-1) and Y-XS was estimated as 0.1. The produced biosurfactant was also found to be thermal and colloidal stable. The biosurfactant solutions altered wettability of hydrophobic rock surface from 90 +/- 1 degrees to 26 +/- 1 degrees indicating a better interfacial interaction. The IFT of the produced biosurfactant was found to be 0.32 +/- 0.02 mN/m. The oil washing efficiency (80 +/- 2%) of the produced surfactin was comparable with chemical surfactants and the process involved two-step: initial a faster (surface) washing followed by a slower (internal) washing. The first process was dependent on micelle sizes, while the latter was dependent on water-oil emulsion size. The lower emulsion size of surfactin contributed to a greater internal washing as compared to chemical surfactants.",12,12,2
Oil Recovery,Wettability Alteration,"Khurshid, Ilyas; Al-Shalabi, Emad W.; Alameri, Waleed",Influence of water composition on formation damage and related oil recovery in carbonates: A geochemical study,Low salinity water injection (LSWI); Engineered water injection (EWI); Formation damage by low salinity water; Oil recovery by low salinity water; Geochemical modeling; Carbonate reservoirs,WETTABILITY ALTERATION; SCALE DEPOSITION; FINES-MIGRATION; SALINITY; SURFACE; CHALK; MODEL; CALCIUM; IMPACT,"Several benefits of low salinity/engineered water injection (LSWI/EWI) have been reported in the literature including its ability to increase oil recovery at low cost and with least environmental impact. Nevertheless, the related reservoir-engineering problems to this technique such as formation damage is still uncertain and has not been thoroughly investigated. This study investigates the effect of water composition on formation damage and the related oil recovery from a geochemical prospective. The study presents coupling of the IPhreeqc geochemical engine with Matlab to simultaneously solve the oil-water multiphase flow in 1-D and the related geochemical reactions. Using this coupling technique, the geochemical capabilities of Phreeqc were successfully incorporated in a multiphase flow simulator. The latter enabled modeling of reactive transport and formation damage in subsurface multiphase reservoir. The developed model was validated against single phase geochemical simulator, analytical solution of Buckley-Leverette equation, commercial reservoir engineering simulator, and experimental data. The results showed that the temperature, sulfate concentration, and dilution of injection water have a pronounced effect on formation dissolution and precipitation during LSWI/EWI. Also, anhydride scale is the main controlling solid specie for formation damage in the investigated case study. In addition, high temperature water injection should be avoided in carbonate reservoirs due to the likelihood of anhydride precipitation and formation damage. This precipitation occurs because of the low-solubility of anhydride at high temperature. Moreover, water dilution could decrease scale formation while sulfate spiking might increase anhydride precipitation. Hence, sulfate concentration should be optimized as a wettability alteration agent to enhance oil recovery while avoid formation damage. Furthermore, as a sequence of anhydride precipitation by sulfate spiking, oil production is expected to decrease by around 10% in the selected case study. The dissolution and precipitation mechanisms during LSWI/EWI are very case-dependent and hence, the findings of this study cannot be generalized.",10,10,2
Oil Recovery,Wettability Alteration,"Jafarbeigi, Ehsan; Kamari, Ehsan; Salimi, Farhad; Mohammadidoust, Akbar",Experimental study of the effects of a novel nanoparticle on enhanced oil recovery in carbonate porous media,Interfacial tension (IFT); Nanofluid flooding; Wettability alteration; Contact angle; Enhanced oil recovery (EOR),WETTABILITY ALTERATION; INTERFACIAL-TENSION; GRAPHENE OXIDE; SILICA NANOPARTICLES; SULFONATED GRAPHENE; WATER INJECTION; NANOFLUID; SALINITY; FUNCTIONALIZATION; ADSORPTION,"One of the effective methods in the process of enhancing the oil recovery from oil reservoirs is the use of nanotechnology. For this purpose, a new nanofluid was used to enhance the oil recovery from the reservoir at the scale of carbonate rocks. Finally, the obtained compound, in the first stage, nano-graphene oxide (NGO) were synthesized using Hummer's method and then they were subjected to surface modifications under new compounds. Finally, the obtained compound was known as (graphene oxide (N-(1-naphthyl) ethylenediamine)) (G-NEA), where G stands for graphene oxide (GO). Also, to determine the morphological characteristics and structure of the synthesized nanoparticles, Field Emission Scanning Electron Microscopy (FESEM), Fourier-transform infrared spectroscopy (FTIR), and Transmission electron microscopy (TEM) were performed. In addition, zeta-potential analysis was performed to investigate the stability of nanofluids at different pHs. In order to investigate the effect of nanofluids on oil recovery, three concentrations (200, 400, and 500 ppm) of G-NEA nanofluids were prepared. Also, the interfacial-tension (IFT) measurement and rock angle measurement in the presence of nanofluid were investigated using a pendant drop and sessile drop method, respectively. The coreflood experiment was performed to evaluate the effect of G-NEA nanofluid on carbonate plugs. The results showed that when the G-NEA nanofluid concentration increased, the IFT value of 19.34 (mN/m) for deionized water to 10.8 (mN/m) for 500 ppm G-NEA and the contact angle decreased from the initial value of 166 degrees to 40 degrees, indicating the tendency of the wettability alteration of the rock to a water-wet conditions. The results of the coreflood experiment showed that at 400 and 500 ppm concentrations, the G-NEA nanofluid enhanced the oil recovery by 23 and 15%, respectively. Therefore, this synthesized nanofluid can have an effective approach to drive the carbonate reservoir rock into a water-wet condition and enhance oil recovery.",9,9,6
Oil Recovery,Wettability Alteration,"Drexler, Santiago; Correia, Elton L.; Jerdy, Ana Carolina; Cavadas, Leandro A.; Couto, Paulo",Effect of CO2 on the dynamic and equilibrium interfacial tension between crude oil and formation brine for a deepwater Pre-salt field,Interfacial tension; CO2 flooding; Pre-salt reservoirs; WAG; Reservoir fluid characterization; Capillary forces; Dynamic IFT,ASPHALTENE; RESIN; SALINITY; SURFACTANT; SYSTEMS; PH,"Interfacial tension (IFT) between oil and brine is key to determine the Capillary Number, which governs capillary forces in the porous medium. As a result, changes in IFT affect the displacement efficiency and the residual oil saturation having direct impact on the Recovery Factor. Fluids in Pre-salt fields (offshore Brazil) have particular characteristics, such as high salinity in the brines, elevated content of asphaltenes and resins in the oils and high CO2 content in the produced gas for some fields. The effect of CO2 on the IFT depends on complex electrostatic and acid-base equilibria, and cannot be predicted by a single fluid property. This work presents the experimental study of the effect of CO2 dissolution on the IFT between a Pre-salt oil with a high total base number (TBN) and non-negligible total acid number (TAN) and a high salinity brine using the pendant drop technique. The oil and its asphaltenic fraction were characterized by Fourier-transform infrared spectroscopy, nuclear magnetic resonance spectroscopy, and elemental analysis identifying characteristic functional groups and indicating both acidic and basic polar functional groups. CO2 dissolution resulted in an IFT increase of 56% evidencing that, despite the high TBN of this oil, basic groups have low surface-activity. Moreover, a study of IFT as a function of pH showed that the maximum IFT was found in strongly acidic environments, but constant IFT values were obtained at neutral and basic pH values. Thus, the interfacial activity is governed by asphaltenes and resins with polar groups of varying acid/base behavior. The presence of CO2 also accelerated the dynamic behavior of IFT reducing the equilibrium time by 70%. This is caused by the reduction of oil viscosity, which impacts the relaxation time and enhances the diffusion of surface-active species towards the interface. The results in this work evidence that the CO2 content should be considered when modeling fluid properties for this type of reservoirs, as it affects the oil-brine IFT. In addition, for this oil with high content of surface-active compounds and non-negligible TAN and TBN, CO2 flooding does not contribute to reduce the IFT. Therefore, the efficiency of this Enhanced Oil Recovery technique in this type of field relies on viscosity reduction, miscible displacement and wettability alteration rather than IFT reduction.",9,10,4
Oil Recovery,Wettability Alteration,"Wijaya, Nur; Sheng, James J.",Optimum surfactant criteria for controlling invasion-induced water blockage in tight water-wet cores,Surfactant; Hydraulic fracturing; Flowback; Water blockage; Interfacial tension; Wettability alteration,ENHANCED SPONTANEOUS IMBIBITION; CALCIUM ALGINATE BEADS; WETTABILITY ALTERATION; IFT REDUCTION; OIL-RECOVERY; GAS SHALES; RESERVOIRS; FLOW; MECHANISMS; ADSORPTION,"Flowback after hydraulic fracturing shows a poor recovery of the fracturing fluid. The unrecovered fluid is believed to invade the matrix and creates a formation damage called water blockage, which affects the optimum oil production from the reservoir. Surfactant is often added into the fracturing fluid, because it can improve the recovery of the fracturing fluid, and hence minimum water blockage. This objective is achieved by the surfactant's interfacial tension (IFT) reduction and wettability alteration capabilities. This study investigates the optimum surfactant criteria, in terms of the IFT and wettability, to minimize the water blockage. From the perspective of regained oil relative permeability, our history-matched core-scale model reveals that the optimum criteria depend on the matrix capillarity. In conventional reservoirs, the optimum criteria are to select surfactants which offer ultralow IFT (even as low as 0.001 mN/m) and maintain the waterwetness of the rock. However, in tight reservoirs, the optimum criteria are surfactants which strongly alter the rock wettability to oil-wet, while the IFT requirement is more flexible (i.e., from 15 down to 0.001 mN/m). The contradicting optimum criteria can be explained by the relative dominance between relative permeability and capillary pressure. This study emphasizes that the optimum surfactant criteria for conventional reservoirs are not necessarily the same as those for tight reservoirs.",8,8,2
Oil Recovery,Wettability Alteration,"Agi, Augustine; Junin, Radzuan; Abdullah, Mohammed Omar; Jaafar, Mohd Zaidi; Arsad, Agus; Sulaiman, Wan Rosli Wan; Norddin, M. N. A. Mohd; Abdurrahman, Muslim; Abbas, Azza; Gbadamosi, Afeez; Azli, Nur Bashirah",Application of polymeric nanofluid in enhancing oil recovery at reservoir condition,EOR; Cissus populnea; IFT; Wettability; Ultrasound; Nanofluid,CRYSTALLINE STARCH NANOPARTICLES; INTERFACIAL-TENSION; SILICA NANOPARTICLE; GEMINI SURFACTANTS; ACID-HYDROLYSIS; TEMPERATURE; STABILITY; BEHAVIOR; ULTRASOUND; RHEOLOGY,"In this study, ascorbic acid was used to synthesize Cissus populnea nanoparticles (CPNP). The synthesized CPNP was isolated and the influence of the process variables on the physical properties were studied. The rheology of the formulated Cissus populnea nanofluid (CPNF) was measured and compared with Cissus populnea (CP) solution and commercial polymer xanthan. Moreover, the interfacial properties of CPNF were studied at various concentrations and temperatures, and the influence of salinity and their interaction with ultrasound was investigated. Sessile drop contact angle method was used to determine the wettability alteration efficiency of CPNF on an initially oil-wet sandstone core surface. Finally, CPNF and CP solutions were evaluated for EOR purposes at typical reservoir condition. The displacement process was scaled to reduce the number of parameters investigated using dimensionless parameters. The synthesis methods were efficient in generating sphere-shaped and elongated nanoparticles (50 nm mean diameter). Experimental results show that an increase in temperature of CP and CPNP yielded increased viscosity of the solutions in stark contrast to xanthan whose solution viscosity declines as the temperature increases. Besides, the CPNF was effective in lowering IFT at oil-water (O/W) interface and altered the wettability of the sandstone cores to water-wetting condition. The novel CPNF increased the oil recovery by 26% and was effective at high-temperature high-pressure (HTHP) reservoir condition. The result shows a transition from capillary dominated flow to gravity dominated flow as decrease in IFT decreased residual oil saturation and increased capillary and Bond number. The energy consumption and cost estimation of the proposed novel polymeric nanofluid shows it is cost-effective than conventional EOR chemicals.",8,8,2
Oil Recovery,Wettability Alteration,"Afekare, Dayo; Gupta, Ipsita; Rao, Dandina",Nanoscale investigation of silicon dioxide nanofluids and implications for enhanced oil recovery - An atomic force microscope study,Nanofluids; Enhanced oil recovery; Nanotechnology; Atomic force microscope; Wettability; Work of adhesion,WETTABILITY ALTERATION; PHASE-BEHAVIOR; NANOPARTICLES; IMPACT,"The use of silica-based nanofluids in enhanced oil recovery (EOR) has received significant attention recently. Aqueous dispersion of silica nanoparticles (<100 nm) can improve oil recovery through wettability alteration via rock/fluid and fluid/fluid interactions. Silicon dioxide nanofluids also offer superior advantages such as controllable chemistry and environmental safety. The potential of these chemicals has been studied reasonably at larger scales through contact angle and force imbibition tests. However, there is inadequate scientific understanding of nanofluid EOR. Evidence of oil recovery at nanoscale is also limited, which is important for low-porosity and permeability petroleum rocks with nanopores. In this study, we conducted an atomic force microscopy (AFM) study to investigate the effect of silica-based nanofluids on wettability alteration in model sandstones at nanoscale. We used CH2- and C6H5- terminated functionalized AFM probes to represent saturated and aromatic crude oils (respectively), and quartz & feldspar minerals to represent model rock surfaces. Our results show that adhesion force between these non-polar moieties and minerals decrease with increasing nanofluid concentration. We demonstrate experimentally at nanoscale that silica nanofluids significantly reduces work of adhesion - a fundamental wettability indicator - between functionalized probes and substrates. Across all tests, we observed a threshold concentration of 0.5 wt% above which wettability is not improved. Our findings offer fresh insight into the fundamental investigations of oil release mechanism with dispersed nanoparticles and provide original evidence on the implications of nanofluid injection for enhanced oil recovery at sub-micron scale.",7,7,4
Oil Recovery,Wettability Alteration,"Hassan, Anas M.; Ayoub, M.; Eissa, M.; Bruining, Hans; Zitha, P.",Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding,Surface complexes; DLVO theory; Enhanced oil recovery (EOR); Smart water assisted foam (SWAF) flooding; Low-salinity; Wettability alteration; Foam flooding; Foam stability; Carbonate reservoirs; PHREEQC-Software,ACTIVITY-COEFFICIENT; OSMOTIC COEFFICIENTS; THERMODYNAMICS; ELECTROLYTES; TRANSPORT; MECHANISMS; CARBONATE; ORDER; PART; IRON,"This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25 degrees C) and at the reservoir-conditions (80 degrees C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Huckel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foamlaminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25 degrees C) and at (80 degrees C) than the high-salinity case for both (25 degrees C) and (80 degrees C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of ""Smart Water Assisted Foam (SWAF) Flooding"". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.",7,7,4
Oil Recovery,Degrees C,"Hu, Xiao; Xie, Jun; Cai, Wuchao; Wang, Rui; Davarpanah, Afshin",Thermodynamic effects of cycling carbon dioxide injectivity in shale reservoirs,Carbon dioxide storage capacity; Oil recovery factor; Soaking time; Core stimulation; Shale reservoirs,ENHANCED OIL-RECOVERY; BAKKEN TIGHT OIL; N-PUFF PROCESS; GAS; STORAGE; MODEL; PERMEABILITY,"Carbon dioxide injectivity has always been considered as one of the optimum enhanced recovery techniques, especially in tight reservoirs regarding the feasible mobilization of gas through porous media. To have a better understanding of carbon dioxide injectivity performances, it would be of importance to consider crucial parameters and their effects on the carbon dioxide adsorption and oil recovery factor. In this paper, the profound impact of crucial parameters such as temperature, pressure, carbon dioxide soaking time, and core stimulation on the oil recovery enhancement were investigated. Moreover, the considerable influence of pressure and temperature on the carbon dioxide adsorption capacity storage were performed and analyzed. According to the result of this experiment, temperature increase led to reducing carbon dioxide storage capacity, which has a reverse pattern with oil recovery factor by increasing temperature. When the core samples were unstimulated, the oil recovery factor has higher than stimulated core samples. Furthermore, pressure increase resulted in the carbon dioxide storage capacity enhancement, which has a similar increase pattern with oil recovery factor by increasing pressure. The maximum carbon dioxide storage capacity is 91% and 90% at the pressure of 1500 psi and temperature of 20 degrees C respectively. Soaking time rising between oil and carbon dioxide led to producing more oil volume.",98,98,22
Oil Recovery,Degrees C,"Shaik, I. K.; Song, J.; Biswal, S. L.; Hirasaki, G. J.; Bikkina, P. K.; Aichele, C. P.",Effect of brine type and ionic strength on the wettability alteration of naphthenic-acid-adsorbed calcite surfaces,Low salinity; Carbonate reservoir; Enhanced oil recovery; Contact angle; Calcite surface; Naphthenic acid,DROP BUBBLE SIZE; OIL-RECOVERY; CONTACT ANGLES; FATTY-ACIDS; SPONTANEOUS IMBIBITION; BENZOIC-ACID; SESSILE-DROP; SULFATE-IONS; SMART WATER; ADSORPTION,"Low-salinity/smart waterflooding is a technique, used in oil reservoirs, where the salinity and/or ionic composition of the injection water is tuned to improve oil recovery. It has been observed by many researchers that low-salinity waterflooding can enhance oil recovery by altering the wettability of carbonate rock surfaces from oil-wet to water-wet. Though wettability alteration is generally agreed to be the main mechanism for the improved oil recovery, the contributing parameters and necessary conditions for wettability alteration are not clearly understood. Hence, it is essential to decouple the effects of salinity, ionic composition, and oil composition on wettability alteration of the solid surface. In this work, we systematically investigated smart-water induced wettability alteration of naphthenic-acid-adsorbed oil-wet calcite surfaces. Well-characterized model systems were used to understand the effects of individual monovalent and divalent ions (Na+, Cl-, Mg2+ and SO42-), and salinity on the calcite surface wettability. Contact angle measurements were performed on smooth Iceland Spar calcite surfaces that were aged at 120 degrees C in 5M NaCl brine, acid number 1.5 model oil, and single-electrolyte-based brine solutions of different salinity and ionic composition. The extent of wettability alteration was assessed based on ACA values, which are more relevant during waterflooding, using a goniometer customized for obtaining multiple advancing and receding contact angles along the surface by the tilting plate method. The results indicate that, for 0.164 M ionic strength (equivalent to 4-times diluted seawater concentration) brine solutions, the wettability of calcite surfaces was changed from oil-wet state to water-wet state irrespective of the salt type. The lowest advancing contact angle (ACA) values (20 degrees-30 degrees range) were obtained for 0.164 M ionic strength NaCl and Na2SO4 solutions, indicating the presence of SO42- ions or reduction in NaCl concentration act in favor of wettability alteration towards water-wet. At this ionic strength, the relative merit of divalent SO42 ions over monovalent Cl ions was not observed. Upon comparison of ACA values for 0.164 M ionic strength Na2SO4 and MgSO4 (SO42 ion is common) solutions, we concluded that the extent of wettability alteration is lower in the presence of Mg2+ ions. A similar conclusion was made by comparing ACA values for 0.164 M ionic strength NaCl and MgCl2 solutions (Cl ion is common). The calcite surfaces aged in 0.656 M (equivalent to seawater concentration) NaCl solution demonstrated intermediate-wet state indicating the extent of wettability alteration towards water-wet state increases with a decrease in salinity.",14,14,1
Oil Recovery,Degrees C,"Lai, Nanjun; Wen, Yiping; Yang, Zhidong; Chen, Jianlin; Zhao, Xubin; Wang, Dongdong; He, Wei; Chen, Yuemei",Polymer flooding in high-temperature and high-salinity heterogeneous reservoir by using diutan gum,High-temperature; High-salinity; Strong heterogeneity; Diutan gum; Rheological properties; Oil displacement experiments,LASER-LIGHT SCATTERING; HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; WATER-SOLUBLE COPOLYMERS; RHEOLOGICAL PROPERTIES; SOLUTION BEHAVIOR; PROFILE-CONTROL; OIL-RECOVERY; ACRYLAMIDE; DISPLACEMENT; XANTHAN,"Diutan gum, a biopolymer that has been widely used in cement and concrete industries, was introduced in this work to alleviate severe viscosity loss and the poor water solubility of polyacrylamide and its modified products in high-temperature and high-salinity reservoirs. Diutan gum is an exopolysaccharide secreted by sphingomonas. The rheological properties and capacity of diutan gum to enhance oil recovery in high-temperature and highsalinity heterogeneous reservoir (T = 130 degrees C, Total salinity = 223.07 g L-(1), V-k = 0.93) was investigated and compared with those of two other kinds of biopolymer thickeners (xanthan and konjac gum), which are commonly used in oilfield development. The three biopolymers show pseudoplastic fluid properties in a steadystate rheological test: given the strong interactions in the double-helix structure of diutan gum, the number of the Newtonian zone and the shear rate of this zone are higher than the those of the two other biopolymers. The storage modulus (G') of diutan gum are higher than its loss modulus (G '') in all the concentrations and frequencies measured through viscoelasticity tests. This result indicates that diutan gum exhibits remarkable elasticity in slow displacement speed while it seeping in porous media. The capability of establish flow resistance in high-permeability porous medium in high-temperature and high-salinity environment by three biopolymers was studied, and their viscosity and microscopic properties of injected and produced fluid were investigated to understand the reason why diutan gum can have good fluidity control ability. Oil displacement efficiency can be improved by the elasticity of the diutan gum even without an increase in displacement speed. The results of the oil displacement experiments in the heterogeneity model imply that diutan gum is more effective in improving the water injection profile of each layer than xanthan and konjac gum. The water channeling in the high-permeability layer is restrained, and the sweep ability of the displacement phase is improved. Furthermore, the effect of polymer flooding can be maintained for a long time. Under high-temperature, high-salinity and strong heterogeneity, diutan gum recovers 19.34% of original oil in place (OOIP). This value is higher than the values obtained with xanthan gum (14.15% OOIP) and konjac gum (8.60% OOIP). This finding implies that the diutan gum has great application potential in the development of high-temperature and high-salinity reservoirs with strong heterogeneity.",13,12,7
Oil Recovery,Degrees C,"Zamani, Hamed; Jafari, Arezou; Mousavi, Seyyed Mohammad; Darezereshki, Esmaeel",Biosynthesis of silica nanoparticle using Saccharomyces cervisiae and its application on enhanced oil recovery,Microorganism; Enhanced oil recovery; Saccharomyces cervisiae; Precursor; Silica nanoparticles,,"Using nanotechnology to increase the recovery of oil reservoirs can be a good way to meet energy demand, in order to increase oil production and reduce production costs. Biotechnology of nanoparticles using microorganisms as an environmentally friendly research field in nanotechnology around the world is a rapid development and is considered as a substitute for conventional and physical chemical methods. Optimizing processes can lead to morphology, control of the size and speed of nanoparticle synthesis reactions. Therefore, the purpose of this research is to build a reflection on the current status and future projects, and in particular the feasibility and limitations of the biotechnology approach proposed in the oil industry. In this research, Saccharomyces cervisiae yeast has been used for biochemical production of silica nanoparticles. This yeast is cultivated in its own culture medium. This yeast solution made after the addition of Sodium Silicate Precursor placed in the proper conditions of growth, i.e., temperature of 29 degrees C, away from the types of contamination and the passage of time, reducing the silica nanoparticles from the initial precursor. In this research, after performing the silica nanoparticle production processes, identification tests such as FTIR, XRD, SEM, DLS and TGA are performed. Then, in order to investigate the effect of this nanoparticle on the production efficiency of the oil, these nanoparticles were added to injectable solutions to an oil-wet micro-model with different concentrations of 250 ppm, 500 ppm and 1000 ppm. It was observed that the difference in the effect of nanoparticles produced by the biochemical method and commercial nanoparticles purchased in the injection process and on the measurement of the production efficiency of oil was that biosynthesized nanoparticles increased oil production efficiency by about 5-7 percent relative to commercial nanoparticles.",13,13,2
Oil Recovery,Degrees C,"Mpelwa, Musa; Tang, Shanfa; Jin, Lijun; Hu, Ruizhi; Wang, Changquan; Hu, Yang",The study on the properties of the newly extended Gemini surfactants and their application potentials in the petroleum industry,Chemical EOR; Gemini surfactant; Interfacial tension; Rheological behavior; Corrosion inhibition,ENHANCED OIL-RECOVERY; ULTRALOW INTERFACIAL-TENSION; CORROSION-INHIBITORS; PERFORMANCE; BEHAVIOR; SPACER; TEMPERATURE; ADSORPTION; STEEL,"In this study, the newly extended Gemini surfactants (EGSs) were studied as potential candidates in the petroleum industry applications. The performances of EGSs with respect to variant spacer lengths were studied through surface tension, conductivity, dynamic light scattering (DLS), interfacial tension, rheological behavior, field emission electron microscopy (FESEM), core flooding, and corrosion inhibition measurements. The surface pressure (pi(CMC)), surface efficiency (pC(20)), critical micelle concentration (CMC), maximum surface excess concentration (Gamma(max)), minimum area per molecule of surfactant at the air-water interface (A(min)), average the degree of counterion binding to micelle (beta), Gibb's free energy of micellization (Delta G(mic)), and Gibb's free energy of adsorption (Delta G(ads)) of the EGSs were determined from surface tension and conductivity data. The results showed that the EGSs exhibited more surface activity properties, low CMCs, and spontaneously adsorbed at the air-water interface and micellized in the bulk aqueous phase. The surfactants reduced the oil-water interfacial tension (IFT) to ultralow values (10(-3) mN/m) at low concentration, and it decreased substantively to very ultralow values (10(-4) mN/m) due to the addition of inorganic salts. Also, they exhibited fascinating viscosifying effect and viscoelastic behavior at the experimental temperatures (30 degrees C-60 degrees C). The rheological behaviors were influenced by the formation of entangled micelles in aqueous solutions. Furthermore, through core flooding, EGS1 increased oil recovery by 12.30% which is an interesting incremental recovery. Besides, the EGSs surfactants showed high anticorrosion efficacy on A3 carbon steel in 1 M HCl aqueous solution and the inhibitive action mechanism was revealed to be by creating a protective film on the carbon steel surface through physisorption. Overall, the surface activity, interfacial activity, rheological behaviors, and anticorrosion property were dependent on the length of the spacer group. The surfactants, particularly EGS1 demonstrated a more promising interfacial activity and rheological behavior for enhanced oil recovery (EOR) in heterogeneity reservoirs as well as a remarkable anticorrosion property.",13,13,1
Oil Recovery,Degrees C,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Oil Recovery,Degrees C,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Oil Recovery,Degrees C,"Alade, Olalekan S.; Hamdy, Mohamed; Mahmoud, Mohamed; Al Shehri, Dhafer A.; Mokheimer, Esmail; Patil, Shirish; Al-Nakhli, Ayman",A preliminary assessment of thermochemical fluid for heavy oil recovery,Enhanced oil recovery; Heavy oil; Thermal methods; Insitu heat generation; Thermochemical fluids,INJECTION; EXTRACTION; BITUMEN,"Commercial production of heavy oil has heavily relied upon steam injection method due to its effectiveness to reduce the viscosity and improved mobility. However, due to uncertainty of oil price, high energy cost, water requirement, heat loss, and environmental issues, attention is being given to new thermal EOR technologies such as insitu steam generation using thermochemical fluid (TCF) injection. This technology essentially involves downhole generation of heat and pressure from exothermic chemical reaction. In this investigation, thermochemical reactants were injected, at different temperatures (100, 50, and 30 degrees C) and constant rate of 0.5 ml/mln, into Berea sandstone core samples saturated with heavy oil (18 %wt./wt. asphaltene content and 11 degrees API) and brine. It was observed that the pressure generated at the inlet of the core due to 100, 50, and 30 degrees C injection temperatures of the thermochemical fluids rose to 1600, 1200, and 280 psi, respectively; while the recovery factor was 83%, 66% and 54% OOIP, respectively. In comparison, from the injection of steam generated at 250 degrees C, the pressure at the inlet of the core was 212 psi and the recovery factor was 71% OOIP. These results therefore confirm increase in interest in the application of the TCF injection technology in heavy oil production.",11,11,0
Oil Recovery,Degrees C,"Das, A.; Nguyen, N.; Farajzadeh, R.; Southwick, J. G.; Vincent-Bonnieu, S.; Khaburi, S.; Al Kindi, A.; Nguyen, Quoc P.","Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs",Enhanced oil recovery; Foam; Microemulsion; Carbonate; High salinity; Low permeability,ADSORPTION; OIL,"Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging. In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 degrees C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.",10,10,7
Oil Recovery,Degrees C,"Wang, Ruolan; Pu, Wanfen; Dang, Sisi; Jiang, Feng; Zhao, Shuai",Synthesis and characterization of a graft-modified copolymer for enhanced oil recovery,Graft-modified copolymer; Antiaging performance; Welan gum; Enhanced oil recovery; Salt resistance,XANTHAN GUM; ACRYLAMIDE,"A graft-modified copolymer (cWL-g-A) was synthesized using Welan Gum (WLG), acrylamide, acrylic acid, and 0-20 via free-radical copolymerization to be well applied for enhanced oil recovery. The chemical structure of the copolymer was characterized by Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance spectroscopy (NMR), thermogravimetry (TG) and scanning electron microscopy (SEM). The long-term stability, rheology, adsorption, temperature and salt resistance of the copolymer were investigated. The cWL-g-A solution showed superior temperature and salt resistance in comparison with partially hydrolyzed polyacrylamide (HPAM), due to the hydrophobic association of main polymer chain. Particularly in high salinity (230,000 mg/L) solutions, cWL-g-A showed a better antiaging performance at three different temperatures (25, 50 and 65 degrees C). Oil recovery yielded by cWL-g-A was 14.18% higher than that yielded by HPAM, as known from polymer flooding tests. These results elucidated that cWL-g-A synthesized herein was superior to HPAM in high-salinity and medium-high temperature oil reservoirs.",10,9,4
Oil Recovery,Degrees C,"Askarova, Aysylu; Turakhanov, Aman; Markovic, Strahinja; Popov, Evgeny; Maksakov, Kirill; Usachev, Gennady; Karpov, Valery; Cheremisin, Alexey",Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance,Hot water injection; Carbonate reservoirs; Consolidated core; Cementation; Numerical simulation; Kinetic model,IN-SITU COMBUSTION; AQUATHERMOLYSIS; MODEL,"Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100-1500 m require technology that can achieve sufficiently high fluid temperature (250-300 degrees C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling. The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called ""aquathermolysis"" to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons. A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H-2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.",10,10,3
Oil Recovery,Degrees C,"Abalkhail, Nassir; Liyanage, Pathma Jith; Upamali, Karasinghe A. N.; Pope, Gary A.; Mohanty, Kishore K.",Alkaline-surfactant-polymer formulation development for a HTHS carbonate reservoir,Surfactant flooding; Enhanced oil recovery; Carbonate reservoir; High temperature; High salinity,MICROEMULSION PHASE; OIL,"There are many HTHS (high temperature, high salinity) carbonate reservoirs where temperature (>80 degrees C) and salinity (>30,000 ppm) are high. The goal of this study was to develop an alkaline-surfactant-polymer (ASP) formulation for a high temperature (similar to 100 degrees C), high salinity (similar to 60,000 ppm) giant carbonate reservoir with low surfactant retention, an essential requirement for low chemical cost. Phase behavior tests were conducted with anionic surfactants, alkali, co-solvents, brine, and crude oil to identify chemical formulations with ultra-low IFT under reservoir conditions. Corefloods were first conducted in outcrop carbonate cores and then in reservoir cores. The effluent was analyzed for oil, surfactant, pH, salinity and viscosity. Surfactant adsorption on carbonate surfaces decreases at high pH. Ammonia and a new organic alkali ethoxylated diisopropylamine (DIPA-10EO) were studied for this application since there is both anhydrite and dolomite in the formation. Sodium carbonate cannot be used as the alkali in rocks containing anhydrite, and sodium hydroxide cannot be used as the alkali in rocks containing dolomite. Ultralow IFT (similar to 0.001 mN/m) was achieved with several ASP formulations using the reservoir oil. The first three core floods in Indiana limestone yielded excellent tertiary oil recoveries of 85.2, 89.5 and 91.8%, and very low surfactant retentions of 0.06, 0.02, and 0.11 mg/g-rock, respectively. The reservoir coreflood resulted in 93.6% tertiary oil recovery and a final oil saturation of 1.2%. The surfactant retention was 0.083 mg/g-rock. The chemical formulation developed here is applicable to this high permeability, non-fractured, HTHS carbonate reservoir. Future research should address other carbonate reservoir issues such as fractures and low permeability.",9,9,1
Oil Recovery,Degrees C,"Vahdanikia, Nabi; Divandari, Hassan; Hemmati-Sarapardeh, Abdolhossein; Amar, Menad Nait; Schaffie, Mahin; Ranjbar, Mohammad","Integrating new emerging technologies for enhanced oil recovery: Ultrasonic, microorganism, and emulsion",Enhanced oil recovery; Water in oil emulsion; Surfactants; Biosurfactants; Ultrasonic,BIOSURFACTANT-PRODUCING BACTERIA; WATER-CONTENT; STABILITY; TEMPERATURE; DROPLETS; DEMULSIFICATION; VISCOSITY; CULTURE; SOLIDS; FIELD,"Water in oil emulsions have turned into interesting and attractive resources for enhanced oil recovery (EOR). The stability of emulsions is important for its efficiency as EOR agents. The objective of this study was to investigate the simultaneous influence of ultrasound waves and microorganisms on the stability of water-in-oil emulsions. To this end, using an Iranian crude oil, two types of waters, surfactants and three types of biosurfactants producing microorganisms the impacts of temperature, ultrasonic frequency, and radiation time on the stability, viscosity and surface tension of water-in-oil emulsions were studied. From the results of this study, it can be pointed out that compared to the conventional surface-active agents; biosurfactants have a higher impact on the stability of emulsions. In addition, under the optimum conditions of this study, the surface tension decreased about 15% and the stability increased nearby 20%. Ultrasonic radiation reduces emulsion stability by about 6%. The T.F. species have the greatest effect on the emulsion stability up to 70 degrees C (more than 85%). Micromodel flooding experiments showed that injection of T.F biosurfactants emulsion provides the highest oil recovery due to their high stability, high viscosity, and low surface tension.",9,9,1
Oil Recovery,Degrees C,"Liu, Peng; Shi, Lanxiang; Liu, Pengcheng; Li, Lei; Hua, Daode",Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs,Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery; Heterogeneity,ASSISTED GRAVITY DRAINAGE; RECOVERY; SOLVENT; PERFORMANCE; PRESSURE; GAS,"Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.",8,8,4
Oil Recovery,Degrees C,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Oil Recovery,Degrees C,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Oil Recovery,Degrees C,"Mustafin, Robert; Manasrah, Abdallah D.; Vitale, Gerardo; Askari, Roohollah; Nassar, Nashaat N.",Enhanced thermal conductivity and reduced viscosity of aegirine-based VR/VGO nanofluids for enhanced thermal oil recovery application,Nanoparticles; Vacuum residue; Vacuum gas oil; Nanofluids; Thermal conductivity; Oil recovery,HEAVY OIL; OXIDE NANOPARTICLES; CUO NANOPARTICLES; CARBON NANOTUBES; VOLUME FRACTION; CRUDE OILS; ADSORPTION; ASPHALTENES; TEMPERATURE; BITUMEN,"The depleting of the available conventional energy supplies together with an industrial shift towards unconventional resources like heavy oil/bitumen has become more pronounced. The steam-based heating methods are primarily used by the oil industry for the heavy oil/bitumen recovery. However, the thermal recovery methods are energy-intensive and have limited applications, especially for both thin and deep reservoirs. Therefore, there is a high priority need to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection. Hence, the continual improvement of this technique is of utmost importance. This study aims to propose a new injecting nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading and recovery. Here we report a new type of copper-based nanofluid using a blend of vacuum gas oil (VGO) and vacuum residue (VR) as the mother solvent. The nanoparticles were prepared by low-temperature hydrothermal synthesis route. Their detailed surface, morphology and size characterizations were achieved by X-ray diffraction, dynamic light scattering and scanning electron microscopy. The stable nanofluids were prepared by dispersing copper-based nanoparticles in a mixture of VGO and VR, at different ratios and temperatures. A set of measurements to determine the thermal conductivity and viscosity of the nanofluid with different loading of nanoparticle were performed. The thermal conductivity values of nanofluid systems are substantially higher than that of the base fluids. The nanofluid for 2 wt% of copper-doped aegirine nanoparticles dispersed in VGO and VGO/VR mixture exhibits a maximum thermal conductivity of 20% and 24%, respectively. It was found that the thermal conductivity of nanofluids increases with decreasing the hydrodynamic particle size. Moreover, the presence of chemo-physical interactions between nanoparticles and base fluid further enhances the thermal conductivity. Also, the temperature augmentation in a range from 80 to 110 degrees C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. This particular nanofluid may find potential applications in enhancing heavy oil upgrading and recovery.",7,7,5
Oil Recovery,Degrees C,"Hassan, Anas M.; Ayoub, M.; Eissa, M.; Bruining, Hans; Zitha, P.",Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding,Surface complexes; DLVO theory; Enhanced oil recovery (EOR); Smart water assisted foam (SWAF) flooding; Low-salinity; Wettability alteration; Foam flooding; Foam stability; Carbonate reservoirs; PHREEQC-Software,ACTIVITY-COEFFICIENT; OSMOTIC COEFFICIENTS; THERMODYNAMICS; ELECTROLYTES; TRANSPORT; MECHANISMS; CARBONATE; ORDER; PART; IRON,"This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25 degrees C) and at the reservoir-conditions (80 degrees C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Huckel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foamlaminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25 degrees C) and at (80 degrees C) than the high-salinity case for both (25 degrees C) and (80 degrees C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of ""Smart Water Assisted Foam (SWAF) Flooding"". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.",7,7,4
Oil Recovery,Residual Oil,"Chen, Hailong; Wang, Zhuangzhuang; Wang, Kai; Li, Zhaomin; Li, Songyan",Investigation of EOR mechanism for flue gas assisted SAGD,,RESIDUAL OIL SATURATION; GRAVITY DRAINAGE SAGD; HEAVY-OIL; STEAM CHAMBER; CONDENSATION; PRESSURE; RECOVERY; CO2; VISUALIZATION; PERFORMANCE,,15,15,6
Oil Recovery,Residual Oil,"Zhang, Juan; Zhang, Hui Xiao; Ma, Li Yan; Liu, Yi; Zhang, Liang",Performance evaluation and mechanism with different CO2 flooding modes in tight oil reservoir with fractures,CO2 injection; Flooding mechanism; Fractures; Tight reservoir; Miscible pressure,GAS; GENERATION; INJECTION; RECOVERY; EOR,"Due to the abundant reserves in tight reservoirs and the large amounts of residual oil after implementing common enhanced oil recovery methods, profitable methods with a high oil recovery such as CO2 flooding are urgently needed. Although CO2 flooding has attracted much attention and obtained good results in China and abroad, it has the critical problem of a low sweep efficiency, especially in tight reservoirs that develop with hydraulic fractures. In this study, the minimum miscible pressure of oil and CO2 was measured as 17.8 MPa, higher than the original formation pressure. Subsequently, the minimum miscible pressure was matched by means of numerical simulation, and the method of adding intermediate components to the injection CO2 was studied to reduce the miscible pressure in the study area. Afterwards, fractures were added to the geological model to study the mechanism of gas channeling under different CO2 injection modes. The continuous CO2 injection (CGI) mode requires the largest gas injection volume, which is easily affected by fractures and production pressure differences to form irregular gas channeling. Soaking alternating gas injection (SAG) can effectively supplement the formation pressure through periodic well switching, gas channeling delay, and radial gas flooding pattern formation. Water alternating CO2 (WAG) flooding can delay gas channeling, and the rhombus or square gas flooding pattern is formed due to the influence of the well pattern and well spacing. Foam flooding can better mitigate gas channeling but has a poor displacement effect. Through comparison of the various gas injection modes, it is concluded that WAG is the best CO2 flooding mode in the research area, and the cumulative increase in oil over 20 years can reach 390,466 t. The outcome of this work is important to CO2 flooding in tight reservoirs with fractures. The CO2 flooding mechanism in tight reservoir with fractures was examined.",14,14,12
Oil Recovery,Residual Oil,"Aljuboori, Faisal Awad; Lee, Jang Hyun; Elraies, Khaled A.; Stephen, Karl D.",The effectiveness of low salinity waterflooding in naturally fractured reservoirs,Low salinity (LoSal) waterflooding; Naturally fractured reservoirs (NFR's); Wettability alteration; Residual oil reduction; Qamchuqa reservoir,OIL-RECOVERY; BRINE COMPOSITION; MAUDDUD FORMATION; WATER INJECTION; WETTABILITY; FLOW; SIMULATION; SANDSTONE; FIELD,"Low Salinity (LoSal) waterflooding is a technique which promises to improve and enhance oil recovery. The method has been studied widely in the laboratories using various core plug samples of sandstones and carbonates. Most of the experimental outcomes have demonstrated the possibility of recovery increment in conventional reservoirs. Meanwhile, it is rare to find a discussion in these experiments about the effectiveness of LoSal waterflooding in naturally fractured reservoirs. In this paper, we investigate the potential benefits in fractured reservoirs using simulations. It is often reported from coreflood experiments that LoSal injection has the ability to alter the rock wettability and reduce residual oil saturations through chemical and physical interactions between the rock-oil-water system. Based on the published work, we have calculated relative permeability curves to represent the flow in regions flooded with LoSal water. This includes a qualitative representation of uncertainty. In this sense, the relative permeabilities are a proxy for any physical and chemical mechanisms which are not explicitly represented. The newly generated flow curves were applied to simulate LoSal waterflooding using a fine-scale model and a field scale model based on a fractured reservoir from the Middle East. The simulation results underline the benefits of LoSal whereby the oil recovery from fractured reservoirs can be increased. An additional benefit is the control of water production. The fine-scale modelling has provided an in-depth analysis and accurate estimation of the oil recovery without modelling artefacts or limitations, where an increment of (12-14)% of the Stock Tank Oil Initially In Place (STOIIP) were obtained under secondary and tertiary recovery scheme, respectively. The investigated scenarios demonstrated a sensitivity to the newly generated flow curves and how they affect the ultimate oil recovery. However, for the field scale model, a higher oil production rate has maintained during LoSal waterflooding up to 32 K BPD by the end of year fourteen compared with 25 K BPD in case of high salinity scenario, besides a reduction in the produced water by 35.7%. Therefore, the effectiveness of LoSal brine required a longer time frame to observe the improvements in the oil displacement or sweep efficiency.",13,13,2
Oil Recovery,Residual Oil,"Bruns, Fritjof; Babadagli, Tayfun",Heavy-oil recovery improvement by additives to steam injection: Identifying underlying mechanisms and chemical selection through visual experiments,Steam additives; Surfactants and solvents; Nanofluids and ionic liquids; Gravity and viscous displacement; Visual 2D experiments,,"To mimic the gravity assisted drainage and flooding type, steam displacement tests we performed previously (Bruns and Babadagli, 2017) on cores saturated with 27,000 cP heavy-crude-oil; a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. The majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, anionic surfactant (linear toluene sulfonate), non-ionic surfactants, biodiesel (thermally stable surface active agents), solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at a constant rate and pressure after being vaporized in an oven along with steam; the whole process was recorded with a camera. The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface and were observed to be the main reason for positive contribution of chemicals. Biodiesel exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the linear toluene sulfonate (LTS) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep). Non-ionic surfactants showed different emulsion capabilities and high efficiency in steam/condensate displacement with a higher HLB (hydrophile - lipophile balance) value.",12,12,3
Oil Recovery,Residual Oil,"Yang, Qianhong; Yao, Jun; Huang, Zhaoqin; Zhu, Guangpu; Liu, Lijun; Song, Wenhui",Pore-scale investigation of petro-physical fluid behaviours based on multiphase SPH method,Multiphase flow; Contact line dynamics; Porous media; Smoothed particle hydrodynamics; Enhance oil recovery,SMOOTHED PARTICLE HYDRODYNAMICS; LATTICE BOLTZMANN SIMULATION; OPEN-CHANNEL FLOWS; DELTA-PLUS-SPH; POROUS-MEDIA; RELATIVE PERMEABILITY; CONSERVATION PROPERTIES; 2-PHASE FLOW; MODEL; WETTABILITY,"In this work, a series of microscopic simulations are conducted to investigate the effect of wettability, flow rate and surface tension in porous system by using pairwise force smoothed particle hydrodynamics (PF-SPH) method. Firstly, a novel inflow and outflow boundary is introduced in the SPH framework. The overall proposed model is verified by two benchmarks. The test cases are run in the two dimensional heterogeneous porous media. The effect of wettability, flow rate and surface tension to the macroscopic parameters such as relative permeability and residual oil saturation are thoroughly examined. Through our simulations, we conclude that (i) the type of residual oil changes with contact angle; water wetting porous media has a higher level of waterless oil recovery period and the discrepancies of ultimate oil recovery efficiencies happen before water phase breaks through the outlet of porous media; the residual oil saturations present excellent linear correlations with contact angles; (ii) it's better to increase the flow rate at the high water cut stage (eg f(w) = 90%) in hydrophilic porous media and rise the flow rate at early water cut stage (eg f(w) = 0%) in lipophilic porous media; increasing the flow rate dramatically shortens the effective production time in strong oil wetting porous media; (iii) decreasing the surface tension could change the type of residual oil, which leads to the further extraction of oil film and cluster residual oil.",11,11,1
Oil Recovery,Residual Oil,"Das, A.; Nguyen, N.; Farajzadeh, R.; Southwick, J. G.; Vincent-Bonnieu, S.; Khaburi, S.; Al Kindi, A.; Nguyen, Quoc P.","Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs",Enhanced oil recovery; Foam; Microemulsion; Carbonate; High salinity; Low permeability,ADSORPTION; OIL,"Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging. In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 degrees C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.",10,10,7
Oil Recovery,Residual Oil,"Chen, Hailong; Li, Haifeng; Li, Zhaomin; Li, Songyan; Wang, Yujun; Wang, Jian; Li, Binfei",Effects of matrix permeability and fracture on production characteristics and residual oil distribution during flue gas flooding in low permeability/tight reservoirs,Flue gas flooding; Matrix permeability; Fracture; Residual oil distribution; Gas channeling point,HUFF-N-PUFF; HEAVY OIL; CO2; RECOVERY; TIGHT; STEAM; STORAGE; FOAM; INJECTION; DRIVE,"The effects of matrix permeability and fracture on production characteristics and residual oil distribution of flue gas flooding in low permeability/tight conditions are analyzed systematically by laboratory physical simulation experiments and low-field nuclear magnetic resonance (LFNMR) system. T2 spectra results show that the crude oil is mainly distributed in the corresponding macropores of 100-1000 ms before and after the flue gas injection, and the crude oil in macropores is produced in large quantities after the flue gas injection in both fracture and fracture-free low permeability/tight cores. Additionally, oil production performance indicates that matrix permeability has a remarkable effect in fracture-free low permeability/tight cores. T2 spectra combined with slice scanned images show the migration from the macropores to the medium and fine pores is more obvious in the core with high matrix permeability and the final residual oil distribution is more uniform compared to those of the core with low matrix permeability. Matrix permeability is inversely proportional to the gas channeling point and it has a linear relationships with the gas channeling point in a log-log plot in fracture-free low permeability/tight cores. Besides, fracture can significantly reduce the effect of matrix permeability on oil recovery. The presence of fracture weakens the migration of crude oil in low permeability/tight fracture cores, and the residual oil spreads throughout the core. Fracture plays a dominating role in the gas channeling points for different permeability cores.",9,9,15
Oil Recovery,Residual Oil,"Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Cheng, Gang; Yu, Xiaogang",Experiments and analysis on development methods for horizontal well cyclic steam stimulation in heavy oil reservoir with edge water,Heavy oil; Edge water; Cyclic steam stimulation; Physical simulation; Experiment,MULTI-THERMAL FLUID; RELATIVE PERMEABILITIES; RECOVERY; PERFORMANCE; PREDICTION; OIL/WATER; FLOW; TEMPERATURE; PARAMETERS; EFFICIENCY,"In the world, the reserves are very huge in heavy oil reservoirs with edge water. Therefore, the effective development of such reservoirs is of great significance for the petroleum supply. In this paper, in order to transfer aquifer energy from actual reservoir to 3D model, a novel method is established based on the elastic principle to achieve simulation of heavy oil reservoir with edge water. Then the oil-water or oil-steam relative permeability curves are measured to analyze flowing characteristics of oil and water under high temperatures. Finally, three kinds of development methods are studied experimentally including the conventional cyclic steam stimulation (CCSS), the water production at oil-water contact (WPOWC) and the water production for post steam stimulation (WPPSS). The results show that the oil viscosity and the water mobility both reduce at higher temperature; moreover, the residual oil saturation decreases but the mobile water saturation increases during temperature rising. For heavy oil reservoirs with edge water, all these characteristics are advantageous to increase oil production and decrease water production. According to the results of 3D experiments, in the process of steam injection, the heating range mainly concentrates near the wellbore and an obvious steam overlap can be observed. The oil recovery factor (ORF) of WPPSS is 8.21%, which is slightly higher than that of CCSS, however the cumulative oil steam ratio (COSR) of WPPSS is 0.96, which is obvious larger than that of CCSS. Comparing the three development methods, for WPPSS method, the same steam injection can make more oil production and the water channeling can be effectively restrained in the late cycle of CSS. The method of WPPSS can be chosen to develop heavy oil reservoirs with edge water.",9,9,5
Oil Recovery,Residual Oil,"Drexler, Santiago; Correia, Elton L.; Jerdy, Ana Carolina; Cavadas, Leandro A.; Couto, Paulo",Effect of CO2 on the dynamic and equilibrium interfacial tension between crude oil and formation brine for a deepwater Pre-salt field,Interfacial tension; CO2 flooding; Pre-salt reservoirs; WAG; Reservoir fluid characterization; Capillary forces; Dynamic IFT,ASPHALTENE; RESIN; SALINITY; SURFACTANT; SYSTEMS; PH,"Interfacial tension (IFT) between oil and brine is key to determine the Capillary Number, which governs capillary forces in the porous medium. As a result, changes in IFT affect the displacement efficiency and the residual oil saturation having direct impact on the Recovery Factor. Fluids in Pre-salt fields (offshore Brazil) have particular characteristics, such as high salinity in the brines, elevated content of asphaltenes and resins in the oils and high CO2 content in the produced gas for some fields. The effect of CO2 on the IFT depends on complex electrostatic and acid-base equilibria, and cannot be predicted by a single fluid property. This work presents the experimental study of the effect of CO2 dissolution on the IFT between a Pre-salt oil with a high total base number (TBN) and non-negligible total acid number (TAN) and a high salinity brine using the pendant drop technique. The oil and its asphaltenic fraction were characterized by Fourier-transform infrared spectroscopy, nuclear magnetic resonance spectroscopy, and elemental analysis identifying characteristic functional groups and indicating both acidic and basic polar functional groups. CO2 dissolution resulted in an IFT increase of 56% evidencing that, despite the high TBN of this oil, basic groups have low surface-activity. Moreover, a study of IFT as a function of pH showed that the maximum IFT was found in strongly acidic environments, but constant IFT values were obtained at neutral and basic pH values. Thus, the interfacial activity is governed by asphaltenes and resins with polar groups of varying acid/base behavior. The presence of CO2 also accelerated the dynamic behavior of IFT reducing the equilibrium time by 70%. This is caused by the reduction of oil viscosity, which impacts the relaxation time and enhances the diffusion of surface-active species towards the interface. The results in this work evidence that the CO2 content should be considered when modeling fluid properties for this type of reservoirs, as it affects the oil-brine IFT. In addition, for this oil with high content of surface-active compounds and non-negligible TAN and TBN, CO2 flooding does not contribute to reduce the IFT. Therefore, the efficiency of this Enhanced Oil Recovery technique in this type of field relies on viscosity reduction, miscible displacement and wettability alteration rather than IFT reduction.",9,10,4
Oil Recovery,Residual Oil,"Haq, Bashirul; Liu, Jishan; Liu, Keyu; Al Shehri, Dhafer",The role of biodegradable surfactant in microbial enhanced oil recovery,MEOR; Green surfactant; GEOR,INTERFACIAL-TENSION,"Many aerobic microorganisms can produce bio-surfactants which are capable of effectively reducing interfacial tensions between oil, water and rock. However, there are few publications on the production of bio-surfactants from anaerobic organisms. The combined effect of bio-surfactant, green surfactant and alcohol in the MEOR process, are not well understood yet and require further investigation. This experimental study was conducted to examine the effectiveness of combination of two microbial by-products, bio-surfactant and bio-alcohol, in recovering residual oil within the pores of rock. It also considered whether bio-surfactant capability could be improved by blending it with non-ionic green surfactant. Two formulations of surfactant and co-surfactant mixtures were selected for core-flood experiments based on phase behaviour study and IFT reduction to examine their potential for enhanced oil recovery. In the first formulation, JF-2 bio-surfactant was mixed with butanol; it was found that this formulation did not produce a significant quantity of incremental oil after water flooding. Lastly, a bio-surfactant (anionic) was blended with non-ionic green surfactant alkyl polyglucoside and butanol; this produced about 25% tertiary oil and 64% OIIP.",9,11,3
Oil Recovery,Residual Oil,"Feldmann, Felix; Strobel, Gion J.; Masalmeh, Shehadeh K.; AlSumaiti, Ali M.","An experimental and numerical study of low salinity effects on the oil recovery of carbonate rocks combining spontaneous imbibition, centrifuge method and coreflooding experiments",Low-salinity; Carbonates; Coreflooding; Centrifuge method; DuMuX; Numerical modeling,WETTABILITY; IMPACT; WATER,"Low-salinity waterflooding (LSF) is a relatively simple and cheap Enhanced Oil Recovery technique in which the salinity of the injected water is optimized to improve oil recovery over conventional waterflooding. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low-salinity effect, spontaneous imbibition and/or waterflooding experiments have been reported. This paper combines spontaneous imbibition, centrifuge and unsteady state (USS) coreflooding experiments to investigate low-salinity effects in carbonate samples. The experimental study used three brine compositions to investigate low-salinity effects. A high-saline Formation-water (salinity of 183.4 g/l), Sea-water (43.8 g/l) and 100-times Diluted-sea-water (0.4 g/l). Initially, a sequence of spontaneous imbibition experiments was conducted to screen the impact of connate and imbibing water composition on spontaneous oil recovery. After completing the spontaneous imbibition tests, the samples were drained inside a centrifuge to determine the impact of brine composition on residual saturation and capillary pressure. Moreover, three USS corefloodings were conducted to test the different brine compositions in secondary and tertiary injection mode. The spontaneous imbibition, centrifuge method and coreflooding tests showed a consistent trend. Compared to Formation-water and Sea-water, Diluted-sea water demonstrated the most promising potential to recover oil efficiently. The numerical part of the study includes the transparent development of a numerical centrifuge and coreflooding model on the top of the open-source simulator DuMu(x). The mathematical model formulation demonstrates that a simple numerical approach is sufficient to history match the centrifuge and coreflooding experiments. In line with the experimental data, the numerically derived capillary pressure and relative permeability showed an increasing water-wetting behavior as the salinity of the imbibing/injection water decreased. All implemented numerical models were validated against the commercially established Cydar software.",8,8,2
Oil Recovery,Residual Oil,"Agi, Augustine; Junin, Radzuan; Abdullah, Mohammed Omar; Jaafar, Mohd Zaidi; Arsad, Agus; Sulaiman, Wan Rosli Wan; Norddin, M. N. A. Mohd; Abdurrahman, Muslim; Abbas, Azza; Gbadamosi, Afeez; Azli, Nur Bashirah",Application of polymeric nanofluid in enhancing oil recovery at reservoir condition,EOR; Cissus populnea; IFT; Wettability; Ultrasound; Nanofluid,CRYSTALLINE STARCH NANOPARTICLES; INTERFACIAL-TENSION; SILICA NANOPARTICLE; GEMINI SURFACTANTS; ACID-HYDROLYSIS; TEMPERATURE; STABILITY; BEHAVIOR; ULTRASOUND; RHEOLOGY,"In this study, ascorbic acid was used to synthesize Cissus populnea nanoparticles (CPNP). The synthesized CPNP was isolated and the influence of the process variables on the physical properties were studied. The rheology of the formulated Cissus populnea nanofluid (CPNF) was measured and compared with Cissus populnea (CP) solution and commercial polymer xanthan. Moreover, the interfacial properties of CPNF were studied at various concentrations and temperatures, and the influence of salinity and their interaction with ultrasound was investigated. Sessile drop contact angle method was used to determine the wettability alteration efficiency of CPNF on an initially oil-wet sandstone core surface. Finally, CPNF and CP solutions were evaluated for EOR purposes at typical reservoir condition. The displacement process was scaled to reduce the number of parameters investigated using dimensionless parameters. The synthesis methods were efficient in generating sphere-shaped and elongated nanoparticles (50 nm mean diameter). Experimental results show that an increase in temperature of CP and CPNP yielded increased viscosity of the solutions in stark contrast to xanthan whose solution viscosity declines as the temperature increases. Besides, the CPNF was effective in lowering IFT at oil-water (O/W) interface and altered the wettability of the sandstone cores to water-wetting condition. The novel CPNF increased the oil recovery by 26% and was effective at high-temperature high-pressure (HTHP) reservoir condition. The result shows a transition from capillary dominated flow to gravity dominated flow as decrease in IFT decreased residual oil saturation and increased capillary and Bond number. The energy consumption and cost estimation of the proposed novel polymeric nanofluid shows it is cost-effective than conventional EOR chemicals.",8,8,2
Oil Recovery,Residual Oil,"Zhao, Han; Yang, Hongbin; Kang, Xin; Jiang, Haizhuang; Li, Menglan; Kang, Wanli; Sarsenbekuly, Bauyrzhan",Study on the types and formation mechanisms of residual oil after two surfactant imbibition,Imbibition; Surfactant; Micromodel; Residual oil; Interfacial film; Emulsion,POROUS-MEDIA; PORE-SCALE; SNAP-OFF; WATER; EMULSION; RECOVERY; WET; DISPLACEMENT; VISCOELASTICITY; PERFORMANCE,"For investigating the types and formation mechanisms of residual oil after surfactant imbibition, the easyemulsifying surfactant Sodium Dodecylbenzene Sulfonate (SDBS) and ultra-low interfacial tension surfactant Sodium Oleate (SOL) were selected. The visual micromodel was adopted to observe the oil morphologies, while the rheometer and the emulsion stability analyzer were applied to analyze formation mechanisms. According to micro experiments, the main types of residual oil after SDBS imbibition are columnar, cluster, blind-end and small drop residual oil whose structure was small fragmented droplet. As for SOL solution, they are mainly blindend and island residual oil. The formation mechanism of columnar and cluster residual oil is capillary force offsetting, the direction of capillary force forms the blind-end residual oil, while the Marangoni effect and snapoff effect are responsible for island residual oil. The small drop residual oil is from emulsification, which always appears at the intersection of multiple flows. The aromatic groups of SDBS can promote the emulsion more stable by increasing the strength of interfacial film, hence the small drop residual oil only exists after SDBS imbibition.",7,6,8
Oil Recovery,Residual Oil,"Luan, Yalin; Liu, Bing; Hao, Peng; Zhan, Kaiyun; Liu, Jianlin",Oil displacement by supercritical CO2 in a water cut dead-end pore: Molecular dynamics simulation,Supercritical CO2; Dead-end pore; Oil displacement; Molecular dynamics; Energy analysis,RECOVERY; INJECTION; DISSOLUTION; MECHANISMS; REDUCTION; MODELS,"Exploitation of residual oils from the micro/nanopores in the reservoir is one perpetual goal of Enhancing oil recovery (EOR), which presents a big challenge for both advanced technologies and fundamental theories. In the current study, we make a comprehensive molecular dynamics (MD) simulation on the displacement process of trapped oils inside a water cut dead-end pore driven by supercritical CO2 molecules. Firstly, the whole displacement process is fully demonstrated by snapshots of MD simulation. Next, the collapse details of the water film between carbon dioxide and octane are simulated, where the hydrogen bonds and the evolution of ruptured hole are discussed. Thirdly, the configuration of the oil-water interface is computed and analyzed by the Laplace equation. Fourthly, the displacement mechanism of octane by carbon dioxide is explained according to the energy principle. These findings can strengthen our understandings on the details of the residual oil displacement in rocks, which may provide some inspirations on the oil recovery enhancement.",7,7,8
Oil Recovery,Residual Oil,"Hassan, Anas M.; Ayoub, M.; Eissa, M.; Bruining, Hans; Zitha, P.",Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding,Surface complexes; DLVO theory; Enhanced oil recovery (EOR); Smart water assisted foam (SWAF) flooding; Low-salinity; Wettability alteration; Foam flooding; Foam stability; Carbonate reservoirs; PHREEQC-Software,ACTIVITY-COEFFICIENT; OSMOTIC COEFFICIENTS; THERMODYNAMICS; ELECTROLYTES; TRANSPORT; MECHANISMS; CARBONATE; ORDER; PART; IRON,"This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25 degrees C) and at the reservoir-conditions (80 degrees C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Huckel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foamlaminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25 degrees C) and at (80 degrees C) than the high-salinity case for both (25 degrees C) and (80 degrees C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of ""Smart Water Assisted Foam (SWAF) Flooding"". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.",7,7,4
Oil Recovery,Design,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Oil Recovery,Design,"Cheng, Linsong; Wang, Deqiang; Cao, Renyi; Xia, Rufeng",The influence of hydraulic fractures on oil recovery by water flooding processes in tight oil reservoirs: An experimental and numerical approach,Tight oil; Hydraulic fracture; Water flooding; Water breakthrough; Core flood experiment,HORIZONTAL WELLS; SHALE; FLOW; GAS; STORAGE; EOR,"The use of multi-fractured horizontal wells has helped to develop tight oil reservoirs, but, if oil depletion occurs, the estimated ultimate recovery is low. Water flooding can be regarded as an easily applied method for improving oil recovery. This study aimed to optimize the scale of the stimulated reservoir volume (SRV) by conducting an experiment to verify the water injection capacity of the Chang 7 Formation, which is situated within in a typical tight oilfield. A one-dimensional long core displacement experiment was designed based on injecting formation water into a tight matrix core and fractured cores with different fracture lengths. Results were then verified and analyzed using core flood simulation and targeted field tests, and they clarified the feasibility of injecting water into a tight oil formation when the injection well is fractured, or when fractures exist near the injection well. It was also verified that although fractures increase the equivalent permeability in the fractured core and promote pressure propagation, they can also lead to rapid water breakthrough if they communicate with the producer well. It is thus considered that optimization of the SRV extent would enhance the recovery of oil and decrease the risk of water breakthrough.",16,15,3
Oil Recovery,Design,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Oil Recovery,Design,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Oil Recovery,Design,"Zhong, Zhi; Sun, Alexander Y.; Wang, Yanyong; Ren, Bo",Predicting field production rates for waterflooding using a machine learning-based proxy model,Machine learning; Conditional deep convolutional generative adversarial neural network; Data-driven proxy model; Waterflooding; Field production rate,RESPONSE-SURFACE METHODOLOGY; ALTERNATING-GAS-INJECTION; RELATIVE PERMEABILITY; OIL-FIELD; WORK FLOW; OPTIMIZATION; PRESSURE; DESIGN,"Waterflooding, during which water is injected in the reservoir to increase pressure and therefore boost oil production, is extensively used as a secondary oil recovery technology. Tracking the extent and efficacy of waterflooding (i.e., fluid distributions) is a primary task of reservoir engineers and is traditionally achieved by running full reservoir models. In this work, we design and implement a proxy model using a conditional deep convolutional generative neural network (cDC-GAN), which can be used to quickly calculate the dynamic fluid distribution of a heterogeneous reservoir under waterflooding. Zero-sum game theory is the basis for the cDC-GAN, which includes a pair of generative discriminative models. The generative model tries to learn the relationship between input and output and makes the generated output as close as possible to the training data, while the discriminative model tries to distinguish the fake output and the real data used for training, such that the cDC-GAN learns the real data distribution at the end. In our cDC-GAN formulation, the reservoir properties (permeability distribution in this research) and forecast time information are treated as input, and water saturation is the desired output. The reservoir fluid production rate can be calculated based on the material balance principle. The most significant contribution of this work resides in training a cDC-GAN proxy model to accurately predict fluid saturation. A cDC-GAN has several advantages over the traditional full-model based workflow. First, the model parameters estimated from history matching help to improve reservoir characterization. Second, this proposed proxy model can predict the water and oil saturation distributions simultaneously, which can be used to calculate the water and oil flow rates. Third, this proposed proxy model can be used for waterflooding optimization and uncertainty analysis with far less computational effort than with the traditional method, which uses a reservoir simulator.",13,13,9
Oil Recovery,Design,"Qu, Ming; Hou, Jirui; Wen, Yuchen; Liang, Tuo",Nitrogen gas channeling characteristics in fracture-vuggy carbonate reservoirs,Fracture-vuggy carbonate reservoir; Gas channeling; Physical model; Gas flooding,BOTTOM-WATER DRIVE; N-2 INJECTION; MECHANISM,"Tahe Oilfield, located in Tarim Basin, Northwest China, is a typical carbonate fracture-vuggy reservoir. Nitrogen gas flooding is a vital technology for improving oil recovery by enlarging sweep volume in fracture-vuggy reservoirs. However, gas channeling restricts further application of nitrogen gas flooding. This paper studied the characteristics of gas channeling in fracture-vuggy carbonate reservoirs using physical simulation. Visual physical models and macroscopic physical models were designed and fabricated based on similarity criterion. Nitrogen gas flooding experiments were conducted in both types of models. Experimental results demonstrated that once the dominant channel of gas is formed, the remaining oil cannot be effectively swept. The greater the areal heterogeneity of fracture-vuggy carbonate reservoir is, the easier the formation of gas channeling is. Gas channeling was accompanied by a large amount of oil and water production. The initial gas channeling was followed by several additional occurrences of gas channeling. In addition, PIR risk assessment method was proposed to predict gas channeling by assigning values to each coefficient of P, I and R. This method verified by oilfield data can be used to prevent and evaluate the risk of gas channeling in fracture-vuggy carbonate reservoirs.",12,13,14
Oil Recovery,Design,"Liu, Zhao-xia; Liang, Yan; Wang, Qiang; Guo, Yong-jun; Gao, Ming; Wang, Zheng-bo; Liu, Wan-lu",Status and progress of worldwide EOR field applications,Chemical flooding; Gas injection; Thermal recovery; Smart water flooding; EOR; Field application,PREFORMED PARTICLE GEL; CONFORMANCE-CONTROL; BRINE COMPOSITION; POROUS-MEDIA; OIL-RECOVERY; CO2 PILOT; NANOTECHNOLOGY; RESERVOIR; FLOOD; NANOMATERIALS,"Nowadays, EOR has been an important research topic in oilfield development and has made greater contribution to worldwide oil production. Whereas, a few of available statistical resources and the lack of systematical analysis hinder the understanding of the latest status and progress of different EOR technologies. This work, on the basis of systematic survey and data collection, makes a latest overview and analysis of worldwide EOR field application cases and gives a systematical discussion and summary from various aspects of different EOR methods (chemical flooding, gas injection, thermal recovery and smart water flooding, etc.), involving development status, maturity, advantages and limitations and so forth. Moreover, some reservoir statistics of some EOR field application cases in China (from 2008) and other countries (from 2014) are systematically presented and discussed. The work not only is beneficial for the reservoir workers to share the successful experience and learn the lessons of failure in oilfield development plan design and operation, but also is helpful to grasp the latest development status and maturity of EOR field applications and to provide important guarantee for the future development of different EOR techniques.",12,12,10
Oil Recovery,Design,"Bruns, Fritjof; Babadagli, Tayfun",Heavy-oil recovery improvement by additives to steam injection: Identifying underlying mechanisms and chemical selection through visual experiments,Steam additives; Surfactants and solvents; Nanofluids and ionic liquids; Gravity and viscous displacement; Visual 2D experiments,,"To mimic the gravity assisted drainage and flooding type, steam displacement tests we performed previously (Bruns and Babadagli, 2017) on cores saturated with 27,000 cP heavy-crude-oil; a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. The majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, anionic surfactant (linear toluene sulfonate), non-ionic surfactants, biodiesel (thermally stable surface active agents), solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at a constant rate and pressure after being vaporized in an oven along with steam; the whole process was recorded with a camera. The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface and were observed to be the main reason for positive contribution of chemicals. Biodiesel exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the linear toluene sulfonate (LTS) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep). Non-ionic surfactants showed different emulsion capabilities and high efficiency in steam/condensate displacement with a higher HLB (hydrophile - lipophile balance) value.",12,12,3
Oil Recovery,Design,"Datta, Poulami; Tiwari, Pankaj; Pandey, Lalit M.",Oil washing proficiency of biosurfactant produced by isolated Bacillus tequilensis MK 729017 from Assam reservoir soil,Biosurfactant production; Optimization; Wetting; Surface tension; Oil washing efficiency; Emulsion,CELL-SURFACE HYDROPHOBICITY; CRUDE-OIL; INTERFACIAL-TENSION; RAPID IDENTIFICATION; RECOVERY; OPTIMIZATION; WETTABILITY; STRAIN; WATER; MEOR,"The present study describes elaborately the isolation of a potential biosurfactant producing and crude oil degrading strains isolated from the reservoir soil of Assam oil reservoir field. The produced biosurfactant was chemically characterized for its applicability for the enhanced oil recovery applications in terms of wetting, interfacial tension (IFT) and oil washing. From the seven isolated strains, Bacillus tequilensis MK 729017 was chosen based on the better surface active properties as it reduced the surface tension to 30 +/- 2 mN/m along with a moderate emulsification index of 66 +/- 2%. The produced biosurfactant was chemically identified to be lipopeptide, surfactin with a lower critical micelle concentration value of 90 mg/L. The carbon source and environmental parameters were optimized for the maximum concentration of the biosurfactant using response surface methodology based on the central composite design (RSM-CCD). The maximum biosurfactant concentration was measured to be 7.46 +/- 0.39 g/L and Y-PS was determined as 0.45. The specific growth rate of the isolate was 0.15 +/- 0.01 h(-1) and Y-XS was estimated as 0.1. The produced biosurfactant was also found to be thermal and colloidal stable. The biosurfactant solutions altered wettability of hydrophobic rock surface from 90 +/- 1 degrees to 26 +/- 1 degrees indicating a better interfacial interaction. The IFT of the produced biosurfactant was found to be 0.32 +/- 0.02 mN/m. The oil washing efficiency (80 +/- 2%) of the produced surfactin was comparable with chemical surfactants and the process involved two-step: initial a faster (surface) washing followed by a slower (internal) washing. The first process was dependent on micelle sizes, while the latter was dependent on water-oil emulsion size. The lower emulsion size of surfactin contributed to a greater internal washing as compared to chemical surfactants.",12,12,2
Oil Recovery,Design,"Sun, Qian; Ertekin, Turgay",Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies,Artificial neural network; Polymer injection; Optimization; EOR screening; EOR project design,ALGORITHM,"Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.",11,11,2
Oil Recovery,Design,"Eren, Tuna; Polat, Can",Natural gas underground storage and oil recovery with horizontal wells,Reservoir engineering; Production engineering; Reservoir simulation; Underground gas storage; Horizontal well design,,"In this research study a reservoir simulation is conducted to compare the performance of the wells in a depleted oilfield for Enhanced Oil Recovery (EOR) and subsequent Underground Natural Gas Storage considering different well profiles including vertical and horizontal trajectories. The underground gas is simulated to be stored at an increasing reservoir pressure up to a magnitude that is to 85% of the initial pressure, and reservoir pressure remains constant throughout. The results of the simulations reveal more oil which can be potentially recovered by means of developing the field with horizontal wells. The extended component transformation between the oil and gas phases, additional viscosity reduction in oil phase, low gas oil ratio, and favoring bottomhole pressures attained by means of horizontal wells has shown to be considerably effective for EOR and underground storage applications.",10,11,7
Oil Recovery,Design,Liu Shun; Ni Jun; Wen Xianli; Liu Xiong; Huang Zhaoqin; Zhou Desheng; Ren Pengju,A dual-porous and dual-permeable media model for imbibition in tight sandstone reservoirs,Imbibition; Numerical model; imbibition index; Tight sandstone reservoir,OIL; RECOVERY,"Tight sandstone is an important oil reservoir in China which development is required water flooding. During water flooding treatments, imbibition is proven to strongly affect oil displacement. In this paper, capillary pressure is found not to be the only driving force to control imbibition in tight sandstone rock. Imbibition index is defined to be the second driving force. An experiment was designed to prove the imbibition index when water contacted tight sandstone samples. Then, a dual-porosity and dual-permeability numerical model was developed to simulate imbibition effect during water flooding in tight sandstone formations. Experimental results indicated that imbibition caused the weight of samples increased first and then declined. Increase is controlled by capillary force, and decline is affected by imbibition index. In Changqing formation in China, the imbibition index is 0.17-0.24, and the average imbibition index is 0.21.",9,9,12
Oil Recovery,Design,"Yang, Xi; Dindoruk, Birol; Lu, Ligang",A comparative analysis of bubble point pressure prediction using advanced machine learning algorithms and classical correlations,"Bubble point pressure; PVT; Fluid properties; Machine learning methods (XGBoost, LightGBM, random forest regressor, MLP neural network, and super learner); Correlations",PVT PROPERTIES; SUPER LEARNER; MODEL,"The need for fluid properties or PVT (Pressure-Volume-Temperature) properties, is part of the entire Exploration and Production (E&P) lifecycle from exploration to mature asset management to the typical later life events such as, Improved Oil Recovery (IOR). As the projects mature, the need for such data and its integration for various discipline-specific workflows and its interpretation in the light of reservoir performance varies. Among all the key PVT properties, bubble point pressure is probably the most important parameter. Bubble point pressure is important because it is the point at which constant composition and variable composition portions of the depletion paths merge. Geometrically, bubble point pressure appears to be a discontinuity. In addition, it dictates the existence (or not) of the incipient phase (i.e., gas phase) leading to the changes in the flow characteristics both in porous media and as well as within the wellbore and the facilities. Furthermore, it is also a good indicative of a possible gas cap when the reservoir is at saturation (reservoir pressure is equal to the bubble point pressure) or near-saturated. Among the highlighted uses, there are many more used such as the determination of the elements of miscibility, gas lift design, etc. Therefore, it is very important to estimate the bubble point pressure accurately. In this study, tree-based advanced machine learning algorithm including XGBoost, LightGBM, and random forest regressor, and multi-layer perceptron (neural network) regressor are implemented to predict bubble point pressure (P-bp). A novel super learner model which is also known as stacking ensemble is used to enhance base machine learning model performance on predicting bubble point pressure. Three datasets with different predictors are prepared to study machine learning algorithms' performance for three situations: only compositional data are available; only bulk properties (Gas-Oil-Ratio, gas gravity, API gravity and reservoir Temperature) are available; both compositional data and bulk properties are available. Through literature review, there is no research on using only compositional data and temperature to predict bubble point pressure. Our super learner model offers an accurate solution for oil bubble point pressure when only compositional data and temperature are available. Machine learning models perform better than empirical correlations with limited input data (i.e., bulk properties). When compositional data and bulk properties are all used as predictors, super learner reaches about 5.146% mean absolute relative error on predicting the bubble point pressure from global samples with bubble point pressures in the range of 100 to 10,000 psi, which is a wider range compared to most ANN models published in literature.",9,9,1
Oil Recovery,Design,"Aldhaheri, Munqith; Wei, Mingzhen; Zhang, Na; Bai, Baojun",Field design guidelines for gel strengths of profile-control gel treatments based on reservoir type,Enhanced oil recovery; Excessive water production; Conformance improvement; Gel treatments; Field project survey; Gel strength designs; Field design guidelines,POLYMER GEL,"Bulk gels are increasingly applied to alleviate the costly burden of excessive water production in mature oil fields. Practically, designs of new treatments are adopted from previous field projects conducted in analogous reservoirs. This case-finding procedure requires reservoir engineers to have thorough knowledge about how gel treatments, for each reservoir type, should be designed and have been mostly applied. This paper presents comprehensive design guidelines for injection-well gel treatments based on 61 worldwide field projects. It also assesses typical and most-applied designs and introduces them as new designing strategy. Seven gel strength design parameters were evaluated using the univariate descriptive analysis, stacked histograms, and scatterplots. Results indicated that gel strength parameters have very wide ranges and are considerably affected by the formation type. Gel treatments typically start with 3000 ppm polymer concentration, end with 7600 ppm, and a constant polymer-crosslinker ratio (PCR) of 40:1 is maintained during the treatments. They are often performed using the injection waters (to avoid type II gel syneresis) and polymers of 10-11 MM Da molecular weight (MW) and 30% hydrolysis that are injected in 4-5 treatment stages. The gel strength is principally designed based on the problem channeling strength and the planned gel volume. However, in cases of void-space-type problems, the gel extrusion, breakthrough, and breakdown become important designing criteria. To address these issues, more advanced tapering schemes than normal gradual increase of polymer concentrations are used to optimize gel plugging efficiency. In these schemes, small volumes of cement or low MW, fast-maturing, rigid gels (i.e., MARA-SEAL (TM)) are injected in front (gels only) or behind the high-MW MARCITsm gels as capping-materials. The novelty of present review lies in providing conformance specialists with new design strategy that would markedly facilitate designing of gel treatments and save time needed to identify analogs for a given candidate reservoir.",8,8,5
Oil Recovery,Design,"Kumar, Amit; Mandal, Ajay",Core-scale modelling and numerical simulation of zwitterionic surfactant flooding: Designing of chemical slug for enhanced oil recovery,Enhanced oil recovery; Zwitterionic surfactant; Core flooding; Simulation; CMG-STARS,,"Surfactant flooding is a proven enhanced oil recovery method for the recovery of trapped crude oil from the pores of the reservoir. In the present study, the applicability of a synthesized zwitterionic surfactant as an efficient EOR agent was tested, in terms of its interfacial tension reduction capability, emulsification behavior, and wettability modification behavior. Core flooding experiments conducted in sandstone core with the injection of 0.3 pore volume of chemical slug after water flooding showed 20% of additional oil recovery. The core flooding experiment was simulated using CMG-STARS simulator and history matching of relative permeability curve and its interpolation parameters were done. The validated model closely represented the experimental core flooding with very low error of 6%. The validated model helps in understanding the movement of crude oil and its interaction with the injected surfactant slug in the porous media. The validated model was further used for optimization of injected chemical slug by varying the parameters such as the surfactant concentration in the injected slug, the volume of injected chemical slug, and the injection rate of chemical slug. Each parameter had different effects on the oil recovery efficiency and cumulative oil recovery of more than 90% OOIP was obtained using model with injection of 1 PV of chemical slug containing 100 ppm of surfactant with the injection rate of 0.3 mL/min. The simulation of core flooding helped in optimization of crude oil production by zwitterionic surfactant and its implementation on field scale production by zwitterionic surfactant flooding.",8,8,4
Oil Recovery,Design,"Wei, Bing; Liu, Jiang; Zhang, Xiang; Xiang, Hua; Zou, Peng; Cao, Jie; Bai, Mingxing",Nuclear Magnetic Resonance (NMR) mapping of remaining oil distribution during sequential rate waterflooding processes for improving oil recovery,Waterflooding; Sequential rate mode; Remaining oil saturation; NMR; Enhanced oil recovery,CHEMICAL-TRACER TESTS; SILICA NANOPARTICLES; POROSITY TYPES; POROUS-MEDIA; FLOW; DISPLACEMENT; CHALLENGES; CAPILLARY; RESERVOIR; FORCES,"At the conclusion of waterflooding phase, significant volume of oil still remains in reservoir formations. In this paper, waterflooding was performed at a designed sequential rate mode with an aim to further reduce the remaining oil saturation (S-or). Waterflooding process was monitored continuously by a low-field Nuclear Magnetic Resonance (NMR) spectrometer attempting to map pore-scale displacing behaviors and also quantify the reduction in S-or in-situ. The results showed that the main pore size of the cores ranged from 1.6 mu m to 63.0 mu m inferred by T-2 (transverse relaxation time) distributions. The value of S-or in the cores increased towards the outlet face during waterflooding because of capillary end effect, which became more significant for heavy oil. At the termination of this waterflooding process, S-or was found to be further reduced by approximately 5.0% in the presence of thief water pathways as a result of the improved viscous forces. Water fingering and capillary imbibition effects were clearly visualized in the NMR images. These observations are expected to be useful for heavy oil waterflooding operations especially in post-breakthrough phase.",8,8,4
Oil Recovery,Injection Rate,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Oil Recovery,Injection Rate,"Lang, Liyuan; Li, Huabin; Wang, Xiong; Liu, Ning",Experimental study and field demonstration of air-foam flooding for heavy oil EOR,Heavy oil; Foam; EOR,NITROGEN FOAM; RECOVERY; INJECTION; TEMPERATURE; BEHAVIOR,"Foam flooding is an effective oil displacement technique to improve fluid sweep efficiency and increase oil recovery. The objective of this study is to investigate the application of air-foam for heavy oil recovery under heterogeneous reservoir conditions. The paper first investigated the air-foam flow behavior in porous media and identified the effects of different factors such as gas-liquid ratio, injection rate, and crude oil saturation on air-foam resistance. Then, dual-tube sand-packs were used to evaluate the performance of air-foam for heavy oil recovery from heterogeneous reservoir conditions. The results indicated that the air-foam could divert the fluid from the high-permeability zone to the low-permeability zone, decrease the water cut and improve the oil recovery. Further studies revealed that there existed an optimal reservoir permeability contrast ratio in air-foam flooding for heavy oil recovery. The air foam performance for oil recovery would be reduced beyond or below this permeability contrast ratio. Finally, field tests on air-foam for heavy oil recover demonstrated that air foam flooding could increase heavy oil production rate and decrease the production water cut.",16,17,7
Oil Recovery,Injection Rate,"Chen, Meng; Dai, Jiacai; Liu, Xiangjun; Kuang, Yan; Wang, Zhongtao; Gou, Shunchao; Qin, Minjun; Li, Min",Effect of displacement rates on fluid distributions and dynamics during water flooding in tight oil sandstone cores from nuclear magnetic resonance (NMR),Tight oil sandstone cores; Water flooding; Displacement rate; Nuclear magnetic resonance; Oil distribution,CRITICAL CAPILLARY NUMBER; HUFF-N-PUFF; PERFORMANCE EVALUATION; SPONTANEOUS IMBIBITION; CO2 INJECTION; RECOVERY; RESERVOIR; BAKKEN; STATE; FLOW,"Water flooding is widely used as an economical and recyclable method to improve oil recovery in unconventional reservoirs. In this study, the effects of injection rates on oil distribution, the seepage dynamics and the contributions of increasing injection rates on enhancing oil recovery during water flooding are investigated. Typical tight oil sandstone cores with different permeabilities are obtained from Junggar Basin, Northwest China, for experimental studies that incorporate nuclear magnetic resonance analyses. Synthetic kerosene (viscosity = 11.2 mPa s) and heavy water (D2O) are used to simulate crude oil and formation water under formation conditions. The samples are first saturated with simulation water and thereafter displaced by synthetic oil until no water is produced to simulate the fully oil-saturated condition. To simulate the water flooding process, the samples are stably displaced by simulation water at injection rates increasing from 0.01 mL/min until no oil is produced. The T-2 spectra, injection pressures, and produced oil at different injection rates and water injection volumes are measured simultaneously. The transverse relaxation time (T-2) is converted for the corresponding pore-throat radius (r) by combining pore-throat size distributions (obtained from constant-rate mercury injection) and the fully oil saturated T-2 spectra. It indicates that the amplitude of T-2 spectra for macropore (>100 mu m) and mesopore (10-100 mu m) spaces decreases more rapidly than those for the micropore spaces (0-10 mu m) as injection rate increases. The classical capillary number theory is introduced to represent the effect of injection rate and characterize the dynamics of seepage processes. Results show that the oil recovery factor can be considerably improved by increasing the injection rate in tight oil cores, and this significant improvement is primarily attributed to mesopores and micropores.",15,15,7
Oil Recovery,Injection Rate,"Zhong, Zhi; Sun, Alexander Y.; Wang, Yanyong; Ren, Bo",Predicting field production rates for waterflooding using a machine learning-based proxy model,Machine learning; Conditional deep convolutional generative adversarial neural network; Data-driven proxy model; Waterflooding; Field production rate,RESPONSE-SURFACE METHODOLOGY; ALTERNATING-GAS-INJECTION; RELATIVE PERMEABILITY; OIL-FIELD; WORK FLOW; OPTIMIZATION; PRESSURE; DESIGN,"Waterflooding, during which water is injected in the reservoir to increase pressure and therefore boost oil production, is extensively used as a secondary oil recovery technology. Tracking the extent and efficacy of waterflooding (i.e., fluid distributions) is a primary task of reservoir engineers and is traditionally achieved by running full reservoir models. In this work, we design and implement a proxy model using a conditional deep convolutional generative neural network (cDC-GAN), which can be used to quickly calculate the dynamic fluid distribution of a heterogeneous reservoir under waterflooding. Zero-sum game theory is the basis for the cDC-GAN, which includes a pair of generative discriminative models. The generative model tries to learn the relationship between input and output and makes the generated output as close as possible to the training data, while the discriminative model tries to distinguish the fake output and the real data used for training, such that the cDC-GAN learns the real data distribution at the end. In our cDC-GAN formulation, the reservoir properties (permeability distribution in this research) and forecast time information are treated as input, and water saturation is the desired output. The reservoir fluid production rate can be calculated based on the material balance principle. The most significant contribution of this work resides in training a cDC-GAN proxy model to accurately predict fluid saturation. A cDC-GAN has several advantages over the traditional full-model based workflow. First, the model parameters estimated from history matching help to improve reservoir characterization. Second, this proposed proxy model can predict the water and oil saturation distributions simultaneously, which can be used to calculate the water and oil flow rates. Third, this proposed proxy model can be used for waterflooding optimization and uncertainty analysis with far less computational effort than with the traditional method, which uses a reservoir simulator.",13,13,9
Oil Recovery,Injection Rate,"Lai, Nanjun; Wen, Yiping; Yang, Zhidong; Chen, Jianlin; Zhao, Xubin; Wang, Dongdong; He, Wei; Chen, Yuemei",Polymer flooding in high-temperature and high-salinity heterogeneous reservoir by using diutan gum,High-temperature; High-salinity; Strong heterogeneity; Diutan gum; Rheological properties; Oil displacement experiments,LASER-LIGHT SCATTERING; HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; WATER-SOLUBLE COPOLYMERS; RHEOLOGICAL PROPERTIES; SOLUTION BEHAVIOR; PROFILE-CONTROL; OIL-RECOVERY; ACRYLAMIDE; DISPLACEMENT; XANTHAN,"Diutan gum, a biopolymer that has been widely used in cement and concrete industries, was introduced in this work to alleviate severe viscosity loss and the poor water solubility of polyacrylamide and its modified products in high-temperature and high-salinity reservoirs. Diutan gum is an exopolysaccharide secreted by sphingomonas. The rheological properties and capacity of diutan gum to enhance oil recovery in high-temperature and highsalinity heterogeneous reservoir (T = 130 degrees C, Total salinity = 223.07 g L-(1), V-k = 0.93) was investigated and compared with those of two other kinds of biopolymer thickeners (xanthan and konjac gum), which are commonly used in oilfield development. The three biopolymers show pseudoplastic fluid properties in a steadystate rheological test: given the strong interactions in the double-helix structure of diutan gum, the number of the Newtonian zone and the shear rate of this zone are higher than the those of the two other biopolymers. The storage modulus (G') of diutan gum are higher than its loss modulus (G '') in all the concentrations and frequencies measured through viscoelasticity tests. This result indicates that diutan gum exhibits remarkable elasticity in slow displacement speed while it seeping in porous media. The capability of establish flow resistance in high-permeability porous medium in high-temperature and high-salinity environment by three biopolymers was studied, and their viscosity and microscopic properties of injected and produced fluid were investigated to understand the reason why diutan gum can have good fluidity control ability. Oil displacement efficiency can be improved by the elasticity of the diutan gum even without an increase in displacement speed. The results of the oil displacement experiments in the heterogeneity model imply that diutan gum is more effective in improving the water injection profile of each layer than xanthan and konjac gum. The water channeling in the high-permeability layer is restrained, and the sweep ability of the displacement phase is improved. Furthermore, the effect of polymer flooding can be maintained for a long time. Under high-temperature, high-salinity and strong heterogeneity, diutan gum recovers 19.34% of original oil in place (OOIP). This value is higher than the values obtained with xanthan gum (14.15% OOIP) and konjac gum (8.60% OOIP). This finding implies that the diutan gum has great application potential in the development of high-temperature and high-salinity reservoirs with strong heterogeneity.",13,12,7
Oil Recovery,Injection Rate,"Aljuboori, Faisal Awad; Lee, Jang Hyun; Elraies, Khaled A.; Stephen, Karl D.",The effectiveness of low salinity waterflooding in naturally fractured reservoirs,Low salinity (LoSal) waterflooding; Naturally fractured reservoirs (NFR's); Wettability alteration; Residual oil reduction; Qamchuqa reservoir,OIL-RECOVERY; BRINE COMPOSITION; MAUDDUD FORMATION; WATER INJECTION; WETTABILITY; FLOW; SIMULATION; SANDSTONE; FIELD,"Low Salinity (LoSal) waterflooding is a technique which promises to improve and enhance oil recovery. The method has been studied widely in the laboratories using various core plug samples of sandstones and carbonates. Most of the experimental outcomes have demonstrated the possibility of recovery increment in conventional reservoirs. Meanwhile, it is rare to find a discussion in these experiments about the effectiveness of LoSal waterflooding in naturally fractured reservoirs. In this paper, we investigate the potential benefits in fractured reservoirs using simulations. It is often reported from coreflood experiments that LoSal injection has the ability to alter the rock wettability and reduce residual oil saturations through chemical and physical interactions between the rock-oil-water system. Based on the published work, we have calculated relative permeability curves to represent the flow in regions flooded with LoSal water. This includes a qualitative representation of uncertainty. In this sense, the relative permeabilities are a proxy for any physical and chemical mechanisms which are not explicitly represented. The newly generated flow curves were applied to simulate LoSal waterflooding using a fine-scale model and a field scale model based on a fractured reservoir from the Middle East. The simulation results underline the benefits of LoSal whereby the oil recovery from fractured reservoirs can be increased. An additional benefit is the control of water production. The fine-scale modelling has provided an in-depth analysis and accurate estimation of the oil recovery without modelling artefacts or limitations, where an increment of (12-14)% of the Stock Tank Oil Initially In Place (STOIIP) were obtained under secondary and tertiary recovery scheme, respectively. The investigated scenarios demonstrated a sensitivity to the newly generated flow curves and how they affect the ultimate oil recovery. However, for the field scale model, a higher oil production rate has maintained during LoSal waterflooding up to 32 K BPD by the end of year fourteen compared with 25 K BPD in case of high salinity scenario, besides a reduction in the produced water by 35.7%. Therefore, the effectiveness of LoSal brine required a longer time frame to observe the improvements in the oil displacement or sweep efficiency.",13,13,2
Oil Recovery,Injection Rate,"Bruns, Fritjof; Babadagli, Tayfun",Heavy-oil recovery improvement by additives to steam injection: Identifying underlying mechanisms and chemical selection through visual experiments,Steam additives; Surfactants and solvents; Nanofluids and ionic liquids; Gravity and viscous displacement; Visual 2D experiments,,"To mimic the gravity assisted drainage and flooding type, steam displacement tests we performed previously (Bruns and Babadagli, 2017) on cores saturated with 27,000 cP heavy-crude-oil; a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. The majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, anionic surfactant (linear toluene sulfonate), non-ionic surfactants, biodiesel (thermally stable surface active agents), solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at a constant rate and pressure after being vaporized in an oven along with steam; the whole process was recorded with a camera. The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface and were observed to be the main reason for positive contribution of chemicals. Biodiesel exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the linear toluene sulfonate (LTS) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep). Non-ionic surfactants showed different emulsion capabilities and high efficiency in steam/condensate displacement with a higher HLB (hydrophile - lipophile balance) value.",12,12,3
Oil Recovery,Injection Rate,"Chen, Hongquan; Onishi, Tsubasa; Olalotiti-Lawal, Feyi; Datta-Gupta, Akhil",Streamline tracing and applications in embedded discrete fracture models,Fractured reservoir; Streamline tracing; Embedded discrete fracture models; Flow diagnostics; Water flood optimization,FLOW DIAGNOSTICS; SHALE FORMATION; PATH LINES; BLACK-OIL; SIMULATION; RESERVOIR; PRESSURE,"Fractures play important role in unconventional resources by influencing the fluid flow pattern underground. Streamline-based flow diagnostic is important to the history matching or operational optimization process of fractured reservoirs. This paper presents a robust streamline tracing framework for use in the Embedded Discrete Fracture Models (EDFM) and several applications including flow visualization, flow diagnostics, and rate allocation optimization. The proposed streamline tracing framework is based on a boundary layer method that can honor the flux communications between the matrix and fractures or between fracture and fracture. The proposed method is benchmarked with a semi-analytical solution and its robustness is illustrated by a series of numerical examples encompassing different levels of geologic and geometrical complexity. Streamlines in complex fracture networks provide flow diagnostics such as sweep efficiency and connectivity of wells and fractures. The streamlines are then utilized to develop a workflow for rate allocation optimization for waterflood in naturally fractured reservoirs. We apply a streamline-based gradient free algorithm whereby both injection and production rates are adjusted under realistic operational constraints to a field scale fractured reservoir. This approach only requires a few forward simulations and therefore offers significant advantage in terms of computational efficiency. It is confirmed that the optimized schedule provides improvements in oil recovery and sweep efficiency compared to the base scenario with uniform injection and production rates.",11,11,1
Oil Recovery,Injection Rate,"Alade, Olalekan S.; Hamdy, Mohamed; Mahmoud, Mohamed; Al Shehri, Dhafer A.; Mokheimer, Esmail; Patil, Shirish; Al-Nakhli, Ayman",A preliminary assessment of thermochemical fluid for heavy oil recovery,Enhanced oil recovery; Heavy oil; Thermal methods; Insitu heat generation; Thermochemical fluids,INJECTION; EXTRACTION; BITUMEN,"Commercial production of heavy oil has heavily relied upon steam injection method due to its effectiveness to reduce the viscosity and improved mobility. However, due to uncertainty of oil price, high energy cost, water requirement, heat loss, and environmental issues, attention is being given to new thermal EOR technologies such as insitu steam generation using thermochemical fluid (TCF) injection. This technology essentially involves downhole generation of heat and pressure from exothermic chemical reaction. In this investigation, thermochemical reactants were injected, at different temperatures (100, 50, and 30 degrees C) and constant rate of 0.5 ml/mln, into Berea sandstone core samples saturated with heavy oil (18 %wt./wt. asphaltene content and 11 degrees API) and brine. It was observed that the pressure generated at the inlet of the core due to 100, 50, and 30 degrees C injection temperatures of the thermochemical fluids rose to 1600, 1200, and 280 psi, respectively; while the recovery factor was 83%, 66% and 54% OOIP, respectively. In comparison, from the injection of steam generated at 250 degrees C, the pressure at the inlet of the core was 212 psi and the recovery factor was 71% OOIP. These results therefore confirm increase in interest in the application of the TCF injection technology in heavy oil production.",11,11,0
Oil Recovery,Injection Rate,"Askarova, Aysylu; Turakhanov, Aman; Markovic, Strahinja; Popov, Evgeny; Maksakov, Kirill; Usachev, Gennady; Karpov, Valery; Cheremisin, Alexey",Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance,Hot water injection; Carbonate reservoirs; Consolidated core; Cementation; Numerical simulation; Kinetic model,IN-SITU COMBUSTION; AQUATHERMOLYSIS; MODEL,"Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100-1500 m require technology that can achieve sufficiently high fluid temperature (250-300 degrees C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling. The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called ""aquathermolysis"" to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons. A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H-2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.",10,10,3
Oil Recovery,Injection Rate,"Zhao, Yan",Laboratory experiment and field application of high pressure and high quality steam flooding,Heavy oil; Steam flooding; Pressure; Steam quality; Recovery factor,,"Steam flooding is an effective way to improve oil recovery after steam huff and puff for heavy oil reservoirs. The typical screening criteria for steam flooding requires reservoir pressure to be less than 5 MPa, the steam quality of conventional steam flooding in bottom hole is about 30%, heavy oil reservoir in Shengli Oilfield with character of deep burial depth, active edge and bottom water and high formation pressure (7-8 MPa), the increase of oil recovery using conventional steam flooding is not obvious, Therefore, the formation and development of steam chamber during steam flooding are studied by indoor physical simulation experiments, the feasibility of high-quality steam flooding under high pressure is analyzed. The experimental results show that the quality of steam injection has obvious influence on the expansion of steam chamber. As the steam quality increases under high pressure, the specific volume of underground steam increases, the formation time of steam chamber is shortened, the expansion distance of steam chamber increases, the effective steam flooding time is prolonged, and recovery rate improves obviously. Field tests of high-quality steam flooding under high pressure were carried out in Gudao Zhongerbei heavy oil reservoir of Shengli Oilfield, the result shows that the bottom-hole steam quality of steam injection wells is 50% and above (20% higher than conventional steam flooding), the steam chamber was effectively expanded and the performance of producing rate for production wells improves obviously. The recovery rate of the test area reached 52.1%, which was 16.8% higher than that of steam huff and puff. High-quality steam flooding technology was an effective way to improve the recovery rate of high-pressure heavy oil reservoirs.",9,9,5
Oil Recovery,Injection Rate,"Kumar, Amit; Mandal, Ajay",Core-scale modelling and numerical simulation of zwitterionic surfactant flooding: Designing of chemical slug for enhanced oil recovery,Enhanced oil recovery; Zwitterionic surfactant; Core flooding; Simulation; CMG-STARS,,"Surfactant flooding is a proven enhanced oil recovery method for the recovery of trapped crude oil from the pores of the reservoir. In the present study, the applicability of a synthesized zwitterionic surfactant as an efficient EOR agent was tested, in terms of its interfacial tension reduction capability, emulsification behavior, and wettability modification behavior. Core flooding experiments conducted in sandstone core with the injection of 0.3 pore volume of chemical slug after water flooding showed 20% of additional oil recovery. The core flooding experiment was simulated using CMG-STARS simulator and history matching of relative permeability curve and its interpolation parameters were done. The validated model closely represented the experimental core flooding with very low error of 6%. The validated model helps in understanding the movement of crude oil and its interaction with the injected surfactant slug in the porous media. The validated model was further used for optimization of injected chemical slug by varying the parameters such as the surfactant concentration in the injected slug, the volume of injected chemical slug, and the injection rate of chemical slug. Each parameter had different effects on the oil recovery efficiency and cumulative oil recovery of more than 90% OOIP was obtained using model with injection of 1 PV of chemical slug containing 100 ppm of surfactant with the injection rate of 0.3 mL/min. The simulation of core flooding helped in optimization of crude oil production by zwitterionic surfactant and its implementation on field scale production by zwitterionic surfactant flooding.",8,8,4
Oil Recovery,Injection Rate,"Epelle, Emmanuel, I; Gerogiorgis, Dimitrios, I",Adjoint-based well placement optimisation for Enhanced Oil Recovery (EOR) under geological uncertainty: From seismic to production,Well placement; Oil saturation; Well allocation factors; Geological uncertainty; Adjoint formulation; Production optimisation,JOINT OPTIMIZATION; PARAMETERS,"The development of new and existing oil fields is very expensive and technically challenging; this provides an important economic incentive to improve oil recovery via efficient computational optimisation. Decisions related to these activities may be significantly aided by sound and proven mathematical-oriented methods. The use of intuitive engineering judgement alone cannot guarantee sustainable profitability over long periods, especially under geological (reservoir model) uncertainty. To capture the uncertainties in the subsurface geological/reservoir model in this work, geostatistical realisations of the model are obtained using available information (permeabilities and porosities). We also apply specialised algorithms within the MATLAB Reservoir Simulation Toolbox - MRST (interfaced with PETREL (TM)) to optimally vary the well locations and production rates, thus maximising the field's oil recovery. A new modification of an existing pseudowell-based injection well placement algorithm is presented herein with the application of adjoint-computed gradients of an auxiliary objective function (the Lorenz coefficient). The difficulty of this problem is characterised by the presence of discrete variables, a nonlinear and nonconvex objective function and constraints. The developed workflow is applied to a realistic case study, for which robust optimality is demonstrated using the worst case realisation for the determination of optimal well locations and controls. A comparative investigation of optimising injection well location vs. simultaneous optimisation of injection and production well placement is also presented. In our presented case studies, we also discover that increasing the optimisation search space does not necessarily guarantee improved results.",8,8,0
Oil Recovery,Polymer,"Chaturvedi, Krishna Raghav; Sharma, Tushar",Carbonated polymeric nanofluids for enhanced oil recovery from sandstone reservoir,Carbonated water injection; CO2 absorption; Enhanced oil recovery; Nanofluid; Polymeric nanoparticle suspension; Sandstone,WATER INJECTION; DEPLETION FLOCCULATION; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; INTERFACIAL-TENSION; SILICA NANOFLUIDS; CO2 SOLUBILITY; NANOPARTICLES; SURFACTANT; STABILITY,"Polymeric nanoparticle (NP) suspensions are colloidal suspensions where NPs (size <= 100 nm) are suspended in the polymer-enhanced base fluid, mainly water. Compared to water or sole polymer solutions, they exhibit superior rheological, mass transfer, and heat tolerance attributes. While the use of polymeric NP suspensions as injection fluids for enhanced oil recovery has been explored in past studies, their use as carrier fluids for CO2-loaded (carbonated) water injection has not been explored to date. Thus, this study explores the use of polymeric NP suspensions prepared using SiO2, ZnO, and TiO2 nanoparticles of varying concentration for CO2 loading and their use as carbonated fluids for enhanced oil recovery from sand-packs mimicking a sandstone reservoir. It was observed that the use of nanoparticles improved CO2 absorption in the base fluid, water by a significant margin (approximate to 8-23%). The inclusion of salt (3 wt% NaCl) induced aggregation in NP suspensions and reduced their CO2 loading capacity. When used for flooding, the carbonated polymeric NP suspensions exhibited superior oil mobilization than their non-carbonated peers resulting in more oil produced even at a higher temperature and salinity (additional 12-20% of OOIP). Increasing temperature reduced the loading (absorption) of CO2 and oil recovery effectiveness of the polymeric NP suspensions while salt majorly impacted oil recovery efficiency under the investigated conditions. Based on the results obtained in this study, the use of 0.1 wt% SiO2 NPs has been recommended as the ideal concentration for use in carbonated water injection.",21,21,3
Oil Recovery,Polymer,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Oil Recovery,Polymer,"Kumar, Ravi Shankar; Chaturvedi, Krishna Raghav; Iglauer, Stefan; Trivedi, Japan; Sharma, Tushar","Impact of anionic surfactant on stability, viscoelastic moduli, and oil recovery of silica nanofluid in saline environment",EOR; Nanofluid; Nanoparticle; Rheology; Salinity; SDS,PARTIALLY HYDROLYZED POLYACRYLAMIDE; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; CHARGED NANOPARTICLES; THERMAL-CONDUCTIVITY; DISPERSION STABILITY; AQUEOUS-SOLUTIONS; IONIC-STRENGTH; POLYMER FLOOD; BEHAVIOR,"Controlling nanofluid stability in saline environment has been a long-standing challenge as salt ions screen-out the surface charge of the nanoparticles (NPs), rendering them unstable. This study thus reports the use of an anionic surfactant (sodium dodecylsulfate, SDS), as co-stabilizer, that not only controls the effect of salt, but also dramatically improves nanofluid stability by controlling the agglomeration rate. Silica NPs of 0.5 wt%, SDS with concentration >= critical micelles concentration (CMC), and polymer polyacrylamide (PAM) of 1000 ppm were used while the concentration of NaCl was explored up to 5 wt%. The dispersion stability of nanofluid without salt (NaCl) was found to be similar to 4 weeks which further increased to similar to 7 weeks with increasing SDS concentration. With increasing SDS (>CMC), a reduction in NP agglomeration was observed that delayed the NP settlement. The effect of salinity was also investigated for flow properties of nanofluids and, an unstable rheological response (transition from viscoelastic to viscous) was observed with increasing NaCl concentration. However, SDS (>CMC) made nanofluid rheologically stable up to saline environment of 3 wt%, an optimum salinity was identified. SDS role on nanofluid stabilization in saline environment is also generalized for enhanced oil recovery (EOR) applications in a porous media enriched with varying salinity. With increasing salinity, the cumulative oil recovery from sand-pack reduced and reached to minimum level of 48% original oil in place (OOIP) at 3 wt% NaCl which was 58% OOIP without salinity. Oil recovery re-established to 55% OOIP in presence of increasing SDS concentration, which is remarkable for nanofluid applicability in saline environment where conventional methods typically show challenges. Even in the presence of 4 wt% NaCl, the synergy between surfactant and nanofluid enabled an improvement in oil recovery and subdued surfactant adsorption in both unconsolidated and consolidated porous media, paving future way for field implementation.",18,18,4
Oil Recovery,Polymer,"Lai, Nanjun; Wen, Yiping; Yang, Zhidong; Chen, Jianlin; Zhao, Xubin; Wang, Dongdong; He, Wei; Chen, Yuemei",Polymer flooding in high-temperature and high-salinity heterogeneous reservoir by using diutan gum,High-temperature; High-salinity; Strong heterogeneity; Diutan gum; Rheological properties; Oil displacement experiments,LASER-LIGHT SCATTERING; HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; WATER-SOLUBLE COPOLYMERS; RHEOLOGICAL PROPERTIES; SOLUTION BEHAVIOR; PROFILE-CONTROL; OIL-RECOVERY; ACRYLAMIDE; DISPLACEMENT; XANTHAN,"Diutan gum, a biopolymer that has been widely used in cement and concrete industries, was introduced in this work to alleviate severe viscosity loss and the poor water solubility of polyacrylamide and its modified products in high-temperature and high-salinity reservoirs. Diutan gum is an exopolysaccharide secreted by sphingomonas. The rheological properties and capacity of diutan gum to enhance oil recovery in high-temperature and highsalinity heterogeneous reservoir (T = 130 degrees C, Total salinity = 223.07 g L-(1), V-k = 0.93) was investigated and compared with those of two other kinds of biopolymer thickeners (xanthan and konjac gum), which are commonly used in oilfield development. The three biopolymers show pseudoplastic fluid properties in a steadystate rheological test: given the strong interactions in the double-helix structure of diutan gum, the number of the Newtonian zone and the shear rate of this zone are higher than the those of the two other biopolymers. The storage modulus (G') of diutan gum are higher than its loss modulus (G '') in all the concentrations and frequencies measured through viscoelasticity tests. This result indicates that diutan gum exhibits remarkable elasticity in slow displacement speed while it seeping in porous media. The capability of establish flow resistance in high-permeability porous medium in high-temperature and high-salinity environment by three biopolymers was studied, and their viscosity and microscopic properties of injected and produced fluid were investigated to understand the reason why diutan gum can have good fluidity control ability. Oil displacement efficiency can be improved by the elasticity of the diutan gum even without an increase in displacement speed. The results of the oil displacement experiments in the heterogeneity model imply that diutan gum is more effective in improving the water injection profile of each layer than xanthan and konjac gum. The water channeling in the high-permeability layer is restrained, and the sweep ability of the displacement phase is improved. Furthermore, the effect of polymer flooding can be maintained for a long time. Under high-temperature, high-salinity and strong heterogeneity, diutan gum recovers 19.34% of original oil in place (OOIP). This value is higher than the values obtained with xanthan gum (14.15% OOIP) and konjac gum (8.60% OOIP). This finding implies that the diutan gum has great application potential in the development of high-temperature and high-salinity reservoirs with strong heterogeneity.",13,12,7
Oil Recovery,Polymer,"Kang, Wanli; Sarsenbekuly, Bauyrzhan; Turtabayev, Sarsenbek; Yang, Hongbin; Zhu, Tongyu; Aidarova, Saule; Gabdullin, Maratbek; Ospanova, Zhanar; Issakhov, Miras",Study on the influence of emulsification property of functional polymers on enhanced oil recovery and its mechanism,Functional polymer; Emulsification; Enhanced oil recovery; Sweep volume; Washing efficiency,HYDROPHOBICALLY-MODIFIED POLYACRYLAMIDE; PARTIALLY HYDROLYZED POLYACRYLAMIDE; AQUEOUS-SOLUTIONS; PERFORMANCE; RESISTANCE; BEHAVIOR,"Functional polymer flooding has been proven to be capable to improve oil recovery by mobility control and emulsification. However, the contribution degree of emulsification function of polymer flooding to oil recovery has not been clarified. This work experimentally investigated the ability of two functional polymers (RH-4 and KLP-6) with emulsification property and common polymer (HPAM) to enhance oil recovery. The steady shear viscosity, viscoelasticity and emulsification property of polymers were measured by rheometer and bottle tests, respectively. The core displacement experiments and etched glass micro-model were conducted to measure the oil recovery and the mechanism. The results showed that under the same viscosity of the three polymers, RH-4 and KLP-6 with emulsification property exhibited higher improvement of oil recovery over the emulsification-free HPAM polymer due to their higher washing efficiency. And in heterogeneous formation, the KLP-6 polymer obtained the highest recovery which can be attributed to the higher sweep volume by Jamin effect of the emulsified oil droplets. This work establishes a theoretical foundation for the application of functional polymers in oil fields.",11,13,11
Oil Recovery,Polymer,"Sun, Qian; Ertekin, Turgay",Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies,Artificial neural network; Polymer injection; Optimization; EOR screening; EOR project design,ALGORITHM,"Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.",11,11,2
Oil Recovery,Polymer,"Wang, Ruolan; Pu, Wanfen; Dang, Sisi; Jiang, Feng; Zhao, Shuai",Synthesis and characterization of a graft-modified copolymer for enhanced oil recovery,Graft-modified copolymer; Antiaging performance; Welan gum; Enhanced oil recovery; Salt resistance,XANTHAN GUM; ACRYLAMIDE,"A graft-modified copolymer (cWL-g-A) was synthesized using Welan Gum (WLG), acrylamide, acrylic acid, and 0-20 via free-radical copolymerization to be well applied for enhanced oil recovery. The chemical structure of the copolymer was characterized by Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance spectroscopy (NMR), thermogravimetry (TG) and scanning electron microscopy (SEM). The long-term stability, rheology, adsorption, temperature and salt resistance of the copolymer were investigated. The cWL-g-A solution showed superior temperature and salt resistance in comparison with partially hydrolyzed polyacrylamide (HPAM), due to the hydrophobic association of main polymer chain. Particularly in high salinity (230,000 mg/L) solutions, cWL-g-A showed a better antiaging performance at three different temperatures (25, 50 and 65 degrees C). Oil recovery yielded by cWL-g-A was 14.18% higher than that yielded by HPAM, as known from polymer flooding tests. These results elucidated that cWL-g-A synthesized herein was superior to HPAM in high-salinity and medium-high temperature oil reservoirs.",10,9,4
Oil Recovery,Polymer,"Wei, Peng; Guo, Kaidi; Xie, Yahong",Polysaccharide-stabilized oil-laden foam for enhancing oil recovery,Oil-laden foam; Xanthan gum; Emulsion; Pseudoemulsion film; Enhanced oil recovery,HIGH-TEMPERATURE; SURFACE-TENSION; XANTHAN GUM; POLYMER; GAS; MECHANISMS; NANOPARTICLES; COALESCENCE; PRESSURE; BULK,"Understanding the influence of crude oil on foam stability is critical to investigations of improved foam-EOR process. With enough physical actions, the oil phase can pour into and be trapped in the aqueous network, enfolding the gas bubbles with a honeycombed structure, which forms an extraordinary ternary system also known as oil-laden foam (see Fig.1). The goal of this study is to investigate the synergistic effects of using a blend of xanthan gum (XG) and alkyl polyglycoside (APG) on the stability of oil-laden foam, and a series of experiments are developed. The results indicate that the addition of XG in the oil-laden foam can boost the performance including both emulsification and pseudoemulsion film aspects. One way is to reduce the liquid drainage or hinder the movement of oil droplets within liquid films by increasing the emulsion stability and liquid viscosity. Another is to decrease the rupture of tri-phase foam by creating the high-stable pseudoemulsion film with a dense and elastic adsorption layer. Under the synergistic effect of these two mechanisms, the dynamic stability of liquid films can be improved, bubble coarsening and gas diffusion can be hindered, and finally the stability of the oilladen foam can be greatly increased. The stable oil-laden foam (i.e., the oil-continuous films) is created during the XG/APG foam injection, which is in favor of mobility control and oil displacement.",8,8,16
Oil Recovery,Polymer,"Aldhaheri, Munqith; Wei, Mingzhen; Zhang, Na; Bai, Baojun",Field design guidelines for gel strengths of profile-control gel treatments based on reservoir type,Enhanced oil recovery; Excessive water production; Conformance improvement; Gel treatments; Field project survey; Gel strength designs; Field design guidelines,POLYMER GEL,"Bulk gels are increasingly applied to alleviate the costly burden of excessive water production in mature oil fields. Practically, designs of new treatments are adopted from previous field projects conducted in analogous reservoirs. This case-finding procedure requires reservoir engineers to have thorough knowledge about how gel treatments, for each reservoir type, should be designed and have been mostly applied. This paper presents comprehensive design guidelines for injection-well gel treatments based on 61 worldwide field projects. It also assesses typical and most-applied designs and introduces them as new designing strategy. Seven gel strength design parameters were evaluated using the univariate descriptive analysis, stacked histograms, and scatterplots. Results indicated that gel strength parameters have very wide ranges and are considerably affected by the formation type. Gel treatments typically start with 3000 ppm polymer concentration, end with 7600 ppm, and a constant polymer-crosslinker ratio (PCR) of 40:1 is maintained during the treatments. They are often performed using the injection waters (to avoid type II gel syneresis) and polymers of 10-11 MM Da molecular weight (MW) and 30% hydrolysis that are injected in 4-5 treatment stages. The gel strength is principally designed based on the problem channeling strength and the planned gel volume. However, in cases of void-space-type problems, the gel extrusion, breakthrough, and breakdown become important designing criteria. To address these issues, more advanced tapering schemes than normal gradual increase of polymer concentrations are used to optimize gel plugging efficiency. In these schemes, small volumes of cement or low MW, fast-maturing, rigid gels (i.e., MARA-SEAL (TM)) are injected in front (gels only) or behind the high-MW MARCITsm gels as capping-materials. The novelty of present review lies in providing conformance specialists with new design strategy that would markedly facilitate designing of gel treatments and save time needed to identify analogs for a given candidate reservoir.",8,8,5
Oil Recovery,Polymer,"Agi, Augustine; Junin, Radzuan; Abdullah, Mohammed Omar; Jaafar, Mohd Zaidi; Arsad, Agus; Sulaiman, Wan Rosli Wan; Norddin, M. N. A. Mohd; Abdurrahman, Muslim; Abbas, Azza; Gbadamosi, Afeez; Azli, Nur Bashirah",Application of polymeric nanofluid in enhancing oil recovery at reservoir condition,EOR; Cissus populnea; IFT; Wettability; Ultrasound; Nanofluid,CRYSTALLINE STARCH NANOPARTICLES; INTERFACIAL-TENSION; SILICA NANOPARTICLE; GEMINI SURFACTANTS; ACID-HYDROLYSIS; TEMPERATURE; STABILITY; BEHAVIOR; ULTRASOUND; RHEOLOGY,"In this study, ascorbic acid was used to synthesize Cissus populnea nanoparticles (CPNP). The synthesized CPNP was isolated and the influence of the process variables on the physical properties were studied. The rheology of the formulated Cissus populnea nanofluid (CPNF) was measured and compared with Cissus populnea (CP) solution and commercial polymer xanthan. Moreover, the interfacial properties of CPNF were studied at various concentrations and temperatures, and the influence of salinity and their interaction with ultrasound was investigated. Sessile drop contact angle method was used to determine the wettability alteration efficiency of CPNF on an initially oil-wet sandstone core surface. Finally, CPNF and CP solutions were evaluated for EOR purposes at typical reservoir condition. The displacement process was scaled to reduce the number of parameters investigated using dimensionless parameters. The synthesis methods were efficient in generating sphere-shaped and elongated nanoparticles (50 nm mean diameter). Experimental results show that an increase in temperature of CP and CPNP yielded increased viscosity of the solutions in stark contrast to xanthan whose solution viscosity declines as the temperature increases. Besides, the CPNF was effective in lowering IFT at oil-water (O/W) interface and altered the wettability of the sandstone cores to water-wetting condition. The novel CPNF increased the oil recovery by 26% and was effective at high-temperature high-pressure (HTHP) reservoir condition. The result shows a transition from capillary dominated flow to gravity dominated flow as decrease in IFT decreased residual oil saturation and increased capillary and Bond number. The energy consumption and cost estimation of the proposed novel polymeric nanofluid shows it is cost-effective than conventional EOR chemicals.",8,8,2
Oil Recovery,Carbon Dioxide,"Hu, Xiao; Xie, Jun; Cai, Wuchao; Wang, Rui; Davarpanah, Afshin",Thermodynamic effects of cycling carbon dioxide injectivity in shale reservoirs,Carbon dioxide storage capacity; Oil recovery factor; Soaking time; Core stimulation; Shale reservoirs,ENHANCED OIL-RECOVERY; BAKKEN TIGHT OIL; N-PUFF PROCESS; GAS; STORAGE; MODEL; PERMEABILITY,"Carbon dioxide injectivity has always been considered as one of the optimum enhanced recovery techniques, especially in tight reservoirs regarding the feasible mobilization of gas through porous media. To have a better understanding of carbon dioxide injectivity performances, it would be of importance to consider crucial parameters and their effects on the carbon dioxide adsorption and oil recovery factor. In this paper, the profound impact of crucial parameters such as temperature, pressure, carbon dioxide soaking time, and core stimulation on the oil recovery enhancement were investigated. Moreover, the considerable influence of pressure and temperature on the carbon dioxide adsorption capacity storage were performed and analyzed. According to the result of this experiment, temperature increase led to reducing carbon dioxide storage capacity, which has a reverse pattern with oil recovery factor by increasing temperature. When the core samples were unstimulated, the oil recovery factor has higher than stimulated core samples. Furthermore, pressure increase resulted in the carbon dioxide storage capacity enhancement, which has a similar increase pattern with oil recovery factor by increasing pressure. The maximum carbon dioxide storage capacity is 91% and 90% at the pressure of 1500 psi and temperature of 20 degrees C respectively. Soaking time rising between oil and carbon dioxide led to producing more oil volume.",98,98,22
Oil Recovery,Carbon Dioxide,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Water-oil interfacial tension (IFT) reduction and wettability alteration in surfactant flooding process using extracted saponin from Anabasis Setifera plant,Surfactant flooding; Saponin; Interfacial tension (IFT); Wettability alteration; Chemical enhanced oil recovery; Anabasis Setifera,DISSOLVED CARBON-DIOXIDE; LEAF-DERIVED SURFACTANTS; SMART WATER; POROUS-MEDIA; CO2 FOAM; RECOVERY; IONS; INJECTION; RESERVOIR; EMULSIFICATION,"Surfactants are known as interfacial tension (IFT) reducer additives in enhanced oil recovery (EOR) process. The use of chemical surfactants has always been a challenge due to the high cost of materials and sometimes noncompliance with the environment. Hence, researchers are looking for alternative ways to make them cheap and affordable. Herbal extracts that combine some surfactants, such as saponins, are a new source for replacing with expensive chemical surfactants. In this study, Anabasis Setifera plant was used as a source of natural surfactant supply. Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance ((HNMR)-H-1) and thermal gravimetric analysis (TGA) were performed to characterize and determine the temperature stability, as well as surface tension tests for estimating the critical micelle concentration (CMC) of saponin extracted from Anabasis Setifera. In addition, pendant drop water-oil IFT test, contact angle test, and flooding of surfactant solution at CMC and optimum salinity were performed to study the application of the natural surfactant in EOR process. The effects of NaCl, KCl, CaCl2, MgCl2, FeSO4, K2SO4 and NaHCO3 salts and formation water salinity were investigated at different concentrations on the IFT and contact angle. The results show that the surfactant is more effective than conventional plant extracts and in combination with chemical surfactants and an IFT value of 1.066 mN/m was obtained at CMC. The contact angle tests also show the capability of this surfactant to alter the wettability to a poor water-wetting (a contact angle of 56.51. Ultimately, an oil recovery of 15.4% was obtained by flooding of the surfactant solution at CMC and optimum formation water salinity.",37,37,18
Oil Recovery,Carbon Dioxide,"Yekeen, Nurudeen; Padmanabhan, Eswaran; Syed, Asad Hassan; Sevoo, Thenesh; Kanesen, Kamalarasan","Synergistic influence of nanoparticles and surfactants on interfacial tension reduction, wettability alteration and stabilization of oil-in-water emulsion",Nanoparticles; Surfactants; Interfacial properties; Micro-pores; Dead-end pores; Emulsion,METAL-OXIDE NANOPARTICLES; WALLED CARBON NANOTUBES; SILICON DIOXIDE; FOAM STABILITY; ADSORPTION; RECOVERY; NANOFLUIDS; DISPERSION; SALINITY; BEHAVIOR,"In this study, the synergistic interaction of nanoparticles and surfactants were explored for oil-water interfacial tension (IFT) reduction, alteration of rock wettability, and stabilization of oil-in-water emulsion. The interfacial properties were investigated using drop-shape analyzer (DSA 25) while the pore scale visualization studies were conducted using the etched glass micromodels. The most stable surfactant-stabilized emulsion was formed in presence of cetyltrimethylammonium bromide (CTAB) while the order of increasing emulsion stability in presence of nanoparticles was obtained as follows: carbon nanotubes > copper oxide > silicon dioxide > aluminum oxide > titanium dioxide. Compared to pure nanofluids or surfactant solutions, the nanoparticles-surfactant solutions demonstrated promising tendency for significant reduction in oil-water interfacial tension and alteration of rock wetting properties. Specifically, the carbon nanotubes (CN) based nanofluids, reduced the contact angle of the rock from 68.73 degrees to 65.5 degrees (4.7%) while the Triton X-100 (TX 100) and CN-TX100 solutions reduced the contact angles to 10.65 degrees (84.5%) and 7.0 degrees (89.8%) respectively. The dominant mechanism of resident oil mobilization from the micro and dead-end pores was identified as emulsification-entrainment. A correlation exists between influence of nanoparticles-surfactant solutions on interfacial properties and resident oil mobilization from the micro and dead-end pores. The CN-CTAB solution that was the most effective in mobilization of the resident oil from the micro and dead-end pores significantly reduced the crude oil-water IFT to 0.63 mN/m. The mechanisms of IFT reduction, wetting properties alteration, as well as emulsion stabilization have been identified as the orientation of the particles at the interface and the electrostatic interaction between the nanoparticles and surfactant molecules. These procedures could be exploited to achieve significant reduction in IFT, rock wettability alteration and emulsion stabilization than could be achieved using pure nanofluids or surfactant solutions only.",18,17,8
Oil Recovery,Carbon Dioxide,"Janiga, Damian; Czarnota, Robert; Kuk, Edyta; Stopa, Jerzy; Wojnarowski, Pawel",Measurement of Oil-CO2 diffusion coefficient using pulse-echo method for pressure-volume decay approach under reservoir conditions,CO2 diffusion coefficient; Mass transfer; Pressure-volume decay; Acoustically monitored separator (AMS); CO2-EOR,SATURATED POROUS-MEDIA; HEAVY-OIL; GAS DIFFUSIVITY; LIQUID HYDROCARBONS; CO2 DIFFUSION; MASS-TRANSFER; PUFF PROCESS; HUFF; RECOVERY; BITUMEN,In order to achieve synergic environmental effect CO2-EOR can be applied to improve oil production and reduce carbon dioxide emission. Greater results can be obtained by the CO2 huff-n-puff process which in the case of oil reservoirs is based mainly on the oil swelling effect. During the soaking period the primary mechanism distributing CO2 in the reservoir is molecular diffusion. To calculate mass transferred to oil phase molecular diffusion coefficient is used. Its determination can be based on direct or indirect techniques but no standard method is normed. This paper presents a pulse-echo pressure-volume decay technique to determine oil-CO2 diffusion coefficient under reservoir conditions with the use of acoustically monitored separator. In the proposed method measurements of difference between signal routing are recalculated to volume change in order to compute diffusion coefficient. Experimental procedure was conducted for three different temperatures. The obtained results are consistent with previous studies on diffusion coefficient determination. The proposed technique is more reliable and yields straightforward solution due to simultaneous binary measurements of pressure and volume system.,14,13,6
Oil Recovery,Carbon Dioxide,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Oil Recovery,Carbon Dioxide,"Guo, Jian-Xin; Huang, Chen; Wang, Jian-Liang; Meng, Xiao-Yan",Integrated operation for the planning of CO2 capture path in CCS-EOR project,Carbon capture and storage; Enhanced oil recovery; Integrated operation; Carbon capture path,ENHANCED OIL-RECOVERY; CARBON CAPTURE; POWER-PLANTS; NORTH-SEA; STORAGE; CO2-EOR; OPTIMIZATION; TECHNOLOGIES; DIOXIDE; UNCERTAINTY,"Carbon utilization and storage (CCUS) project represented by enhanced oil recovery (EOR) technology provides a feasible way for the CCS dynamic cost to decline. With the development of CCS and the cost reduction of power plant capture, the possibility of oil companies receiving CO2 from power plants will increase, which makes CO2 and oil resources more fully utilized. Based on this fact, this work proposes a novel model regarding the CCS-EOR project to systematically evaluate the CCS development path and the EOR utilization process. By considering the CO2 source captured by CCS and the utilization process of EOR process, the cost-benefit model of integrated system is established, and the CO2 capture/injection path of CCS/EOR is optimized. This model helps to analyze CCS investment and carbon capture process from the perspective of the whole project process, and provides a feasible reference for practical large-scale engineering decision-making project.",8,8,9
Oil Recovery,Carbon Dioxide,"Luan, Yalin; Liu, Bing; Hao, Peng; Zhan, Kaiyun; Liu, Jianlin",Oil displacement by supercritical CO2 in a water cut dead-end pore: Molecular dynamics simulation,Supercritical CO2; Dead-end pore; Oil displacement; Molecular dynamics; Energy analysis,RECOVERY; INJECTION; DISSOLUTION; MECHANISMS; REDUCTION; MODELS,"Exploitation of residual oils from the micro/nanopores in the reservoir is one perpetual goal of Enhancing oil recovery (EOR), which presents a big challenge for both advanced technologies and fundamental theories. In the current study, we make a comprehensive molecular dynamics (MD) simulation on the displacement process of trapped oils inside a water cut dead-end pore driven by supercritical CO2 molecules. Firstly, the whole displacement process is fully demonstrated by snapshots of MD simulation. Next, the collapse details of the water film between carbon dioxide and octane are simulated, where the hydrogen bonds and the evolution of ruptured hole are discussed. Thirdly, the configuration of the oil-water interface is computed and analyzed by the Laplace equation. Fourthly, the displacement mechanism of octane by carbon dioxide is explained according to the energy principle. These findings can strengthen our understandings on the details of the residual oil displacement in rocks, which may provide some inspirations on the oil recovery enhancement.",7,7,8
Oil Recovery,Carbon Dioxide,"Hassan, Anas M.; Ayoub, M.; Eissa, M.; Bruining, Hans; Zitha, P.",Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding,Surface complexes; DLVO theory; Enhanced oil recovery (EOR); Smart water assisted foam (SWAF) flooding; Low-salinity; Wettability alteration; Foam flooding; Foam stability; Carbonate reservoirs; PHREEQC-Software,ACTIVITY-COEFFICIENT; OSMOTIC COEFFICIENTS; THERMODYNAMICS; ELECTROLYTES; TRANSPORT; MECHANISMS; CARBONATE; ORDER; PART; IRON,"This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25 degrees C) and at the reservoir-conditions (80 degrees C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Huckel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foamlaminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25 degrees C) and at (80 degrees C) than the high-salinity case for both (25 degrees C) and (80 degrees C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of ""Smart Water Assisted Foam (SWAF) Flooding"". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.",7,7,4
Oil Recovery,Horizontal Wells,"He, Youwei; Qin, Jiazheng; Cheng, Shiqing; Chen, Jianwen",Estimation of fracture production and water breakthrough locations of multi-stage fractured horizontal wells combining pressure-transient analysis and electrical resistance tomography,Multi-stage fractured horizontal wells; Water breakthrough location; Pressure-transient analysis; Electrical resistance tomography; Well performance evaluation,MODEL; FLOW; PERFORMANCE,"The production of multi-stage fractured horizontal wells (MFHWs) decline fast, and water cut quickly increase after short producing period. How to evaluate well performance and estimate the water breakthrough segments become significant for improving oil recovery. The production logging test (PLT) enables to obtain the production profile along horizontal wellbore, however, it's difficult and expensive to carry out PLT for the MFHW. This work presents a new method to estimate production of hydraulic fractures and determine the water-breakthrough locations by combining pressure-transient analysis (PTA) and electrical-resistance tomography (ERT). This paper presents a PTA model of an MFHW which considers the nonuniform properties of fractures, including unequal fracture conductivity, nonuniform production distribution, asymmetric fractures, and arbitrary locations. The proposed model has been verified with the numerical PTA model in KAPPA Ecrin Saphir software. The type curves are developed and the impact of well and fracture properties on pressure and pressure derivative are also analyzed in detail. When the distance between fractures with high production (FHP) increases or number of FHP decreases, the early-radial flow can be obviously observed, and the duration of this regime depends on the interference among fractures. We define a parameter (N*) to describe the number of FHP, and the N* is determined by properties of hydraulic fractures. N* equals to N (total number of hydraulic fractures) if factures are symmetrically and uniformly distributed along wellbore and have equal production and conductivity. N* approximately equals to the number of producing fractures when all producing factures uniformly distribute along wellbore and have equal production, conductivity, and length. The developed PTA model is used to interpret production of different fractures by matching BHP data. The use of ERT enables to track water front, further estimate the water-breakthrough segments and reduce the non-uniqueness of PTA interpretation. The proposed approach is used to evaluate the well performance of MFHWs from Changqing Oil field, and interpretation results obtained in this work match with the results obtained by PLT.",29,29,1
Oil Recovery,Horizontal Wells,"Cheng, Linsong; Wang, Deqiang; Cao, Renyi; Xia, Rufeng",The influence of hydraulic fractures on oil recovery by water flooding processes in tight oil reservoirs: An experimental and numerical approach,Tight oil; Hydraulic fracture; Water flooding; Water breakthrough; Core flood experiment,HORIZONTAL WELLS; SHALE; FLOW; GAS; STORAGE; EOR,"The use of multi-fractured horizontal wells has helped to develop tight oil reservoirs, but, if oil depletion occurs, the estimated ultimate recovery is low. Water flooding can be regarded as an easily applied method for improving oil recovery. This study aimed to optimize the scale of the stimulated reservoir volume (SRV) by conducting an experiment to verify the water injection capacity of the Chang 7 Formation, which is situated within in a typical tight oilfield. A one-dimensional long core displacement experiment was designed based on injecting formation water into a tight matrix core and fractured cores with different fracture lengths. Results were then verified and analyzed using core flood simulation and targeted field tests, and they clarified the feasibility of injecting water into a tight oil formation when the injection well is fractured, or when fractures exist near the injection well. It was also verified that although fractures increase the equivalent permeability in the fractured core and promote pressure propagation, they can also lead to rapid water breakthrough if they communicate with the producer well. It is thus considered that optimization of the SRV extent would enhance the recovery of oil and decrease the risk of water breakthrough.",16,15,3
Oil Recovery,Horizontal Wells,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Oil Recovery,Horizontal Wells,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Oil Recovery,Horizontal Wells,Wang Xue-wu; Xiao Pufu; Yang Zheng-ming; Liu Xue-wei; Xia Zhi-zeng; Wang Li-qiang,Laboratory and field-scale parameter optimization of CO2 huff-n-puff with the staged-fracturing horizontal well in tight oil reservoirs,Tight oil reservoirs; Horizontal well; Fracture; CO2 huff-n-puff; Production mechanism; Parameters optimization,RECOVERY,"With the help of large-scale physical simulation experiment technology, the physical simulation experiments of the CO2 huff-n-puff with the staged-fracturing horizontal well could be acheived. We studied the production process of CO2 huff-n-puff and influence of different parameters affect oil recovery during the CO2 huff-n-puff procedure, ultimately, the operation parameters were optimized by numerical simulation. The results show that CO2 can quickly enter the deep formation through the horizontal well and the fracture during the huff period and staged-fracturing horizontal well can greatly increase the contact area between CO2 and crude oil, which improves the efficiency of extraction, dissolution, reduction of viscosity between CO2 and crude oil. During the puff period, the horizontal well and fractures can reduce the flow resistance effectively, so as to improve the flow capacity of crude oil. After 3 cycles of CO2 huff and puff, the oil recovery can be enhanced by 11.13%-21.39% compared with that obtained by elastic flooding, which indicates that the exploitation method of CO2 huff-n-puff can improve the development effects of tight oil reservoirs. CO2 huff-n-puff injection parameters are optimized, the results show that the optimum time of injection is 1 year, the optimum soaking time is 30d, and the optimal injection pore volume is 0.18HCPV. This research can provide a certain technical support for effective development of tight oil reservoirs.",11,12,3
Oil Recovery,Horizontal Wells,"Eren, Tuna; Polat, Can",Natural gas underground storage and oil recovery with horizontal wells,Reservoir engineering; Production engineering; Reservoir simulation; Underground gas storage; Horizontal well design,,"In this research study a reservoir simulation is conducted to compare the performance of the wells in a depleted oilfield for Enhanced Oil Recovery (EOR) and subsequent Underground Natural Gas Storage considering different well profiles including vertical and horizontal trajectories. The underground gas is simulated to be stored at an increasing reservoir pressure up to a magnitude that is to 85% of the initial pressure, and reservoir pressure remains constant throughout. The results of the simulations reveal more oil which can be potentially recovered by means of developing the field with horizontal wells. The extended component transformation between the oil and gas phases, additional viscosity reduction in oil phase, low gas oil ratio, and favoring bottomhole pressures attained by means of horizontal wells has shown to be considerably effective for EOR and underground storage applications.",10,11,7
Oil Recovery,Horizontal Wells,"Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Cheng, Gang; Yu, Xiaogang",Experiments and analysis on development methods for horizontal well cyclic steam stimulation in heavy oil reservoir with edge water,Heavy oil; Edge water; Cyclic steam stimulation; Physical simulation; Experiment,MULTI-THERMAL FLUID; RELATIVE PERMEABILITIES; RECOVERY; PERFORMANCE; PREDICTION; OIL/WATER; FLOW; TEMPERATURE; PARAMETERS; EFFICIENCY,"In the world, the reserves are very huge in heavy oil reservoirs with edge water. Therefore, the effective development of such reservoirs is of great significance for the petroleum supply. In this paper, in order to transfer aquifer energy from actual reservoir to 3D model, a novel method is established based on the elastic principle to achieve simulation of heavy oil reservoir with edge water. Then the oil-water or oil-steam relative permeability curves are measured to analyze flowing characteristics of oil and water under high temperatures. Finally, three kinds of development methods are studied experimentally including the conventional cyclic steam stimulation (CCSS), the water production at oil-water contact (WPOWC) and the water production for post steam stimulation (WPPSS). The results show that the oil viscosity and the water mobility both reduce at higher temperature; moreover, the residual oil saturation decreases but the mobile water saturation increases during temperature rising. For heavy oil reservoirs with edge water, all these characteristics are advantageous to increase oil production and decrease water production. According to the results of 3D experiments, in the process of steam injection, the heating range mainly concentrates near the wellbore and an obvious steam overlap can be observed. The oil recovery factor (ORF) of WPPSS is 8.21%, which is slightly higher than that of CCSS, however the cumulative oil steam ratio (COSR) of WPPSS is 0.96, which is obvious larger than that of CCSS. Comparing the three development methods, for WPPSS method, the same steam injection can make more oil production and the water channeling can be effectively restrained in the late cycle of CSS. The method of WPPSS can be chosen to develop heavy oil reservoirs with edge water.",9,9,5
Oil Recovery,Gas Channeling,"Zhang, Juan; Zhang, Hui Xiao; Ma, Li Yan; Liu, Yi; Zhang, Liang",Performance evaluation and mechanism with different CO2 flooding modes in tight oil reservoir with fractures,CO2 injection; Flooding mechanism; Fractures; Tight reservoir; Miscible pressure,GAS; GENERATION; INJECTION; RECOVERY; EOR,"Due to the abundant reserves in tight reservoirs and the large amounts of residual oil after implementing common enhanced oil recovery methods, profitable methods with a high oil recovery such as CO2 flooding are urgently needed. Although CO2 flooding has attracted much attention and obtained good results in China and abroad, it has the critical problem of a low sweep efficiency, especially in tight reservoirs that develop with hydraulic fractures. In this study, the minimum miscible pressure of oil and CO2 was measured as 17.8 MPa, higher than the original formation pressure. Subsequently, the minimum miscible pressure was matched by means of numerical simulation, and the method of adding intermediate components to the injection CO2 was studied to reduce the miscible pressure in the study area. Afterwards, fractures were added to the geological model to study the mechanism of gas channeling under different CO2 injection modes. The continuous CO2 injection (CGI) mode requires the largest gas injection volume, which is easily affected by fractures and production pressure differences to form irregular gas channeling. Soaking alternating gas injection (SAG) can effectively supplement the formation pressure through periodic well switching, gas channeling delay, and radial gas flooding pattern formation. Water alternating CO2 (WAG) flooding can delay gas channeling, and the rhombus or square gas flooding pattern is formed due to the influence of the well pattern and well spacing. Foam flooding can better mitigate gas channeling but has a poor displacement effect. Through comparison of the various gas injection modes, it is concluded that WAG is the best CO2 flooding mode in the research area, and the cumulative increase in oil over 20 years can reach 390,466 t. The outcome of this work is important to CO2 flooding in tight reservoirs with fractures. The CO2 flooding mechanism in tight reservoir with fractures was examined.",14,14,12
Oil Recovery,Gas Channeling,"Qu, Ming; Hou, Jirui; Wen, Yuchen; Liang, Tuo",Nitrogen gas channeling characteristics in fracture-vuggy carbonate reservoirs,Fracture-vuggy carbonate reservoir; Gas channeling; Physical model; Gas flooding,BOTTOM-WATER DRIVE; N-2 INJECTION; MECHANISM,"Tahe Oilfield, located in Tarim Basin, Northwest China, is a typical carbonate fracture-vuggy reservoir. Nitrogen gas flooding is a vital technology for improving oil recovery by enlarging sweep volume in fracture-vuggy reservoirs. However, gas channeling restricts further application of nitrogen gas flooding. This paper studied the characteristics of gas channeling in fracture-vuggy carbonate reservoirs using physical simulation. Visual physical models and macroscopic physical models were designed and fabricated based on similarity criterion. Nitrogen gas flooding experiments were conducted in both types of models. Experimental results demonstrated that once the dominant channel of gas is formed, the remaining oil cannot be effectively swept. The greater the areal heterogeneity of fracture-vuggy carbonate reservoir is, the easier the formation of gas channeling is. Gas channeling was accompanied by a large amount of oil and water production. The initial gas channeling was followed by several additional occurrences of gas channeling. In addition, PIR risk assessment method was proposed to predict gas channeling by assigning values to each coefficient of P, I and R. This method verified by oilfield data can be used to prevent and evaluate the risk of gas channeling in fracture-vuggy carbonate reservoirs.",12,13,14
Oil Recovery,Gas Channeling,"Chen, Hailong; Li, Haifeng; Li, Zhaomin; Li, Songyan; Wang, Yujun; Wang, Jian; Li, Binfei",Effects of matrix permeability and fracture on production characteristics and residual oil distribution during flue gas flooding in low permeability/tight reservoirs,Flue gas flooding; Matrix permeability; Fracture; Residual oil distribution; Gas channeling point,HUFF-N-PUFF; HEAVY OIL; CO2; RECOVERY; TIGHT; STEAM; STORAGE; FOAM; INJECTION; DRIVE,"The effects of matrix permeability and fracture on production characteristics and residual oil distribution of flue gas flooding in low permeability/tight conditions are analyzed systematically by laboratory physical simulation experiments and low-field nuclear magnetic resonance (LFNMR) system. T2 spectra results show that the crude oil is mainly distributed in the corresponding macropores of 100-1000 ms before and after the flue gas injection, and the crude oil in macropores is produced in large quantities after the flue gas injection in both fracture and fracture-free low permeability/tight cores. Additionally, oil production performance indicates that matrix permeability has a remarkable effect in fracture-free low permeability/tight cores. T2 spectra combined with slice scanned images show the migration from the macropores to the medium and fine pores is more obvious in the core with high matrix permeability and the final residual oil distribution is more uniform compared to those of the core with low matrix permeability. Matrix permeability is inversely proportional to the gas channeling point and it has a linear relationships with the gas channeling point in a log-log plot in fracture-free low permeability/tight cores. Besides, fracture can significantly reduce the effect of matrix permeability on oil recovery. The presence of fracture weakens the migration of crude oil in low permeability/tight fracture cores, and the residual oil spreads throughout the core. Fracture plays a dominating role in the gas channeling points for different permeability cores.",9,9,15
Oil Recovery,Gas Channeling,"Liu, Peng; Shi, Lanxiang; Liu, Pengcheng; Li, Lei; Hua, Daode",Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs,Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery; Heterogeneity,ASSISTED GRAVITY DRAINAGE; RECOVERY; SOLVENT; PERFORMANCE; PRESSURE; GAS,"Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.",8,8,4
Oil Recovery,Mu M,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Oil Recovery,Mu M,"Chen, Meng; Dai, Jiacai; Liu, Xiangjun; Kuang, Yan; Wang, Zhongtao; Gou, Shunchao; Qin, Minjun; Li, Min",Effect of displacement rates on fluid distributions and dynamics during water flooding in tight oil sandstone cores from nuclear magnetic resonance (NMR),Tight oil sandstone cores; Water flooding; Displacement rate; Nuclear magnetic resonance; Oil distribution,CRITICAL CAPILLARY NUMBER; HUFF-N-PUFF; PERFORMANCE EVALUATION; SPONTANEOUS IMBIBITION; CO2 INJECTION; RECOVERY; RESERVOIR; BAKKEN; STATE; FLOW,"Water flooding is widely used as an economical and recyclable method to improve oil recovery in unconventional reservoirs. In this study, the effects of injection rates on oil distribution, the seepage dynamics and the contributions of increasing injection rates on enhancing oil recovery during water flooding are investigated. Typical tight oil sandstone cores with different permeabilities are obtained from Junggar Basin, Northwest China, for experimental studies that incorporate nuclear magnetic resonance analyses. Synthetic kerosene (viscosity = 11.2 mPa s) and heavy water (D2O) are used to simulate crude oil and formation water under formation conditions. The samples are first saturated with simulation water and thereafter displaced by synthetic oil until no water is produced to simulate the fully oil-saturated condition. To simulate the water flooding process, the samples are stably displaced by simulation water at injection rates increasing from 0.01 mL/min until no oil is produced. The T-2 spectra, injection pressures, and produced oil at different injection rates and water injection volumes are measured simultaneously. The transverse relaxation time (T-2) is converted for the corresponding pore-throat radius (r) by combining pore-throat size distributions (obtained from constant-rate mercury injection) and the fully oil saturated T-2 spectra. It indicates that the amplitude of T-2 spectra for macropore (>100 mu m) and mesopore (10-100 mu m) spaces decreases more rapidly than those for the micropore spaces (0-10 mu m) as injection rate increases. The classical capillary number theory is introduced to represent the effect of injection rate and characterize the dynamics of seepage processes. Results show that the oil recovery factor can be considerably improved by increasing the injection rate in tight oil cores, and this significant improvement is primarily attributed to mesopores and micropores.",15,15,7
Oil Recovery,Mu M,"Wei, Bing; Liu, Jiang; Zhang, Xiang; Xiang, Hua; Zou, Peng; Cao, Jie; Bai, Mingxing",Nuclear Magnetic Resonance (NMR) mapping of remaining oil distribution during sequential rate waterflooding processes for improving oil recovery,Waterflooding; Sequential rate mode; Remaining oil saturation; NMR; Enhanced oil recovery,CHEMICAL-TRACER TESTS; SILICA NANOPARTICLES; POROSITY TYPES; POROUS-MEDIA; FLOW; DISPLACEMENT; CHALLENGES; CAPILLARY; RESERVOIR; FORCES,"At the conclusion of waterflooding phase, significant volume of oil still remains in reservoir formations. In this paper, waterflooding was performed at a designed sequential rate mode with an aim to further reduce the remaining oil saturation (S-or). Waterflooding process was monitored continuously by a low-field Nuclear Magnetic Resonance (NMR) spectrometer attempting to map pore-scale displacing behaviors and also quantify the reduction in S-or in-situ. The results showed that the main pore size of the cores ranged from 1.6 mu m to 63.0 mu m inferred by T-2 (transverse relaxation time) distributions. The value of S-or in the cores increased towards the outlet face during waterflooding because of capillary end effect, which became more significant for heavy oil. At the termination of this waterflooding process, S-or was found to be further reduced by approximately 5.0% in the presence of thief water pathways as a result of the improved viscous forces. Water fingering and capillary imbibition effects were clearly visualized in the NMR images. These observations are expected to be useful for heavy oil waterflooding operations especially in post-breakthrough phase.",8,8,4
Oil Recovery,Mu M,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Oil Recovery,Tight Sandstone,"Chen, Meng; Dai, Jiacai; Liu, Xiangjun; Kuang, Yan; Wang, Zhongtao; Gou, Shunchao; Qin, Minjun; Li, Min",Effect of displacement rates on fluid distributions and dynamics during water flooding in tight oil sandstone cores from nuclear magnetic resonance (NMR),Tight oil sandstone cores; Water flooding; Displacement rate; Nuclear magnetic resonance; Oil distribution,CRITICAL CAPILLARY NUMBER; HUFF-N-PUFF; PERFORMANCE EVALUATION; SPONTANEOUS IMBIBITION; CO2 INJECTION; RECOVERY; RESERVOIR; BAKKEN; STATE; FLOW,"Water flooding is widely used as an economical and recyclable method to improve oil recovery in unconventional reservoirs. In this study, the effects of injection rates on oil distribution, the seepage dynamics and the contributions of increasing injection rates on enhancing oil recovery during water flooding are investigated. Typical tight oil sandstone cores with different permeabilities are obtained from Junggar Basin, Northwest China, for experimental studies that incorporate nuclear magnetic resonance analyses. Synthetic kerosene (viscosity = 11.2 mPa s) and heavy water (D2O) are used to simulate crude oil and formation water under formation conditions. The samples are first saturated with simulation water and thereafter displaced by synthetic oil until no water is produced to simulate the fully oil-saturated condition. To simulate the water flooding process, the samples are stably displaced by simulation water at injection rates increasing from 0.01 mL/min until no oil is produced. The T-2 spectra, injection pressures, and produced oil at different injection rates and water injection volumes are measured simultaneously. The transverse relaxation time (T-2) is converted for the corresponding pore-throat radius (r) by combining pore-throat size distributions (obtained from constant-rate mercury injection) and the fully oil saturated T-2 spectra. It indicates that the amplitude of T-2 spectra for macropore (>100 mu m) and mesopore (10-100 mu m) spaces decreases more rapidly than those for the micropore spaces (0-10 mu m) as injection rate increases. The classical capillary number theory is introduced to represent the effect of injection rate and characterize the dynamics of seepage processes. Results show that the oil recovery factor can be considerably improved by increasing the injection rate in tight oil cores, and this significant improvement is primarily attributed to mesopores and micropores.",15,15,7
Oil Recovery,Tight Sandstone,Liu Shun; Ni Jun; Wen Xianli; Liu Xiong; Huang Zhaoqin; Zhou Desheng; Ren Pengju,A dual-porous and dual-permeable media model for imbibition in tight sandstone reservoirs,Imbibition; Numerical model; imbibition index; Tight sandstone reservoir,OIL; RECOVERY,"Tight sandstone is an important oil reservoir in China which development is required water flooding. During water flooding treatments, imbibition is proven to strongly affect oil displacement. In this paper, capillary pressure is found not to be the only driving force to control imbibition in tight sandstone rock. Imbibition index is defined to be the second driving force. An experiment was designed to prove the imbibition index when water contacted tight sandstone samples. Then, a dual-porosity and dual-permeability numerical model was developed to simulate imbibition effect during water flooding in tight sandstone formations. Experimental results indicated that imbibition caused the weight of samples increased first and then declined. Increase is controlled by capillary force, and decline is affected by imbibition index. In Changqing formation in China, the imbibition index is 0.17-0.24, and the average imbibition index is 0.21.",9,9,12
Oil Recovery,Tight Sandstone,"Ye, Tao; Niu, Chengmin; Wei, Ajuan","Characteristics and genetic mechanism of large granitic buried-hill reservoir, a case study from PengLai oil field of Bohai Bay Basin, north China",,WEATHERING CRUST; TIGHT SANDSTONES; JUNGGAR BASIN; ZHENJING AREA; BONGOR BASIN; FAULT ZONE; BASEMENT; ROCK; FRACTURES; MIGRATION,"In recent years, a major breakthrough has been made in granite hydrocarbon exploration in the Bohai Bay Basin. With the proven reserves of more than 2 x 10(8)t, the Penglai (PL) oilfield is the largest granite oilfield discovered in China. Although the reservoir scale is large, the reservoir heterogeneity is also strong, which brings challenges to its exploration and evaluation. Based on the data of cores, thin sections, whole rock and physical property, the reservoir characteristics and control factors of reservoir-forming in the study area are discussed through the fault analysis and the recovery of tectonic uplift history. The results show that the lithology of PL structure are mainly Mesozoic intrusive granite and Proterozoic mica quartz schist, which develops reservoirs related to the weathered crust and internal fractures. Due to the influence of weathering intensity and fault activity, the porous reservoirs in weathered glutenite zone, pore-fractured reservoirs in weathered fracture zone and fractured reservoirs in the inner fracture zone were distributed orderly from top to bottom vertically. The scale of the high quality reservoir on the plane is controlled by lithology, faults, weathering and buried depth. Granite is the main reservoir-forming lithology for more brittle and less resistant to weathering than mica quartz schist, which forms a special phenomenon that the granite in saddle is rich for hydrocarbon while the mica quartz schist in high position is poor for hydrocarbon accumulation. The northwest Miaoxi fault is the main controlling-fault in the study area, and there is an obvious negative correlation between reservoir thickness and distance from this fault. The long-term uplift of Cenozoic provides conditions for strong weathering, while the shallow burial in the late stage provides effective protection for weathered crust reservoirs. The coupling of the above conditions is the main reason of large scale reservoir development in the study area, and among them, the long-term uplift is the key factor for reservoir-forming.",9,10,3
Oil Recovery,Tight Sandstone,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Oil Recovery,Gel,"Liu, Zhao-xia; Liang, Yan; Wang, Qiang; Guo, Yong-jun; Gao, Ming; Wang, Zheng-bo; Liu, Wan-lu",Status and progress of worldwide EOR field applications,Chemical flooding; Gas injection; Thermal recovery; Smart water flooding; EOR; Field application,PREFORMED PARTICLE GEL; CONFORMANCE-CONTROL; BRINE COMPOSITION; POROUS-MEDIA; OIL-RECOVERY; CO2 PILOT; NANOTECHNOLOGY; RESERVOIR; FLOOD; NANOMATERIALS,"Nowadays, EOR has been an important research topic in oilfield development and has made greater contribution to worldwide oil production. Whereas, a few of available statistical resources and the lack of systematical analysis hinder the understanding of the latest status and progress of different EOR technologies. This work, on the basis of systematic survey and data collection, makes a latest overview and analysis of worldwide EOR field application cases and gives a systematical discussion and summary from various aspects of different EOR methods (chemical flooding, gas injection, thermal recovery and smart water flooding, etc.), involving development status, maturity, advantages and limitations and so forth. Moreover, some reservoir statistics of some EOR field application cases in China (from 2008) and other countries (from 2014) are systematically presented and discussed. The work not only is beneficial for the reservoir workers to share the successful experience and learn the lessons of failure in oilfield development plan design and operation, but also is helpful to grasp the latest development status and maturity of EOR field applications and to provide important guarantee for the future development of different EOR techniques.",12,12,10
Oil Recovery,Gel,"Cui, Chunxue; Zhou, Zhijun; He, Ziang",Enhance oil recovery in low permeability reservoirs: Optimization and evaluation of ultra-high molecular weight HPAM/phenolic weak gel system,Cross-linking mechanism; Ultra-high molecular weight weak gel; Core flooding; Oil recovery; Field application,GELATION,"With the development and application of water flooding technology in low permeability reservoirs, at the later stage, the excessive water cut and the low oil recovery is inevitable. Therefore, it is of great importance to apply chemical flooding technology in the oilfield exploitation. In order to improve the oil recovery, the mechanism of ultra-high molecular weight HPAM/water-soluble phenolic weak gel formulation and the optimization of indepth profile control parameters for low permeability reservoirs are studied in this work. By condensation reaction between -CONH2 in HPAM and -CH2OH in water-soluble phenolic aldehydes, it is found that the weak gel can form a stable network structure under the microscope. The cross-linking kinetics of ultra-high molecular weight HPAM/water-soluble phenolic weak gel system is studied by the viscosity method, and the optimum concentration of HPAM and cross-linking agent are determined as follows: strong thermal stability and shear resistance can be got while concentration of HPAM is above 600 mg/L and the concentration of cross-linking agent is above 1400 mg/L. Based on the core flooding experiment, the displacement pressure and the oil recovery measured are compared at different molecular weights of HPAM, and the optimum molecular weight of HPAM for flooding applied in low permeability reservoirs is screened out as 1100*million. Microscopic displacement experiment indicates that large oil droplets were formed by the remaining oil in the small pores during the process of displacement, and were displaced out in the form of oil flow. The experimental findings were applied in Block Pu125, which is a low permeability reservoir in Daqing. The result shows that the production of a single well increased by 1400t, the comprehensive water cut in the whole area decreased by 7.16%, and the oil recovery increased by 3.58% after the weak gel flooding. Therefore, it is proved that the ultra-high molecular weight HPAM/water-soluble phenolic weak gel flooding system for profile control can effectively improve the oil recovery efficiency of low permeability oilfield.",8,8,8
Oil Recovery,Gel,"Aldhaheri, Munqith; Wei, Mingzhen; Zhang, Na; Bai, Baojun",Field design guidelines for gel strengths of profile-control gel treatments based on reservoir type,Enhanced oil recovery; Excessive water production; Conformance improvement; Gel treatments; Field project survey; Gel strength designs; Field design guidelines,POLYMER GEL,"Bulk gels are increasingly applied to alleviate the costly burden of excessive water production in mature oil fields. Practically, designs of new treatments are adopted from previous field projects conducted in analogous reservoirs. This case-finding procedure requires reservoir engineers to have thorough knowledge about how gel treatments, for each reservoir type, should be designed and have been mostly applied. This paper presents comprehensive design guidelines for injection-well gel treatments based on 61 worldwide field projects. It also assesses typical and most-applied designs and introduces them as new designing strategy. Seven gel strength design parameters were evaluated using the univariate descriptive analysis, stacked histograms, and scatterplots. Results indicated that gel strength parameters have very wide ranges and are considerably affected by the formation type. Gel treatments typically start with 3000 ppm polymer concentration, end with 7600 ppm, and a constant polymer-crosslinker ratio (PCR) of 40:1 is maintained during the treatments. They are often performed using the injection waters (to avoid type II gel syneresis) and polymers of 10-11 MM Da molecular weight (MW) and 30% hydrolysis that are injected in 4-5 treatment stages. The gel strength is principally designed based on the problem channeling strength and the planned gel volume. However, in cases of void-space-type problems, the gel extrusion, breakthrough, and breakdown become important designing criteria. To address these issues, more advanced tapering schemes than normal gradual increase of polymer concentrations are used to optimize gel plugging efficiency. In these schemes, small volumes of cement or low MW, fast-maturing, rigid gels (i.e., MARA-SEAL (TM)) are injected in front (gels only) or behind the high-MW MARCITsm gels as capping-materials. The novelty of present review lies in providing conformance specialists with new design strategy that would markedly facilitate designing of gel treatments and save time needed to identify analogs for a given candidate reservoir.",8,8,5
Oil Recovery,Gel,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Oil Recovery,Machine Learning,"Ershadnia, Reza; Amooie, Mohammad Amin; Shams, Reza; Hajirezaie, Sassan; Liu, Yuanhong; Jamshidi, Saeid; Soltanian, Mohamad Reza",Non-Newtonian fluid flow dynamics in rotating annular media: Physics-based and data-driven modeling,Pressure loss ratio; Non-Newtonian fluid; CFD; LSSVM; Rotating Couette flow,SHEAR-THINNING FLUIDS; LAMINAR-FLOW; ECCENTRIC ANNULI; STROUHAL NUMBERS; PRESSURE LOSSES; OIL; CYLINDER; CFD; OPTIMIZATION; TRANSPORT,"A thorough understanding and accurate prediction of non-Newtonian fluid flow dynamics in rotating annular media are of paramount importance to numerous engineering applications. This is in particular relevant to oil and gas industry where this type of flow could occur during, e.g., drilling, well completion, and enhanced oil recovery scenarios. Here, mathematically we report on physical-based (numerical) and data-driven (intelligent) modeling of three-dimensional laminar flow of non-Newtonian fluids driven by axial pressure gradient in annular media that consist of a coaxially rotating inner cylinder. We focus on the dynamics of pressure loss ratio (PLR)-the ratio of total pressure loss in presence of rotation to that in stationary condition. We develop a novel and computationally efficient machine-learning based predictive model based on a Least Square Support Vector Machine (LSSVM) optimized with a Coupled Simulated Annealing (CSA) algorithm, which is trained and tested by 730 experimental data collected for this study. We then perform numerous CFD simulations governed by Navier-Stokes set of equations, which correspond to each of the experimental cases. Comparing the results with those obtained from a widely used empirical correlation for PLR, we find that the both of our numerical and machine-learning based models are more accurate and present a larger applicability domain. The predictive LSSVM model enjoys a supervised learning paradigm and leads to the highest accuracy, while the physically originated CFD approach captures more consistently the nonlinear behavior of PLR versus key system features. Following the validation of our models, we study the less understood effects of fluid viscosity, axial velocity and rotational velocity on PLR dynamics. We employ a dimensionless parameter analogous to Strouhal number and identify specific regimes where PLR shows a distinct behavior. Our study elucidates the role of shear-thinning effect and its interplay with inertial forces on the dynamical behavior of pressure loss (ratio) in rotating yield-power-law fluids.",20,20,8
Oil Recovery,Machine Learning,"Zhong, Zhi; Sun, Alexander Y.; Wang, Yanyong; Ren, Bo",Predicting field production rates for waterflooding using a machine learning-based proxy model,Machine learning; Conditional deep convolutional generative adversarial neural network; Data-driven proxy model; Waterflooding; Field production rate,RESPONSE-SURFACE METHODOLOGY; ALTERNATING-GAS-INJECTION; RELATIVE PERMEABILITY; OIL-FIELD; WORK FLOW; OPTIMIZATION; PRESSURE; DESIGN,"Waterflooding, during which water is injected in the reservoir to increase pressure and therefore boost oil production, is extensively used as a secondary oil recovery technology. Tracking the extent and efficacy of waterflooding (i.e., fluid distributions) is a primary task of reservoir engineers and is traditionally achieved by running full reservoir models. In this work, we design and implement a proxy model using a conditional deep convolutional generative neural network (cDC-GAN), which can be used to quickly calculate the dynamic fluid distribution of a heterogeneous reservoir under waterflooding. Zero-sum game theory is the basis for the cDC-GAN, which includes a pair of generative discriminative models. The generative model tries to learn the relationship between input and output and makes the generated output as close as possible to the training data, while the discriminative model tries to distinguish the fake output and the real data used for training, such that the cDC-GAN learns the real data distribution at the end. In our cDC-GAN formulation, the reservoir properties (permeability distribution in this research) and forecast time information are treated as input, and water saturation is the desired output. The reservoir fluid production rate can be calculated based on the material balance principle. The most significant contribution of this work resides in training a cDC-GAN proxy model to accurately predict fluid saturation. A cDC-GAN has several advantages over the traditional full-model based workflow. First, the model parameters estimated from history matching help to improve reservoir characterization. Second, this proposed proxy model can predict the water and oil saturation distributions simultaneously, which can be used to calculate the water and oil flow rates. Third, this proposed proxy model can be used for waterflooding optimization and uncertainty analysis with far less computational effort than with the traditional method, which uses a reservoir simulator.",13,13,9
Oil Recovery,Machine Learning,"Yang, Xi; Dindoruk, Birol; Lu, Ligang",A comparative analysis of bubble point pressure prediction using advanced machine learning algorithms and classical correlations,"Bubble point pressure; PVT; Fluid properties; Machine learning methods (XGBoost, LightGBM, random forest regressor, MLP neural network, and super learner); Correlations",PVT PROPERTIES; SUPER LEARNER; MODEL,"The need for fluid properties or PVT (Pressure-Volume-Temperature) properties, is part of the entire Exploration and Production (E&P) lifecycle from exploration to mature asset management to the typical later life events such as, Improved Oil Recovery (IOR). As the projects mature, the need for such data and its integration for various discipline-specific workflows and its interpretation in the light of reservoir performance varies. Among all the key PVT properties, bubble point pressure is probably the most important parameter. Bubble point pressure is important because it is the point at which constant composition and variable composition portions of the depletion paths merge. Geometrically, bubble point pressure appears to be a discontinuity. In addition, it dictates the existence (or not) of the incipient phase (i.e., gas phase) leading to the changes in the flow characteristics both in porous media and as well as within the wellbore and the facilities. Furthermore, it is also a good indicative of a possible gas cap when the reservoir is at saturation (reservoir pressure is equal to the bubble point pressure) or near-saturated. Among the highlighted uses, there are many more used such as the determination of the elements of miscibility, gas lift design, etc. Therefore, it is very important to estimate the bubble point pressure accurately. In this study, tree-based advanced machine learning algorithm including XGBoost, LightGBM, and random forest regressor, and multi-layer perceptron (neural network) regressor are implemented to predict bubble point pressure (P-bp). A novel super learner model which is also known as stacking ensemble is used to enhance base machine learning model performance on predicting bubble point pressure. Three datasets with different predictors are prepared to study machine learning algorithms' performance for three situations: only compositional data are available; only bulk properties (Gas-Oil-Ratio, gas gravity, API gravity and reservoir Temperature) are available; both compositional data and bulk properties are available. Through literature review, there is no research on using only compositional data and temperature to predict bubble point pressure. Our super learner model offers an accurate solution for oil bubble point pressure when only compositional data and temperature are available. Machine learning models perform better than empirical correlations with limited input data (i.e., bulk properties). When compositional data and bulk properties are all used as predictors, super learner reaches about 5.146% mean absolute relative error on predicting the bubble point pressure from global samples with bubble point pressures in the range of 100 to 10,000 psi, which is a wider range compared to most ANN models published in literature.",9,9,1
Shale Gas,Organic Matter,"Fan, Cunhui; Li, Hu; Qin, Qirong; He, Shun; Zhong, Cheng","Geological conditions and exploration potential of shale gas reservoir in Wufeng and Longmaxi Formation of southeastern Sichuan Basin, China",Shale gas; Geological conditions; Tectonic uplift; Preservation conditions; Longmaxi Formation; Southeastern Sichuan Basin,TIGHT SANDSTONE RESERVOIRS; PERMIAN LUCAOGOU FORMATION; ORDOS BASIN; UPPER ORDOVICIAN; TECTONIC FRACTURES; DINGSHAN AREA; SOUTH CHINA; OIL-SHALE; GEOCHEMICAL CHARACTERISTICS; PRESERVATION CONDITIONS,"The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R-o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration.",39,40,8
Shale Gas,Organic Matter,"Cao, Taotao; Xu, Hao; Liu, Guangxiang; Deng, Mo; Cao, Qinggu; Yu, Ye","Factors influencing microstructure and porosity in shales of the Wufeng-Longmaxi formations in northwestern Guizhou, China",Microstructure; OM pore type; Water saturation; Shale gas content; Wufeng-Longmaxi formation; Northeastern Guizhou,PORE STRUCTURE CHARACTERISTICS; NORTHEASTERN BRITISH-COLUMBIA; METHANE ADSORPTION CAPACITY; MISSISSIPPIAN BARNETT SHALE; SOUTHERN SICHUAN BASIN; ORGANIC-RICH SHALES; GAS SHALES; NORTHERN GUIZHOU; SURFACE-AREA; MARINE SHALE,"Thickness marine shale of Paleozoic Wufeng-Longmaxi Formations is deposited in the northwestern Guizhou province, which borders on the shale gas production area in southeast Sichuan Basin. However, few studies have been performed to characterize shale gas reservoir of the Wufeng-Longmaxi Formations in this area. In this study, 80 shale samples collected from the LY1 well were designed to conduct a series of analyses, aiming to obtain microstructure features and reveal their controlling factors. Shales within the Upper Longmaxi Formation characterized by low total organic carbon (TOC) content, high clay mineral content and low porosity are considered to be unfavorable interval for shale gas exploration. Whereas, a high-quantity shale (TOC>2%, clay<40%) interval with thickness of about 27 m exists within Lower Longmaxi Formation and Wufeng Formation. Pores in the studied shales are dominated by organic matter (OM) pores, followed intraparticle (intraP) within carbonates and intercrystalline pores within pyrite framboids. OM pores could be divided into three types, as OM pores within solid bitumen, in-situ amorphous kerogen and graptolite. OM pores are extremely developed in solid bitumen and in-situ amorphous kerogen, and the former have larger diameter than the latter. Rare pores are developed in graptolite. The total porosity and specific surface area of the shales within the Lower Longmaxi Formation and Wufeng Formation are twice more than those within the Upper Longmaxi Formation. Samples with higher TOC values commonly have higher porosities and specific surface areas, suggesting TOC content determines shale physical property. Clay mineral content exhibits a negative influence on microstructure and porosity but determines water saturation. Water saturation has significant negative relationships with micro-to mesopore volumes, porosity and TOC content, illustrating water molecular stores mainly in hydrophilic pores associated with clay minerals rather than OM-hosted nanopores. The gas generation, reservoir quantity and gas content of the Longmaxi-Wufeng shales in northwestern Guizhou are also compared with those of the famous Fuling and Weiyuan districts in eastern Sichuan Basin, and we considered that the shale gas prospect in northwestern Guizhou is excellent.",17,19,7
Shale Gas,Organic Matter,"Ma, Weijiao; Hou, Lianhua; Luo, Xia; Liu, Jinzhong; Tao, Shizhen; Guan, Ping; Cai, Yuwen",Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature -based semi -open pyrolysis: Implications for in -situ conversion process,Chang 7 oil shale; In-situ conversion process; Temperature-based semi-open pyrolysis; Hydrocarbon generation process; Hydrocarbon expulsion process,TRIASSIC YANCHANG FORMATION; ORGANIC-MATTER; HYDROUS PYROLYSIS; GAS GENERATION; CHINA IMPLICATIONS; SOURCE-ROCK; II KEROGEN; PETROLEUM; EVOLUTION; SYSTEM,"There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300-320 degrees C, 0.53-0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320-380 degrees C, 0.55-1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380-420 degrees C, 1.09-1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 degrees C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24-1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.",16,19,10
Shale Gas,Organic Matter,"Yu, Kun; Ju, Yiwen; Shao, Chunjing",Structure characteristics and evolution mechanism of nanopore in transitional coal-bearing shale,Transitional coal-bearing shale; Pore structure; Pore type; Characteristics; Evolution,PORE-SIZE DISTRIBUTION; DENSITY-FUNCTIONAL THEORY; GAS-ADSORPTION; NITROGEN ADSORPTION; ELECTRON-MICROSCOPY; METHANE ADSORPTION; FRACTAL DIMENSION; HUAINAN COALFIELD; POSIDONIA SHALE; SICHUAN BASIN,"Nanopore plays a crucial role in shale gas adsorption, and its characteristics and evolution are significant for the evaluation of shale reservoirs with strong heterogeneity. In this study, transitional coal-bearing shale samples from the south margin of North China were selected for investigation of pore structure characteristics and evolution mechanism. Results indicated that nanopores of the studied shales are fractal with strong heterogeneity. The higher fractal dimension leads to larger surface area and micropore volume of shale samples. The abundant terrigenous material and limited hydrocarbon generation and expulsion are favorable for the development of intraP pores in clay, so that the Organic matter (OM) pores are poorly developed and are partially filled with clay minerals and pyrite framboids. Shale samples having higher levels of clay content and lower levels of quartz content tend to develop more heterogeneous micropores, producing a more complex pore structure in shale. The evolution of nanopore in studied shales is simultaneously determined by the coupling relationship between clay content and the thermal maturation of OM. In the early oil and low clay content stage, the low degree of the thermal evolution of OM leads to generation of less acidic fluid during the decarboxylation of kerogen, resulting in a weak physical combination and chemical corrosion between OM and clay minerals, with the macropores taking the main place in the pore structure. In the main to late oil and medium clay content stage, hydrocarbon generation of OM leads to the development of pores in kerogen and the gradual generation of more acidic fluids that dissolve clay minerals, so that the mesopores are dominant. In the wet gas and high clay content stage, increases in hydrocarbon generation intensity and clay mineral content cause development of more complexes of OM and clay, with a large number of micropores produced in shale reservoirs.",16,16,3
Shale Gas,Organic Matter,"Kang, Zhiqin; Zhao, Yangsheng; Yang, Dong; Tian, Lijun; Li, Xiang",A pilot investigation of pyrolysis from oil and gas extraction from oil shale by in-situ superheated steam injection,Oil shale; In-situ pyrolysis; Superheated steam injection; Experimental investigation; Oil-recovery rate,COMPREHENSIVE UTILIZATION; NUMERICAL-SIMULATION; THERMAL-CRACKING; HIGH-TEMPERATURE; ORGANIC-MATTER; X-RAY; TECHNOLOGY; COMBUSTION; PERMEABILITY; EVOLUTION,"Oil shale is a critical strategic energy with huge reserve. The research and development of an economically feasible in-situ retorting technology for oil and gas extraction from oil shale is of great significance. Thus, this paper experimentally studied the large oil-shale samples pyrolysis by in-situ superheated steam injection (MTI) implemented from 2014 to 2016. The structure of the large-scale in-situ pyrolysis test system, the experimental procedure, and the results are presented here. The steam fracturing-connection was used during the initial stage, and the pressure of the superheated steam for fracturing was similar to 2 times higher than the strata stress. The variation of temperature and pressure during pyrolysis was controlled by the variation in steam seepage. The operating steam pressure during pyrolysis was lower than 1/4 of the strata stress. The energy utilization of the superheated steam for the pyrolysis reaction was 42.7%. The average temperature of the fluid that was discharged from the production wells was around 170 degrees C, which can be recycled to achieve a heat-utilization coefficient of 13.19% in commercial operations. The oil-recovery rate in the pyrolysis area exceeded 95%, and the overall oil-recovery rate reached up to 70.7% of the tested large oil-shale samples. The gas production rate and the effective energy rate of the injected steam are correlated with an exponential function. Our pilot tests indicate that the in-situ retorting technology of oil shale by MTI shows great potential for commercial operation in oil-shale formation.",15,18,10
Shale Gas,Organic Matter,"He, Taohua; Lu, Shuangfang; Li, Wenhao; Sun, Dongquan; Pan, Wenqing; Zhang, Baoshou; Tan, Zhaozhao; Ying, Junfeng","Paleoweathering, hydrothermal activity and organic matter enrichment during the formation of earliest Cambrian black strata in the northwest Tarim Basin, China",Paleoweathering; Hydrothermal activity; Palaeoproductivity; Euxinic benthic condition; Deep hydrocarbon exploration,SOURCE-ROCK; BIYANG DEPRESSION; SEDIMENTARY-ROCKS; DEPOSITIONAL ENVIRONMENT; METAL ENRICHMENT; NANXIANG BASIN; SOUTH CHINA; SHALES; GEOCHEMISTRY; OIL,"The earliest Cambrian black strata are widely deposited in many continents, and attracted increasing attention from scholars worldwide. Based on detailed investigations of strata from the Shiairike section in the Aksu area, northwest Tarim Basin, China, the effects of paleoweathering and hydrothermal activity on the organic matter enrichment of this black series was revealed. Combined organic and inorganic geochemistry evidence indicated that relatively strong weathering carried abundant nutrient elements and terrigenous detritus into the sea, which promoted a period of paleoproductivity and enhanced the sinking of dissolved organic matter. Moreover, the hydrothermal activity triggered the enrichment of abundant reducing gases (e.g. H2S) and minerals, whereby gases created euxinic benthic conditions that were favorable for the preservation of sedimentary organic matter, while minerals simultaneously diluted primary productivity. As a result, the low section of the black strata was characterized by dominant siliceous rocks with enrichments of P, Ba, Zn and Cu; whereas the upper section contained abundant organic matters that had the potential to generate and expel a remarkable volume of hydrocarbons. These results provide a theoretical basis for the international exploration of paleo-hydrothermal minerals within the early Cambrian black strata as well as that of the deep Cambrian oil and gas, particularly in the Tarim Basin, northwest China.",14,14,4
Shale Gas,Organic Matter,"Cui, Guanglei; Xia-Ting, Feng; Pan, Zhejun; Chen, Tianyu; Liu, Jishan; Elsworth, Derek; Tan, Yuling; Wang, Chunguang",Impact of shale matrix mechanical interactions on gas transport during production,Effective diffusion; Surface diffusion; Organic matter; Inorganic minerals; Effective stress,ORGANIC-RICH SHALE; COAL PERMEABILITY; SURFACE-DIFFUSION; FLOW BEHAVIOR; ADSORBED GAS; SLIP-FLOW; MODEL; EVOLUTION; RESERVOIR; ADSORPTION,"Shale gas has played an increasingly important role in world energy supply in recent years. The gas transport process in the shale matrix is particularly important as it affects the long-term production behavior of shale gas. The shale matrix consists of inorganic minerals and embedded organic matter with mass transfer influenced by mechanical interactions. We develop a micro-scale discrete coupled model to explicitly account for mass transfer and mechanical interactions, and how these interactions affect the gas transport characteristics of both components. Specifically, the model comprises organic matter embedded within inorganic minerals. The proposed model is implemented and solved within the framework of COMSOL Multiphysics (Version 5.4). The model is first verified against the results of a desorption-diffusion-seepage coupled experiment and then extended to field scale. It is found that the impacts of gas pressure and effective strain are different for the gas seepage in inorganic minerals and gas diffusion in organic matter. Gas pressure may enhance the permeability of the inorganic phase due to the gas slippage effect while compactive effective strain decreases permeability during the gas depletion process. For gas diffusion in the organic matter, surface diffusion decreases and effective diffusion coefficient increases with declining gas pressure. While the impacts of effective strain on the effective diffusion are dependent on the external boundary conditions, the effective diffusion coefficient is lower than the initial value under constant stress conditions and larger than the initial value under constant volume conditions. The proposed model provides a complementary method to conventional continuum dual-media approaches and provides a clear understanding of the interactions between the two components. Field-observed oscillatory gas production data is readily history-matched and key mechanisms explained with the proposed approach presented in this work.",13,13,11
Shale Gas,Organic Matter,"Sun, Wenjibin; Zuo, Yujun; Wu, Zhonghu; Liu, Hao; Zheng, Lujing; Wang, Hong; Shui, Yue; Lou, Yili; Xi, Shijun; Li, Taotao; Luo, Xuan","Pore characteristics and evolution mechanism of shale in a complex tectonic area: Case study of the Lower Cambrian Niutitang Formation in Northern Guizhou, Southwest China",Shale; Pore structure; Niutitang formation; Northern Guizhou,LONGMAXI FORMATION SHALE; SICHUAN BASIN; FRACTAL CHARACTERIZATION; QIANNAN DEPRESSION; MIGRATION PATHWAYS; ORGANIC POROSITY; GAS-ADSORPTION; RESERVOIRS; NMR; PROVINCE,"The Lower Cambrian Niutitang Formation is one of the most important shale reservoirs in the Northern Guizhou. To study the characteristics of pore structures and the relationships between shale's physical properties and pore structures in the complex tectonic area, from the perspective of hydrocarbon generation and evolution, the mineral composition, pore structure characteristics of shale samples in northern Guizhou were analyzed using X-ray diffraction (XRD), optical microscopic composition analysis, focused ion beam-scanning electron microscopy (FIB-SEM), vitrinite reflectivity and nitrogen adsorption experiments. Results indicate that the pore structures can be categorized into conical, ink bottle, spherical, elliptical, beaded, irregular, and plate-like intersecting microfractures. Shale samples are organic-rich with an average total organic carbon content of 4.39%. Organic matter is consumed within the shale matrix during the hydrocarbon generation and evolution, which increases the organic pore size and the proportion of organic pores. The high TOC content is conducive to developing organic pores. In addition, the average content of brittle minerals is greater than 70%. High content of brittle minerals during diagenesis is conducive to developing the residual pores at the edges of mineral particles and dissolved pores within mineral particles. Thus, the high content of brittle minerals and TOC content is favorable for the development of meso-macropores. The content of clay minerals within the shale samples ranges from 6.3% to 42.2%, with an average of 20.02%. Micropores and mesopores mainly occur in the clay minerals. Pores in clay minerals are easily compacted under tectonic stress. Meanwhile, high thermal evolution degree and the vitrinite reflectance R-o greater than 3.5 is not conducive to developing pores. Hence, high TOC content, high brittle minerals content, and thermal evolution degree ranging from 0.6% to 3% make the Lower Cambrian Niutitang Formation shale reservoirs favorable for shale gas exploration.",13,13,8
Shale Gas,Organic Matter,"Wang, Yang; Liu, Luofu; Cheng, Hongfei","Pore structure of Triassic Yanchang mudstone, Ordos Basin: Insights into the impact of solvent extraction on porosity in lacustrine mudstone within the oil window",Pore structure; Solvent extraction; Nitrogen adsorption; Lacustrine mudstone; Oil window,CONTINENTAL TRANSITIONAL SHALE; ORGANIC-MATTER; SICHUAN BASIN; MARINE SHALE; GEOCHEMICAL CHARACTERISTICS; CHINA IMPLICATIONS; NETWORK EVOLUTION; THERMAL MATURITY; LONGMAXI SHALE; GAS,"Low-pressure nitrogen physisorption was performed on Triassic Yanchang mudstones before and after solvent extraction to characterize the extractable organic matter (EOM) occurrence and ascertain the impact of extracts on the nanoporosity of lacustrine mudstone within the oil window. Organic-rich Yanchang mudstones are currently thermally mature (vitrinite reflectance of 0.48%-0.92%). SEM-observed pore types chiefly comprise interparticle and intraparticle pores related to inorganic minerals, with organic matter pores less developed. Pore volume (PV) of the original mudstones is 0.35-2.15 cm(3)/100 g and the specific surface area (SSA) is 1.22-7.77 m(2)/g. Brittle minerals (quartz + feldspar + carbonates) and I/S mixed layer jointly show the positive effect on the pore space development in the Yanchang mudstone. Four groups of mudstones with obvious differences in pore structure properties were identified, which probably result from the various development degrees of interparticle pores at the edge of brittle minerals, and intraparticle pores associated with I/S aggregates. Generally, solvent extraction will result in a noticeable increase in the volume of N-2 adsorbed due to the reopening of pore space blocked by EOM, which is related to increases in PV an SSA. A declining case, probably caused by the progressive shift of the enlarged open pore space to the larger macropore range (d > 200 nm) which is not detected by N-2 adsorption and counteracts the increased porosity by extraction, however, was also observed in the current study. Overall, the infilling degree of EOM increased with increasing thermal evolution degree of shales within the oil window, which mainly blocks minor pores in lower mature samples but larger pores in higher mature samples.",13,13,6
Shale Gas,Organic Matter,"Zou, Jie; Rezaee, Reza; Yuan, Yujie; Liu, Kouqi; Xie, Quan; You, Lijun",Distribution of adsorbed water in shale: An experimental study on isolated kerogen and bulk shale samples,Shale; Isolated kerogen; Adsorbed water distribution; Pore size distribution; Gas adsorption,METHANE ADSORPTION CAPACITY; NORTHEASTERN BRITISH-COLUMBIA; ORGANIC-RICH WUFENG; PORE STRUCTURE; GAS SHALES; SORPTION BEHAVIOR; PERMEABILITY; RESERVOIRS; MOISTURE; BASINS,"Bakken shale samples were studied for distribution of adsorbed water using low-pressure nitrogen sorption. By comparing results between dry and wet samples, the distribution of adsorbed water in shale was determined. Two of the isolated kerogen samples show a striking change of pore size distribution (PSD) in large pores (>16 nm), indicating the pronounced distribution of adsorbed water in large pores of organic matter. As for the bulk shale, water can adsorb in both small (<16 nm) and large pores (>16 nm) depending on hydrophilic sites. However, hydrophilic sites in small pores are mainly contributed by inorganic matter, while hydrophilic sites in large pores are composed of inorganic or organic matter. The overall results therefore clarify the contribution of inorganic and organic matter to water adsorption in shale and provide a better understanding of the significance of adsorbed water in shale.",13,13,2
Shale Gas,Organic Matter,"Han, Hui; Pang, Peng; Zhong, Ningning; Luo, Qingyong; Ma, Yong; Gao, Yuan","The pore characteristics and gas potential of the Jurassic continental shales in the middle-small basins, northwest China",Continental shales; Type III organic matters; Northwest China; Shale gas; Pore,MISSISSIPPIAN BARNETT SHALE; TRIASSIC YANCHANG FORMATION; THRUST-FOLD BELT; BOHAI BAY BASIN; CHANG 7 MEMBER; ORDOS BASIN; SICHUAN BASIN; LACUSTRINE SHALES; ORGANIC-MATTER; FRACTAL CHARACTERISTICS,"Jurassic continental shales were extensively developed in the northwest of China. To characterize and analyze the pores and gas potential of these shales, geochemical, mineralogical, petmphysical, and methane adsorption capacity (MAC) experiments were performed on 10 samples. The results indicated that these shales have a high total organic carbon (TOC) content, low porosity and permeability. Interparticle pores between clay platelets are dominant. Organic matter (OM) pores cannot be observed using scanning electron microscope. The methane adsorption capacity is strong, and it is controlled by TOC content. Strong MAC indicated the shales have an excellent capacity of storing gas. In addition, type III organic matters can generate amount of gas at a lowly mature stage. Therefore, it is speculated that the studied shales have a good gas potential, which is supported by canister desorption results.",12,12,4
Shale Gas,Organic Matter,"Tang, Ling; Song, Yan; Pang, Xiongqi; Jiang, Zhenxue; Guo, Yingchun; Zhang, Hongan; Pan, Zhihong; Jiang, Hang","Effects of paleo sedimentary environment in saline lacustrine basin on organic matter accumulation and preservation: A case study from the Dongpu Depression, Bohai Bay Basin, China",Saline lacustrine basin; Organic matter; Enrichment and preservation; Sedimentary environment; Dongpu depression; Shahejie formation,WATER-COLUMN ANOXIA; MARINE BLACK SHALES; QAIDAM BASIN; ISOTOPIC COMPOSITION; CARBON; PRODUCTIVITY; ANCIENT; DEPOSITION; MECHANISMS; INDICATORS,"The Dongpu Depression has abundant oil and gas resources, but the distribution of hydrocarbon resources and enrichment degrees of organic matter (OM) in the northern and southern Dongpu Depression have significant differences due to the diverse sedimentary environment. To gain deep insight into the effects of sedimentary environment on OM accumulation and preservation, a series of experiments including element geochemistry, organic geochemistry and isotope geochemistry were performed on core samples collected from the fresh, brackish and saline regions of the third member of the Eocene Shahejie Formation (Es-3). The lacustrine closure, paleo-salinity, redox conditions, hydrodynamic conditions, paleo-climate and paleo-productivity were quantitatively evaluated. Controlling factors and OM enrichment models were evaluated and established. The results show that the Es-3 Formation was deposited as the lake experienced closed saline to transitional and then fresh lake stages. The lacustrine deposits were accompanied by climate changes from dry to humid and strongly rifting during Es-3 deposition. The weak hydrodynamic conditions (Zr/Rb) and paleo climate indices (delta O-18, climate index, Fe/Mn, Sr/Cu and Al/Mg) imply that moderate humid and dry climate can encourage OM development and preservation. The paleo productivity indices (delta C-13, P/Al, P/Ti and P content) are positively related to TOC indicating that high productivity promotes OM accumulation. All the paleo salinity indices (Z value, Sr/Ba and B/Ga) have positive correlations with TOC content, suggesting that OM enrichment increases with salinity to some extent. The positive relationships between the redox indices (V/Cr, V/Sc, U/Th, and dU) and TOC indicate that redox conditions are the most important for OM preservation. This study not only advances the theory of OM enrichment mechanism in saline basins, but also provides guidance for predicting the distributions of high-quality source rocks in the Dongpu Depression.",9,10,5
Shale Gas,Organic Matter,"Li, Xin; Jiang, Zhenxue; Jiang, Shu; Li, Zhuo; Song, Yan; Jiang, Hongyang; Cao, Xiangni; Qiu, Hengyuan; Huang, Yizhou; Ming, Wen; Miao, Yanan","Characteristics of matrix-related pores associated with various lithofacies of marine shales inside of Guizhong Basin, South China",Matrix-related pore; Controlling factors; Lithofacies; Lower Carboniferous; Middle Devonian; Guizhong Basin,METHANE SORPTION CAPACITY; UPPER YANGTZE PLATFORM; SICHUAN BASIN; GAS-ADSORPTION; ORGANIC-MATTER; LONGMAXI SHALE; POROSITY; SEM; SYSTEMS; OIL,"Matrix-related pore characteristics of between Lower Carboniferous shale and Middle Devonian shale in Guizhong Basin were investigated to explore the reservoir capacity. Via the combination of organic geochemistry analysis, X-ray diffraction, gas adsorption, mercury intrusion porosimetry, helium porosimetry and focused ion beam-scanning electron microscopy, material basics and physical properties were studied. Five lithofacies were divided as comparable units in two formations according to thermal maturity, OM abundance and mineral components, namely organic-moderate argillaceous shale with high thermal maturity (OMAS-H) and organiclean argillaceous shale with high thermal maturity (OLAS-H) in Lower Carboniferous Formation, and organiclean mixed shale with over thermal maturity (OLMS-O), organic-rich mixed shale with over thermal maturity (ORMS-O) as well as organic-rich calcareous shale with over thermal maturity (ORCS-O) in Middle Devonian Formation. Results showed that (1) OMAS-H and OLAS-H performed better porous features than OLMS-O, ORMS-O and ORCS-O, in terms of PV, PSA and porosity, (2) pores developed better in OMAS-H and OLAS-H than those in OLMS-O, ORMS-O and ORCS-O, in terms of pores of rigid grains, pores associated with clay flakes and OM-hosted pores, (3) specific PVs of OM were dramatically larger than those of mineral components, while specific PVs of OM in both OMAS-H (0.348 ml/g x 10(-6)) and OLAS-H (0.248 ml/g x 10(-6)) were about an order of magnitude higher than those in OLMS-O (0.055 ml/g x 10(-6)), ORMS-O (0.025 ml/g x 10(-6)) and ORCS-O (0.011 ml/g x 10(-6)). The ability of pore contribution largely depends on whether corresponding components are suited in the appropriate evolution stage with suitable thermal and pressure circumstance. Then sufficient degree of pore carriers (matrixes) need to be thought about, especially OM and clay as the secondary pore providers. Also, the demand for pore preservation highlights the importance of brittle minerals which can establish rigid frameworks. Therefore, in the case of controlling factors on pore characteristics, the importance ranking should be taken into consideration.",8,8,5
Shale Gas,Organic Matter,"Yang, Wei; He, Sheng; Iglauer, Stefan; Guo, Xiaowen; Zhai, Gangyi; Zhou, Zhi; Dong, Tian; Tao, Ze; Wei, Sile","Porosity characteristics of different lithofacies in marine shale: A case study of Neoproterozoic Sinian Doushantuo formation in Yichang area, China",Doushantuo Shale; Yichang area; Lithofacies classification; Porosity development; Controlling factors,MISSISSIPPIAN BARNETT SHALE; PORE STRUCTURE; SICHUAN BASIN; GAS-STORAGE; MARCELLUS; WOODFORD; WUFENG; CLASSIFICATION; ACCUMULATION; ADSORPTION,"This study evaluates the pore network systems in the Neoproterozoic Sinian Doushantuo (Z(1)d) shale from the Yichang area in the Middle Yangtze region. All samples were classified based on their lithologies and examined by geochemical and petrographic analysis, assisted with carbon dioxide/nitrogen (CO2/N-2) adsorption, mercury injection capillary pressure (MICP) and focused ion beam-scanning electron microscopy (FIB-SEM) to fully characterize the nanoscale porosity of the different shale lithofacies. The calcareous shale lithofacies group (I-C), mixed shale lithofacies group (II-M) and siliceous shale lithofacies group (III-S) were identified via ternary mineralogy diagrams. Clearly, different lithofacies had different porosities, pore volume, surface area and pore-size distribution (ranging from 0.3 nm to 36 mu m). The mixed shale lithofacies group (II-M) had the highest total pore volumes, followed by the calcareous shale lithofacies group (I-C) and the siliceous shale lithofacies group (III-S). Peak values (2-20 nm, 20-50 nm, 50-60 nm and 90-200 nm) obtained from N-2 adsorption were identified as organic matter (OM) pores, dissolution intraparticle (intraP) pores and intercrystalline pores (using SEM images analysis). Porosity shows a non-monotonic trend with TOC content and a maximum at 4.5-5.5 wt% TOC, similar relationships between TOC and mesopore/macropore volumes, due to pore collapse and compaction. The FIB-SEM images revealed solid bitumen and two types of kerogen in the examined shale samples; these different organic matter types had clearly distinct pore characteristics. While the smaller OM particles mobilized and converted into solid bitumen in which OM pores were larger and more abundant, the large-scale OM particles were most likely non-porous inert maceral and sponge-like porous amorphous kerogen. Overall TOC content and organic types are the key controlling factors to the nanoscale porosity development in the Doushantuo Shale, and the Sinian Doushantuo shale (in the Yichang area) has great potential for shale gas exploration and exploitation in South China.",8,8,3
Shale Gas,Organic Matter,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Shale Gas,Sichuan BASIN,"Fan, Cunhui; Li, Hu; Qin, Qirong; He, Shun; Zhong, Cheng","Geological conditions and exploration potential of shale gas reservoir in Wufeng and Longmaxi Formation of southeastern Sichuan Basin, China",Shale gas; Geological conditions; Tectonic uplift; Preservation conditions; Longmaxi Formation; Southeastern Sichuan Basin,TIGHT SANDSTONE RESERVOIRS; PERMIAN LUCAOGOU FORMATION; ORDOS BASIN; UPPER ORDOVICIAN; TECTONIC FRACTURES; DINGSHAN AREA; SOUTH CHINA; OIL-SHALE; GEOCHEMICAL CHARACTERISTICS; PRESERVATION CONDITIONS,"The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R-o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration.",39,40,8
Shale Gas,Sichuan BASIN,"Yang, Rui; Jia, Aoqi; He, Sheng; Hu, Qinhong; Dong, Tian; Hou, Yuguang; Yan, Jianping","Water adsorption characteristics of organic -rich Wufeng and Longmaxi Shales, Sichuan Basin (China)",,SEDIMENTARY GEOCHEMICAL PROXIES; METHANE ADSORPTION; GAS SHALES; PALEOENVIRONMENT INTERPRETATION; SORPTION BEHAVIOR; MESOPOROUS SILICA; JIAOSHIBA AREA; CARBON-DIOXIDE; VAPOR SORPTION; PORE STRUCTURE,,29,30,4
Shale Gas,Sichuan BASIN,"Xu, Shang; Gou, Qiyang; Hao, Fang; Zhang, Baiqiao; Shu, Zhiguo; Zhang, Yuanyin","Multiscale faults and fractures characterization and their effects on shale gas accumulation in the Jiaoshiba area, Sichuan Basin, China",Shale; Multiscale faults and fractures; Seal conditions; Accumulation mechanism; Jiaoshiba area,SILURIAN LONGMAXI FORMATION; UPPER ORDOVICIAN WUFENG; PORE STRUCTURE; MARINE SHALE; BOREHOLE IMAGE; SCALE PORES; ENRICHMENT; BARNETT; STORAGE; LOGS,"The distribution and development of faults and fractures in organic-rich shales are important factors for the accumulation or loss of shale gas. In this work, merged three-dimensional seismic data, automated fault extraction, imaging logging, rock core examination, micro-CT scans, and field emission scanning electron microscopy were used to precisely characterize the distribution of faults and fractures of the Wufeng-Longmaxi shales from the Zilichang Block, Jiaoshiba area. The effects of faults and fractures on the accumulation and loss of shale gas were analyzed. The results show that the microfractures of shale samples from the JYA well of the Zilichang Block mainly consisted of intergranular, intragranular, and contraction fractures, and the fracture porosity of the samples is approximately 1.24%. These fractures help to increase the storage space of the shale reservoirs and are conducive for shale gas accumulation. In micro-CT scans, the microfractures were linked in a network-like structure and generally had excellent connectivity. Therefore, the microfractures could enhance the seepage capacity of the shale reservoirs and help the shale gas to migrate to hydraulically induced fractures. As a result, the productivity of the shale reservoirs could be dramatically improved. Macroscopic fractures were found to play a key role in the storage of shale gas. Many natural fractures, mainly are faults and open fractures, have developed in the caprock strata that directly overly the main production layers shales. The shale gas direct seal conditions are poor, which is not conducive to shale gas accumulation. Therefore, the Wufeng-Longmaxi shales in the JYA well is a relatively open shale system, with a formation pressure coefficient and gas saturation value of 0.96 and 37%, respectively. The single-well hydraulic fracturing productivity of the JYA well is low, with an absolute open flow value less than 0.5 x 10(4) m(3)/d.",19,19,7
Shale Gas,Sichuan BASIN,"Cao, Taotao; Xu, Hao; Liu, Guangxiang; Deng, Mo; Cao, Qinggu; Yu, Ye","Factors influencing microstructure and porosity in shales of the Wufeng-Longmaxi formations in northwestern Guizhou, China",Microstructure; OM pore type; Water saturation; Shale gas content; Wufeng-Longmaxi formation; Northeastern Guizhou,PORE STRUCTURE CHARACTERISTICS; NORTHEASTERN BRITISH-COLUMBIA; METHANE ADSORPTION CAPACITY; MISSISSIPPIAN BARNETT SHALE; SOUTHERN SICHUAN BASIN; ORGANIC-RICH SHALES; GAS SHALES; NORTHERN GUIZHOU; SURFACE-AREA; MARINE SHALE,"Thickness marine shale of Paleozoic Wufeng-Longmaxi Formations is deposited in the northwestern Guizhou province, which borders on the shale gas production area in southeast Sichuan Basin. However, few studies have been performed to characterize shale gas reservoir of the Wufeng-Longmaxi Formations in this area. In this study, 80 shale samples collected from the LY1 well were designed to conduct a series of analyses, aiming to obtain microstructure features and reveal their controlling factors. Shales within the Upper Longmaxi Formation characterized by low total organic carbon (TOC) content, high clay mineral content and low porosity are considered to be unfavorable interval for shale gas exploration. Whereas, a high-quantity shale (TOC>2%, clay<40%) interval with thickness of about 27 m exists within Lower Longmaxi Formation and Wufeng Formation. Pores in the studied shales are dominated by organic matter (OM) pores, followed intraparticle (intraP) within carbonates and intercrystalline pores within pyrite framboids. OM pores could be divided into three types, as OM pores within solid bitumen, in-situ amorphous kerogen and graptolite. OM pores are extremely developed in solid bitumen and in-situ amorphous kerogen, and the former have larger diameter than the latter. Rare pores are developed in graptolite. The total porosity and specific surface area of the shales within the Lower Longmaxi Formation and Wufeng Formation are twice more than those within the Upper Longmaxi Formation. Samples with higher TOC values commonly have higher porosities and specific surface areas, suggesting TOC content determines shale physical property. Clay mineral content exhibits a negative influence on microstructure and porosity but determines water saturation. Water saturation has significant negative relationships with micro-to mesopore volumes, porosity and TOC content, illustrating water molecular stores mainly in hydrophilic pores associated with clay minerals rather than OM-hosted nanopores. The gas generation, reservoir quantity and gas content of the Longmaxi-Wufeng shales in northwestern Guizhou are also compared with those of the famous Fuling and Weiyuan districts in eastern Sichuan Basin, and we considered that the shale gas prospect in northwestern Guizhou is excellent.",17,19,7
Shale Gas,Sichuan BASIN,"Yu, Kun; Ju, Yiwen; Shao, Chunjing",Structure characteristics and evolution mechanism of nanopore in transitional coal-bearing shale,Transitional coal-bearing shale; Pore structure; Pore type; Characteristics; Evolution,PORE-SIZE DISTRIBUTION; DENSITY-FUNCTIONAL THEORY; GAS-ADSORPTION; NITROGEN ADSORPTION; ELECTRON-MICROSCOPY; METHANE ADSORPTION; FRACTAL DIMENSION; HUAINAN COALFIELD; POSIDONIA SHALE; SICHUAN BASIN,"Nanopore plays a crucial role in shale gas adsorption, and its characteristics and evolution are significant for the evaluation of shale reservoirs with strong heterogeneity. In this study, transitional coal-bearing shale samples from the south margin of North China were selected for investigation of pore structure characteristics and evolution mechanism. Results indicated that nanopores of the studied shales are fractal with strong heterogeneity. The higher fractal dimension leads to larger surface area and micropore volume of shale samples. The abundant terrigenous material and limited hydrocarbon generation and expulsion are favorable for the development of intraP pores in clay, so that the Organic matter (OM) pores are poorly developed and are partially filled with clay minerals and pyrite framboids. Shale samples having higher levels of clay content and lower levels of quartz content tend to develop more heterogeneous micropores, producing a more complex pore structure in shale. The evolution of nanopore in studied shales is simultaneously determined by the coupling relationship between clay content and the thermal maturation of OM. In the early oil and low clay content stage, the low degree of the thermal evolution of OM leads to generation of less acidic fluid during the decarboxylation of kerogen, resulting in a weak physical combination and chemical corrosion between OM and clay minerals, with the macropores taking the main place in the pore structure. In the main to late oil and medium clay content stage, hydrocarbon generation of OM leads to the development of pores in kerogen and the gradual generation of more acidic fluids that dissolve clay minerals, so that the mesopores are dominant. In the wet gas and high clay content stage, increases in hydrocarbon generation intensity and clay mineral content cause development of more complexes of OM and clay, with a large number of micropores produced in shale reservoirs.",16,16,3
Shale Gas,Sichuan BASIN,"Sun, Wenjibin; Zuo, Yujun; Wu, Zhonghu; Liu, Hao; Zheng, Lujing; Wang, Hong; Shui, Yue; Lou, Yili; Xi, Shijun; Li, Taotao; Luo, Xuan","Pore characteristics and evolution mechanism of shale in a complex tectonic area: Case study of the Lower Cambrian Niutitang Formation in Northern Guizhou, Southwest China",Shale; Pore structure; Niutitang formation; Northern Guizhou,LONGMAXI FORMATION SHALE; SICHUAN BASIN; FRACTAL CHARACTERIZATION; QIANNAN DEPRESSION; MIGRATION PATHWAYS; ORGANIC POROSITY; GAS-ADSORPTION; RESERVOIRS; NMR; PROVINCE,"The Lower Cambrian Niutitang Formation is one of the most important shale reservoirs in the Northern Guizhou. To study the characteristics of pore structures and the relationships between shale's physical properties and pore structures in the complex tectonic area, from the perspective of hydrocarbon generation and evolution, the mineral composition, pore structure characteristics of shale samples in northern Guizhou were analyzed using X-ray diffraction (XRD), optical microscopic composition analysis, focused ion beam-scanning electron microscopy (FIB-SEM), vitrinite reflectivity and nitrogen adsorption experiments. Results indicate that the pore structures can be categorized into conical, ink bottle, spherical, elliptical, beaded, irregular, and plate-like intersecting microfractures. Shale samples are organic-rich with an average total organic carbon content of 4.39%. Organic matter is consumed within the shale matrix during the hydrocarbon generation and evolution, which increases the organic pore size and the proportion of organic pores. The high TOC content is conducive to developing organic pores. In addition, the average content of brittle minerals is greater than 70%. High content of brittle minerals during diagenesis is conducive to developing the residual pores at the edges of mineral particles and dissolved pores within mineral particles. Thus, the high content of brittle minerals and TOC content is favorable for the development of meso-macropores. The content of clay minerals within the shale samples ranges from 6.3% to 42.2%, with an average of 20.02%. Micropores and mesopores mainly occur in the clay minerals. Pores in clay minerals are easily compacted under tectonic stress. Meanwhile, high thermal evolution degree and the vitrinite reflectance R-o greater than 3.5 is not conducive to developing pores. Hence, high TOC content, high brittle minerals content, and thermal evolution degree ranging from 0.6% to 3% make the Lower Cambrian Niutitang Formation shale reservoirs favorable for shale gas exploration.",13,13,8
Shale Gas,Sichuan BASIN,"Wang, Yang; Liu, Luofu; Cheng, Hongfei","Pore structure of Triassic Yanchang mudstone, Ordos Basin: Insights into the impact of solvent extraction on porosity in lacustrine mudstone within the oil window",Pore structure; Solvent extraction; Nitrogen adsorption; Lacustrine mudstone; Oil window,CONTINENTAL TRANSITIONAL SHALE; ORGANIC-MATTER; SICHUAN BASIN; MARINE SHALE; GEOCHEMICAL CHARACTERISTICS; CHINA IMPLICATIONS; NETWORK EVOLUTION; THERMAL MATURITY; LONGMAXI SHALE; GAS,"Low-pressure nitrogen physisorption was performed on Triassic Yanchang mudstones before and after solvent extraction to characterize the extractable organic matter (EOM) occurrence and ascertain the impact of extracts on the nanoporosity of lacustrine mudstone within the oil window. Organic-rich Yanchang mudstones are currently thermally mature (vitrinite reflectance of 0.48%-0.92%). SEM-observed pore types chiefly comprise interparticle and intraparticle pores related to inorganic minerals, with organic matter pores less developed. Pore volume (PV) of the original mudstones is 0.35-2.15 cm(3)/100 g and the specific surface area (SSA) is 1.22-7.77 m(2)/g. Brittle minerals (quartz + feldspar + carbonates) and I/S mixed layer jointly show the positive effect on the pore space development in the Yanchang mudstone. Four groups of mudstones with obvious differences in pore structure properties were identified, which probably result from the various development degrees of interparticle pores at the edge of brittle minerals, and intraparticle pores associated with I/S aggregates. Generally, solvent extraction will result in a noticeable increase in the volume of N-2 adsorbed due to the reopening of pore space blocked by EOM, which is related to increases in PV an SSA. A declining case, probably caused by the progressive shift of the enlarged open pore space to the larger macropore range (d > 200 nm) which is not detected by N-2 adsorption and counteracts the increased porosity by extraction, however, was also observed in the current study. Overall, the infilling degree of EOM increased with increasing thermal evolution degree of shales within the oil window, which mainly blocks minor pores in lower mature samples but larger pores in higher mature samples.",13,13,6
Shale Gas,Sichuan BASIN,"Zhang, Ruxin; Hou, Bing; Tan, Peng; Muhadasi, Yeerfulati; Fu, Weineng; Dong, Xiaomu; Chen, Mian",Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing,Fracture propagation behavior; Temporary plugging agent; Fracture diversion pattern; Horizontal stress difference; 3D scanning,NUMERICAL-SIMULATION; INITIATION,"The exploitation of shale oil and gas has become commercial in the Sichuan basin, China. However, initial fracture closure will result in low production. Therefore, temporary plugging fracturing technology is proposed to create new fractures in alternate directions using a temporary plugging agent that blocks initial fractures, which will lead to a complex fracture morphology. The mechanism of temporary plugging and fracture propagation behavior remains ambiguous, even with many successful operations. Hence, five shale outcrops are used to conduct large-size true tri-axial temporary plugging fracturing simulation experiments to study the issues mentioned above. The effects of horizontal stress difference and temporary plugging agent amount on plugging effectiveness as well as fracture propagation behavior are discussed. The results reveal that the initial fractures are sealed successfully by a water soluble temporary plugging agent. Two plugging positions, fracture heel and tip, result in three main fracture diversion patterns: fracture diversion at the old fracture heel, fracture diversion inside the old fracture, and a new fracture induced at a new position. Based on the fracturing pressure curve, fracturing pressure in the second fracturing is higher than that of the first fracturing, which indicates effective plugging and fracture diversion. A large horizontal stress difference has prevented fracture diversion, and led to a small diversion angle. However, it has improved the induced fracture propagation length. Moreover, the temporary plugging agent amount determines the plugging position and fracture diversion pattern. Fracture diversion inside existing fractures is a result of a small amount sealing at the fracture tip. The other two patterns are created by a large amount of plugging at the fracture heel. Therefore, in order to achieve successful plugging effectiveness, it is necessary to conduct more experiments to optimize operation parameters according to the specific horizontal in-stress state.",13,13,6
Shale Gas,Sichuan BASIN,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Shale Gas,Sichuan BASIN,"Nie, Haikuan; He, Zhiliang; Wang, Ruyue; Zhang, Guangrong; Chen, Qian; Li, Donghui; Lu, Zhiyuan; Sun, Chuanxiang","Temperature and origin of fluid inclusions in shale veins of Wufeng?Longmaxi Formations, Sichuan Basin, south China: Implications for shale gas preservation and enrichment",,UPPER ORDOVICIAN WUFENG; SILURIAN LONGMAXI FORMATION; FORT-WORTH BASIN; BARNETT SHALE; ACCUMULATION; FRACTURES; MIGRATION; HISTORY; GENERATION; MECHANISM,,12,13,4
Shale Gas,Sichuan BASIN,"Han, Hui; Pang, Peng; Zhong, Ningning; Luo, Qingyong; Ma, Yong; Gao, Yuan","The pore characteristics and gas potential of the Jurassic continental shales in the middle-small basins, northwest China",Continental shales; Type III organic matters; Northwest China; Shale gas; Pore,MISSISSIPPIAN BARNETT SHALE; TRIASSIC YANCHANG FORMATION; THRUST-FOLD BELT; BOHAI BAY BASIN; CHANG 7 MEMBER; ORDOS BASIN; SICHUAN BASIN; LACUSTRINE SHALES; ORGANIC-MATTER; FRACTAL CHARACTERISTICS,"Jurassic continental shales were extensively developed in the northwest of China. To characterize and analyze the pores and gas potential of these shales, geochemical, mineralogical, petmphysical, and methane adsorption capacity (MAC) experiments were performed on 10 samples. The results indicated that these shales have a high total organic carbon (TOC) content, low porosity and permeability. Interparticle pores between clay platelets are dominant. Organic matter (OM) pores cannot be observed using scanning electron microscope. The methane adsorption capacity is strong, and it is controlled by TOC content. Strong MAC indicated the shales have an excellent capacity of storing gas. In addition, type III organic matters can generate amount of gas at a lowly mature stage. Therefore, it is speculated that the studied shales have a good gas potential, which is supported by canister desorption results.",12,12,4
Shale Gas,Sichuan BASIN,"Lin, Botao; Guo, Jiancheng; Liu, Xing; Xiang, Jianhua; Zhong, Hua",Prediction of flowback ratio and production in Sichuan shale gas reservoirs and their relationships with stimulated reservoir volume,Flowback ratio; Productivity; Shale gas reservoir; Neural network; Stimulated reservoir volume,WATER; IMBIBITION,"Good flowback management in shale gas reservoirs not only preserves the conductivity of the flow paths created by the fracture network but also assists the subsequent production by minimizing the damage of the fracturing fluid to the fluid-sensitive formation. However, a quantitative prediction of its behavior and impact on the productivity of a reservoir is not available yet. This study proposed a mathematical approach to predict the flowback behavior concerning flow back ratio (FBR), and the productivity represented by first-month production (PROD), of the Changning-Weiyuan shale gas reserve in Sichuan basin, southwest China. First, a BP (Back Propagation) neural network model was established to filter out the controlling factors given the actual FBRs and the geological and engineering characteristics of seventy-six sample wells. Secondly, a correlation was generated between the FBR, the geological index g, and the engineering index e by non-linear fitting. In subsequence, the PROD was predicted based on the field recorded FBR and the comprehensive index c that combines the influences of both geological and engineering parameters. Finally, the stimulated reservoir volumes (SRVs) of twelve wells were estimated using the K-means clustering and Delaunay triangulation to assess their impact on the FBR and PROD data. It was found that the associated FBR and PROD diagrams can provide accurate predictions for the sixteen additional wells. Meanwhile, there exists an optimum FBR range of 20-40% for the shale gas region of concern where the productivity of the formation can be maximized. It is also observed that the FBR and PROD fail to display any specific trend with the value of the SRV magnitude. In general, the proposed approach can be used in shale gas reservoirs to examine the favorable FBR and guide the engineering designs to enhance production if adequate reservoir data are accessible.",10,10,6
Shale Gas,Sichuan BASIN,"Zhai, Hongyu; Chang, Xu; Wang, Yibo; Lei, Xinglin; Xue, Ziqiu",Analysis of acoustic emission events induced during stress unloading of a hydraulic fractured Longmaxi shale sample,,MOMENT TENSORS; MECHANICAL-PROPERTIES; SICHUAN BASIN; ROCKS; EVOLUTION; FAILURE; COAL,"In shale-gas exploitation, hydraulic fracturing technology is essential to successfully create complex fracture networks in formations. To investigate the dynamic fracturing process, we performed a hydraulic fracturing experiment on a Longmaxi shale sample in the laboratory. After hydrofracturing, hundreds of induced acoustic emission (AE) events were recorded during the stress unloading procedure. At the same time, the high-pressure water stored in the sample fracture network was also discharged. The fracture network inside the fractured sample was studied using medical X-ray computed tomography (CT) scanning technology. Then, the locations and characteristics of the shale failure were analyzed by localizing and inversing the source mechanism of the AE events. Furthermore, the inversion results were verified by comparing with the scanned internal cracks images. According to the source mechanism inversion result, the induced AE events mainly stemmed from the dilatation or compression of fractures and the shear slip of shale along the fracture plane. Finally, the influence of formation attenuation error (underestimated or overestimated attenuation value) on source mechanism inversion results were quantitatively analyzed. It was confirmed that the shear component of the AE event was more sensitive than the volume component to medium attenuation change, especially when the attenuation value was overestimated.",8,9,10
Shale Gas,Sichuan BASIN,"Li, Xin; Jiang, Zhenxue; Jiang, Shu; Li, Zhuo; Song, Yan; Jiang, Hongyang; Cao, Xiangni; Qiu, Hengyuan; Huang, Yizhou; Ming, Wen; Miao, Yanan","Characteristics of matrix-related pores associated with various lithofacies of marine shales inside of Guizhong Basin, South China",Matrix-related pore; Controlling factors; Lithofacies; Lower Carboniferous; Middle Devonian; Guizhong Basin,METHANE SORPTION CAPACITY; UPPER YANGTZE PLATFORM; SICHUAN BASIN; GAS-ADSORPTION; ORGANIC-MATTER; LONGMAXI SHALE; POROSITY; SEM; SYSTEMS; OIL,"Matrix-related pore characteristics of between Lower Carboniferous shale and Middle Devonian shale in Guizhong Basin were investigated to explore the reservoir capacity. Via the combination of organic geochemistry analysis, X-ray diffraction, gas adsorption, mercury intrusion porosimetry, helium porosimetry and focused ion beam-scanning electron microscopy, material basics and physical properties were studied. Five lithofacies were divided as comparable units in two formations according to thermal maturity, OM abundance and mineral components, namely organic-moderate argillaceous shale with high thermal maturity (OMAS-H) and organiclean argillaceous shale with high thermal maturity (OLAS-H) in Lower Carboniferous Formation, and organiclean mixed shale with over thermal maturity (OLMS-O), organic-rich mixed shale with over thermal maturity (ORMS-O) as well as organic-rich calcareous shale with over thermal maturity (ORCS-O) in Middle Devonian Formation. Results showed that (1) OMAS-H and OLAS-H performed better porous features than OLMS-O, ORMS-O and ORCS-O, in terms of PV, PSA and porosity, (2) pores developed better in OMAS-H and OLAS-H than those in OLMS-O, ORMS-O and ORCS-O, in terms of pores of rigid grains, pores associated with clay flakes and OM-hosted pores, (3) specific PVs of OM were dramatically larger than those of mineral components, while specific PVs of OM in both OMAS-H (0.348 ml/g x 10(-6)) and OLAS-H (0.248 ml/g x 10(-6)) were about an order of magnitude higher than those in OLMS-O (0.055 ml/g x 10(-6)), ORMS-O (0.025 ml/g x 10(-6)) and ORCS-O (0.011 ml/g x 10(-6)). The ability of pore contribution largely depends on whether corresponding components are suited in the appropriate evolution stage with suitable thermal and pressure circumstance. Then sufficient degree of pore carriers (matrixes) need to be thought about, especially OM and clay as the secondary pore providers. Also, the demand for pore preservation highlights the importance of brittle minerals which can establish rigid frameworks. Therefore, in the case of controlling factors on pore characteristics, the importance ranking should be taken into consideration.",8,8,5
Shale Gas,Sichuan BASIN,"Yang, Wei; He, Sheng; Iglauer, Stefan; Guo, Xiaowen; Zhai, Gangyi; Zhou, Zhi; Dong, Tian; Tao, Ze; Wei, Sile","Porosity characteristics of different lithofacies in marine shale: A case study of Neoproterozoic Sinian Doushantuo formation in Yichang area, China",Doushantuo Shale; Yichang area; Lithofacies classification; Porosity development; Controlling factors,MISSISSIPPIAN BARNETT SHALE; PORE STRUCTURE; SICHUAN BASIN; GAS-STORAGE; MARCELLUS; WOODFORD; WUFENG; CLASSIFICATION; ACCUMULATION; ADSORPTION,"This study evaluates the pore network systems in the Neoproterozoic Sinian Doushantuo (Z(1)d) shale from the Yichang area in the Middle Yangtze region. All samples were classified based on their lithologies and examined by geochemical and petrographic analysis, assisted with carbon dioxide/nitrogen (CO2/N-2) adsorption, mercury injection capillary pressure (MICP) and focused ion beam-scanning electron microscopy (FIB-SEM) to fully characterize the nanoscale porosity of the different shale lithofacies. The calcareous shale lithofacies group (I-C), mixed shale lithofacies group (II-M) and siliceous shale lithofacies group (III-S) were identified via ternary mineralogy diagrams. Clearly, different lithofacies had different porosities, pore volume, surface area and pore-size distribution (ranging from 0.3 nm to 36 mu m). The mixed shale lithofacies group (II-M) had the highest total pore volumes, followed by the calcareous shale lithofacies group (I-C) and the siliceous shale lithofacies group (III-S). Peak values (2-20 nm, 20-50 nm, 50-60 nm and 90-200 nm) obtained from N-2 adsorption were identified as organic matter (OM) pores, dissolution intraparticle (intraP) pores and intercrystalline pores (using SEM images analysis). Porosity shows a non-monotonic trend with TOC content and a maximum at 4.5-5.5 wt% TOC, similar relationships between TOC and mesopore/macropore volumes, due to pore collapse and compaction. The FIB-SEM images revealed solid bitumen and two types of kerogen in the examined shale samples; these different organic matter types had clearly distinct pore characteristics. While the smaller OM particles mobilized and converted into solid bitumen in which OM pores were larger and more abundant, the large-scale OM particles were most likely non-porous inert maceral and sponge-like porous amorphous kerogen. Overall TOC content and organic types are the key controlling factors to the nanoscale porosity development in the Doushantuo Shale, and the Sinian Doushantuo shale (in the Yichang area) has great potential for shale gas exploration and exploitation in South China.",8,8,3
Shale Gas,Sichuan BASIN,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Shale Gas,Natural Fractures,"Fan, Cunhui; Li, Hu; Qin, Qirong; He, Shun; Zhong, Cheng","Geological conditions and exploration potential of shale gas reservoir in Wufeng and Longmaxi Formation of southeastern Sichuan Basin, China",Shale gas; Geological conditions; Tectonic uplift; Preservation conditions; Longmaxi Formation; Southeastern Sichuan Basin,TIGHT SANDSTONE RESERVOIRS; PERMIAN LUCAOGOU FORMATION; ORDOS BASIN; UPPER ORDOVICIAN; TECTONIC FRACTURES; DINGSHAN AREA; SOUTH CHINA; OIL-SHALE; GEOCHEMICAL CHARACTERISTICS; PRESERVATION CONDITIONS,"The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R-o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration.",39,40,8
Shale Gas,Natural Fractures,"Xu, Shang; Gou, Qiyang; Hao, Fang; Zhang, Baiqiao; Shu, Zhiguo; Zhang, Yuanyin","Multiscale faults and fractures characterization and their effects on shale gas accumulation in the Jiaoshiba area, Sichuan Basin, China",Shale; Multiscale faults and fractures; Seal conditions; Accumulation mechanism; Jiaoshiba area,SILURIAN LONGMAXI FORMATION; UPPER ORDOVICIAN WUFENG; PORE STRUCTURE; MARINE SHALE; BOREHOLE IMAGE; SCALE PORES; ENRICHMENT; BARNETT; STORAGE; LOGS,"The distribution and development of faults and fractures in organic-rich shales are important factors for the accumulation or loss of shale gas. In this work, merged three-dimensional seismic data, automated fault extraction, imaging logging, rock core examination, micro-CT scans, and field emission scanning electron microscopy were used to precisely characterize the distribution of faults and fractures of the Wufeng-Longmaxi shales from the Zilichang Block, Jiaoshiba area. The effects of faults and fractures on the accumulation and loss of shale gas were analyzed. The results show that the microfractures of shale samples from the JYA well of the Zilichang Block mainly consisted of intergranular, intragranular, and contraction fractures, and the fracture porosity of the samples is approximately 1.24%. These fractures help to increase the storage space of the shale reservoirs and are conducive for shale gas accumulation. In micro-CT scans, the microfractures were linked in a network-like structure and generally had excellent connectivity. Therefore, the microfractures could enhance the seepage capacity of the shale reservoirs and help the shale gas to migrate to hydraulically induced fractures. As a result, the productivity of the shale reservoirs could be dramatically improved. Macroscopic fractures were found to play a key role in the storage of shale gas. Many natural fractures, mainly are faults and open fractures, have developed in the caprock strata that directly overly the main production layers shales. The shale gas direct seal conditions are poor, which is not conducive to shale gas accumulation. Therefore, the Wufeng-Longmaxi shales in the JYA well is a relatively open shale system, with a formation pressure coefficient and gas saturation value of 0.96 and 37%, respectively. The single-well hydraulic fracturing productivity of the JYA well is low, with an absolute open flow value less than 0.5 x 10(4) m(3)/d.",19,19,7
Shale Gas,Natural Fractures,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Shale Gas,Natural Fractures,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Shale Gas,Natural Fractures,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Shale Gas,Natural Fractures,"Ren, Wenxi; Lau, Hon Chung",Analytical modeling and probabilistic evaluation of gas production from a hydraulically fractured shale reservoir using a quad-linear flow model,Shale gas; Secondary fractures; Analytical model; Global sensitivity analysis; Probabilistic assessment,PRESSURE-TRANSIENT ANALYSIS; TIGHT OIL-RESERVOIRS; HORIZONTAL WELLS; SENSITIVITY-ANALYSIS; NATURAL FRACTURES; COMPREHENSIVE MODEL; BARNETT SHALE; TRANSPORT; MULTIPLE; PERFORMANCE,"During hydraulic fracturing, secondary fractures are created around hydraulic fractures and serve as important channels connecting the shale matrix and the hydraulic fractures. We developed an analytical model to simulate shale gas production from a multi-stage fractured horizontal well. The analytical model is based on the trilinear flow model, but it is free from the assumption that the length of secondary fractures is equal to the half-distance between hydraulic fractures. This analytical model captures the fundamental characteristics of a hydraulically fractured shale reservoir by incorporating transient gas flow in the matrix, secondary fractures, and hydraulic fractures. Because this model describes four linear flow systems (unstimulated reservoir volume, matrix in the stimulated reservoir volume, secondary fracture, and hydraulic fracture), it is called the quad-linear flow model. Production data from two shale gas wells were used to validate the model. Moreover, using the variance-based method and quasi-Monte Carlo simulation, we developed a stochastic framework to perform a probabilistic assessment of shale gas production. We also conducted a global sensitivity study with nine uncertainty parameters to identify important parameters and their interactions that affect well productivity. The results indicate that the existence of dense secondary fractures (the distance between secondary fractures is small) results in higher initial production rate and ultimate recovery, but a sharper decline in production rate. Increasing the length of the secondary fractures can more effectively enhance gas production in the presence of dense secondary fractures. Moreover, the benefits of dense secondary fractures are mostly limited to a high porosity shale reservoir.",12,12,3
Shale Gas,Natural Fractures,"Zeng, Jie; Li, Wai; Liu, Jishan; Leong, Yee-Kwong; Elsworth, Derek; Tian, Jianwei; Guo, Jianchun; Zeng, Fanhua",Analytical solutions for multi-stage fractured shale gas reservoirs with damaged fractures and stimulated reservoir volumes,Shale gas reservoir; SRV; Fracture damage,LINEAR FLOW MODEL; HORIZONTAL WELLS; PERMEABILITY; ADSORPTION; TRANSPORT; MECHANISMS; NANOPORES; IMPACT; FACE,"After performing hydraulic fracturing in shale reservoirs, the hydraulic fractures and their adjacent rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures; (2) partially propped fractures with unpropped or poorly propped sections at the middle or tail of fractures; (3) fracture face damage; and (4) multiple damage cases. The classical fracture skin factors are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple damage and partially propped fractures. In this article, a new analytical model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs. The matrix model is a spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly envelops the matrix. The reservoir-fracture flow model is a ten-region linear flow model which can handle fracture damage mechanisms. Specifically, the inner reservoir region is treated as an SRV where the secondary fracture permeability obeys a power-law decreasing trend due to the attenuate stimulation intensity. This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of a published linear flow model. New type curves are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Different damage mechanisms all control specific flow regimes but the fracture face damage shows the slightest influence. In the multiple fracture damage case, some typical flow regimes can be easily identified except those induced by the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.",12,12,3
Shale Gas,Natural Fractures,"Gu, Yang; Ding, Wenlong; Tian, Qianning; Xu, Sheng; Zhang, Wei; Zhang, Bairen; Jiao, Baocheng","Developmental characteristics and dominant factors of natural fractures in lower Silurian marine organic-rich shale reservoirs: A case study of the Longmaxi formation in the Fenggang block, southern China",The longmaxi shale; Natural fractures; Developmental characteristics; Dominant factors; South China,CAMBRIAN NIUTITANG FORMATION; NORTHERN GUIZHOU PROVINCE; FORT-WORTH BASIN; BOHAI BAY BASIN; BARNETT SHALE; CENGONG BLOCK; QUANTITATIVE PREDICTION; LOGGING IDENTIFICATION; MIGRATION PATHWAYS; GAS-STORAGE,"Natural fractures are an important storage space and main seepage channel of shale gas reservoirs, controlling the permeability of shale gas reservoirs and the migration, enrichment, preservation conditions and single-well productivity of shale gas. The successful production of shale gas has shown that the development of natural fractures in shale is beneficial, and a high degree of natural fracture development can allow a large-scale fracture network to form in the process of hydraulic fracturing, which can effectively improve the shale reservoir conditions. The development of fractures in shale reservoirs not only effectively improves the permeability of shale reservoirs but also increases the gas content, improving the productivity of shale reservoirs. Therefore, the degree of shale fracture development is the key to the production of shale gas reservoirs. Through the outcrop, shale core, thin section and scanning electron microscopy observations of the Longmaxi shale in the Fenggang block of Guizhou Province and the experimental data analysis of the corresponding samples, the fracture characteristics are statistically analyzed, and the fracture development characteristics and dominant factors are discussed in depth. The study area is located in the complex tectonic area of southern China, which experienced a strong tectonic deformation and a high degree of fracture development. The multiscale characterization of Longmaxi shale fractures indicates the following: the fractures observable in the field are mainly regional structural fractures, fold-related fractures, fault-related fractures and bedding fractures; additionally, the statistical analysis of core fractures shows that the structural fractures, including high-angle shear fractures, tension-shear fractures, and low-angle slip fractures are dominant and that most of them are filled with calcite; the micro-fractures are mainly intragranular fractures and intergranular fractures, and the fracture aperture is 0.01-2 mu m. The degree of fracture development is controlled by structural factors, lithology, mineral composition and content, TOC, rock mechanical properties, paleoenvironment and diagenesis, and the structural factors are the most influential. The gentle transition zone of a fold limb is a favorable position for shale gas structure preservation. Fractures significantly impact the formation of seepage channels and storage space and the connection of isolated micropores, so the degree of fracture development has a positive relationship with the total and analytical gas contents.",11,13,8
Shale Gas,Natural Fractures,"Liu, Yongzan; Liu, Lijun; Leung, Juliana Y.; Moridis, George J.",Sequentially coupled flow and geomechanical simulation with a discrete fracture model for analyzing fracturing fluid recovery and distribution in fractured ultra-low permeability gas reservoirs,Coupled flow and geomechanics; Flowback; Fracturing-fluid distribution; Tight/shale gas; Fracture geometry,TRANSIENT-BEHAVIOR; WATER-FLOWBACK; TIGHT-GAS; SHALE; WELLS; PERFORMANCE; MECHANISMS; IMPACT,"More accurate characterization and prediction of the in-situ distribution of fracturing fluid in fractured reservoirs are needed for enhancing well productivity. In this study, an implicit-sequentially coupled flow/geomechanics simulator incorporating an efficient discrete fracture model is developed to model fluid distribution and recovery performance of ultra-low permeability gas reservoirs. The finite-volume and finite-element methods are used for space discretization of the flow and geomechanics equations, respectively, while the backward Euler method is employed for time discretization. The flow and geomechanics equations are solved sequentially based on fixed-stress splitting. An efficient discrete-fracture model is used to explicitly model the fractured system. Flexible unstructured gridding is employed to model arbitrarily-oriented fractures. The interrelations among pore volume, permeability and geomechanical conditions are considered dynamically using two-way coupled flow and geomechanics computations. The geometry of fracture (networks) due to hydraulic fracturing has significant impacts on the fracturing fluid recovery efficiency and ensuing fluid distribution. Under the same injection volume, the fracturing fluid recovery is higher when the fracture geometry is planar. Fluid recovery is relatively lower whenever natural fractures are activated during fracturing treatments; flowback time is also shortened when complex fracture network with enlarged fracture interface is present. Fracturing fluid in hydraulic fractures may leak off into the natural fractures and subsequently imbibes into the surrounding matrix due to capillarity effects. The fracturing fluid recovery and in-situ fluid distribution are sensitive to the shut-in duration and fracture closure behavior. This study analyzes the coupled flow-geomechanical responses of fractured gas reservoirs during the post-fracturing periods. Understanding the fate of the fracturing fluid can provide insights on, to some extent, the stimulated fracture volume, size of the water invasion zone, and efficiency of the fracturing design. The simulation predictions can also provide more accurate initial reservoir conditions (e.g. distributions of different phases and pressure) for long-term well performance estimation.",10,10,5
Shale Gas,Natural Fractures,"Wei, Shiming; Jin, Yan; Xia, Yang; Lin, Botao",The flowback and production analysis in sub-saturated fractured shale reservoirs,Sub-saturated shale reservoirs; Flowback; Production; Gas-water flow; Discrete fractures,DISCRETE-FRACTURE; 2-PHASE FLOW; GAS-FLOW; HYDRAULIC-FRACTURE; TRIPLE-CONTINUUM; NUMERICAL-METHOD; HORIZONTAL WELL; POROUS-MEDIA; MODEL; SIMULATION,"The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced ""skin factor"" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model.",10,10,3
Shale Gas,Natural Fractures,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Shale Gas,Natural Fractures,"Zhao, Peng; Xie, Lingzhi; Ge, Qi; Zhang, Yao; Liu, Jun; He, Bo",Numerical study of the effect of natural fractures on shale hydraulic fracturing based on the continuum approach,Hydraulic fracturing simulation; Anisotropic strength criterion; Discontinuities; Continuum method; Fracturing geometry; Complexity and scale,STIMULATED RESERVOIR VOLUME; PROPAGATION; SIMULATION; MODEL; STRESS; FLOW; GAS; PERMEABILITY; DEFORMATION; MEDIA,"Because of the complexity of shale reservoirs and multiple physical coupling processes, numerical implementation remains a challenge in engineering applications. Unlike conventional reservoirs, shale reservoirs always contain two main discontinuities: bedding interface and natural fractures. The existence of these discontinuities is the key reason a fracture network is formed. Therefore, the numerical model should contain both bedding interface and natural fractures. In this paper, the fracturing propagation process is described based on continuum theory. In contrast to other research, an anisotmpic strength criterion is adopted to consider the anisotropic properties of shale, including the failure of both shale matrix and discontinuities. The criterion is described by the Mohr-Coulomb model combined with tensile failure. When fractures are generated in the shale rock mass, the stiffness and permeability of the fractured rock are homogenized in an element, and volume fracturing is represented by the deformation of three orthogonal fractures in the rock element. Simultaneously, the anisotropic permeability is also enhanced. Hence, based on this continuum approach and finite element method, a three-dimensional model for shale hydraulic fracturing simulation is presented. This model fully considers the direct coupling of fluid flow and rock deformation during hydraulic fracturing. To verify the anisotropic strength criterion, a shale compression test is conducted. Through a comparison of the numerical and experimental results, the applied criterion can describe the shale compressive strength anisotropy. In addition, the KGD analytical model is also adopted to verify the performance of the developed model for hydraulic fracturing. Finally, several cases of shale hydraulic fracturing are simulated, and the results show the geometry of the fracture region under different conditions. Furthermore, the impacts of three factors on hydraulic fracturing geometry are considered, including natural fractures, spacing of perforations and differential in situ stress. The influence of these factors on the complexity and scale of the fracturing region is also discussed.",7,7,7
Shale Gas,Horizontal Wells,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Shale Gas,Horizontal Wells,"Cheng, Linsong; Wang, Deqiang; Cao, Renyi; Xia, Rufeng",The influence of hydraulic fractures on oil recovery by water flooding processes in tight oil reservoirs: An experimental and numerical approach,Tight oil; Hydraulic fracture; Water flooding; Water breakthrough; Core flood experiment,HORIZONTAL WELLS; SHALE; FLOW; GAS; STORAGE; EOR,"The use of multi-fractured horizontal wells has helped to develop tight oil reservoirs, but, if oil depletion occurs, the estimated ultimate recovery is low. Water flooding can be regarded as an easily applied method for improving oil recovery. This study aimed to optimize the scale of the stimulated reservoir volume (SRV) by conducting an experiment to verify the water injection capacity of the Chang 7 Formation, which is situated within in a typical tight oilfield. A one-dimensional long core displacement experiment was designed based on injecting formation water into a tight matrix core and fractured cores with different fracture lengths. Results were then verified and analyzed using core flood simulation and targeted field tests, and they clarified the feasibility of injecting water into a tight oil formation when the injection well is fractured, or when fractures exist near the injection well. It was also verified that although fractures increase the equivalent permeability in the fractured core and promote pressure propagation, they can also lead to rapid water breakthrough if they communicate with the producer well. It is thus considered that optimization of the SRV extent would enhance the recovery of oil and decrease the risk of water breakthrough.",16,15,3
Shale Gas,Horizontal Wells,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Shale Gas,Horizontal Wells,"Zhang, Jiyuan; Feng, Qihong; Zhang, Xianmin; Hu, Qiujia; Wen, Shengming; Chen, Dong; Zhai, Yuyang; Yan, Xia","Multi-fractured horizontal well for improved coalbed methane production in eastern Ordos basin, China: Field observations and numerical simulations",Coalbed methane; Multi-fractured horizontal well; Numerical simulation; Improved recovery; Producibility comparison,RATE-TRANSIENT ANALYSIS; PERMEABILITY CHANGES; RESERVOIR SIMULATION; PREDICTION; EVOLUTION; SEAM; PERFORMANCE,"Eastern margin of Ordos basin has been an active commercial coalbed methane (CBM) production area in China, where coal seams are typically characterized with thin layers, low permeability and high gas content. Hydraulically fractured vertical wells (HFVWs) are the primary means for recovery of CBM in this area, which however are usually subject to low gas production and unpromising economics. Although the multi-fractured horizontal well (MFHW) has proven as an effective solution for producing hydrocarbon resources from both tight and shale reservoirs, its applicability in efficient development of CBM reservoirs remains yet unclear. This paper presents a pilot field application of MFHW to improve CBM recovery in eastern Ordos basin. A horizontal well stimulated with 6 stages of hydraulic fractures was observed to significantly outperform HFVWs in terms of depressurization efficiency, gas production and ultimate recovery factor. Peak gas rate of the MFHW is more than five times higher than an HFVW. History matches of the MFHW and representative HFVWs were conducted to obtain key reservoir properties that are subsequently used for production predictions. Numerical simulation predicts that cumulative gas production for the MFHW is 3-15 times as that for each of the HFVWs during a production duration of 15 years. A total of 500 stochastic geological scenarios for the study area were simulated to analyze the effect of geological parameters on the superiority of an MFHW over a group of four HFVWs (which are at equivalent well construction outlays) in terms of cumulative gas production. A correlation was then developed using the alternating conditional expectation (ACE) regression method, resulting in a linear relationship between an indicator of the superiority with permeability and desorption pressure in a log-log coordinate system. This correlation can be potentially used as a criterion for fast determination of the optimal completion option in the target CBM seams. The regression results also show that the superiority of an MFHW over HFVWs is especially highlighted in thin coal seams with low permeability and low gas content. Finally, the effect of the size and spacing of stimulated area (SA) on MFHW producibility was analyzed, showing that increasing the spacing between SAs is an economically viable option when the budget for fracturing operations is limited.",13,13,10
Shale Gas,Horizontal Wells,"Zhang, Ruxin; Hou, Bing; Tan, Peng; Muhadasi, Yeerfulati; Fu, Weineng; Dong, Xiaomu; Chen, Mian",Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing,Fracture propagation behavior; Temporary plugging agent; Fracture diversion pattern; Horizontal stress difference; 3D scanning,NUMERICAL-SIMULATION; INITIATION,"The exploitation of shale oil and gas has become commercial in the Sichuan basin, China. However, initial fracture closure will result in low production. Therefore, temporary plugging fracturing technology is proposed to create new fractures in alternate directions using a temporary plugging agent that blocks initial fractures, which will lead to a complex fracture morphology. The mechanism of temporary plugging and fracture propagation behavior remains ambiguous, even with many successful operations. Hence, five shale outcrops are used to conduct large-size true tri-axial temporary plugging fracturing simulation experiments to study the issues mentioned above. The effects of horizontal stress difference and temporary plugging agent amount on plugging effectiveness as well as fracture propagation behavior are discussed. The results reveal that the initial fractures are sealed successfully by a water soluble temporary plugging agent. Two plugging positions, fracture heel and tip, result in three main fracture diversion patterns: fracture diversion at the old fracture heel, fracture diversion inside the old fracture, and a new fracture induced at a new position. Based on the fracturing pressure curve, fracturing pressure in the second fracturing is higher than that of the first fracturing, which indicates effective plugging and fracture diversion. A large horizontal stress difference has prevented fracture diversion, and led to a small diversion angle. However, it has improved the induced fracture propagation length. Moreover, the temporary plugging agent amount determines the plugging position and fracture diversion pattern. Fracture diversion inside existing fractures is a result of a small amount sealing at the fracture tip. The other two patterns are created by a large amount of plugging at the fracture heel. Therefore, in order to achieve successful plugging effectiveness, it is necessary to conduct more experiments to optimize operation parameters according to the specific horizontal in-stress state.",13,13,6
Shale Gas,Horizontal Wells,"Zhang, Fengyuan; Emami-Meybodi, Hamid",Flowback fracture closure of multi-fractured horizontal wells in shale gas reservoirs,Flowback; Multiphase flow; Production data analysis; Fracture closure; Shale reservoirs; Multi-fractured horizontal wells,EARLY-TIME PRODUCTION; MODELING 2-PHASE FLOWBACK; MATERIAL BALANCE EQUATION; RATE-TRANSIENT ANALYSIS; ANALYZING LINEAR FLOW; TIGHT GAS; SEMIANALYTICAL MODEL; LOW PERMEABILITY; BEHAVIOR,"In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties using production data. This paper presents two multiphase flowback models for gas and water phase under boundary dominated flow (BDF) condition by considering gas influx from matrix. In addition, a workflow is proposed to quantitatively evaluate hydraulic fracture closure and fracture properties using both water-phase and gas-phase flowback data. A material balance equation (MBE) is derived to obtain average pressure in the fracture by calculating gas influx from matrix under variable bottomhole pressure (BHP) condition based on Duhamel's principle. The flowback models, average pressure calculation method, and workflow are validated against numerical simulations and applied to an MFHW drilled in Marcellus Shale. The results show that the developed models are capable of predicting fracture properties, and MBE could accurately calculate average pressure in the fracture. Furthermore, the proposed workflow provides quantitative insights into the performance of stimulation jobs by accurately predicting fracture half-length, fracture permeability, and permeability modulus using flowback data. By reconciling flowback analysis with long-term production data analysis, a significant decrease in fracture properties due to fracture closure is observed in the Marcellus MFHW.",12,12,3
Shale Gas,Horizontal Wells,"Ren, Wenxi; Lau, Hon Chung",Analytical modeling and probabilistic evaluation of gas production from a hydraulically fractured shale reservoir using a quad-linear flow model,Shale gas; Secondary fractures; Analytical model; Global sensitivity analysis; Probabilistic assessment,PRESSURE-TRANSIENT ANALYSIS; TIGHT OIL-RESERVOIRS; HORIZONTAL WELLS; SENSITIVITY-ANALYSIS; NATURAL FRACTURES; COMPREHENSIVE MODEL; BARNETT SHALE; TRANSPORT; MULTIPLE; PERFORMANCE,"During hydraulic fracturing, secondary fractures are created around hydraulic fractures and serve as important channels connecting the shale matrix and the hydraulic fractures. We developed an analytical model to simulate shale gas production from a multi-stage fractured horizontal well. The analytical model is based on the trilinear flow model, but it is free from the assumption that the length of secondary fractures is equal to the half-distance between hydraulic fractures. This analytical model captures the fundamental characteristics of a hydraulically fractured shale reservoir by incorporating transient gas flow in the matrix, secondary fractures, and hydraulic fractures. Because this model describes four linear flow systems (unstimulated reservoir volume, matrix in the stimulated reservoir volume, secondary fracture, and hydraulic fracture), it is called the quad-linear flow model. Production data from two shale gas wells were used to validate the model. Moreover, using the variance-based method and quasi-Monte Carlo simulation, we developed a stochastic framework to perform a probabilistic assessment of shale gas production. We also conducted a global sensitivity study with nine uncertainty parameters to identify important parameters and their interactions that affect well productivity. The results indicate that the existence of dense secondary fractures (the distance between secondary fractures is small) results in higher initial production rate and ultimate recovery, but a sharper decline in production rate. Increasing the length of the secondary fractures can more effectively enhance gas production in the presence of dense secondary fractures. Moreover, the benefits of dense secondary fractures are mostly limited to a high porosity shale reservoir.",12,12,3
Shale Gas,Horizontal Wells,"Zeng, Jie; Li, Wai; Liu, Jishan; Leong, Yee-Kwong; Elsworth, Derek; Tian, Jianwei; Guo, Jianchun; Zeng, Fanhua",Analytical solutions for multi-stage fractured shale gas reservoirs with damaged fractures and stimulated reservoir volumes,Shale gas reservoir; SRV; Fracture damage,LINEAR FLOW MODEL; HORIZONTAL WELLS; PERMEABILITY; ADSORPTION; TRANSPORT; MECHANISMS; NANOPORES; IMPACT; FACE,"After performing hydraulic fracturing in shale reservoirs, the hydraulic fractures and their adjacent rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures; (2) partially propped fractures with unpropped or poorly propped sections at the middle or tail of fractures; (3) fracture face damage; and (4) multiple damage cases. The classical fracture skin factors are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple damage and partially propped fractures. In this article, a new analytical model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs. The matrix model is a spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly envelops the matrix. The reservoir-fracture flow model is a ten-region linear flow model which can handle fracture damage mechanisms. Specifically, the inner reservoir region is treated as an SRV where the secondary fracture permeability obeys a power-law decreasing trend due to the attenuate stimulation intensity. This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of a published linear flow model. New type curves are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Different damage mechanisms all control specific flow regimes but the fracture face damage shows the slightest influence. In the multiple fracture damage case, some typical flow regimes can be easily identified except those induced by the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.",12,12,3
Shale Gas,Horizontal Wells,"Wei, Shiming; Jin, Yan; Xia, Yang; Lin, Botao",The flowback and production analysis in sub-saturated fractured shale reservoirs,Sub-saturated shale reservoirs; Flowback; Production; Gas-water flow; Discrete fractures,DISCRETE-FRACTURE; 2-PHASE FLOW; GAS-FLOW; HYDRAULIC-FRACTURE; TRIPLE-CONTINUUM; NUMERICAL-METHOD; HORIZONTAL WELL; POROUS-MEDIA; MODEL; SIMULATION,"The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced ""skin factor"" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model.",10,10,3
Shale Gas,Horizontal Wells,"Zhao, Yulong; Lu, Guang; Zhang, Liehui; Wei, Yunsheng; Guo, Jingjing; Chang, Cheng",Numerical simulation of shale gas reservoirs considering discrete fracture network using a coupled multiple transport mechanisms and geomechanics model,Shale gas; Multistage fractured horizontal well; Multiple migration mechanisms; Geomechanics; Discrete fracture network,APPARENT PERMEABILITY; HORIZONTAL WELL; COMPOSITE MODEL; FLOW; MATRIX; COAL; DESORPTION; NANOPORES; STRESS; ADSORPTION,"Shale has typical characteristics of multi-scale space for gas storage and migration. It is suitable for description by a triple medium model composed of double continuous medium and discrete fracture model, and need to consider multiple migration mechanisms. Besides, during gas production, effective stress and desorption will cause the deformation of shale, leading to the dynamic changes in porosity and permeability. In this paper, a fully coupled model was established to evaluate the shale gas production dynamics, including the governing equation of shale deformation and the governing equation of gas migration in the matrix, micro-fractures, and hydraulic fractures, respectively. All processes are coupled by the dynamic models of porosity and permeability for matrix and micro-fractures, and by the gas exchange between different systems. The fully coupled model was solved by the finite element method through the PDE solver software named COMSOL Multiphysics. The rationality of this fully coupled model is verified by the production data of Barnett shale. The validated model was applied to study the effects of adsorption and geomechanics parameters on dynamic changes of porosity and permeability, and gas production. Moreover, the impact of primary fracture geometry and secondary fracture distribution parameters on production were also analyzed. Simulation results show that the adsorption parameters have essential effects on both gas flow and production; that the geomechanics parameters have important influences on the evolution of porosity and permeability; that optimizing the distribution and development of hydraulic fracture and secondary fracture is beneficial to the efficient development of shale gas.",9,9,9
Shale Gas,Horizontal Wells,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Shale Gas,Degrees C,"Hu, Xiao; Xie, Jun; Cai, Wuchao; Wang, Rui; Davarpanah, Afshin",Thermodynamic effects of cycling carbon dioxide injectivity in shale reservoirs,Carbon dioxide storage capacity; Oil recovery factor; Soaking time; Core stimulation; Shale reservoirs,ENHANCED OIL-RECOVERY; BAKKEN TIGHT OIL; N-PUFF PROCESS; GAS; STORAGE; MODEL; PERMEABILITY,"Carbon dioxide injectivity has always been considered as one of the optimum enhanced recovery techniques, especially in tight reservoirs regarding the feasible mobilization of gas through porous media. To have a better understanding of carbon dioxide injectivity performances, it would be of importance to consider crucial parameters and their effects on the carbon dioxide adsorption and oil recovery factor. In this paper, the profound impact of crucial parameters such as temperature, pressure, carbon dioxide soaking time, and core stimulation on the oil recovery enhancement were investigated. Moreover, the considerable influence of pressure and temperature on the carbon dioxide adsorption capacity storage were performed and analyzed. According to the result of this experiment, temperature increase led to reducing carbon dioxide storage capacity, which has a reverse pattern with oil recovery factor by increasing temperature. When the core samples were unstimulated, the oil recovery factor has higher than stimulated core samples. Furthermore, pressure increase resulted in the carbon dioxide storage capacity enhancement, which has a similar increase pattern with oil recovery factor by increasing pressure. The maximum carbon dioxide storage capacity is 91% and 90% at the pressure of 1500 psi and temperature of 20 degrees C respectively. Soaking time rising between oil and carbon dioxide led to producing more oil volume.",98,98,22
Shale Gas,Degrees C,"Ma, Weijiao; Hou, Lianhua; Luo, Xia; Liu, Jinzhong; Tao, Shizhen; Guan, Ping; Cai, Yuwen",Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature -based semi -open pyrolysis: Implications for in -situ conversion process,Chang 7 oil shale; In-situ conversion process; Temperature-based semi-open pyrolysis; Hydrocarbon generation process; Hydrocarbon expulsion process,TRIASSIC YANCHANG FORMATION; ORGANIC-MATTER; HYDROUS PYROLYSIS; GAS GENERATION; CHINA IMPLICATIONS; SOURCE-ROCK; II KEROGEN; PETROLEUM; EVOLUTION; SYSTEM,"There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300-320 degrees C, 0.53-0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320-380 degrees C, 0.55-1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380-420 degrees C, 1.09-1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 degrees C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24-1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.",16,19,10
Shale Gas,Degrees C,"Kang, Zhiqin; Zhao, Yangsheng; Yang, Dong; Tian, Lijun; Li, Xiang",A pilot investigation of pyrolysis from oil and gas extraction from oil shale by in-situ superheated steam injection,Oil shale; In-situ pyrolysis; Superheated steam injection; Experimental investigation; Oil-recovery rate,COMPREHENSIVE UTILIZATION; NUMERICAL-SIMULATION; THERMAL-CRACKING; HIGH-TEMPERATURE; ORGANIC-MATTER; X-RAY; TECHNOLOGY; COMBUSTION; PERMEABILITY; EVOLUTION,"Oil shale is a critical strategic energy with huge reserve. The research and development of an economically feasible in-situ retorting technology for oil and gas extraction from oil shale is of great significance. Thus, this paper experimentally studied the large oil-shale samples pyrolysis by in-situ superheated steam injection (MTI) implemented from 2014 to 2016. The structure of the large-scale in-situ pyrolysis test system, the experimental procedure, and the results are presented here. The steam fracturing-connection was used during the initial stage, and the pressure of the superheated steam for fracturing was similar to 2 times higher than the strata stress. The variation of temperature and pressure during pyrolysis was controlled by the variation in steam seepage. The operating steam pressure during pyrolysis was lower than 1/4 of the strata stress. The energy utilization of the superheated steam for the pyrolysis reaction was 42.7%. The average temperature of the fluid that was discharged from the production wells was around 170 degrees C, which can be recycled to achieve a heat-utilization coefficient of 13.19% in commercial operations. The oil-recovery rate in the pyrolysis area exceeded 95%, and the overall oil-recovery rate reached up to 70.7% of the tested large oil-shale samples. The gas production rate and the effective energy rate of the injected steam are correlated with an exponential function. Our pilot tests indicate that the in-situ retorting technology of oil shale by MTI shows great potential for commercial operation in oil-shale formation.",15,18,10
Shale Gas,Degrees C,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Shale Gas,Degrees C,"Paswan, Bhola K.; Mahto, Vikas",Development of environment-friendly oil-in-water emulsion based drilling fluid for shale gas formation using sunflower oil,Surfactant synthesis; Rheology; Filtration properties; Zeta potential; Contact; Angle; Interfacial tension,TRIBOLOGICAL PROPERTIES; RHEOLOGICAL PROPERTIES; SURFACTANT; POLYMER; BENTONITE; BEHAVIOR; ADSORPTION; PARTICLES; STABILITY; WEIGHT,"Mineral oils are frequently used for the making of synthetic-based drilling fluids. However, there are several downsides associated with these oils. These mineral oils are non-renewable, toxic in nature, non-biodegradable and prompting towards the incredible expense of waste treatment. In this research article, an anionic surfactant sodium methyl ester sulfonate (SMES) was synthesized using sunflower oil. SMES is then used to formulate environment-friendly oil-in-water emulsion-based drilling fluid. The synthesized surfactant is characterized by FT-IR, H-1-NMR and TGA analysis. The effect of xanthan gum (XG), bentonite, and sodium methyl ester sulfonate (SMES) on the rheology and filtration characteristics of developed emulsion based drilling fluid was analyzed thoroughly. The developed emulsion based drilling fluid had lower friction coefficient in case of oil concentration compared to SMES concentration. The zeta potential has been measured to check the emulsion stability and it has been attended that an increase in the concentration of SMES (0.3-0.7 wt/v %) and xanthan gum (0.2-0.6 wt/v %) has improved the stability of the emulsion. The contact angle and interfacial tension were analyzed and it was observed that interfacial tension was reduced from 102.5 to 25.35 mN/m and contact angle increased from 32.5 degrees to 92.3 degrees. The thermal stability of oil-in-water emulsion based drilling fluid was maintained up to 140 degrees C.",14,14,2
Shale Gas,Degrees C,Deng Kuanhai; Yuan Yue; Hao Yi; Li Zhonghui; Lin Yuanhua,Experimental study on the integrity of casing-cement sheath in shale gas wells under pressure and temperature cycle loading,Casing-cement sheath; Full-scale integrity test; Temperature cycle loading; Pressure cycle loading; Interface mechanical properties; Multistage hydraulic fracturing,ZONAL ISOLATION; FAILURE; MODEL,"During large-scale multistage hydraulic fracturing in shale-gas wells, the cement sheath loses its integrity easily because of repeated temperature and pressure variations in the wellbore. This is likely to form a potential leak path, subsequently leading to the loss of zonal isolation and sustained casing pressure. To prevent such barrier failures, it is crucial to investigate and understand the failure mechanism of cement sheath. In this study, an experimental apparatus and evaluation method of the sealing integrity and mechanical integrity for casing-cement sheath under temperatures and pressures cycle loading have been presented in this paper by which sixteen groups of full-scale integrity tests of general and high-strength cement sheath have been conducted under temperature ranging from 30 to 150 degrees C and pressure ranging from 0 to 70 MPa cycling loading. The anti-channeling/sealing performance and interface mechanical behavior of casing-cement sheath are measured and characterized respectively under different loading-unloading methods. The cycle numbers required for sealing integrity failure of cement sheath under different cyclic temperatures and pressures have been obtained. The interface mechanical properties (cementing force, friction force, shearing strength and lateral bonding strength) of cement sheath have been obtained, and effects of alternating temperatures and pressures on those mechanical properties and late integrity have been analyzed. Research results can provide a very important reference for the fracturing design of shale-gas wells.",8,8,6
Shale Gas,Degrees C,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Shale Gas,Apparent Permeability,"Li, Zihao; Ripepi, Nino; Chen, Cheng",Using pressure pulse decay experiments and a novel multi-physics shale transport model to study the role of Klinkenberg effect and effective stress on the apparent permeability of shales,Apparent permeability; Klinkenberg effect; Shale gas; Biot's coefficient; Multi-physics shale transport,GAS-FLOW; POROUS-MEDIA; HETEROGENEITY; DEPENDENCE; ANISOTROPY; PIPES; ROCKS; COAL; LAW,"The confining pressure imposed on a shale formation has a significant impact on the apparent permeability of the rock. Gas flow in low-permeability shales differs significantly from liquid flow because of the Klinkenberg effect, which results from gas molecule slip at the wall surfaces inside the nanopores. This effect causes the increase of apparent permeability (i.e., the measured permeability). In this study, cores extracted from four U.S. shale formations were tested using a pulse decay permeameter (PDP) under varying combinations of confining and pore pressures. The Klinkenberg coefficient was calculated to interpret the change in the measured apparent permeability as a function of pore pressure and effective stress. Next, based on the various combinations of confining and pore pressures, the actual values of the Biot coefficient were calculated by data fitting. Moreover, the samples were cored in the directions parallel to and perpendicular to the shale bedding planes to unravel the role of bedding plane direction on the apparent permeability. Furthermore, a novel, multi-physics shale transport (MPST) model was developed to account for the coupled multi-physics processes of geomechanics, fluid dynamics, and Klinkenberg effect for gas transport in shales. In the MPST model, pore pressure and effective stress are the two independent input variables, and the measured apparent permeability is the model output. The MPST model was then used to fit the PDP experimental data, and the successful data fitting confirmed that the MPST model captures the critical multi-physics processes that regulate the apparent permeability.",12,14,1
Shale Gas,Apparent Permeability,"Song, Wenhui; Yao, Jun; Wang, Dongying; Li, Yang; Sun, Hai; Yang, Yongfei",Dynamic pore network modelling of real gas transport in shale nanopore structure,Shale gas; Transport mechanisms; Dynamic pore network model; Gas permeability,SURFACE-DIFFUSION; POROUS-MEDIA; SLIP-FLOW; APPARENT PERMEABILITY; ADSORPTION; MICRO; RESERVOIRS; MULTISCALE; METHANE; PREDICTION,"Gas transport in shale nanopores is controlled by the complex transport mechanisms and pore structure characteristics. So far much work has been done on the single pore and regular structure based pore network but lithe is known on real gas transport behavior on a realistic shale pore structure model. In this work, a dynamic pore network model is proposed to describe single component methane transport in nano-scale porous media. Gas transport behavior takes transport mechanisms of slip flow, transition flow, surface diffusion and ad/desorption into account. Real gas effect under high pressure and temperature is considered when calculating gas properties. A three dimensional pore network model is built from a three dimensional image that is reconstructed using multi-point statistics from a small organic-rich area on a two dimensional shale SEM image. This pore network model is used to analyze dynamic gas transport and pressure drop transmission process. Our simulated results reveal that there exists a time period that gas permeability on the pore network is influenced by the pressure drop transmission process and pore structure that flows on. When pressure drop reaches outlet, gas transport turns steady state. At steady state period gas permeability becomes constant and is influenced by the effective stress, pressure, temperature and shale rock property.",11,12,6
Shale Gas,Apparent Permeability,"Zhao, Yulong; Lu, Guang; Zhang, Liehui; Wei, Yunsheng; Guo, Jingjing; Chang, Cheng",Numerical simulation of shale gas reservoirs considering discrete fracture network using a coupled multiple transport mechanisms and geomechanics model,Shale gas; Multistage fractured horizontal well; Multiple migration mechanisms; Geomechanics; Discrete fracture network,APPARENT PERMEABILITY; HORIZONTAL WELL; COMPOSITE MODEL; FLOW; MATRIX; COAL; DESORPTION; NANOPORES; STRESS; ADSORPTION,"Shale has typical characteristics of multi-scale space for gas storage and migration. It is suitable for description by a triple medium model composed of double continuous medium and discrete fracture model, and need to consider multiple migration mechanisms. Besides, during gas production, effective stress and desorption will cause the deformation of shale, leading to the dynamic changes in porosity and permeability. In this paper, a fully coupled model was established to evaluate the shale gas production dynamics, including the governing equation of shale deformation and the governing equation of gas migration in the matrix, micro-fractures, and hydraulic fractures, respectively. All processes are coupled by the dynamic models of porosity and permeability for matrix and micro-fractures, and by the gas exchange between different systems. The fully coupled model was solved by the finite element method through the PDE solver software named COMSOL Multiphysics. The rationality of this fully coupled model is verified by the production data of Barnett shale. The validated model was applied to study the effects of adsorption and geomechanics parameters on dynamic changes of porosity and permeability, and gas production. Moreover, the impact of primary fracture geometry and secondary fracture distribution parameters on production were also analyzed. Simulation results show that the adsorption parameters have essential effects on both gas flow and production; that the geomechanics parameters have important influences on the evolution of porosity and permeability; that optimizing the distribution and development of hydraulic fracture and secondary fracture is beneficial to the efficient development of shale gas.",9,9,9
Shale Gas,Apparent Permeability,"Berawala, Dhruvit S.; Andersen, Pal O.",Numerical investigation of Non-Darcy flow regime transitions in shale gas production,Shale gas production; Non-Darcy flow; Forchheimer equation; Fracture-matrix flow; Apparent permeability,APPARENT PERMEABILITY; STRESS-DEPENDENCE; MODEL; RESERVOIRS; ADSORPTION; IMBIBITION; DIFFUSION; TRANSPORT; NANOPORES; EVOLUTION,"Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable. The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure depletion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir isotherm and is a key production mechanism. This model is implemented in Matlab using Marcellus shale data. Scaling the model shows that recovery of gas depends on two dimensionless number that incorporates geometry relations, time scales of flow, intrinsic parameters of the porous media, non-Darcy constants, adsorption and boundary conditions. The dimensionless numbers define respectively if 1) the fracture or matrix limit the gas production rate 2) if non-Darcy flow is significant in the fracture or matrix. When one of the media limit production, the non-Darcy flow in the other medium has reduced importance and can be excluded from the model. Non-Darcy flow is important if it limits flow in the medium limiting the production. By checking the magnitude of the selected dimensionless numbers, the modelling approach can be determined in advance and significant computational time can be saved. The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.",8,8,4
Shale Gas,Apparent Permeability,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Shale Gas,Carbon Dioxide,"Hu, Xiao; Xie, Jun; Cai, Wuchao; Wang, Rui; Davarpanah, Afshin",Thermodynamic effects of cycling carbon dioxide injectivity in shale reservoirs,Carbon dioxide storage capacity; Oil recovery factor; Soaking time; Core stimulation; Shale reservoirs,ENHANCED OIL-RECOVERY; BAKKEN TIGHT OIL; N-PUFF PROCESS; GAS; STORAGE; MODEL; PERMEABILITY,"Carbon dioxide injectivity has always been considered as one of the optimum enhanced recovery techniques, especially in tight reservoirs regarding the feasible mobilization of gas through porous media. To have a better understanding of carbon dioxide injectivity performances, it would be of importance to consider crucial parameters and their effects on the carbon dioxide adsorption and oil recovery factor. In this paper, the profound impact of crucial parameters such as temperature, pressure, carbon dioxide soaking time, and core stimulation on the oil recovery enhancement were investigated. Moreover, the considerable influence of pressure and temperature on the carbon dioxide adsorption capacity storage were performed and analyzed. According to the result of this experiment, temperature increase led to reducing carbon dioxide storage capacity, which has a reverse pattern with oil recovery factor by increasing temperature. When the core samples were unstimulated, the oil recovery factor has higher than stimulated core samples. Furthermore, pressure increase resulted in the carbon dioxide storage capacity enhancement, which has a similar increase pattern with oil recovery factor by increasing pressure. The maximum carbon dioxide storage capacity is 91% and 90% at the pressure of 1500 psi and temperature of 20 degrees C respectively. Soaking time rising between oil and carbon dioxide led to producing more oil volume.",98,98,22
Shale Gas,Carbon Dioxide,"Yang, Rui; Jia, Aoqi; He, Sheng; Hu, Qinhong; Dong, Tian; Hou, Yuguang; Yan, Jianping","Water adsorption characteristics of organic -rich Wufeng and Longmaxi Shales, Sichuan Basin (China)",,SEDIMENTARY GEOCHEMICAL PROXIES; METHANE ADSORPTION; GAS SHALES; PALEOENVIRONMENT INTERPRETATION; SORPTION BEHAVIOR; MESOPOROUS SILICA; JIAOSHIBA AREA; CARBON-DIOXIDE; VAPOR SORPTION; PORE STRUCTURE,,29,30,4
Shale Gas,Carbon Dioxide,"Memon, Asadullah; Li, Aifen; Jacqueline, Nangendo; Kashif, Muhammad; Ma, Min","Study of gas sorption, stress effects and analysis of effective porosity and permeability for shale gas reservoirs",Adsorption; Absorption; Sorption; Stress; Effective porosity; Effective permeability,METHANE ADSORPTION; CARBON-DIOXIDE; MOLECULAR SIMULATION; MATRIX PERMEABILITY; CONFINING STRESS; MATURITY; WATER; FLOW; CAPACITY; IMPACT,"The gas sorption capacity, effective porosity, and effective permeability are important to shale gas reservoir characterization, gas-in-place estimation, and production behavior prediction. Previous studies have ignored the absorption gas in gas sorption measurements; however, the absorption gas is dissolved into kerogen and cannot be underestimated. In this study, experiments are performed on shale samples to quantify the gas sorption capacity with new sights and to analyze the effective porosity and permeability in adsorbed and absorbed gas considering gas sorption and stress impacts. Then, data are also obtained for quantitative analysis. This study revealed that the proposed gas sorption model (sum of adsorption and absorption of gases) is as accurate as the Langmuir model. Based on this model, converted excessive to absolute gas sorption and the contribution of the absorption gas to the total gas sorption are estimated. The porosity and permeability in adsorbed/absorbed and sorption gas increases with increasing pore pressure, whereas the effective porosity and permeability decreases with increasing pore pressure. The effective porosity is affected more at low pressure, whereas it is almost the same or changes slightly at higher pressure; however, the effective permeability is dependent on the adsorbed porosity. The amount of absorbed gas increases linearly with increasing pore pressure, and that it followed Henry's law, whereas the effective absorbed porosity decreases linearly with increasing pore pressure. The effective absorbed permeability increases at a lower rate at low pressure, while at a high pressure, the rate of increase is higher. It is also observed that the adsorbed/absorbed porosity, such as gas sorption, is a function of the total organic carbon and specific surface area. However, both parameters vary with kerogen quality. The combined impact of gas sorption and stress may change the controlling factors of shale gas properties and enable the accurate measurement of the effective porosity and permeability.",14,14,2
Shale Gas,Carbon Dioxide,"Zhang, Shasha; Wu, Caifang; Liu, Huan","Comprehensive characteristics of pore structure and factors influencing micropore development in the Laochang mining area, eastern Yunnan, China",Pore structure; Micropores; Influencing factors; The Laochang mining area,ANGLE NEUTRON-SCATTERING; GAS SHALE RESERVOIRS; SIZE DISTRIBUTION; MERCURY INTRUSION; SURFACE-AREA; MATRIX COMPRESSIBILITY; ELECTRON-MICROSCOPY; JUNGGAR BASIN; COAL; ADSORPTION,"Characterization of coal pore structure plays an important role in the exploration and development of coalbed methane. Results from corrected high-pressure mercury injection porosimetry, low-temperature liquid nitrogen adsorption, and low temperature carbon dioxide adsorption were used in combination with fractal theory. This study aims to gain insight into full-scale pore size distribution and to discuss factors influencing micropore development in relation to physical properties of coal samples. The results show that coal compressibility in the study area is between 0.79-1.27 x 10(-10) m(2)/N, the maximum cumulative mercury intrusion volume was 75%-85% of that before correction. Pore shapes are mainly cone pores and parallel plate-shaped pores. The total pore volume (PV) ranges from 0.071-0.084 cm(3)/g. Micropores, especially those with diameters less than 1.5 nm, account for more than 90% of PV, providing storage space for most of the adsorbed gas. The effect of coalification on pore development is complex, there is no obvious relationship between micropore volume, specific surface area (SSA) and coal rank; however, a negative correlation exists between micropore volume, SSA and volatile yield. Moisture and fixed carbon content can increase micropore volume and SSA, while ash yield and minerals tend to reduce micropore volume and SSA.",8,8,20
Shale Gas,Damage,"Zeng, Jie; Li, Wai; Liu, Jishan; Leong, Yee-Kwong; Elsworth, Derek; Tian, Jianwei; Guo, Jianchun; Zeng, Fanhua",Analytical solutions for multi-stage fractured shale gas reservoirs with damaged fractures and stimulated reservoir volumes,Shale gas reservoir; SRV; Fracture damage,LINEAR FLOW MODEL; HORIZONTAL WELLS; PERMEABILITY; ADSORPTION; TRANSPORT; MECHANISMS; NANOPORES; IMPACT; FACE,"After performing hydraulic fracturing in shale reservoirs, the hydraulic fractures and their adjacent rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures; (2) partially propped fractures with unpropped or poorly propped sections at the middle or tail of fractures; (3) fracture face damage; and (4) multiple damage cases. The classical fracture skin factors are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple damage and partially propped fractures. In this article, a new analytical model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs. The matrix model is a spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly envelops the matrix. The reservoir-fracture flow model is a ten-region linear flow model which can handle fracture damage mechanisms. Specifically, the inner reservoir region is treated as an SRV where the secondary fracture permeability obeys a power-law decreasing trend due to the attenuate stimulation intensity. This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of a published linear flow model. New type curves are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Different damage mechanisms all control specific flow regimes but the fracture face damage shows the slightest influence. In the multiple fracture damage case, some typical flow regimes can be easily identified except those induced by the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.",12,12,3
Shale Gas,Damage,"Lin, Botao; Guo, Jiancheng; Liu, Xing; Xiang, Jianhua; Zhong, Hua",Prediction of flowback ratio and production in Sichuan shale gas reservoirs and their relationships with stimulated reservoir volume,Flowback ratio; Productivity; Shale gas reservoir; Neural network; Stimulated reservoir volume,WATER; IMBIBITION,"Good flowback management in shale gas reservoirs not only preserves the conductivity of the flow paths created by the fracture network but also assists the subsequent production by minimizing the damage of the fracturing fluid to the fluid-sensitive formation. However, a quantitative prediction of its behavior and impact on the productivity of a reservoir is not available yet. This study proposed a mathematical approach to predict the flowback behavior concerning flow back ratio (FBR), and the productivity represented by first-month production (PROD), of the Changning-Weiyuan shale gas reserve in Sichuan basin, southwest China. First, a BP (Back Propagation) neural network model was established to filter out the controlling factors given the actual FBRs and the geological and engineering characteristics of seventy-six sample wells. Secondly, a correlation was generated between the FBR, the geological index g, and the engineering index e by non-linear fitting. In subsequence, the PROD was predicted based on the field recorded FBR and the comprehensive index c that combines the influences of both geological and engineering parameters. Finally, the stimulated reservoir volumes (SRVs) of twelve wells were estimated using the K-means clustering and Delaunay triangulation to assess their impact on the FBR and PROD data. It was found that the associated FBR and PROD diagrams can provide accurate predictions for the sixteen additional wells. Meanwhile, there exists an optimum FBR range of 20-40% for the shale gas region of concern where the productivity of the formation can be maximized. It is also observed that the FBR and PROD fail to display any specific trend with the value of the SRV magnitude. In general, the proposed approach can be used in shale gas reservoirs to examine the favorable FBR and guide the engineering designs to enhance production if adequate reservoir data are accessible.",10,10,6
Shale Gas,Damage,"Duan, Y. T.; Li, X.; Ranjith, P. G.; Wu, Y. F.",An investigation of the evolution of the internal structures and failure modes of Longmaxi shale using novel X-ray microscopy,X-ray microscopy; Longmaxi shale; Void evolution; Crack connectivity; Meso-scale mineral; Intergranular fracture,PARTIALLY SATURATED SAND; CRACKING PROCESS; CT; LOCALIZATION; ROCKS,"An accurate description of the evolution of the internal structure of shale during loading and fracturing is important to understand the failure mechanisms that are related to shale-gas migration. The aim of this work was to investigate and characterize the void evolution and failure of Longmaxi shale quantitatively under uniaxial tests, and analyze the relationship between the distribution of the meso-scale (voxel-scale) minerals and the failure mode. Novel X-ray microscopy combined with an in-situ microtest device was used and three groups of shale specimens were tested under uniaxial conditions with different scanning stresses. Some three-dimensional stereograms of different loading forces and an entire force-displacement curve were obtained for each in-situ test. Based on the results, an evolution of the void distribution was characterized and divided into four stages: weakened damage, linear, damage evolution and stable development, and accelerated damage development. The degree of development of the final cracks was distinguished by the crack volume, equivalent aperture width and connectivity rate. The structure evolution and failure mode of shale were described quantitatively by the void changes and the crack characteristics. Three phenomena of intergranular fracture, transgranular fracture and arrest cracks were observed at a meso-scale to explain the effect of mineral distribution on the crack pattern. These quantitative results can provide a guide for the design in shale fracturing engineering and some references for numerical analysis.",9,9,6
Shale Gas,Damage,"Wijaya, Nur; Sheng, James J.",Optimum surfactant criteria for controlling invasion-induced water blockage in tight water-wet cores,Surfactant; Hydraulic fracturing; Flowback; Water blockage; Interfacial tension; Wettability alteration,ENHANCED SPONTANEOUS IMBIBITION; CALCIUM ALGINATE BEADS; WETTABILITY ALTERATION; IFT REDUCTION; OIL-RECOVERY; GAS SHALES; RESERVOIRS; FLOW; MECHANISMS; ADSORPTION,"Flowback after hydraulic fracturing shows a poor recovery of the fracturing fluid. The unrecovered fluid is believed to invade the matrix and creates a formation damage called water blockage, which affects the optimum oil production from the reservoir. Surfactant is often added into the fracturing fluid, because it can improve the recovery of the fracturing fluid, and hence minimum water blockage. This objective is achieved by the surfactant's interfacial tension (IFT) reduction and wettability alteration capabilities. This study investigates the optimum surfactant criteria, in terms of the IFT and wettability, to minimize the water blockage. From the perspective of regained oil relative permeability, our history-matched core-scale model reveals that the optimum criteria depend on the matrix capillarity. In conventional reservoirs, the optimum criteria are to select surfactants which offer ultralow IFT (even as low as 0.001 mN/m) and maintain the waterwetness of the rock. However, in tight reservoirs, the optimum criteria are surfactants which strongly alter the rock wettability to oil-wet, while the IFT requirement is more flexible (i.e., from 15 down to 0.001 mN/m). The contradicting optimum criteria can be explained by the relative dominance between relative permeability and capillary pressure. This study emphasizes that the optimum surfactant criteria for conventional reservoirs are not necessarily the same as those for tight reservoirs.",8,8,2
Shale Gas,Brittleness Evaluation,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Shale Gas,Brittleness Evaluation,"Wang, Tingting; Zhang, Tao; Ranjith, P. G.; Li, Yuwei; Song, Zhenlong; Wang, Sheng; Zhao, Wanchun",A new approach to the evaluation of rock mass rupture and brittleness under triaxial stress condition,Brittleness; Catastrophe theory; Energy dissipation; Double-body system,MECHANICAL-PROPERTIES; SHALE; INDEXES; PREDICTION; HARDNESS,"It is significant to accurately evaluate the brittleness of rock mass for the effective evaluation post-fracture of unconventional oil and gas reservoirs and stability of underground mining engineering. The failure of rock mass under compression is regarded as deformation and rupture of the double-body system. A new index for the brittleness evaluation of rock mass is proposed based on catastrophe theory. The new method can provide critical detail description to the variation of critical rupture point, catastrophe energy, post-peak external work, and brittleness index of rock mass under different confining pressures. Red sandstone and granite specimens were selected for compression tests under different confining pressures. The results showed that released kinetic energy, strain of the critical rupture position, and external work varied linearly, approximately, while softening modulus and brittleness index varied polynomially, as confining pressure increased. The results are reliable and reasonable when the rock is regarded as double-body system to study the rupture and brittleness characteristics. The findings of this paper can mitigate some of limitations in existing research.",11,11,5
Shale Gas,Brittleness Evaluation,"Liu, Bo; Wang, Sheng; Ke, Xuan; Fu, Xiaofei; Liu, Xingzhou; Bai, Yunfeng; Pan, Zhejun",Mechanical characteristics and factors controlling brittleness of organic-rich continental shales,Organic-rich shale; Rock mechanics; Stress-strain curve; Mineral composition; Brittleness evaluation,SICHUAN BASIN; GAS; RESERVOIRS; ROCKS; CHALLENGES; PARAMETERS; INDEXES; COAL,"Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures.",7,7,10
Shale Gas,Rock Physics Model,"Mehmani, Ayaz; Kelly, Shaina; Torres-Verdin, Carlos","Leveraging digital rock physics workflows in unconventional petrophysics: A review of opportunities, challenges, and benchmarking",Digital rock physics; Pore-scale modeling; Unconventional petrophysics; Representative elementary volume; Best practices,ENHANCED OIL-RECOVERY; PORE-SCALE; RELATIVE PERMEABILITY; POROUS-MEDIA; MULTISCALE; SHALE; FLOW; GAS; MICROPOROSITY; IMBIBITION,"Digital rock physics (DRP), via both direct numerical simulation and pore-network modeling, holds great promise in terms of probing such pore-scale controls on transport, particularly with multiphase flow and sensitivity analysis of time-intensive measurements such as relative permeability. However, despite advances in micro-computed tomography (microCT) and scanning electron microscopy (SEM) techniques, obtaining cost-effective representative elementary volumes (REV) at sufficient resolution that capture dual-scale porosity and surface textures remains a formidable challenge in establishing digital rock physics as a predictive toolset. Furthermore, implementers are faced with several options of numerical solvers such as finite element method, lattice Boltzmann method, and mass balance-based pore-network modeling. This paper reviews the current status of establishing an REV and upscaling techniques for DRP in tight and/or diagenetically-altered rocks, highlighting successful and unsuccessful pore-to-core data benchmarking examples by the authors and the greater literature in terms of static and dynamic properties. The review finds that performing DRP on a single image modality is not sufficient, even for many conventional rocks, and that it is crucial to interface with experimental data, be it core analysis deliverables or subpore-scale and Darcy-scale microfluidics. In unconventional rocks, the majority of work does not leverage mesoscale simulations, instead zooming in to a discrete pore-scale scenario that is often not benchmarked with SCAL data. Even when a simulation domain is benchmarked, the matching of a discrete case with a multivariable situation is non-unique. Benchmarking with dynamic or pseudo-dynamic core data such as MICP and single phase perm will greatly help reduce variables. Finally, this paper offers a technical roadmap for the robust application of unconventional DRP for the petrophysical and general subsurface community.",11,11,3
Shale Gas,Rock Physics Model,"Sohail, Ghulam Mohyuddin; Hawkes, Christopher D.",An evaluation of empirical and rock physics models to estimate shear wave velocity in a potential shale gas reservoir using wireline logs,Shear wave velocity; Compressional wave velocity; Lower Indus Basin; Biot model,LOWER INDUS BASIN; POROSITY; PREDICTION; FIELD,"Shear wave velocity (Vs) is essential for determining the elastic properties of rocks, which are useful for shale gas reservoir characterization. Many investigators have developed empirical models of varying form and complexity, and simplified rock physics models for the estimation of Vs using conventional well logs and/or laboratory measurements on core samples. Other investigators have developed rock physics models and used them to estimate velocities based on fundamental rock properties such as mineralogy, pore geometry and fluid saturations. The selection of a suitable model based on well logs is challenging, especially in cases where cores are not available. This study evaluates various relationships in the literature for the estimation of shear wave velocity applied to sandy shale and shale intervals of the Lower Goru Formation, Lower Indus Basin, Pakistan. Some inputs (e.g., compressional wave velocity) are directly taken from conventional log measurements, while others (e.g., petrophysical and elastic properties) are estimated using available log and the literature data. A statistical analysis has been used to quantify the difference between measured and predicted Vs. The results reveal that some empirical models can produce a coefficient of determination (R-2) of roughly 0.8 when cross-plotted against measured Vs values, and R-2 values can be further increased by 10%-20% if the coefficients are adjusted based on available Vs data. However, these models do not explicitly account for the mechanisms of velocity variations in sandy shale and shale due to pore geometry (aspect ratio), consolidation and fluid saturations in the manner that rock physics models do. The rock physics modeling conducted for this work demonstrated that the use of Biot's model (rather than Gassmann's model) for fluid substitution improved model performance for Vs estimation in gas-saturated sandy shale and shale of the Lower Goru Formation. Although statistical analysis showed this model to be slightly less accurate than the best empirical models (R-2 of approximately 0.77), it is suggested that the rock physics model should be reliable when applied to a broader range of saturations and lithologies in the Lower Goru Formation. Also, using the rock physics approach, model input parameters can be optimized using Vp data, which represents a significant advantage over the empirical models which require Vs data for optimization. The modified rock physics model is thus deemed to be the best option available at present for the study area, and it is suggested that it should be appropriate for use in other settings - assuming that Vp data are available and sufficient knowledge regarding rock lithology is available.",9,9,1
Shale Gas,Rock Physics Model,"Zhao, Peng; Xie, Lingzhi; Ge, Qi; Zhang, Yao; Liu, Jun; He, Bo",Numerical study of the effect of natural fractures on shale hydraulic fracturing based on the continuum approach,Hydraulic fracturing simulation; Anisotropic strength criterion; Discontinuities; Continuum method; Fracturing geometry; Complexity and scale,STIMULATED RESERVOIR VOLUME; PROPAGATION; SIMULATION; MODEL; STRESS; FLOW; GAS; PERMEABILITY; DEFORMATION; MEDIA,"Because of the complexity of shale reservoirs and multiple physical coupling processes, numerical implementation remains a challenge in engineering applications. Unlike conventional reservoirs, shale reservoirs always contain two main discontinuities: bedding interface and natural fractures. The existence of these discontinuities is the key reason a fracture network is formed. Therefore, the numerical model should contain both bedding interface and natural fractures. In this paper, the fracturing propagation process is described based on continuum theory. In contrast to other research, an anisotmpic strength criterion is adopted to consider the anisotropic properties of shale, including the failure of both shale matrix and discontinuities. The criterion is described by the Mohr-Coulomb model combined with tensile failure. When fractures are generated in the shale rock mass, the stiffness and permeability of the fractured rock are homogenized in an element, and volume fracturing is represented by the deformation of three orthogonal fractures in the rock element. Simultaneously, the anisotropic permeability is also enhanced. Hence, based on this continuum approach and finite element method, a three-dimensional model for shale hydraulic fracturing simulation is presented. This model fully considers the direct coupling of fluid flow and rock deformation during hydraulic fracturing. To verify the anisotropic strength criterion, a shale compression test is conducted. Through a comparison of the numerical and experimental results, the applied criterion can describe the shale compressive strength anisotropy. In addition, the KGD analytical model is also adopted to verify the performance of the developed model for hydraulic fracturing. Finally, several cases of shale hydraulic fracturing are simulated, and the results show the geometry of the fracture region under different conditions. Furthermore, the impacts of three factors on hydraulic fracturing geometry are considered, including natural fractures, spacing of perforations and differential in situ stress. The influence of these factors on the complexity and scale of the fracturing region is also discussed.",7,7,7
Shale Gas,Proppant,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Shale Gas,Proppant,"Voltolini, Marco; Ajo-Franklin, Jonathan",Evolution of propped fractures in shales: The microscale controlling factors as revealed by in situ X-Ray microtomography,Proppant; Fractures; Tight oil and gas shales; X-ray microtomography; Permeability,GAS; CONDUCTIVITY; CHALLENGES,"The behavior of proppant at the microscale during fracture closure in oil and gas shales is not yet well understood. In this context, we used a combination of dynamic synchrotron X-ray micro computed tomography with morphometric analysis and flow modeling to provide new insight into the dominant physical processes acting at the microscale during fracture closure, and understand their impact on hydraulic properties of the fracture. The roles of three variables have been investigated in proppant monolayers: i) Shale mineralogy and microstructure; ii) Shale bedding orientation with respect to the fracture plane; iii) Proppant characteristics. Unsurprisingly, all three variables have an impact on the permeability evolution during closure and their extent has been quantified via Stokes flow simulations. For the fracture geometry considered, proppant rearrangement during loading is the leading cause of permeability loss. The mechanical strength of proppant and shale becomes important at the later stages of the fracture closure. Bedding orientation has an impact on the mechanical response of the proppantshale contact areas. The more regular morphology and higher mechanical strength of ceramic proppant allows to maintain a better permeability throughout the whole fracture evolution cycle when compared to quartz sand. This combined analysis approach allowed us to understand and quantify the processes involved during the closure of a propped fracture and to directly link them to the evolution of morphology and hydraulic properties. A better understanding of the contributions of these processes could ultimately help in the design and optimization of proppants, enabling more efficient extraction of hydrocarbons from unconventional systems.",10,10,2
Shale Gas,Drilling Fluid,"Paswan, Bhola K.; Mahto, Vikas",Development of environment-friendly oil-in-water emulsion based drilling fluid for shale gas formation using sunflower oil,Surfactant synthesis; Rheology; Filtration properties; Zeta potential; Contact; Angle; Interfacial tension,TRIBOLOGICAL PROPERTIES; RHEOLOGICAL PROPERTIES; SURFACTANT; POLYMER; BENTONITE; BEHAVIOR; ADSORPTION; PARTICLES; STABILITY; WEIGHT,"Mineral oils are frequently used for the making of synthetic-based drilling fluids. However, there are several downsides associated with these oils. These mineral oils are non-renewable, toxic in nature, non-biodegradable and prompting towards the incredible expense of waste treatment. In this research article, an anionic surfactant sodium methyl ester sulfonate (SMES) was synthesized using sunflower oil. SMES is then used to formulate environment-friendly oil-in-water emulsion-based drilling fluid. The synthesized surfactant is characterized by FT-IR, H-1-NMR and TGA analysis. The effect of xanthan gum (XG), bentonite, and sodium methyl ester sulfonate (SMES) on the rheology and filtration characteristics of developed emulsion based drilling fluid was analyzed thoroughly. The developed emulsion based drilling fluid had lower friction coefficient in case of oil concentration compared to SMES concentration. The zeta potential has been measured to check the emulsion stability and it has been attended that an increase in the concentration of SMES (0.3-0.7 wt/v %) and xanthan gum (0.2-0.6 wt/v %) has improved the stability of the emulsion. The contact angle and interfacial tension were analyzed and it was observed that interfacial tension was reduced from 102.5 to 25.35 mN/m and contact angle increased from 32.5 degrees to 92.3 degrees. The thermal stability of oil-in-water emulsion based drilling fluid was maintained up to 140 degrees C.",14,14,2
Shale Gas,Drilling Fluid,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Shale Gas,Cement,"Xi, Yan; Li, Jun; Tao, Qian; Guo, Boyun; Liu, Gonghui",Experimental and numerical investigations of accumulated plastic deformation in cement sheath during multistage fracturing in shale gas wells,Multistage fracturing; Accumulated plastic deformation; Cyclic loading; Cement sheath integrity,CASING DEFORMATION; INTEGRITY; PRESSURE; INTERFACE,"Sustained Casing Pressure (SCP) has become a serious problem in the development of shale gas fields, which is believed to relate to the multistage fracturing. However, few researches were on this, especially the study of micro-annulus at the interface between the cement sheath and casing, which was one of the mechanisms of the cement sheath integrity failure, and always caused by accumulated plastic deformation. This paper presented experimental and numerical investigations of the emergence and development of plastic deformation occurred at the interface between the cement sheath and casing during multistage fracturing. Mechanical tests and physical simulation experiments were carried out so as to analyze the plastic deformation variation characteristic of the cement sheath under cyclical loading and unloading. 3-D numerical models were established to analyze the emergence and development of the accumulated plastic deformation based on the test results, considering the actual engineering and geological conditions during multistage fracturing in shale gas wells, which presented a new method to calculate the width of the micro-annulus between the cement sheath and casing. The research showed that the numerical results were in accordance with the experimental results. With the increase of cycle times, the accumulated plastic deformation increased, which was the greatest for the first time, and then increased linearly. Decreasing elastic modulus and increasing Poisson's ratio, cohesive force and internal friction angle could facilitate the protection of the cement sheath integrity. Finally, a new cement slurry system was proposed based on the results of study and applied in 5 wells with good effects acquired, none of them showed SCP after fracturing.",12,13,2
Shale Gas,Cement,Deng Kuanhai; Yuan Yue; Hao Yi; Li Zhonghui; Lin Yuanhua,Experimental study on the integrity of casing-cement sheath in shale gas wells under pressure and temperature cycle loading,Casing-cement sheath; Full-scale integrity test; Temperature cycle loading; Pressure cycle loading; Interface mechanical properties; Multistage hydraulic fracturing,ZONAL ISOLATION; FAILURE; MODEL,"During large-scale multistage hydraulic fracturing in shale-gas wells, the cement sheath loses its integrity easily because of repeated temperature and pressure variations in the wellbore. This is likely to form a potential leak path, subsequently leading to the loss of zonal isolation and sustained casing pressure. To prevent such barrier failures, it is crucial to investigate and understand the failure mechanism of cement sheath. In this study, an experimental apparatus and evaluation method of the sealing integrity and mechanical integrity for casing-cement sheath under temperatures and pressures cycle loading have been presented in this paper by which sixteen groups of full-scale integrity tests of general and high-strength cement sheath have been conducted under temperature ranging from 30 to 150 degrees C and pressure ranging from 0 to 70 MPa cycling loading. The anti-channeling/sealing performance and interface mechanical behavior of casing-cement sheath are measured and characterized respectively under different loading-unloading methods. The cycle numbers required for sealing integrity failure of cement sheath under different cyclic temperatures and pressures have been obtained. The interface mechanical properties (cementing force, friction force, shearing strength and lateral bonding strength) of cement sheath have been obtained, and effects of alternating temperatures and pressures on those mechanical properties and late integrity have been analyzed. Research results can provide a very important reference for the fracturing design of shale-gas wells.",8,8,6
Drilling,Cutting,"Zhu, Wenxi; Zheng, Xiuhua; Li, Guomin","Micro-bubbles size, rheological and filtration characteristics of Colloidal Gas Aphron (CGA) drilling fluids for high temperature well: Role of attapulgite",Attapulgite; colloidal gas aphron drilling fluid; Aphron size distribution; Rheology; Filtration loss; Fluid loss control mechanism,STABILITY; SURFACTANT; BEHAVIOR; SYSTEM,"Colloidal Gas Aphron drilling fluids have been successfully applied in petroleum industry to drill low pressure formations and depleted reservoirs. As the increase of drilling depth and reservoir temperature, characteristics of CGA drilling fluids at high temperature are more concerned, yet less investigated. In this paper, attapulgite with better performance at high temperatures was selected to prepare CGA drilling fluids and the bubbles size distribution, rheological and fluid loss performance at 25 degrees C/90 degrees C/120 degrees C/150 degrees C/180 degrees C were studied. CGA fluid with Xanthan gum and 3% bentonite were prepared and tested as control group. Result indicates that: 1) The addition of attapulgite significantly reduces the average diameter of aphrons and improves the bubble size distribution of CGA fluids, which is conducive to the stability of CGA fluids; 2) Attapulgite effectively increases low shear rate viscosity (LSRV) of CGA fluid at room temperature, which will help to carry cuttings and seal formation. Power law model is the optimal model to describe the rheological behaviors of attapulgite-based CGA drilling fluids. Rheological parameters of Power law model show that the tested fluids have a shear thinning behavior at all temperatures and the flow behavior index can be controlled to an appropriate range by adjusting the amount of attapulgite; 3) Attapulgite greatly reduces the fluid loss of CGA drilling fluid, especially at high temperature. The attapulgite-based CGA drilling fluids can maintain an acceptable fluid loss (within 15 mL) for drilling operations at 120 degrees C. At 150/180 degrees C, 3% attapulgite exhibited the lowest fluid loss volume, which is reduced by 46.7%/25% as compared to 3% bentonite. In addition, the mechanism of attapulgite-based CGA fluid loss control was studied and can be concluded as the ""embedded"" mud cake structure composed by aphrons and attapulgite.",14,15,3
Drilling,Cutting,"He, Mingming; Li, Ning; Zhu, Jiwei; Chen, Yunsheng",Advanced prediction for field strength parameters of rock using drilling operational data from impregnated diamond bit,Analytical model; Rock strength parameters; Impregnated diamond bit; Drilling logging data,TOOTH WEAR; ROLLER-BITS; DRAG BITS; CUTTER; MODEL,"Field drilling can be a continuous, fast, and reliable technology to predict the cohesion, internal friction angle, and unconfined compressive strength (UCS) of rock in petroleum engineering. Herein, a theoretical model is established in an impregnated diamond bit considering some effective parameters including friction parameter, crushed zone, and bit geometry parameter. A novel method is proposed to determine field strength parameters including the cohesion, internal friction angle, and UCS of four types of rock using drilling logging data. Many drilling experiments in the field are conducted using a drilling process monitoring apparatus to obtain drilling logging data (thrust force, torque, penetration rate, and rotation speed). Experimental results on weak, medium-strong, and strong rock show that drilling with an impregnated diamond core bit includes two fully dependent and simultaneous processes: rock cutting and frictional contact, the dominant role of which is dependent on the cutting point. The cohesion, internal friction angle, and UCS estimated from the proposed method for the four types of rocks are close to those from standard laboratory tests. This practical method can provide practical, fast, and reliable estimation for field strength parameters of rock and should be highly beneficial to field applications in rock engineering.",11,12,11
Drilling,Cutting,"Busch, Alexander; Johansen, Stein Tore",Cuttings transport: On the effect of drill pipe rotation and lateral motion on the cuttings bed,Cuttings transport; Hole cleaning; Drilling; CFD; Rotation; Whirling; Orbital motion,NON-NEWTONIAN FLUID; ECCENTRIC ANNULI; PRESSURE LOSSES; ORBITAL MOTION; TURBULENT-FLOW; INNER-CYLINDER; KINETIC-THEORY; GRANULAR FLOW; LAW; SIMULATION,"Drill pipe rotation is considered a relevant factor for cuttings transport and hole cleaning. However, in the term ""rotation"" is often used as a moniker for the combination of plain drill pipe rotation around its own axis and more complex lateral motion, as many laboratory setups feature an unconstrained drill string. Lateral motion is generally considered to benefit the transports of cuttings due to increased bed agitation. By means of Computational Fluid Dynamics, we have investigated the effect of synchronous and asynchronous whirling drill string motion on the cuttings bed and cuttings transport for water and a more viscous, shear-thinning fluid using the Two Fluid Model in conjunction with the Kinetic Theory Of Granular Flows and closures from soil mechanics to rheologically describe granular matter. The dynamic mesh capability of ANSYS Fluent R17.2 is exploited to account for the orbital motion of the drill string. In addition, three base cases (negative eccentric, concentric, and positive eccentric) are investigated for comparison. Whirling motion helps tremendously to disperse the solids into the main flow region and hence improves the quality of cuttings transport and hole cleaning, with synchronous whirl by far outperforming asynchronous whirl due to the cumulative tangential and radial velocities. The effect is much more prominent for water than for the more viscous, shear-thinning fluid because the latter already shows a comparatively good cuttings transport performance. Moreover, in case of the more viscous, shear-thinning fluid, the positive eccentric annulus provides an even better cuttings transport capability, if comparison is made on equivalent pressure gradients. Because of the higher viscosity level, the whirling motion reduces the axial throughput, which despite the increased bed agitation results in worse performance compared to the positive eccentric case.",11,12,4
Drilling,Cutting,"Mansour, Ahmed; Gentzis, Thomas; El Nady, Mohamed M.; Mostafa, Fatma; Tahoun, Sameh S.","Hydrocarbon potential of the Albian-early Cenomanian formations (Kharita- Bahariya) in the North Western Desert, Egypt: A review",Abu gharadig basin; Shushan basin; Matruh basin; Thermal maturity; Depositional paleoenvironment; Burial history,ABU-GHARADIG BASIN; SOURCE ROCKS; SHUSHAN BASIN; DEPOSITIONAL-ENVIRONMENTS; PETROLEUM GENERATION; WELLS; OIL; SUCCESSION; EVOLUTION; SYSTEMS,"Rock-Eval pyrolysis/TOC, petrographic, and geochemical data available in the public domain for a total of 296 core and 243 drill cuttings samples from the Albian-early Cenomanian Kharita and Bahariya formations of four main basins, Shushan, Abu Gharadig, Matruh and Dahab-Mireir, were reviewed. This review provides a comprehensive overview to understand the organic richness, type, and thermal maturity of potential source rock intervals within the Kharita and Bahariya formations in northern Egypt by means of burial history modeling and oil -in -place calculations. Geochemical data of both formations confirmed the presence of up to excellent source rocks of varied kerogen types but mainly of Type III (gas -prone) and mixed types II/III. Thermal maturity levels ranged from immature to the early stage of oil window, although some intervals reached the peak oil window in the Abu Gharadig and Shushan basins compared to their counterparts. The depositional paleoenvironment of the Kharita and Bahariya formations is interpreted based on the organic biomarker compounds and palynofacies associations. Generally, both formations in the four basins were inter- preted to accumulate in a fluvio-deltaic to marginal marine setting, although the Kharita rock unit was slightly less marine based on the isoprenoids pristane and phytane to nC 17 and nC 18 ratios. The ratio of 22S/(22S ? 22R) for the homohopanes C 31 and C 32 of Kharita oils from the Shushan Basin ranged from 0.50 to 0.60, indicating marginally mature to the onset of oil generation. However, common amongst much of the previous studies was the notable differences in organic matter contents, thermal maturity levels and hydrocarbon potential. Environmental and ecological processes, including proximity to shoreline, terrestrial/riverine input, oxygenation levels and water column conditions, are consid- ered the primary drivers that triggered variable amounts of organic carbon accumulation. While differences in thermal maturity levels were attributed to tectonic activities and related structural processes.",11,11,2
Drilling,Cutting,"Tong, Tran A.; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",Numerical simulation of non-Newtonian fluid flow in partially blocked eccentric annuli,Numerical simulation; Non-Newtonian fluid; Eccentricity; Obstructed annuli; Pressure loss gradient,,"A cuttings bed formed on the lower side of the wellbore is the most common drilling problem confronted when horizontal or highly deviated wells are drilled. The phenomenon is undesirable and has a detrimental effect on wellbore hydraulics and drilling performance. To achieve an efficient drilling operation, hydraulics optimization should be implemented by precisely predicting annular pressure loss and other hydraulic parameters. The accumulation of cuttings at the lower side of horizontal or highly inclined wellbores, combined with wellbore eccentricity and fluid rheological properties, create a complex behavior of pressure loss. In this study, a numerical approach is used to investigate the influence of the aforementioned factors. A numerical solution is performed for laminar flow of non-Newtonian fluids. A non -orthogonal, boundary-fitted curvilinear coordinate is developed, which is based on elliptic partial differential equations (PDE) to accommodate annular flow geometry with arbitrary cross-sections. Finite difference numerical schemes adapted to the coordinates is then used to analyze the problem. The numerical model determines the effect of hydraulic parameters of fluid flow thorough an irregularly shaped annulus and considers the following factors: flow rate, fluid rheological parameters, annular geometry and bed appearance. Numerical predictions from the model are verified against existing models and experimental data in literature; and good agreements are obtained. The developed numerical model can be combined with a 1-D solids transport model for designing oil and gas well drilling operations.",11,11,0
Drilling,Cutting,"Gao, Mingyang; Zhang, Kai; Zhou, Qin; Zhou, Huifeng; Liu, Baolin; Zheng, Guojing",Numerical investigations on the effect of ultra-high cutting speed on the cutting heat and rock-breaking performance of a single cutter,Ultra-high-speed cutting; Thermal elastoplastic damage model; Rock-breaking mechanism; Cutting heat,DRILLING RESPONSE; BIT; SIMULATION; SURFACE; FORCE; MODEL,"As a new drilling technology, the ultra-high-speed diamond drilling can exhibit great superiority in drilling deep hard rock, which can achieve high rates of penetration (ROP) with substantially lower energy and load. In order to better understand the removal mechanism, the effect of ultra-high cutting speed on the cutting heat and rock-breaking performance of a single cutter was investigated by using ABAQUS software. A thermal elastoplastic damage model has been established by using a finite element analysis system aiming at the linear cutting operations. The changes of stress state, strain accumulation, and heat migration in the tool unit were analyzed. The results show that when the cutting speed exceeds 8 m/s, the heat flux and mechanical specific energy (MSE) decrease as the rotary speed (RPM) increases. That is, when cutting at ultra-high linear speed (>8 m/s), more input energy was used to break rock. In addition, when the cutting speed is in the ultra-high-speed stage and continues to increase, the proportion of brittle failure of the rock will gradually increase, and a new balance will not be reached until the cutting speed reaches 12 m/s, which helps to improve the rock breaking efficiency.",9,9,14
Drilling,Cutting,"Zhang, Zengzeng; Zhao, Dajun; Zhao, Yan; Zhou, Yu; Tang, Qiongqiong; Han, Junpeng",Simulation and experimental study on temperature and stress field of full-sized PDC bits in rock breaking process,Full-sized PDC bits; Temperature field; Stress field; Finite element simulation,THERMAL RESPONSE; CUTTERS; FORCE; WEAR; REDUCTION; FRACTURE; FATIGUE; SURFACE; STATE; MODEL,"The failure rate of polycrystalline diamond compact (PDC) bits mainly depended on the cutting temperature and the force of the cutting teeth. It was of great value to study the distribution of temperature and stress fields on the PDC cutting teeth during rock breaking for exploring the failure mechanism and improving the service life of the bits. In this paper, the finite element was used to simulate the thermal-structural coupling of rock breaking process of the full-sized PDC bits. The simulation results show that the high temperature region of the cutting teeth was offset from the top of the crown to the outside of the cutting teeth during drilling process, and the high temperature region of the cutting teeth was fan-shaped. The failure reason of PDC cutting teeth was analyzed by simulation. The maximum principal stress of PDC cutting teeth existed in the interface between the polycrystalline diamond (PCD) layer and the cemented carbide (WC-Co) substrate, fracture and delamination were concentrated at the top of the cutting teeth crown. The experimental results show that the temperature of cutting teeth when drilling the granite was about 2 times that of the marble and 3 times that of the sandstone under the same conditions. The simulation results were basically consistent with the experimental results, which verified the accuracy of the finite element model simulation analysis method.",8,9,11
Drilling,Cutting,"Xiong, Chao; Huang, Zhongwei; Yang, Ruiyue; Sheng, Mao; Shi, Huaizhong; Dai, Xianwei; Wu, Xiaoguang; Zhang, Shikun",Comparative analysis cutting characteristics of stinger PDC cutter and conventional PDC cutter,Stinger PDC cutter; Cutting characteristics; Single cutter tests; Rock-breaking mechanism,ROCK; TEMPERATURE; BREAKING; GRANITE; SURFACE; FORCE,"The Stinger PDC cutter has a better performance than the conventional PDC cutter drilling for hard, interbedded and highly abrasive rocks. Although researchers have investigated the cutter's characteristic, such as impact resistance, wear resistance and cutter's life, the cutting behaviors of the Stinger PDC cutter still remains unclear. In this study, the single cutter tests were carried out with a Stinger PDC cutter and a conventional PDC cutter as comparisons. The cutting force, cuttings size, surface topography along the cutting trajectory and microscopic morphology of the fracture surface were compared and analyzed. The results show that the average cutting force of a Stinger PDC cutter is 46.14% lower than that of a conventional PDC cutter. The proportion of large cuttings (r > 2.36 mm) generated in the Stinger PDC cutter test is higher than that in the conventional PDC cutter test. In addition, the energy consumption of breaking rocks by a Stinger PDC cutter is 34.09% lower than that by a conventional PDC cutter. The cutting trajectory in the Stinger PDC cutter test has a ""V"" shape and the surface is relatively rough (Sa = 617.08 mu m), while the conventional PDC cutter produces a ""U"" shape cutting trajectory and the surface is relatively smooth (Sa = 462.18 mu m). Furthermore, the SEM analysis shows that the Stinger PDC cutter breaks granite mainly by tensile stress, which is different with the conventional PDC cutter by shear stress. The key findings of this work will help to reveal the rock-breaking process and mechanism with the Stinger PDC cutters.",8,8,7
Drilling,Cutting,"Mazen, Ahmed Z.; Mujtaba, Iqbal M.; Hassanpour, Ali; Rahmanian, Nejat","Mathematical modelling of performance and wear prediction of PDC drill bits: Impact of bit profile, bit hydraulic, and rock strength",PDC cutters wear; Mechanical specific energy; Depth of cut; Effective blades; ROP,CUTTER,"The estimation of Polycrystalline Diamond Compact (PDC) cutters wear has been an area of concern for the drilling industry for years now. The cutter's wear has been measured practically by pulling the bit out for evaluation at the surface. It is important to find the right time for tripping out as this helps to avoid the fishing job and reduces the operational cost significantly. The prediction of the drilling performance is based on the interaction of cutter and rock. Several authors focused on the cutter-rock interface but only a few researchers tried to model the wear of the PDC bit cutters. The aim of this research is to understand the relationships between the rate of penetration (ROP) and the drilling variables per each foot, and then determine the overall bit efficiency for the whole drilling operation. A new mathematical model is derived to predict the PDC bit performance by considering the factors that were already not taken into account. These factors include rock strength, bit design, and bit hydraulic. The model investigates the effect of these parameters to estimate the abrasive cutters wear on the inner and the outer bit cones by deriving modified equations to calculate the mechanical specific energy (MSE), torque, and depth of cut (DOC) as a function of effective blades (EB). The model is used to forecast the bit cutters wear conditions in four wells in the oil fields located in Libya, which were drilled with three different PDC's sizes. The model enables the results to be compared to the actual bit cutters wear measured for inner and outer cones. The results are found that are well in agreement with the actual field data obtained in bit records.",8,8,4
Drilling,Cutting,"Rossi, Edoardo; Jamali, Shahin; Schwarz, Dennis; Saar, Martin O.; von Rohr, Philipp Rudolf",Field test of a Combined Thermo-Mechanical Drilling technology. Mode II: Flame-assisted rotary drilling,Deep resource; Granite; Thermally assisted drilling; Field demonstration; Drilling performance; Acoustic emission,SIZE REDUCTION RELATIONSHIPS; ACOUSTIC-EMISSION; HIGH-TEMPERATURE; MECHANICAL-BEHAVIOR; PENETRATION RATE; THERMAL-DAMAGE; ROCK; ENERGY; VELOCITY; GRANITE,"To enhance the drilling performance in deep hard rocks and reduce overall drilling efforts, this work proposes a Combined Thermo-Mechanical Drilling (CTMD) technology. This technology employs a heat source (e.g., a flame jet) and includes two main drilling modes: (I) thermal spallation drilling, investigated in the companion paper and (II) flame-assisted rotary drilling, investigated here as a field test. The CTMD technology is expected to reduce drilling efforts, especially in hard rocks, enhancing the rock penetration rate and increasing the bit lifetime, all of which reduces the drilling costs. The present work investigates Mode II (flame-assisted rotary drilling) of the CTMD technology by implementing the concept in an existing drilling rig and testing the technology under relevant process conditions. This contribution studies the underlying rock removal mechanism of CTMD and demonstrates its drilling performance, compared to conventional rotary drilling methods. Acoustic emission monitoring, and analysis of the collected drill cuttings provide multiple evidences for thermal-cracking-enhanced rock removal during the flame-assisted rotary drilling. This removal mechanism appears to represent an optimal compromise to minimize rock fragmentation and cutting transport efforts during drilling, compared to a less efficient mechanical scraping of the hard granite rock, observed during the standalone-mechanical drill test. The drilling performance, in terms of removal and wear rates, are evaluated for the flame-assisted rotary drilling. This shows that the proposed drilling approach is capable of enhancing the removal process in hard granite rock, by a factor of 2.5, compared to standalone-mechanical drilling. The implementation of this drilling approach into a conventional drilling system shows that integration of thermal assistance to conventional rotary drilling requires marginal technical efforts. Additionally, this technology can profit from established knowledge in conventional mechanical drilling, facilitating its implementation to improve drilling performance in hard rocks. Hence, this study demonstrates that the Combined Thermo-Mechanical Drilling method is feasible and concludes that this technology constitutes a promising approach to improve the drilling process, thereby increasing the viability of accessing deep geo-resources in hard rocks.",8,8,3
Drilling,Cutting,"Vaziri, Ehsan; Simjoo, Mohammad; Chahardowli, Mohammad",Application of foam as drilling fluid for cuttings transport in horizontal and inclined wells: A numerical study using computational fluid dynamics,Cuttings transport; Foam; Horizontal well; Inclined well; Computational fluid dynamics,ROTATION,"Proper hole-cleaning is an important part of drilling operations. Foam with a low density and a high apparent viscosity could be considered as a good candidate for cuttings lifting and transportability. This paper aims to investigate the potential of foam for drilling cuttings transport in inclined and horizontal wells by performing a simulation study. To this end, a computational fluid dynamics (CFD) approach was used to simulate foam flow for cuttings transport by employing Eulerian multi-phase model. Foam rheology was expressed using a non-Newtonian power law model. A detailed sensitivity analysis including the effect of foam quality, foam injection velocity, well inclination, pipe eccentricity and pipe rotation on the cuttings transport efficiency was presented. The simulation results were also validated by a series of previously reported laboratory-scale experiments. Numerical results showed that by increasing foam quality from 70 to 90% at an injection velocity of 5 ft/s in a horizontal well condition, in-situ cuttings concentration decreased by 1.3 times. Also, increase of the foam injection velocity from 3 to 5 ft/s at a foam quality of 90% exhibited a positive impact on the cuttings transport efficiency. This was mainly due to the foam capability to remove stationary cuttings bed. Numerical results also showed that increase of well inclination led to a formation of a static cuttings bed. As to the results, increase of well inclination angle from vertical position to 30 degrees caused an increase in in-situ cuttings concentration by 3.6 times. Moreover, results revealed that pipe eccentricity led to inefficient cuttings transport and thus resulted in cuttings accumulation in wellbore. However, pipe rotation improved cuttings transport efficiency due to an asymmetric distribution of cuttings bed through the annulus.",8,8,2
Drilling,Cutting,"Oseh, Jeffrey O.; Norddin, M. N. A. Mohd; Ismail, Issham; Gbadamosi, Afeez O.; Agi, Augustine; Ismail, Abdul R.",Experimental investigation of cuttings transportation in deviated and horizontal wellbores using polypropylene-nanosilica composite drilling mud,Deviated; Horizontal wellbores; Cuttings transportation; Polypropylene-nanosilica composite; Rheological properties; Drilling fluids,SILICA NANOPARTICLES; PERFORMANCE; FLUIDS; BEADS; POLYETHYLENE; ROTATION; DENSITY,"The experience acquired in the field showed that poor cuttings transportation results in several drilling problems, such as pipe sticking, undue torque and drag, hole-pack off, or lower than projected drilling performance. In this study, complex water-based mud (WBM) formulated with polypropylene-nanosilica composite (PP-SiO2 NC) and partially hydrolyzed polyacrylamide (PHPA), a drag-reducing agent were used to examine cuttings transferring efficiencies (CTEs). The examination focused on the impact of diameters of cuttings (between 0.50 and 4.00 mm), hole angles (45, 60, 75, 901, mud velocities (between 0.457 and 1.80 m/s) and different concentrations (0.4, 0.5, 0.8 and 1.2 ppb) of PP-SiO2 NC and PHPA. A field-oriented cuttings transport flow loop of dimensions (69.85 mm x 26.67 mm, 6.07 m-long annulus) was constructed to determine the CTEs of the drilling muds. Results showed that smallest cuttings were easiest to remove when mud velocities of 0.457, 0.630, 0.823 and 0.960 m/s were used, but when the velocity increased to 1.80 m/s, the transport of largest cuttings became the easiest. Results also confirmed that PP-SiO2 NC muds are more capable of transferring cuttings than PHPA mud samples with or without pipe rotation speed due to increased colloidal forces that increase the interaction between cuttings and PP-SiO2 NC particles. Rotation of drill pipe and an increase in mud velocity will effectively increase the drag effects, which will lead to increased CTE. Hole angle 45 degrees was the most difficult inclination in the cuttings transport process due to the higher settling tendency of cuttings on the low side of the hole. The application of complex WBM with PP-SiO2 NC showed promising attributes in a cuttings transport process.",8,8,0
Drilling,Fluid Loss,"Vipulanandan, C.; Mohammed, A.",Effect of drilling mud bentonite contents on the fluid loss and filter cake formation on a field clay soil formation compared to the API fluid loss method and characterized using Vipulanandan models,Fluid loss; Bentonite; Soil formation; Filter cake; Vipulanandan models,PIEZORESISTIVE BEHAVIOR; ELECTRICAL-RESISTIVITY; RHEOLOGICAL PROPERTIES; SMART,"Quantification of fluid losses and filter cake formations during the drilling operations using water-based muds (WBM) are some of the critical issues related to successful operations. In this study, short term (30 min) and long term (420 min) fluid loss tests on the drilling mud with various amounts of bentonite contents were performed using the API fluid loss device with filter paper and compared it to the field clay soil (porous media) at a pressure of 100 psi (0.69 MPa). The permeability of the saturated clay soil was 0.026 mD, representing a porous formation. Bentonite content in the drilling mud was varied from 2% to 8% (by the weight of water). The field soil and bentonite were characterized using the particle size distribution and X-ray diffraction (XRD) analyses. Bentonite particle size distribution was finer than the field clay soil. Vipulanandan correlation model predicted the changes in the permeability with time in the clay soil with the filter cake formation very well. With the API fluid loss study, the long-term (420 min) fluid losses were about 2.5-4 times greater than the standard fluid loss study of 30 min (short-term). The filter cake thickness was high with the soil formation compared to the API method. Also, the fluid loss per unit area with the API method was higher than the clay soil formation agreeing with the observed differences in the filter cake thicknesses. The Vipulanandan fluid loss model predictions were compared to the API model and it predicted both short term and long term fluid losses very well based on the root mean square error (RMSE) values. Also, the Vipulanandan fluid loss model predicted the maximum fluid losses under various testing conditions.",30,30,8
Drilling,Fluid Loss,"Ershadnia, Reza; Amooie, Mohammad Amin; Shams, Reza; Hajirezaie, Sassan; Liu, Yuanhong; Jamshidi, Saeid; Soltanian, Mohamad Reza",Non-Newtonian fluid flow dynamics in rotating annular media: Physics-based and data-driven modeling,Pressure loss ratio; Non-Newtonian fluid; CFD; LSSVM; Rotating Couette flow,SHEAR-THINNING FLUIDS; LAMINAR-FLOW; ECCENTRIC ANNULI; STROUHAL NUMBERS; PRESSURE LOSSES; OIL; CYLINDER; CFD; OPTIMIZATION; TRANSPORT,"A thorough understanding and accurate prediction of non-Newtonian fluid flow dynamics in rotating annular media are of paramount importance to numerous engineering applications. This is in particular relevant to oil and gas industry where this type of flow could occur during, e.g., drilling, well completion, and enhanced oil recovery scenarios. Here, mathematically we report on physical-based (numerical) and data-driven (intelligent) modeling of three-dimensional laminar flow of non-Newtonian fluids driven by axial pressure gradient in annular media that consist of a coaxially rotating inner cylinder. We focus on the dynamics of pressure loss ratio (PLR)-the ratio of total pressure loss in presence of rotation to that in stationary condition. We develop a novel and computationally efficient machine-learning based predictive model based on a Least Square Support Vector Machine (LSSVM) optimized with a Coupled Simulated Annealing (CSA) algorithm, which is trained and tested by 730 experimental data collected for this study. We then perform numerous CFD simulations governed by Navier-Stokes set of equations, which correspond to each of the experimental cases. Comparing the results with those obtained from a widely used empirical correlation for PLR, we find that the both of our numerical and machine-learning based models are more accurate and present a larger applicability domain. The predictive LSSVM model enjoys a supervised learning paradigm and leads to the highest accuracy, while the physically originated CFD approach captures more consistently the nonlinear behavior of PLR versus key system features. Following the validation of our models, we study the less understood effects of fluid viscosity, axial velocity and rotational velocity on PLR dynamics. We employ a dimensionless parameter analogous to Strouhal number and identify specific regimes where PLR shows a distinct behavior. Our study elucidates the role of shear-thinning effect and its interplay with inertial forces on the dynamical behavior of pressure loss (ratio) in rotating yield-power-law fluids.",20,20,8
Drilling,Fluid Loss,"Mao, Hui; Yang, Yan; Zhang, Hao; Zheng, Jie; Zhong, Ying",Conceptual design and methodology for rheological control of water-based drilling fluids in ultra-high temperature and ultra-high pressure drilling applications,Water-based drilling fluid; Rheological control methodology; Particle dense packing; Weighting particles; Deep well drilling; Ultra-high temperature and ultra-high pressure,FILTRATION PROPERTIES; SILICA NANOPARTICLES; OXIDE NANOPARTICLES; PERFORMANCE; COMPOSITE; MODIFIER; MUDS,"A new concept for the design and development of ultra-high temperature and ultra-high pressure water-based drilling fluid (ultra-HTHP WBDF), based on particle dense packing theory and suitable for ultra-HT (205-260 degrees C) and ultra-HP (138-241 MPa) drilling applications is proposed in this study. The concept for the rheological control of ultra-HTHP WBDF can be concluded as that the drilling fluid would have the highest possible density and the best fluidity when the mix of weighting agent particles of variable density, size and size distribution form the closest packing. An experimental study was conducted to verify the new concept by investigating how the weighting agent particle density, size and size distribution affect the rheological properties, filtration loss and sagging characteristics of WBDF designed for ultra-HTHP drilling applications. The ultra-high density (ultra-HD) WBDFs were formulated according to this concept by using the optimum mixtures of the weighting agents, which include industrial ferroferric oxide, barite and ultrafine barite. The laser particle size analysis technique was used to determine particle size and size distribution in different drilling fluid samples. The sagging characteristics of the drilling fluids were determined by using the Static Sagging Test method. Test results of the fluids formulated according to particles dense packing theory confirmed that rheological properties, filtration loss and sagging characteristics and density limit of the drilling fluid were all significantly influenced by the variation of the particle size, size distribution and the packing of the weighting agents, which indicated that the non-structural viscosity caused by the interactions among the weighting agent particles such as friction and collision dominantly controlled the rheological properties of ultra-HTHP WBDF. Finally, a new methodology for rheological control of ultra-HTHP WBDF was proposed, which can be summarized as using all means and methodologies to drive the dispersion state of solid weighting agent particles in ultra-HTHP WBDF to be at a more discrete state. By proper selection of the weighting agent particle size and size distribution, it was possible to form a thin, dense mud cake, which was conducive to decrease the filtration loss. Moreover, results have also shown that rheological properties, filtration loss and sagging characteristics of ultra-HT-HP WBDF can be effectively controlled by using three or even more different types of weighting agents with varying density, particle size and size distribution.",14,14,4
Drilling,Fluid Loss,"Zhu, Wenxi; Zheng, Xiuhua; Li, Guomin","Micro-bubbles size, rheological and filtration characteristics of Colloidal Gas Aphron (CGA) drilling fluids for high temperature well: Role of attapulgite",Attapulgite; colloidal gas aphron drilling fluid; Aphron size distribution; Rheology; Filtration loss; Fluid loss control mechanism,STABILITY; SURFACTANT; BEHAVIOR; SYSTEM,"Colloidal Gas Aphron drilling fluids have been successfully applied in petroleum industry to drill low pressure formations and depleted reservoirs. As the increase of drilling depth and reservoir temperature, characteristics of CGA drilling fluids at high temperature are more concerned, yet less investigated. In this paper, attapulgite with better performance at high temperatures was selected to prepare CGA drilling fluids and the bubbles size distribution, rheological and fluid loss performance at 25 degrees C/90 degrees C/120 degrees C/150 degrees C/180 degrees C were studied. CGA fluid with Xanthan gum and 3% bentonite were prepared and tested as control group. Result indicates that: 1) The addition of attapulgite significantly reduces the average diameter of aphrons and improves the bubble size distribution of CGA fluids, which is conducive to the stability of CGA fluids; 2) Attapulgite effectively increases low shear rate viscosity (LSRV) of CGA fluid at room temperature, which will help to carry cuttings and seal formation. Power law model is the optimal model to describe the rheological behaviors of attapulgite-based CGA drilling fluids. Rheological parameters of Power law model show that the tested fluids have a shear thinning behavior at all temperatures and the flow behavior index can be controlled to an appropriate range by adjusting the amount of attapulgite; 3) Attapulgite greatly reduces the fluid loss of CGA drilling fluid, especially at high temperature. The attapulgite-based CGA drilling fluids can maintain an acceptable fluid loss (within 15 mL) for drilling operations at 120 degrees C. At 150/180 degrees C, 3% attapulgite exhibited the lowest fluid loss volume, which is reduced by 46.7%/25% as compared to 3% bentonite. In addition, the mechanism of attapulgite-based CGA fluid loss control was studied and can be concluded as the ""embedded"" mud cake structure composed by aphrons and attapulgite.",14,15,3
Drilling,Fluid Loss,"Busch, Alexander; Johansen, Stein Tore",Cuttings transport: On the effect of drill pipe rotation and lateral motion on the cuttings bed,Cuttings transport; Hole cleaning; Drilling; CFD; Rotation; Whirling; Orbital motion,NON-NEWTONIAN FLUID; ECCENTRIC ANNULI; PRESSURE LOSSES; ORBITAL MOTION; TURBULENT-FLOW; INNER-CYLINDER; KINETIC-THEORY; GRANULAR FLOW; LAW; SIMULATION,"Drill pipe rotation is considered a relevant factor for cuttings transport and hole cleaning. However, in the term ""rotation"" is often used as a moniker for the combination of plain drill pipe rotation around its own axis and more complex lateral motion, as many laboratory setups feature an unconstrained drill string. Lateral motion is generally considered to benefit the transports of cuttings due to increased bed agitation. By means of Computational Fluid Dynamics, we have investigated the effect of synchronous and asynchronous whirling drill string motion on the cuttings bed and cuttings transport for water and a more viscous, shear-thinning fluid using the Two Fluid Model in conjunction with the Kinetic Theory Of Granular Flows and closures from soil mechanics to rheologically describe granular matter. The dynamic mesh capability of ANSYS Fluent R17.2 is exploited to account for the orbital motion of the drill string. In addition, three base cases (negative eccentric, concentric, and positive eccentric) are investigated for comparison. Whirling motion helps tremendously to disperse the solids into the main flow region and hence improves the quality of cuttings transport and hole cleaning, with synchronous whirl by far outperforming asynchronous whirl due to the cumulative tangential and radial velocities. The effect is much more prominent for water than for the more viscous, shear-thinning fluid because the latter already shows a comparatively good cuttings transport performance. Moreover, in case of the more viscous, shear-thinning fluid, the positive eccentric annulus provides an even better cuttings transport capability, if comparison is made on equivalent pressure gradients. Because of the higher viscosity level, the whirling motion reduces the axial throughput, which despite the increased bed agitation results in worse performance compared to the positive eccentric case.",11,12,4
Drilling,Fluid Loss,"Tong, Tran A.; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",Numerical simulation of non-Newtonian fluid flow in partially blocked eccentric annuli,Numerical simulation; Non-Newtonian fluid; Eccentricity; Obstructed annuli; Pressure loss gradient,,"A cuttings bed formed on the lower side of the wellbore is the most common drilling problem confronted when horizontal or highly deviated wells are drilled. The phenomenon is undesirable and has a detrimental effect on wellbore hydraulics and drilling performance. To achieve an efficient drilling operation, hydraulics optimization should be implemented by precisely predicting annular pressure loss and other hydraulic parameters. The accumulation of cuttings at the lower side of horizontal or highly inclined wellbores, combined with wellbore eccentricity and fluid rheological properties, create a complex behavior of pressure loss. In this study, a numerical approach is used to investigate the influence of the aforementioned factors. A numerical solution is performed for laminar flow of non-Newtonian fluids. A non -orthogonal, boundary-fitted curvilinear coordinate is developed, which is based on elliptic partial differential equations (PDE) to accommodate annular flow geometry with arbitrary cross-sections. Finite difference numerical schemes adapted to the coordinates is then used to analyze the problem. The numerical model determines the effect of hydraulic parameters of fluid flow thorough an irregularly shaped annulus and considers the following factors: flow rate, fluid rheological parameters, annular geometry and bed appearance. Numerical predictions from the model are verified against existing models and experimental data in literature; and good agreements are obtained. The developed numerical model can be combined with a 1-D solids transport model for designing oil and gas well drilling operations.",11,11,0
Drilling,Fluid Loss,"Gul, Sercan; van Oort, Eric",A machine learning approach to filtrate loss determination and test automation for drilling and completion fluids,Machine learning; Drilling fluid automation; Filtrate loss determination,CAKE FILTRATION; NEURAL-NETWORK,"Drilling fluid property characterization currently involves several manually executed analytical tests, conducted in accordance with American Petroleum Institute (API) recommended practices 13B-1 and 13B-2. Standard (API) and high-pressure, high-temperature (HPHT) filter press units are used for filtrate loss (FL) measurements. However, these test methods have certain important disadvantages. FL tests are conducted at standardized conditions that generally do not reflect downhole oil and gas well conditions in terms of downhole pressure, temperature and filter medium encountered, present safety concerns due to their elevated pressure and temperature, and are performed only infrequently by a human mud engineer. The human measurement also introduces concerns around inaccuracies due to inconsistent practices and interpretation bias of the results. In addition, FL measurements are hard to automate given their manual, human-centric operating tasks. In this paper, we investigate if it is really necessary to automate FL measurements, or if the (strictly qualitative) information they provide can be obtained in a smarter, more advanced way. For this purpose, the relationship between fluid properties was investigated in detail using machine learning and deep learning techniques. Random forest (RF), XGBoost (XGB), support vector machine (SVM), multilayer perceptron (MLP) and multi-linear regression models were trained and tested to predict API and HPHT FL of water-based muds (WBM) based on fluid property readings of rheology, density, and temperature. A similar approach was also used for HPHT filtrate loss prediction of oil-based muds (OBM), taking into account their electrical stability and water content. A key advantage of this approach is that these WBM and OBM fluid properties can be obtained in real-time with measurements that are relatively simple and easy to automate (e.g. obtaining fluid density automatically and continuously from a Coriolis mass-flow meter measurement). Thus, real-time assessment of API and HPHT FL becomes possible without ever having to actually carry out any filter press measurements, thereby also eliminating the need to directly automate these measurements. The models were verified by dedicated laboratory experiments. The developed models estimated API and HPHT FL of WBM, and HPHT FL of OBM with mean absolute errors (MAE) of 0.56 ml/30min, 1.15 ml/30min and 0.79 ml/30min respectively, well within the measurement accuracy of the observations by a human mud engineer.",10,10,4
Drilling,Fluid Loss,"Ghayedi, Ali; Khosravi, Arezoo",Laboratory investigation of the effect of GO-ZnO nanocomposite on drilling fluid properties and its potential on H2S removal in oil reservoirs,Graphene oxide/ZnO; Nanocomposite; Drilling fluid; Rheological properties; Filtration rate; H2S removal,ZINC-OXIDE NANOPARTICLES; FILTRATION PROPERTIES; GRAPHENE OXIDE; RHEOLOGICAL PROPERTIES; PERFORMANCE; COMPOSITE; CUO,"Drilling fluid loss is one of the basic problems in the drilling industry, which includes 10 to 20 percent of the cost of a drilling operation. It can cause some complications, such as creation of the water in oil emulsion. Furthermore, the presence of toxic hydrogen sulfide (H2S) gas in the excavation formations and the risk of its transfer to the surface, is a hazard to the health of employees on drilling rigs and causes corrosion of surface and subsurface equipment. In this study, the effect of adding Graphene Oxide-Zinc Oxide (GO-ZnO) nanocomposite on the drilling fluid properties and H2S removal were investigated. First, the GO-ZnO nanocomposite was synthesized. After XRD, SEM and EDS characterization tests and assuring the formation of the nanocomposite, drilling fluid samples were prepared by adding different concentrations of GO-ZnO nanocomposite to the base fluid (used in a real reservoir). Then the rheology, filtration, and gas chromatography tests were performed on various fluid samples. The results indicated desirable increases in the rheological properties such as plastic viscosity (5%-28%), yield point (25%-42%) and gel strength (25%-33%) and a significant decrease in the filtration rate. Besides, the results of the chromatographic tests indicated the ability of GO-ZnO nanocomposite to entirely remove the H2S in 15 min.",9,9,2
Drilling,Fluid Loss,"Dokhani, Vahid; Ma, Yue; Li, Zili; Geng, Tie; Yu, Mengjiao",Effects of drill string eccentricity on frictional pressure losses in annuli,Frictional pressure loss; Eccentricity; Yield-power-law; Numerical modeling; Drilling fluid,NON-NEWTONIAN FLOW; POWER-LAW FLUID; LAMINAR-FLOW; ROTATION; PREDICTIONS; LIQUID; MODEL,"It has been shown that drill pipe eccentricity can significantly reduce the annular pressure losses and must be taken in to account for accurate prediction of equivalent circulating density (ECD). This study investigates effects of axial flow of Yield-Power-Law (YPL) drilling fluid on frictional pressure losses in eccentric annuli. A numerical model is developed to simulate the laminar flow of yield-power-law fluids in eccentric annular geometries. The governing equations are solved numerically using an implicit finite difference method and employing a non-uniform grid distribution system. The numerical solution yields velocity profile in the annular space, which is integrated to obtain the volumetric flow rate. The frictional pressure losses are calculated using an iterative scheme that is based on convergence of the calculated volumetric flow rate to the given flow rate. Comparing the frictional pressure loss predictions of the model with three previous numerical studies indicates an excellent agreement for the case of non-Newtonian fluids. The numerical model is validated through extensive comparisons between the predicted frictional pressure losses and experimental data derived from the literature. Our analysis indicates excellent agreement between the model prediction and the experimental data. The numerical results conclude that the reduction in frictional pressure losses due to eccentricity is more prominent at high radii ratios. Results of extensive simulation scenarios for yield-power-law fluids are fitted using non-linear regression analysis, which provides a new correlation for prediction of frictional pressure losses of yield-power-law fluids in eccentric annuli. Comparing the predictions of the developed correlation with the published correlation in the literature reveals more accurate estimation of frictional pressure losses for the proposed correlation and hence safer controlled drilling operations.",8,8,1
Drilling,Fluid Loss,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Drilling,Horizontal Wells,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Drilling,Horizontal Wells,"Ju, Wei; Niu, Xiaobing; Feng, Shengbin; You, Yuan; Xu, Ke; Wang, Geoff; Xu, Haoran","Present-day in-situ stress field within the Yanchang Formation tight oil reservoir of Ordos Basin, central China",In-situ stress field; Tight oil reservoir; Yanchang formation; Stress regime; Natural fracture; Ordos basin,SEDIMENTARY-ROCKS; LOW-PERMEABILITY; TECTONIC STRESS; STATE; AREA; EXPLORATION; FRACTURES; PATTERN; REGION; ORIENTATIONS,"The present-day in-situ stress field has many important and practical applications during the exploration and development of hydrocarbon resources. The Ordos Basin is a significant petroliferous basin in China, within which, the Yanchang Formation serves as the most significant tight oil reservoir. However, an overview of previous studies indicates that little was known as to the present-day stress state in the Yanchang Formation. Therefore, the present-day stress field in the Yanchang Formation tight oil reservoir of the Ordos Basin is systematically analyzed in this study. The orientation of horizontal maximum principal stress (S-Hmax) within the Yanchang Formation of Ordos Basin ranges between north-northeast-south-southwest-trending (NNE-SSW) and east-northeast-west-southwest-trending (ENE-WSW) based on interpretations of borehole breakouts and drilling-induced fractures from borehole imaging logs. The S-Hmax orientation shows various tendencies in different wells, which may result from differential development in lithology, natural fracture and bedding plane over various regions. The estimated magnitudes of vertical stress (S-v), S-Hmax and horizontal minimum principal stress (S-hmin) in the studied wells indicate that the normal faulting stress regime is dominant within the Yanchang Formation. In addition, the geomechanical assessments of wellbore stability and natural fracture reactivation are also performed. Natural fractures in the Yanchang Formation Chang 7 tight oil reservoir of Ordos Basin are developed striking mainly in the northeast-southwest-trending (NE-SW) and west-northwest-east-southeast-trending (WNW-ESE). Among them, those fractures with NE-SW-trending strikes are more conductive with reference to the present-day stress state, contributing more to tight oil production in the Ordos Basin. In addition, within the Yanchang Formation, if horizontal wells are drilled towards the NNE-SSW-trending to ENE-WSW-trending, they are more likely to have wellbore instability issues. The results in this study provide important geological information for tight oil production in the Yanchang Formation of Ordos Basin.",13,14,3
Drilling,Horizontal Wells,"Tariq, Zeeshan; Mahmoud, Mohamed; Abdulraheem, Abdulazeez; Al-Nakhli, Ayman; BaTaweel, Mohammed",An experimental study to reduce the breakdown pressure of the unconventional carbonate rock by cyclic injection of thermochemical fluids,Unconventional formation; Breakdown pressure; Thermochemical; Cyclic fracturing; Multiple fractures,HYDRAULIC FRACTURE PROPAGATION; SIMULATION; RESERVOIR; OIL,"Commercial production from unconventional reservoirs needs massive fracturing operations. Therefore, long horizontal wells are drilled, and multi-stage fractures are created to achieve the desirable production rates from these reservoirs. One common and major problem in most of the unconventional reservoirs is the high breakdown pressure due to the reservoir tightness. When fracturing these types of rocks, the hydraulic fracturing operation becomes much more challenging and difficult. In some scenarios reaches to the maximum pumping capacity without generating any fractures. In this study, a new approach to reduce the breakdown pressure of tight rocks is introduced and compared with the conventional method of fracturing. The new method incorporates the injection of thermochemical fluid in a series of cycles to create micro- and macro-fractures. The cyclic experiments performed in this study were concluded with the recording of breakdown pressure in each case. The post-treatment analysis using medical Computerized Tomography (CT) showed that multiple fractures were created due to the pressure pulse created in the thermochemical reaction. Results showed that the breakdown pressure of the rock decreases with the increasing number of cycles. The proposed method of cyclic thermochemical fracturing reduced the breakdown pressure by 33% in one-cycle, 41% in two-cycles, 53.5% in three-cycles, and 69% in four-cycles, when compared with conventional method of fracturing. An empirical relationship is also presented between the number of cycles of thermochemical fluid injection and the breakdown pressure of the rock.",12,12,5
Drilling,Horizontal Wells,"Zhang, Fengyuan; Emami-Meybodi, Hamid",Flowback fracture closure of multi-fractured horizontal wells in shale gas reservoirs,Flowback; Multiphase flow; Production data analysis; Fracture closure; Shale reservoirs; Multi-fractured horizontal wells,EARLY-TIME PRODUCTION; MODELING 2-PHASE FLOWBACK; MATERIAL BALANCE EQUATION; RATE-TRANSIENT ANALYSIS; ANALYZING LINEAR FLOW; TIGHT GAS; SEMIANALYTICAL MODEL; LOW PERMEABILITY; BEHAVIOR,"In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties using production data. This paper presents two multiphase flowback models for gas and water phase under boundary dominated flow (BDF) condition by considering gas influx from matrix. In addition, a workflow is proposed to quantitatively evaluate hydraulic fracture closure and fracture properties using both water-phase and gas-phase flowback data. A material balance equation (MBE) is derived to obtain average pressure in the fracture by calculating gas influx from matrix under variable bottomhole pressure (BHP) condition based on Duhamel's principle. The flowback models, average pressure calculation method, and workflow are validated against numerical simulations and applied to an MFHW drilled in Marcellus Shale. The results show that the developed models are capable of predicting fracture properties, and MBE could accurately calculate average pressure in the fracture. Furthermore, the proposed workflow provides quantitative insights into the performance of stimulation jobs by accurately predicting fracture half-length, fracture permeability, and permeability modulus using flowback data. By reconciling flowback analysis with long-term production data analysis, a significant decrease in fracture properties due to fracture closure is observed in the Marcellus MFHW.",12,12,3
Drilling,Horizontal Wells,"Tong, Tran A.; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",Numerical simulation of non-Newtonian fluid flow in partially blocked eccentric annuli,Numerical simulation; Non-Newtonian fluid; Eccentricity; Obstructed annuli; Pressure loss gradient,,"A cuttings bed formed on the lower side of the wellbore is the most common drilling problem confronted when horizontal or highly deviated wells are drilled. The phenomenon is undesirable and has a detrimental effect on wellbore hydraulics and drilling performance. To achieve an efficient drilling operation, hydraulics optimization should be implemented by precisely predicting annular pressure loss and other hydraulic parameters. The accumulation of cuttings at the lower side of horizontal or highly inclined wellbores, combined with wellbore eccentricity and fluid rheological properties, create a complex behavior of pressure loss. In this study, a numerical approach is used to investigate the influence of the aforementioned factors. A numerical solution is performed for laminar flow of non-Newtonian fluids. A non -orthogonal, boundary-fitted curvilinear coordinate is developed, which is based on elliptic partial differential equations (PDE) to accommodate annular flow geometry with arbitrary cross-sections. Finite difference numerical schemes adapted to the coordinates is then used to analyze the problem. The numerical model determines the effect of hydraulic parameters of fluid flow thorough an irregularly shaped annulus and considers the following factors: flow rate, fluid rheological parameters, annular geometry and bed appearance. Numerical predictions from the model are verified against existing models and experimental data in literature; and good agreements are obtained. The developed numerical model can be combined with a 1-D solids transport model for designing oil and gas well drilling operations.",11,11,0
Drilling,Horizontal Wells,"Vaziri, Ehsan; Simjoo, Mohammad; Chahardowli, Mohammad",Application of foam as drilling fluid for cuttings transport in horizontal and inclined wells: A numerical study using computational fluid dynamics,Cuttings transport; Foam; Horizontal well; Inclined well; Computational fluid dynamics,ROTATION,"Proper hole-cleaning is an important part of drilling operations. Foam with a low density and a high apparent viscosity could be considered as a good candidate for cuttings lifting and transportability. This paper aims to investigate the potential of foam for drilling cuttings transport in inclined and horizontal wells by performing a simulation study. To this end, a computational fluid dynamics (CFD) approach was used to simulate foam flow for cuttings transport by employing Eulerian multi-phase model. Foam rheology was expressed using a non-Newtonian power law model. A detailed sensitivity analysis including the effect of foam quality, foam injection velocity, well inclination, pipe eccentricity and pipe rotation on the cuttings transport efficiency was presented. The simulation results were also validated by a series of previously reported laboratory-scale experiments. Numerical results showed that by increasing foam quality from 70 to 90% at an injection velocity of 5 ft/s in a horizontal well condition, in-situ cuttings concentration decreased by 1.3 times. Also, increase of the foam injection velocity from 3 to 5 ft/s at a foam quality of 90% exhibited a positive impact on the cuttings transport efficiency. This was mainly due to the foam capability to remove stationary cuttings bed. Numerical results also showed that increase of well inclination led to a formation of a static cuttings bed. As to the results, increase of well inclination angle from vertical position to 30 degrees caused an increase in in-situ cuttings concentration by 3.6 times. Moreover, results revealed that pipe eccentricity led to inefficient cuttings transport and thus resulted in cuttings accumulation in wellbore. However, pipe rotation improved cuttings transport efficiency due to an asymmetric distribution of cuttings bed through the annulus.",8,8,2
Drilling,Horizontal Wells,"Karthikeyan, G.; Chand, Jagadish; Chatterjee, Rima","Impact of geomechanics in coal bed methane development and production, Barakar coals in central India",Coal permeability; Wellbore stability; Critically stressed fractures; Sohagpur coalfield,IN-SITU STRESS; KRISHNA-GODAVARI BASIN; PORE PRESSURE; FLUID-FLOW; PERMEABILITY; GAS; STRAIN; ORIENTATION; PREDICTION; RESERVOIRS,"Geomechanics plays a critical role in the different stages of coal bed methane (CBM) operations, starting from its development through production to its abandonment as in Sohagpur field of central India. In general, higher gas production has been observed from the coal seams in low-stress regimes compared to high-stress regimes; however, during the CBM development planning, stress information has been overlooked. The need for inclined and horizontal wellbores in coal seams has increased due to their many-fold rise in production when compared to vertical wells with a minimum surface footprint. However, these non-vertical wells have wellbore instability issues leading to high nonproductive time (NPT) during drilling and completion operations. Prolong challenges exist in achieving the desired half-length from hydraulic fracturing (HF) stimulation due to the limited understanding of the stress contrast between target coal and bounding lithology. The permeability of the coal reservoir varies greatly during depletion due to the combined effects of effective stress and matrix shrinkage. These effects directly impact productivity and hence, require a detailed understanding of how permeability varies during production life. In many instances, production from coal seams is complicated and unpredictable because of the influence of stress induced natural fractures. A geomechanical earth model is focused on understanding and mitigating the aforementioned challenges. In addition to coal thickness and gas content, stress-permeability maps are prepared to assist in the development program to prioritize wells in lower and moderate stress areas. Wellbore stability analysis has been carried out using calibrated stress and strength profiles along with other rock mechanical inputs to successfully drill high angle wells. This analysis indicates that with a slightly higher mud weight, high angle and horizontal wells can be drilled successfully. Hydraulic fracturing design incorporating the available stress contrast can help in achieving the desired fracture parameters without height growth. The coal permeability model suggests that during depletion, coal permeability is expected to increase by about 1.2-3.5 times with a positive impact on productivity. Critically stressed fracture analysis has been carried out on mapped fractures, which suggest that about 48% of the natural fractures are in a stressed state. Presence of these natural fractures has a positive (faster dewatering) as well as a negative (external water) impact on productivity at different places in the study area.",8,8,2
Drilling,Horizontal Wells,"Gamal, Hany; Elkatatny, Salaheldin; Adebayo, Abdulrauf; Bageri, Badr",Effect of exposure time on the compressive strength and formation damage of sandstone while drilling horizontal wells,Compressive strength; Formation damage; Barite-water-based drilling fluid; Exposure time; Sandstone formation; Horizontal drilling,WATER; FLUID; FIELD; MODEL; MUD,"Worldwide increase demand for oil and gas led to an evolution in drilling techniques that maximize oil and gas production such as inclined, multilateral, and long horizontal drilling. The interaction of the drilling fluid and mud filtration with the penetrated formation is very critical and very important to be evaluated especially in the case of horizontal drilling where the drilling operation may take more than 20 days. This study aims to assess the effect of exposure time on the changes of the unconfined compressive strength (UCS) while drilling horizontal sandstone formation using water-based drilling fluid. Modified high-pressure high-temperature (HPHT) filter press cell was used to soak Buff Berea sandstone cores with barite-weighted mud under 300 psi differential pressure and 200 degrees F temperature for different periods. Nuclear magnetic resonance (NMR) was used to assess the change of the porosity while the scratch test was conducted to evaluate the changes in the UCS. The obtained results showed that UCS decreased significantly with increasing exposure time. For instance, the UCS was reduced by 18% after 5 days. NMR results confirmed that there was a corresponding increase in formation damage as shown by a progressive decrease in the rock porosity and permeability with time. The exposure time was found to be a controlling factor for both reducing the rock UCS and porosity. The statistical analysis showed that there is an inverse linear relationship (with 0.92 coefficient of determination R-2) between the UCS values vs the extended exposure time. Meanwhile, an approximate logarithmic relationship (with R-2 of 0.98) for estimating the reduction in rock porosity with the exposure time was investigated.",8,8,0
Drilling,Horizontal Wells,"Sun, Ruofan; Hu, Jinghong; Zhang, Yuan; Li, Zhiping",A semi-analytical model for investigating the productivity of fractured horizontal wells in tight oil reservoirs with micro-fractures,Micro-fractures; Fractured horizontal wells; Well productivity; Tight oil reservoirs; Sensitivity analysis,PRESSURE-TRANSIENT ANALYSIS; GAS-PRODUCTION; LINEAR FLOW; MICROFRACTURES; SHALE; PERMEABILITY; PERFORMANCE; PREDICTION; BASIN,"Combining horizontal drilling with hydraulic fracturing has become a well-established technique to improve well productivity in tight oil reservoirs. The existence of micro-fractures in these reservoirs affects the fluid flow process as well as the productivity. However, current models for evaluating the well performance of fractured horizontal wells containing micro-fractures lack accuracy. Hence, the objective of this study is to build an efficient model to analyze well productivity, considering the effects of micro-fractures. A novel flow model for multi-fractured horizontal wells was established, considering the effect of micro-fractures on the fluid flow. Subsequently, we built a reservoir model based on the typical fracture and fluid properties of a tight oil block in the Daqing oil field, China. Good agreement between the prediction results and field data was obtained, indicating that the effect of micro-fractures on well productivity cannot be neglected. Further study reveals that micro-fractures essentially function as a joint connecting reservoir matrix and have a persistent impact on well productivity. Micro-fractures can promote well productivity; however, if the value of micro-fracture permeability increases, this promotional effect will slow down. Well productivity can be considerably improved as an increase in micro-fracture percentage. Finally, a series of sensitivity studies were conducted to identify the effects of critical parameters on well productivity. Results show that reservoir permeability significantly influences well productivity, followed by reservoir effective thickness, micro-fracture percentage, fracture number, hydraulic fracture half-length. Pressure sensitivity coefficient, threshold pressure gradient and micro-fracture permeability have the least effect on well productivity. This work provides a sophisticated and efficient tool to evaluate the productivity of multi-fractured horizontal wells in tight oil reservoirs with micro-fractures.",7,7,5
Drilling,Machine Learning,"Wood, David A.","Predicting porosity, permeability and water saturation applying an optimized nearest-neighbour, machine-learning and data-mining network of well-log data",Petrophysical metric prediction from well logs; Data-matching machine learning; Standardized well-log interval representation; Well-log sampling densities; Prediction error analysis,NEURAL-NETWORKS; GAS-FIELD; ALGORITHMS,"Predicting permeability (Ke), water saturation (Sw) and effective porosity (EP) of oil and gas reservoir sections from well log data is necessary task because core data is typically not available for all wells drilled or complete reservoir sections. A novel data matching algorithm is developed to evaluate data from multiple well-log curves. It provides accurate petrophysical metric predictions and extensive data mining insight to the lithological units it evaluates. Expressing the well-log data in a standardized well-log representation and evaluating that network with the data-matching algorithm provides Ke, Sw and EP prediction from datasets that combine standard well logs curves with lithofacies and stratigraphic information. Applying the methodology to a resampled network from a published composite well-log data and lithofacies interpretation (10 variables), for a 100-m section across the Triassic reservoir of the Algerian Hassi R'Mel gas field (Algeria) demonstrates the capabilities of the proposed method. At a screening level of sampling density (similar to 1 sample/10 cm) TOB generates prediction accuracy useful for distinguishing prospective formations (root mean squared errors, RMSE for Ke similar to 15 mD; for Sw similar to 0.1; for EP similar to 0.01). At a zoomed-interval sampling density (similar to 1 sample/1 cm) for a 10-m zone of interest, TOB provides much improved prediction accuracy (RMSE for Ke similar to 1.3 mD; for Sw similar to 0.003, for EP similar to 0.0006) for the Hassi R'Mel well-log network. The level of detail provided for each of the two predictions provided by the proposed data-matching method is useful for detailed prediction error analysis. Such data mining capabilities are better than those provided by regression and/or correlation-based machine-learning methods.",23,23,2
Drilling,Machine Learning,"Ershadnia, Reza; Amooie, Mohammad Amin; Shams, Reza; Hajirezaie, Sassan; Liu, Yuanhong; Jamshidi, Saeid; Soltanian, Mohamad Reza",Non-Newtonian fluid flow dynamics in rotating annular media: Physics-based and data-driven modeling,Pressure loss ratio; Non-Newtonian fluid; CFD; LSSVM; Rotating Couette flow,SHEAR-THINNING FLUIDS; LAMINAR-FLOW; ECCENTRIC ANNULI; STROUHAL NUMBERS; PRESSURE LOSSES; OIL; CYLINDER; CFD; OPTIMIZATION; TRANSPORT,"A thorough understanding and accurate prediction of non-Newtonian fluid flow dynamics in rotating annular media are of paramount importance to numerous engineering applications. This is in particular relevant to oil and gas industry where this type of flow could occur during, e.g., drilling, well completion, and enhanced oil recovery scenarios. Here, mathematically we report on physical-based (numerical) and data-driven (intelligent) modeling of three-dimensional laminar flow of non-Newtonian fluids driven by axial pressure gradient in annular media that consist of a coaxially rotating inner cylinder. We focus on the dynamics of pressure loss ratio (PLR)-the ratio of total pressure loss in presence of rotation to that in stationary condition. We develop a novel and computationally efficient machine-learning based predictive model based on a Least Square Support Vector Machine (LSSVM) optimized with a Coupled Simulated Annealing (CSA) algorithm, which is trained and tested by 730 experimental data collected for this study. We then perform numerous CFD simulations governed by Navier-Stokes set of equations, which correspond to each of the experimental cases. Comparing the results with those obtained from a widely used empirical correlation for PLR, we find that the both of our numerical and machine-learning based models are more accurate and present a larger applicability domain. The predictive LSSVM model enjoys a supervised learning paradigm and leads to the highest accuracy, while the physically originated CFD approach captures more consistently the nonlinear behavior of PLR versus key system features. Following the validation of our models, we study the less understood effects of fluid viscosity, axial velocity and rotational velocity on PLR dynamics. We employ a dimensionless parameter analogous to Strouhal number and identify specific regimes where PLR shows a distinct behavior. Our study elucidates the role of shear-thinning effect and its interplay with inertial forces on the dynamical behavior of pressure loss (ratio) in rotating yield-power-law fluids.",20,20,8
Drilling,Machine Learning,"Gurina, Ekaterina; Klyuchnikov, Nikita; Zaytsev, Alexey; Romanenkova, Evgenya; Antipova, Ksenia; Simon, Igor; Makarov, Victor; Koroteev, Dmitry",Application of machine learning to accidents detection at directional drilling,Machine learning; Anomaly detection; Directional drilling; Classification; Measurements while drilling,,We present a data-driven algorithm and mathematical model for anomaly alarming at directional drilling. The algorithm is based on machine learning. It compares the real-time drilling telemetry with one corresponding to past accidents and analyses the level of similarity. The model performs a time-series comparison using aggregated statistics and Gradient Boosting classification. It is trained on historical data containing the drilling telemetry of 80 wells drilled within 19 oilfields. The model can detect an anomaly and identify its type by comparing the real-time measurements while drilling with the ones from the database of past accidents. Validation tests show that our algorithm identifies half of the anomalies with about 0.53 false alarms per day on average. The model performance ensures sufficient time and cost savings as it enables partial prevention of the failures and accidents at the well construction.,20,22,6
Drilling,Machine Learning,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Drilling,Machine Learning,"Gul, Sercan; van Oort, Eric",A machine learning approach to filtrate loss determination and test automation for drilling and completion fluids,Machine learning; Drilling fluid automation; Filtrate loss determination,CAKE FILTRATION; NEURAL-NETWORK,"Drilling fluid property characterization currently involves several manually executed analytical tests, conducted in accordance with American Petroleum Institute (API) recommended practices 13B-1 and 13B-2. Standard (API) and high-pressure, high-temperature (HPHT) filter press units are used for filtrate loss (FL) measurements. However, these test methods have certain important disadvantages. FL tests are conducted at standardized conditions that generally do not reflect downhole oil and gas well conditions in terms of downhole pressure, temperature and filter medium encountered, present safety concerns due to their elevated pressure and temperature, and are performed only infrequently by a human mud engineer. The human measurement also introduces concerns around inaccuracies due to inconsistent practices and interpretation bias of the results. In addition, FL measurements are hard to automate given their manual, human-centric operating tasks. In this paper, we investigate if it is really necessary to automate FL measurements, or if the (strictly qualitative) information they provide can be obtained in a smarter, more advanced way. For this purpose, the relationship between fluid properties was investigated in detail using machine learning and deep learning techniques. Random forest (RF), XGBoost (XGB), support vector machine (SVM), multilayer perceptron (MLP) and multi-linear regression models were trained and tested to predict API and HPHT FL of water-based muds (WBM) based on fluid property readings of rheology, density, and temperature. A similar approach was also used for HPHT filtrate loss prediction of oil-based muds (OBM), taking into account their electrical stability and water content. A key advantage of this approach is that these WBM and OBM fluid properties can be obtained in real-time with measurements that are relatively simple and easy to automate (e.g. obtaining fluid density automatically and continuously from a Coriolis mass-flow meter measurement). Thus, real-time assessment of API and HPHT FL becomes possible without ever having to actually carry out any filter press measurements, thereby also eliminating the need to directly automate these measurements. The models were verified by dedicated laboratory experiments. The developed models estimated API and HPHT FL of WBM, and HPHT FL of OBM with mean absolute errors (MAE) of 0.56 ml/30min, 1.15 ml/30min and 0.79 ml/30min respectively, well within the measurement accuracy of the observations by a human mud engineer.",10,10,4
Drilling,Machine Learning,"Moazzeni, Ali Reza; Khamehchi, Ehsan",Rain optimization algorithm (ROA): A new metaheuristic method for drilling optimization solutions,Rain optimization algorithm; Drilling rate; Drilling optimization; Machine learning,PENETRATION; PREDICTION; PERFORMANCE,"With the development of powerful computers, some new methods for solving challenging problems are introduced. Some of these methods, which are called metaheuristic algorithms, such as bat algorithm or ant colony algorithm, are inspired by nature and simulate a natural phenomenon for finding the best solution. Today these algorithms with a robust approach can be used to find the solution of a complicated problem very fast although they might be trapped in the local minimums. Rain optimization algorithm (ROA) is a new metaheuristic algorithm that is inspired by the raindrops, which move toward minimum points after getting to the earth. This algorithm can find global extremum as well as local extremums if its parameters are correctly tuned. After the implementation of this algorithm, we compare it with some other existing optimization algorithms such as particle swarm optimization algorithm and bat algorithm by solving 26 benchmarks and three benchmarks in various dimensions as well as a drilling optimization problem. Simulations illustrate the performance and computational time in finding the global minimum. Also, ROA can find local minimum simultaneously and it can be confidently used in optimization problems.",10,10,2
Drilling,Machine Learning,"Osarogiagbon, Augustine Uhunoma; Oloruntobi, Olalere; Khan, Faisal; Venkatesan, Ramachandran; Butt, Stephen",Gamma ray log generation from drilling parameters using deep learning,Deep learning; Logging while drilling; Measurement while drilling; Lithology; Drilling parameters; Gamma ray log; NARX; RNN; TCN; LSTM; GRU; ANN,NEURAL-NETWORKS; PREDICTION,"Lithology identification plays a vital role in defining the petroleum reservoir. Although well logging represents the traditional means of obtaining petrophysical data for lithology identification, there could be cases where logging while drilling instruments may fail during drilling. This paper presents an approach that utilizes drilling parameters obtained from mud logging and measurement while drilling (MWD) for real-time prediction of gamma ray log which is used as a lithology identifier. In this work, several machine learning methodologies, such as simple recurrent neural network (RNN), long short-term memory recurrent neural network (LSTM-RNN), temporal convolution network (TCN), gated recurrent unit (GRU) network, nonlinear autoregressive network with exogenous inputs (NARX) and simple artificial neural network (ANN) were tested for their ability to capture the relationship between hydro-mechanical specific energy (computed from drilling parameters) and gamma ray log. A recently drilled exploration gas well in the tertiary deltaic system of the Niger delta basin was used as the case study. Based on the field data, the results show the TCN and simple RNN performed best. The receptive field of the TCN played a significant role in its performance, and therefore, the LSTM-RNN can be made to perform comparable to that of TCN/simple RNN if the LSTM-RNN is manually made to work with an optimal window of input data points for each output data point. The size and nature of the data (volume, velocity, variety, and veracity) is likely a significant factor in the performance of the machine learning methodologies. Thus, it is recommended to focus on obtaining the best receptive field of the data during the machine learning development phase.",9,9,8
Drilling,Machine Learning,"Hegde, Chiranth; Pyrcz, Michael; Millwater, Harry; Daigle, Hugh; Gray, Ken",Fully coupled end-to-end drilling optimization model using machine learning,ROP; Data-driven; Machine learning; Drilling; Optimization; Vibration,PREDICTION; EFFICIENCY,"Drilling optimization has been studied extensively given its impact on an oil and gas project - especially in a low-price environment. This is generally approached by optimizing the rate of penetration (ROP) of the well, which may not always be the best strategy. Additionally, optimization strategies rarely include the effect of torsional drilling vibrations (stick-slip) - the biggest ROP inhibitor. As such, most optimization studies have attempted to optimize only one drilling metric - ROP, mechanical specific energy (MSE) or vibrations - independent of the other, despite their interaction downhole. This does not represent bottom hole conditions accurately. This paper introduces a method of coupling several downhole parameters using machine learning algorithms. Individual models for ROP, torque on bit (TOB), MSE, and stick-slip are built using a data-driven modeling approach using the random forests algorithm. The random forest algorithm is used given its lower error rate in modeling ROP (11%), TOB (13%), and classifying drilling vibrations (F-1 score of 0.94) as compared to other machine learning algorithms evaluated in this paper (linear regression, k nearest neighbors, bagging, and neural networks). The models are coupled by building them conjointly during training. The model uses weight-on-bit (WOB), rotary speed, flowrate, and rock strength as inputs to provide an optimal set of these input parameters to use ahead of the bit for optimal drilling. The coupled model was evaluated to optimize ROP and MSE on validation data. ROP increased by 31% and MSE decreased by 49% on average with the use of this optimization model. A case study from the Williston Basin is discussed to illustrate the practical application of this model.",9,9,6
Drilling,Flow Rate,"Fu, Weiqi; Wang, Zhiyuan; Zhang, Jianbo; Cao, Yueying; Sun, Baojiang",Investigation of rheological properties of methane hydrate slurry with carboxmethylcellulose,Hydrate slurry rheology; Drilling; Flow assurance; Carboxmethylcellulose (CMC); Shear thinning; Rheological model,GAS-HYDRATE; XANTHAN GUM; FLOW CHARACTERISTICS; PRESSURE RHEOLOGY; TURBULENT-FLOW; DRILLING-FLUID; WATER; CARBOXYMETHYLCELLULOSE; MODEL; TEMPERATURE,"As offshore oil and gas accumulate in deep water environments, the formation of gas hydrates in water-based drilling mud has become a critical safety problem in drilling operations. In this work, rheological experiments on methane hydrate slurry with carboxymethylcellulose (CMC) are performed with a 0.2%-0.5% CMC concentration, 0.97%-8.49% hydrate concentration, and 27-368 s(-1) shear rate. It is confirmed through experiments that hydrate slurry with CMC is a pseudoplastic fluid, whose apparent viscosity decreases with the increase in shear rate and is in a laminar flow regime. The shear-thinning behavior of hydrate slurry with CMC is assumed to be attributed to the shear-thinning behavior of carrier fluids (CMC aqueous solution) and the breakage of agglomerated hydrate particles induced by external shear force. Experimental results reveal that the increase in both hydrate and CMC concentrations in hydrate slurry can decrease its non-Newtonian index and induce shear thinning. Moreover, under a constant shear rate condition, the higher the hydrate and CMC concentration, the higher is the apparent viscosity of the hydrate slurry. The non-Newtonian index and consistence factor of the methane hydrate slurry are correlated as functions of the hydrate concentration and CMC concentration. An empirical Herschel-Bulkley-type rheological model as a function of shear rate, hydrate concentration, and CMC concentration is developed based on experimental data. Moreover, the developed model is validated through additional experiments; the maximum discrepancy is found to be 8.9%.",39,40,25
Drilling,Flow Rate,"Zhu, Wenxi; Zheng, Xiuhua; Li, Guomin","Micro-bubbles size, rheological and filtration characteristics of Colloidal Gas Aphron (CGA) drilling fluids for high temperature well: Role of attapulgite",Attapulgite; colloidal gas aphron drilling fluid; Aphron size distribution; Rheology; Filtration loss; Fluid loss control mechanism,STABILITY; SURFACTANT; BEHAVIOR; SYSTEM,"Colloidal Gas Aphron drilling fluids have been successfully applied in petroleum industry to drill low pressure formations and depleted reservoirs. As the increase of drilling depth and reservoir temperature, characteristics of CGA drilling fluids at high temperature are more concerned, yet less investigated. In this paper, attapulgite with better performance at high temperatures was selected to prepare CGA drilling fluids and the bubbles size distribution, rheological and fluid loss performance at 25 degrees C/90 degrees C/120 degrees C/150 degrees C/180 degrees C were studied. CGA fluid with Xanthan gum and 3% bentonite were prepared and tested as control group. Result indicates that: 1) The addition of attapulgite significantly reduces the average diameter of aphrons and improves the bubble size distribution of CGA fluids, which is conducive to the stability of CGA fluids; 2) Attapulgite effectively increases low shear rate viscosity (LSRV) of CGA fluid at room temperature, which will help to carry cuttings and seal formation. Power law model is the optimal model to describe the rheological behaviors of attapulgite-based CGA drilling fluids. Rheological parameters of Power law model show that the tested fluids have a shear thinning behavior at all temperatures and the flow behavior index can be controlled to an appropriate range by adjusting the amount of attapulgite; 3) Attapulgite greatly reduces the fluid loss of CGA drilling fluid, especially at high temperature. The attapulgite-based CGA drilling fluids can maintain an acceptable fluid loss (within 15 mL) for drilling operations at 120 degrees C. At 150/180 degrees C, 3% attapulgite exhibited the lowest fluid loss volume, which is reduced by 46.7%/25% as compared to 3% bentonite. In addition, the mechanism of attapulgite-based CGA fluid loss control was studied and can be concluded as the ""embedded"" mud cake structure composed by aphrons and attapulgite.",14,15,3
Drilling,Flow Rate,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Drilling,Flow Rate,"Moghaddam, Ali Kariman; Saadatabadi, Ahmad Ramazani",Rheological modeling of water based drilling fluids containing polymer/bentonite using generalized bracket formalism,Rheological model; Normal stress; Bentonite/polymer dispersion; Bracket formalism,FIBER SUSPENSIONS; SHEAR RATE; FLOW; BENTONITE; BEHAVIOR; PERFORMANCE; PARAMETERS; VISCOSITY; STRESS; MUD,"Drilling fluids consist of several components with different physical and structural form which can be assumed as complex fluids. Optimum performance of drilling process could be obtained through the dynamic fluid computation which requires a reliable mathematical model capable to predict transient and steady state rheological behavior of drilling fluid. Generalized Newtonian formulations are the most popular models for drilling fluids due to their simplicity in spite of their inabilities to predict transient and elastic behavior of such fluids. In this paper, we have developed a mathematical model to predict transient and steady state rheological behavior of the complex fluids on the scale between the microscopic and macroscopic which is named mesoscopic scale. Constitutive and governing equations are obtained using the generalized bracket formalism which is based on the thermodynamics of flowing systems in that Hamiltonian mechanics has been used to describe the transport phenomena of internal microstructures. The model is developed for the suspension of bentonite/polymer dispersion and compared with experimental rheological data of different types of drilling fluids under transient and steady state condition. Comparison of model prediction with published data in the literature shows that the model is able to predict rheological behavior of bentonite muds satisfactorily.",11,11,2
Drilling,Flow Rate,"Tong, Tran A.; Yu, Mengjiao; Ozbayoglu, Evren; Takach, Nicholas",Numerical simulation of non-Newtonian fluid flow in partially blocked eccentric annuli,Numerical simulation; Non-Newtonian fluid; Eccentricity; Obstructed annuli; Pressure loss gradient,,"A cuttings bed formed on the lower side of the wellbore is the most common drilling problem confronted when horizontal or highly deviated wells are drilled. The phenomenon is undesirable and has a detrimental effect on wellbore hydraulics and drilling performance. To achieve an efficient drilling operation, hydraulics optimization should be implemented by precisely predicting annular pressure loss and other hydraulic parameters. The accumulation of cuttings at the lower side of horizontal or highly inclined wellbores, combined with wellbore eccentricity and fluid rheological properties, create a complex behavior of pressure loss. In this study, a numerical approach is used to investigate the influence of the aforementioned factors. A numerical solution is performed for laminar flow of non-Newtonian fluids. A non -orthogonal, boundary-fitted curvilinear coordinate is developed, which is based on elliptic partial differential equations (PDE) to accommodate annular flow geometry with arbitrary cross-sections. Finite difference numerical schemes adapted to the coordinates is then used to analyze the problem. The numerical model determines the effect of hydraulic parameters of fluid flow thorough an irregularly shaped annulus and considers the following factors: flow rate, fluid rheological parameters, annular geometry and bed appearance. Numerical predictions from the model are verified against existing models and experimental data in literature; and good agreements are obtained. The developed numerical model can be combined with a 1-D solids transport model for designing oil and gas well drilling operations.",11,11,0
Drilling,Flow Rate,"Abdelhafiz, Mostafa M.; Hegele Jr, Luiz A.; Oppelt, Joachim F.",Numerical transient and steady state analytical modeling of the wellbore temperature during drilling fluid circulation,Modeling; Simulation; Wellbore temperature; Heat transfer; Drilling,HEAT-TRANSFER; DISTRIBUTIONS; PROFILES; FLOW,"In this paper, a transient model that describes the heat transfer processes in the wellbore during circulation is presented. A simulation of the transient effect on these heat transfer processes was achieved by using a numerical approach to solve the thermal balance equations that describe the heat flow in that system. The present model can be applied for both laminar and turbulent flow regimes through the convective heat transfer coefficient (CHTC). The run time of the present model is relatively short, hence it can be applied for real-time simulation applications. This was achieved by simplifying the model and reducing the calculation complexity. Moreover, the present model has gone through different validation processes. First, the present model is reduced to a steady state condition and solved analytically. This solution was used as a reference to verify the results of the numerical model. Additionally, a grid sensitivity analysis was performed. Second, the analytical solution was validated through a comparison with the known literature. Finally, the assumptions that were made to simplify the model were verified by comparing the results with the comprehensive version of the model. The effect of the flow rate and the flow regime on the wellbore temperature profile are examined. The results showed a reverse effect of the flow rate on the bottom hole temperature within each flow regime. However, a significant increase in the bottom hole temperature is observed as the flow regime changed from laminar flow to turbulent flow. Changing the flow regime from laminar to turbulent will affect the value of the CHTC leading to a significant increase in wellbore fluid temperature. It is also shown that the maximum temperature at the annulus is located where the rate of heat exchange between the annulus and the pipe and the heat from the formation to the annulus is equal.",9,9,6
Drilling,Flow Rate,"Muojeke, Somadina; Venkatesan, Ramachandran; Khan, Faisal",Supervised data-driven approach to early kick detection during drilling operation,Artificial neural network; Downhole monitoring; Early kick detection; Supervised learning,ARTIFICIAL NEURAL-NETWORKS; DEVELOPING LEADING INDICATORS; PREDICTING RATE; WELL; PENETRATION; MODELS,"The margin between pore pressure and fracture gradient in new offshore discoveries continues to get narrower. This poses greater risks and higher cost of ensuring safety of lives, facilities and the environment. The 2010 Macondo blowout has fueled increased interests in monitoring downhole parameter for early kick detection. Early detection of kick is important part of the process safety. It provides opportunity to activate safety measures. This work investigates the simplest supervised learning-based kick detection system to ensure higher reliability using experimental data. It combines an Artificial Neural Network (ANN), binary classifier and downhole monitoring of drilling flow parameters to build data-driven kick detection models. Data was generated from experiment that monitors downhole parameters when kick occurs. Recorded parameters such as mud flow-out rate, conductivity, density and downhole pressure are combined to build the model capable of detecting kick events. Abnormal pressure and flow regimes in the wellbore provide early warnings and was shown to be more significant parameters than others, however relying on them alone could increase susceptibility to a false alarm. The model has been tested on data from two different laboratory scale drilling simulator.",9,9,0
Drilling,Flow Rate,"Weijermars, Ruud; Tugan, Murat Fatih; Khanal, Aadi",Production rates and EUR forecasts for interfering parent-parent wells and parent-child wells: Fast analytical solutions and validation with numerical reservoir simulators,Well interfering; Parent-child wells; Fast analytical solutions; Production rates; EUR forecast; Shale oil,DRAINED ROCK VOLUME; HYDRAULIC FRACTURES; FLOW INTERFERENCE; POTENTIALS,"Analytical expressions are given to forecast the production decline and estimated ultimate reserves (EUR) for pairs of both parent-parent wells and parent-child wells. The forecasts use physics-based flow rate quantification in elementary flow cells between hydraulic fractures sets. The intrinsic rate in the flow cells for a given shale formation can be obtained and scaled by a type curve specific for its completion and reservoir parameters. The model then can predict how changes in fracture treatment design parameters will affect the performance of new wells in the same target zone. The effect of well down-spacing and the onset of pressure interference on the performance of parent-parent wells can be forecasted with reasonable accuracy. Similarly, the equations can also predict the effect of infill drilling of child wells on the performance of both well types. The method is applied to real world examples from Eagle Ford acreage. The fast analytical model forecasts are benchmarked against the results from an independent numerical reservoir simulator, with satisfactory matches. The validated approach aims to provide a practical analytical tool for the production forecasting of multi-wells in shale formations.",8,8,2
Drilling,Flow Rate,"Dokhani, Vahid; Ma, Yue; Li, Zili; Geng, Tie; Yu, Mengjiao",Effects of drill string eccentricity on frictional pressure losses in annuli,Frictional pressure loss; Eccentricity; Yield-power-law; Numerical modeling; Drilling fluid,NON-NEWTONIAN FLOW; POWER-LAW FLUID; LAMINAR-FLOW; ROTATION; PREDICTIONS; LIQUID; MODEL,"It has been shown that drill pipe eccentricity can significantly reduce the annular pressure losses and must be taken in to account for accurate prediction of equivalent circulating density (ECD). This study investigates effects of axial flow of Yield-Power-Law (YPL) drilling fluid on frictional pressure losses in eccentric annuli. A numerical model is developed to simulate the laminar flow of yield-power-law fluids in eccentric annular geometries. The governing equations are solved numerically using an implicit finite difference method and employing a non-uniform grid distribution system. The numerical solution yields velocity profile in the annular space, which is integrated to obtain the volumetric flow rate. The frictional pressure losses are calculated using an iterative scheme that is based on convergence of the calculated volumetric flow rate to the given flow rate. Comparing the frictional pressure loss predictions of the model with three previous numerical studies indicates an excellent agreement for the case of non-Newtonian fluids. The numerical model is validated through extensive comparisons between the predicted frictional pressure losses and experimental data derived from the literature. Our analysis indicates excellent agreement between the model prediction and the experimental data. The numerical results conclude that the reduction in frictional pressure losses due to eccentricity is more prominent at high radii ratios. Results of extensive simulation scenarios for yield-power-law fluids are fitted using non-linear regression analysis, which provides a new correlation for prediction of frictional pressure losses of yield-power-law fluids in eccentric annuli. Comparing the predictions of the developed correlation with the published correlation in the literature reveals more accurate estimation of frictional pressure losses for the proposed correlation and hence safer controlled drilling operations.",8,8,1
Drilling,Well Logs,"Wood, David A.","Predicting porosity, permeability and water saturation applying an optimized nearest-neighbour, machine-learning and data-mining network of well-log data",Petrophysical metric prediction from well logs; Data-matching machine learning; Standardized well-log interval representation; Well-log sampling densities; Prediction error analysis,NEURAL-NETWORKS; GAS-FIELD; ALGORITHMS,"Predicting permeability (Ke), water saturation (Sw) and effective porosity (EP) of oil and gas reservoir sections from well log data is necessary task because core data is typically not available for all wells drilled or complete reservoir sections. A novel data matching algorithm is developed to evaluate data from multiple well-log curves. It provides accurate petrophysical metric predictions and extensive data mining insight to the lithological units it evaluates. Expressing the well-log data in a standardized well-log representation and evaluating that network with the data-matching algorithm provides Ke, Sw and EP prediction from datasets that combine standard well logs curves with lithofacies and stratigraphic information. Applying the methodology to a resampled network from a published composite well-log data and lithofacies interpretation (10 variables), for a 100-m section across the Triassic reservoir of the Algerian Hassi R'Mel gas field (Algeria) demonstrates the capabilities of the proposed method. At a screening level of sampling density (similar to 1 sample/10 cm) TOB generates prediction accuracy useful for distinguishing prospective formations (root mean squared errors, RMSE for Ke similar to 15 mD; for Sw similar to 0.1; for EP similar to 0.01). At a zoomed-interval sampling density (similar to 1 sample/1 cm) for a 10-m zone of interest, TOB provides much improved prediction accuracy (RMSE for Ke similar to 1.3 mD; for Sw similar to 0.003, for EP similar to 0.0006) for the Hassi R'Mel well-log network. The level of detail provided for each of the two predictions provided by the proposed data-matching method is useful for detailed prediction error analysis. Such data mining capabilities are better than those provided by regression and/or correlation-based machine-learning methods.",23,23,2
Drilling,Well Logs,"Oloruntobi, Olalere; Butt, Stephen",Application of specific energy for lithology identification,Hydromechanical specific energy; Lithology; Rate of penetration; Drilling; Bit,MECHANICAL SPECIFIC ENERGY; PORE-PRESSURE; ROCK,"The previous applications of specific energy to drilling operations have focused mainly on drilling optimization and identification of inefficient drilling conditions. Recent advances in specific energy extend its applications to overpressure detection and pore pressure prediction. In this paper, an attempt is made to further extend the application of specific energy to real-time identification of subsurface lithology. The concept is based on the principle that the total energy required to break and remove a unit volume of rock is a function of lithology. The proposed methodology is tested using a recently drilled exploratory gas well in the tertiary deltaic system of the Niger Delta basin. In general, an excellent agreement is observed in trend between the traditional lithology identifiers (gamma ray and sonic velocity ratio) and the total energy consumed in breaking and removing the penetrated rocks. Unlike the logging while drilling (LWD) technique commonly employed in the industry (including the application of near bit sensors placed few feet behind the bit), the proposed methodology can provide a reliable means of picking formation tops and identifying subsurface lithology at the bit with no extra cost since drilling parameters are routinely recorded at the wellsite during the drilling of a well. The proposed methodology will assist the drilling engineers and geologists in determining the casing setting depths and coring points without having to drill too deep into the formation of interest.",14,15,2
Drilling,Well Logs,"Ju, Wei; Niu, Xiaobing; Feng, Shengbin; You, Yuan; Xu, Ke; Wang, Geoff; Xu, Haoran","Present-day in-situ stress field within the Yanchang Formation tight oil reservoir of Ordos Basin, central China",In-situ stress field; Tight oil reservoir; Yanchang formation; Stress regime; Natural fracture; Ordos basin,SEDIMENTARY-ROCKS; LOW-PERMEABILITY; TECTONIC STRESS; STATE; AREA; EXPLORATION; FRACTURES; PATTERN; REGION; ORIENTATIONS,"The present-day in-situ stress field has many important and practical applications during the exploration and development of hydrocarbon resources. The Ordos Basin is a significant petroliferous basin in China, within which, the Yanchang Formation serves as the most significant tight oil reservoir. However, an overview of previous studies indicates that little was known as to the present-day stress state in the Yanchang Formation. Therefore, the present-day stress field in the Yanchang Formation tight oil reservoir of the Ordos Basin is systematically analyzed in this study. The orientation of horizontal maximum principal stress (S-Hmax) within the Yanchang Formation of Ordos Basin ranges between north-northeast-south-southwest-trending (NNE-SSW) and east-northeast-west-southwest-trending (ENE-WSW) based on interpretations of borehole breakouts and drilling-induced fractures from borehole imaging logs. The S-Hmax orientation shows various tendencies in different wells, which may result from differential development in lithology, natural fracture and bedding plane over various regions. The estimated magnitudes of vertical stress (S-v), S-Hmax and horizontal minimum principal stress (S-hmin) in the studied wells indicate that the normal faulting stress regime is dominant within the Yanchang Formation. In addition, the geomechanical assessments of wellbore stability and natural fracture reactivation are also performed. Natural fractures in the Yanchang Formation Chang 7 tight oil reservoir of Ordos Basin are developed striking mainly in the northeast-southwest-trending (NE-SW) and west-northwest-east-southeast-trending (WNW-ESE). Among them, those fractures with NE-SW-trending strikes are more conductive with reference to the present-day stress state, contributing more to tight oil production in the Ordos Basin. In addition, within the Yanchang Formation, if horizontal wells are drilled towards the NNE-SSW-trending to ENE-WSW-trending, they are more likely to have wellbore instability issues. The results in this study provide important geological information for tight oil production in the Yanchang Formation of Ordos Basin.",13,14,3
Drilling,Well Logs,"Mamudu, Abbas; Khan, Faisal; Zendehboudi, Sohrab; Adedigba, Sunday",Dynamic risk assessment of reservoir production using data-driven probabilistic approach,Artificial neural network; Bayesian network; Oil production forecast; Reservoir simulation; Dynamic risk assessment,WELL LOG DATA; ARTIFICIAL NEURAL-NETWORK; SHEAR-WAVE VELOCITY; DRILLING OPERATIONS; PREDICTION; INTELLIGENCE; SYSTEMS; PERMEABILITY; PETROLEUM; MODELS,"Oil and gas companies use the reservoir simulation approach to history match and forecast reservoir production. While this strategy is easy and often effective, it has inherent setbacks, including a limited ability to capture temporal and spatial variability of the data, uncertainty in the data and reservoir models, and most importantly, impacts of these factors/parameters on the overall production risk profile. This paper presents a hybrid method to forecast the production rate and risks attributed to oilfield development. The hybrid connectionist strategy integrates a data-driven model to capture variability with a probabilistic model to capture uncertainties and associated risks. The multilayer perceptron artificial neural network (ANN) is built on the basis of geological realizations and used as a substitute for the commercial simulator (e.g., CMG) to model reservoir production behaviour for the effective facilitation of the production prediction. The model has a generalization capability and captures the temporal-spatial dependency and non-linear complex relationships. The Bayesian network model is developed to assess the production risks. It employs the concept of the early warning index system. The results show that the predicted oil production profile closely matches the history matched data from the simulator, and the assessed dynamic risks conform with the field reality. The hybrid modeling strategy leads to the minimum and average percentage errors of 0.02% and 5.28% respectively in the reservoir production forecast. The application of the proposed approach would assist in effective reservoir management decision making, enabling a risk-based optimal field performance of reservoir.",13,13,3
Drilling,Well Logs,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Drilling,Well Logs,"Kirkland, Catherine M.; Thane, Abby; Hiebert, Randy; Hyatt, Robert; Kirksey, Jim; Cunningham, Alfred B.; Gerlach, Robin; Spangler, Lee; Phillips, Adrienne J.",Addressing wellbore integrity and thief zone permeability using microbially-induced calcium carbonate precipitation (MICP): A field demonstration,Microbially-induced calcium carbonate precipitation; MICP; Sporosarcina pasteurii; Ureolysis; Wellbore integrity; Waterflooding,LEAKAGE; OIL; REDUCTION; UREOLYSIS; STORAGE,"Microbially-induced calcium carbonate precipitation (MICP) is an emerging biotechnology for wellbore integrity applications including sealing defects in wellbore cement and modifying the permeability of rock formations. The goal of this field demonstration was to characterize a failed waterflood injection well and provide proof of principle that MICP can reduce permeability in the presence of oil using conventional oilfield fluid delivery methods. We compared well logs performed at the time the well was drilled with ultrasonic logs, sonic cement evaluation, and temperature logs conducted after the well failed. Analysis of these logs suggested that, rather than entering the target waterflood formation, injectate was traveling through defects in the well cement to a higher permeability sandstone layer above the target formation. Sporosarcina pasteurii cultures and urea-calcium media were delivered 2290 ft (698 m) below ground surface using a 3.75 gal (14.2 L) slickline dump bailer to promote mineralization in the undesired flow paths. By Day 6 and after 25 inoculum and 49 calcium media injections, the injectivity [gpm/psi] had decreased by approximately 70%. This demonstration shows that 1) common well logs can be used to identify scenarios where MICP can be employed to reduce system permeability, remediate leakage pathways, and improve waterflood efficiency, and 2) MICP can occur in the presence of hydrocarbons.",13,14,2
Drilling,Well Logs,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Drilling,Well Logs,"Osarogiagbon, Augustine Uhunoma; Oloruntobi, Olalere; Khan, Faisal; Venkatesan, Ramachandran; Butt, Stephen",Gamma ray log generation from drilling parameters using deep learning,Deep learning; Logging while drilling; Measurement while drilling; Lithology; Drilling parameters; Gamma ray log; NARX; RNN; TCN; LSTM; GRU; ANN,NEURAL-NETWORKS; PREDICTION,"Lithology identification plays a vital role in defining the petroleum reservoir. Although well logging represents the traditional means of obtaining petrophysical data for lithology identification, there could be cases where logging while drilling instruments may fail during drilling. This paper presents an approach that utilizes drilling parameters obtained from mud logging and measurement while drilling (MWD) for real-time prediction of gamma ray log which is used as a lithology identifier. In this work, several machine learning methodologies, such as simple recurrent neural network (RNN), long short-term memory recurrent neural network (LSTM-RNN), temporal convolution network (TCN), gated recurrent unit (GRU) network, nonlinear autoregressive network with exogenous inputs (NARX) and simple artificial neural network (ANN) were tested for their ability to capture the relationship between hydro-mechanical specific energy (computed from drilling parameters) and gamma ray log. A recently drilled exploration gas well in the tertiary deltaic system of the Niger delta basin was used as the case study. Based on the field data, the results show the TCN and simple RNN performed best. The receptive field of the TCN played a significant role in its performance, and therefore, the LSTM-RNN can be made to perform comparable to that of TCN/simple RNN if the LSTM-RNN is manually made to work with an optimal window of input data points for each output data point. The size and nature of the data (volume, velocity, variety, and veracity) is likely a significant factor in the performance of the machine learning methodologies. Thus, it is recommended to focus on obtaining the best receptive field of the data during the machine learning development phase.",9,9,8
Drilling,ROP,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Drilling,ROP,"Gao, Mingyang; Zhang, Kai; Zhou, Qin; Zhou, Huifeng; Liu, Baolin; Zheng, Guojing",Numerical investigations on the effect of ultra-high cutting speed on the cutting heat and rock-breaking performance of a single cutter,Ultra-high-speed cutting; Thermal elastoplastic damage model; Rock-breaking mechanism; Cutting heat,DRILLING RESPONSE; BIT; SIMULATION; SURFACE; FORCE; MODEL,"As a new drilling technology, the ultra-high-speed diamond drilling can exhibit great superiority in drilling deep hard rock, which can achieve high rates of penetration (ROP) with substantially lower energy and load. In order to better understand the removal mechanism, the effect of ultra-high cutting speed on the cutting heat and rock-breaking performance of a single cutter was investigated by using ABAQUS software. A thermal elastoplastic damage model has been established by using a finite element analysis system aiming at the linear cutting operations. The changes of stress state, strain accumulation, and heat migration in the tool unit were analyzed. The results show that when the cutting speed exceeds 8 m/s, the heat flux and mechanical specific energy (MSE) decrease as the rotary speed (RPM) increases. That is, when cutting at ultra-high linear speed (>8 m/s), more input energy was used to break rock. In addition, when the cutting speed is in the ultra-high-speed stage and continues to increase, the proportion of brittle failure of the rock will gradually increase, and a new balance will not be reached until the cutting speed reaches 12 m/s, which helps to improve the rock breaking efficiency.",9,9,14
Drilling,ROP,"Hegde, Chiranth; Pyrcz, Michael; Millwater, Harry; Daigle, Hugh; Gray, Ken",Fully coupled end-to-end drilling optimization model using machine learning,ROP; Data-driven; Machine learning; Drilling; Optimization; Vibration,PREDICTION; EFFICIENCY,"Drilling optimization has been studied extensively given its impact on an oil and gas project - especially in a low-price environment. This is generally approached by optimizing the rate of penetration (ROP) of the well, which may not always be the best strategy. Additionally, optimization strategies rarely include the effect of torsional drilling vibrations (stick-slip) - the biggest ROP inhibitor. As such, most optimization studies have attempted to optimize only one drilling metric - ROP, mechanical specific energy (MSE) or vibrations - independent of the other, despite their interaction downhole. This does not represent bottom hole conditions accurately. This paper introduces a method of coupling several downhole parameters using machine learning algorithms. Individual models for ROP, torque on bit (TOB), MSE, and stick-slip are built using a data-driven modeling approach using the random forests algorithm. The random forest algorithm is used given its lower error rate in modeling ROP (11%), TOB (13%), and classifying drilling vibrations (F-1 score of 0.94) as compared to other machine learning algorithms evaluated in this paper (linear regression, k nearest neighbors, bagging, and neural networks). The models are coupled by building them conjointly during training. The model uses weight-on-bit (WOB), rotary speed, flowrate, and rock strength as inputs to provide an optimal set of these input parameters to use ahead of the bit for optimal drilling. The coupled model was evaluated to optimize ROP and MSE on validation data. ROP increased by 31% and MSE decreased by 49% on average with the use of this optimization model. A case study from the Williston Basin is discussed to illustrate the practical application of this model.",9,9,6
Drilling,ROP,"Feng, Shangxin; Wang, Yujie; Zhang, Guolai; Zhao, Yufei; Wang, Shanyong; Cao, Ruilang; Xiao, Enshang",Estimation of optimal drilling efficiency and rock strength by using controllable drilling parameters in rotary non-percussive drilling,Rock drilling; Specific energy; Drilling-monitoring system; Rate of penetration; Torque; Rock strength,MECHANICAL SPECIFIC ENERGY; DRILLABILITY PREDICTION; INDEX,"Fundamental rock-drilling studies are aimed at optimizing the drilling efficiency by identifying the optimal drilling conditions and rock drillability. In this study, a field-drilling test is performed using a rotary non - percussive drilling machine equipped with a new drilling-monitoring system to investigate the effects of dril ling parameters on the specific energy (SE) and rate of penetration (ROP). During the drilling test, different thrusts (8.5-70 kN) and rotation speeds (40-400 r/min) are applied on a predrilled borehole re-injected with pure concrete. The magnitudes of the thrust, torque, ROP, and rotation speed are measured simultaneously by the new drilling-monitoring system to calculate the changes in SE. A modified SE model, which only includes a few controlled drilling parameters, is then proposed to determine the optimal drilling conditions. The results first show that torque has a linear relationship with thrust but shows no obvious changes with respect to the rotation speed. According to the energy balance principle in rock drilling and the relationship between SE and ROP, the optimal drilling efficiency with the maximum attainable ROP is then innovatively identified around the lower point of the second reduction in SE. In conclusion, the slope of the linear relationship between the thrust and penetration rate per revolution is only related to the rock properties and can be used to define the strength parameters of stratification by using the measured drilling parameters.",8,8,8
Drilling,ROP,"Mazen, Ahmed Z.; Mujtaba, Iqbal M.; Hassanpour, Ali; Rahmanian, Nejat","Mathematical modelling of performance and wear prediction of PDC drill bits: Impact of bit profile, bit hydraulic, and rock strength",PDC cutters wear; Mechanical specific energy; Depth of cut; Effective blades; ROP,CUTTER,"The estimation of Polycrystalline Diamond Compact (PDC) cutters wear has been an area of concern for the drilling industry for years now. The cutter's wear has been measured practically by pulling the bit out for evaluation at the surface. It is important to find the right time for tripping out as this helps to avoid the fishing job and reduces the operational cost significantly. The prediction of the drilling performance is based on the interaction of cutter and rock. Several authors focused on the cutter-rock interface but only a few researchers tried to model the wear of the PDC bit cutters. The aim of this research is to understand the relationships between the rate of penetration (ROP) and the drilling variables per each foot, and then determine the overall bit efficiency for the whole drilling operation. A new mathematical model is derived to predict the PDC bit performance by considering the factors that were already not taken into account. These factors include rock strength, bit design, and bit hydraulic. The model investigates the effect of these parameters to estimate the abrasive cutters wear on the inner and the outer bit cones by deriving modified equations to calculate the mechanical specific energy (MSE), torque, and depth of cut (DOC) as a function of effective blades (EB). The model is used to forecast the bit cutters wear conditions in four wells in the oil fields located in Libya, which were drilled with three different PDC's sizes. The model enables the results to be compared to the actual bit cutters wear measured for inner and outer cones. The results are found that are well in agreement with the actual field data obtained in bit records.",8,8,4
Drilling,High Temperature,"Zhu, Wenxi; Zheng, Xiuhua; Li, Guomin","Micro-bubbles size, rheological and filtration characteristics of Colloidal Gas Aphron (CGA) drilling fluids for high temperature well: Role of attapulgite",Attapulgite; colloidal gas aphron drilling fluid; Aphron size distribution; Rheology; Filtration loss; Fluid loss control mechanism,STABILITY; SURFACTANT; BEHAVIOR; SYSTEM,"Colloidal Gas Aphron drilling fluids have been successfully applied in petroleum industry to drill low pressure formations and depleted reservoirs. As the increase of drilling depth and reservoir temperature, characteristics of CGA drilling fluids at high temperature are more concerned, yet less investigated. In this paper, attapulgite with better performance at high temperatures was selected to prepare CGA drilling fluids and the bubbles size distribution, rheological and fluid loss performance at 25 degrees C/90 degrees C/120 degrees C/150 degrees C/180 degrees C were studied. CGA fluid with Xanthan gum and 3% bentonite were prepared and tested as control group. Result indicates that: 1) The addition of attapulgite significantly reduces the average diameter of aphrons and improves the bubble size distribution of CGA fluids, which is conducive to the stability of CGA fluids; 2) Attapulgite effectively increases low shear rate viscosity (LSRV) of CGA fluid at room temperature, which will help to carry cuttings and seal formation. Power law model is the optimal model to describe the rheological behaviors of attapulgite-based CGA drilling fluids. Rheological parameters of Power law model show that the tested fluids have a shear thinning behavior at all temperatures and the flow behavior index can be controlled to an appropriate range by adjusting the amount of attapulgite; 3) Attapulgite greatly reduces the fluid loss of CGA drilling fluid, especially at high temperature. The attapulgite-based CGA drilling fluids can maintain an acceptable fluid loss (within 15 mL) for drilling operations at 120 degrees C. At 150/180 degrees C, 3% attapulgite exhibited the lowest fluid loss volume, which is reduced by 46.7%/25% as compared to 3% bentonite. In addition, the mechanism of attapulgite-based CGA fluid loss control was studied and can be concluded as the ""embedded"" mud cake structure composed by aphrons and attapulgite.",14,15,3
Drilling,High Temperature,"Reinoso, D.; Martin-Alfonso, M. J.; Luckham, P. F.; Martinez-Boza, F. J.",Flow behavior and thermal resistance of xanthan gum in formate brine,Xanthan gum; Formate brine; Flow behavior; Thermal resistance,RHEOLOGY; VISCOSITY; POLYSACCHARIDES; TEMPERATURE; DEGRADATION; GELS,"Drilling and completion operations in HP/HT environments demand the use of environmentally friendly fluids with suitable properties such as solid-free high-density and pseudoplastic behavior. Xanthan gum solutions in different brines may be an interesting alternative to ensure a suitable thermo-rheological behavior and biodegradability. Nevertheless, xanthan exposed at high temperature experiences thermal degradation that can modify the flow properties over time and limits the ceiling temperature of oilfield applications. To gain insight on this issue, this paper characterizes the flow behavior of low concentration XT solutions in calcium and potassium brines, evaluating the effect that potassium formate exerts on both the flow properties and the resistance to thermal degradation of xanthan solutions as a function of the biopolymer concentration. Xanthan in formate brine retains the pseudoplastic behavior up to 190 degrees C, however, low concentrate solutions undergo a thermal degradation that decreases the recovery of pseudoplasticity after being exposed to high temperature.",9,9,1
Drilling,High Temperature,"Zhang, Zengzeng; Zhao, Dajun; Zhao, Yan; Zhou, Yu; Tang, Qiongqiong; Han, Junpeng",Simulation and experimental study on temperature and stress field of full-sized PDC bits in rock breaking process,Full-sized PDC bits; Temperature field; Stress field; Finite element simulation,THERMAL RESPONSE; CUTTERS; FORCE; WEAR; REDUCTION; FRACTURE; FATIGUE; SURFACE; STATE; MODEL,"The failure rate of polycrystalline diamond compact (PDC) bits mainly depended on the cutting temperature and the force of the cutting teeth. It was of great value to study the distribution of temperature and stress fields on the PDC cutting teeth during rock breaking for exploring the failure mechanism and improving the service life of the bits. In this paper, the finite element was used to simulate the thermal-structural coupling of rock breaking process of the full-sized PDC bits. The simulation results show that the high temperature region of the cutting teeth was offset from the top of the crown to the outside of the cutting teeth during drilling process, and the high temperature region of the cutting teeth was fan-shaped. The failure reason of PDC cutting teeth was analyzed by simulation. The maximum principal stress of PDC cutting teeth existed in the interface between the polycrystalline diamond (PCD) layer and the cemented carbide (WC-Co) substrate, fracture and delamination were concentrated at the top of the cutting teeth crown. The experimental results show that the temperature of cutting teeth when drilling the granite was about 2 times that of the marble and 3 times that of the sandstone under the same conditions. The simulation results were basically consistent with the experimental results, which verified the accuracy of the finite element model simulation analysis method.",8,9,11
Drilling,High Temperature,"Xiong, Chao; Huang, Zhongwei; Yang, Ruiyue; Sheng, Mao; Shi, Huaizhong; Dai, Xianwei; Wu, Xiaoguang; Zhang, Shikun",Comparative analysis cutting characteristics of stinger PDC cutter and conventional PDC cutter,Stinger PDC cutter; Cutting characteristics; Single cutter tests; Rock-breaking mechanism,ROCK; TEMPERATURE; BREAKING; GRANITE; SURFACE; FORCE,"The Stinger PDC cutter has a better performance than the conventional PDC cutter drilling for hard, interbedded and highly abrasive rocks. Although researchers have investigated the cutter's characteristic, such as impact resistance, wear resistance and cutter's life, the cutting behaviors of the Stinger PDC cutter still remains unclear. In this study, the single cutter tests were carried out with a Stinger PDC cutter and a conventional PDC cutter as comparisons. The cutting force, cuttings size, surface topography along the cutting trajectory and microscopic morphology of the fracture surface were compared and analyzed. The results show that the average cutting force of a Stinger PDC cutter is 46.14% lower than that of a conventional PDC cutter. The proportion of large cuttings (r > 2.36 mm) generated in the Stinger PDC cutter test is higher than that in the conventional PDC cutter test. In addition, the energy consumption of breaking rocks by a Stinger PDC cutter is 34.09% lower than that by a conventional PDC cutter. The cutting trajectory in the Stinger PDC cutter test has a ""V"" shape and the surface is relatively rough (Sa = 617.08 mu m), while the conventional PDC cutter produces a ""U"" shape cutting trajectory and the surface is relatively smooth (Sa = 462.18 mu m). Furthermore, the SEM analysis shows that the Stinger PDC cutter breaks granite mainly by tensile stress, which is different with the conventional PDC cutter by shear stress. The key findings of this work will help to reveal the rock-breaking process and mechanism with the Stinger PDC cutters.",8,8,7
Drilling,Gamma Ray,"Oloruntobi, Olalere; Butt, Stephen",Application of specific energy for lithology identification,Hydromechanical specific energy; Lithology; Rate of penetration; Drilling; Bit,MECHANICAL SPECIFIC ENERGY; PORE-PRESSURE; ROCK,"The previous applications of specific energy to drilling operations have focused mainly on drilling optimization and identification of inefficient drilling conditions. Recent advances in specific energy extend its applications to overpressure detection and pore pressure prediction. In this paper, an attempt is made to further extend the application of specific energy to real-time identification of subsurface lithology. The concept is based on the principle that the total energy required to break and remove a unit volume of rock is a function of lithology. The proposed methodology is tested using a recently drilled exploratory gas well in the tertiary deltaic system of the Niger Delta basin. In general, an excellent agreement is observed in trend between the traditional lithology identifiers (gamma ray and sonic velocity ratio) and the total energy consumed in breaking and removing the penetrated rocks. Unlike the logging while drilling (LWD) technique commonly employed in the industry (including the application of near bit sensors placed few feet behind the bit), the proposed methodology can provide a reliable means of picking formation tops and identifying subsurface lithology at the bit with no extra cost since drilling parameters are routinely recorded at the wellsite during the drilling of a well. The proposed methodology will assist the drilling engineers and geologists in determining the casing setting depths and coring points without having to drill too deep into the formation of interest.",14,15,2
Drilling,Gamma Ray,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Drilling,Gamma Ray,"Osarogiagbon, Augustine Uhunoma; Oloruntobi, Olalere; Khan, Faisal; Venkatesan, Ramachandran; Butt, Stephen",Gamma ray log generation from drilling parameters using deep learning,Deep learning; Logging while drilling; Measurement while drilling; Lithology; Drilling parameters; Gamma ray log; NARX; RNN; TCN; LSTM; GRU; ANN,NEURAL-NETWORKS; PREDICTION,"Lithology identification plays a vital role in defining the petroleum reservoir. Although well logging represents the traditional means of obtaining petrophysical data for lithology identification, there could be cases where logging while drilling instruments may fail during drilling. This paper presents an approach that utilizes drilling parameters obtained from mud logging and measurement while drilling (MWD) for real-time prediction of gamma ray log which is used as a lithology identifier. In this work, several machine learning methodologies, such as simple recurrent neural network (RNN), long short-term memory recurrent neural network (LSTM-RNN), temporal convolution network (TCN), gated recurrent unit (GRU) network, nonlinear autoregressive network with exogenous inputs (NARX) and simple artificial neural network (ANN) were tested for their ability to capture the relationship between hydro-mechanical specific energy (computed from drilling parameters) and gamma ray log. A recently drilled exploration gas well in the tertiary deltaic system of the Niger delta basin was used as the case study. Based on the field data, the results show the TCN and simple RNN performed best. The receptive field of the TCN played a significant role in its performance, and therefore, the LSTM-RNN can be made to perform comparable to that of TCN/simple RNN if the LSTM-RNN is manually made to work with an optimal window of input data points for each output data point. The size and nature of the data (volume, velocity, variety, and veracity) is likely a significant factor in the performance of the machine learning methodologies. Thus, it is recommended to focus on obtaining the best receptive field of the data during the machine learning development phase.",9,9,8
Drilling,Gamma Ray,"Siddiqui, Numair A.; Mathew, Manoj J.; Ramkumar, M.; Sautter, Benjamin; Usman, Muhammad; Rahman, Abdul Hadi Abdul; El-Ghali, Mohamed A. K.; Menier, David; Zhang Shiqi; Sum, Chow Weng","Sedimentological characterization, petrophysical properties and reservoir quality assessment of the onshore Sandakan Formation, Borneo",Sedimentology; Petrography; Petrophysics; Reservoir quality; Sandstone heterogeneity; Borneo,OUTCROP ANALOG; GRAIN-SIZE; SANDSTONE; BASIN; HETEROGENEITY; ARCHITECTURE; EXAMPLE; FACIES; MEMBER,"Sedimentological parameterization of rock heterogeneity and prediction of shallow-marine siliciclastic reservoir quality remains a challenge globally to date, especially in regions with complex depositional histories, in that, variations in petrographic and petrophysical properties can occur within the same sedimentary sequence of similar age and rock type. Because exploratory drilling strategies and reservoir models can significantly be augmented through direct observation of outcrops that are representative of equivalent reservoir stratigraphic intervals in the offshore zone, outcrop sedimentological characterization can help improve the understanding of subsurface reservoirs of similar strata in surrounding petroliferous basins. To this end, we analyzed well-exposed successions of the mid Mio-Pliocene shallow-marine sandstone deposits of the Sandakan Formation, Borneo, through conventional field investigation, petrographic and petrophysical studies of different sandstone facies types to predict reservoir quality and heterogeneity within different depositional settings. On the basis of these evaluations, the studied sandstone was grouped into three qualitative reservoir rock classes: Class I ((sic) = 18.10-43.60%; K = 1265.20-5986.25 mD), Class II ((sic) = 17.60-37%; K = 21.36-568 mD) and Class III ((sic) = 3.4-15.7%; K = 3.21-201.30 mD). The petrographic and petrophysical results reveals a consistent rise in both gamma ray and permeability values due to a change in depositional environment from proximal lower shoreface to upper shoreface of some successions within the sequence. The change in depositional setting for each sandstone type establishes certain variation in classes within the same facies type. For instance, the permeability may indicate low values due to the presence of bioturbation and increased mud content owing to the burrows with bimodal grain classification, regardless of change in gamma ray readings. This phenomenon signifies that there exists no strict correlation between gamma ray and permeability profile despite containing good quality reservoir rocks and appropriate classification. Our study is of paramount significance to the development of initial exploration strategies in regions where similar siliciclastic strata can be potential reservoirs because it serves as analogs to offshore hydrocarbon bearing packages.",8,8,2
Drilling,Mechanical Properties,"Zhu, Xiaohua; Luo, Yunxu; Liu, Weiji",On the rock-breaking mechanism of plasma channel drilling technology,Plasma channel drilling; High-voltage electric pulse; Rock-breaking mechanism; Formation pressure; Cracks; DEM,BONDED-PARTICLE MODEL; BREAKDOWN; LIBERATION; FRAGMENTATION; DESTRUCTION; ENERGY; ORES,"Plasma channel drilling (PCD), which is also known as high-voltage electric pulse drilling, is a highly efficient rock-breaking drilling technology with great development potential. This paper presents a method to study the rock-breaking mechanism of PCD technology. Then based on the predecessor's foundation, the factors affecting the development of plasma channels are explored using the dielectric breakdown model (DBM). Finally, a numerical rock-breaking model considering electric-thermal-mechanical three fields is established. This paper reveals the basic rock-breaking process of PCD and how the formation pressure affects the rock-breaking process of PCD technology. The main conclusions are: the formation law of plasma channel is related to the electrode structure and the inputting electrical parameters, the electrical properties of the rock and the type of rock; the plasma channel has an internal dynamic effect on the rock breaking process, and this internal dynamic effect of the plasma channel is sharply weakened after the channel is formed; shear cracks play a lead role in PCD, and the number of shear cracks is larger than that of conventional mechanical-rotary drilling; the formation pressure has little effect on the rock failure, the total volume of the chips, and the total number of cracks in the PCD, and the rock-breaking efficiency is not limited by the drilling depth. Finally, in order to improve the rock breaking-efficiency, it is recommended that the PCD technology be used in conjunction with slim hole drilling technology or jet drilling technology.",13,13,10
Drilling,Mechanical Properties,"Li, Yanliang; Peng, Jianming; Bo, Kun; Huang, Chaoyang; Zhang, Yanjun; Zhang, Pengyu",Analysis on the mechanical properties of granite rock near the wellbore after percussive drilling and AWJ perforation,Percussive drilling; AWJ perforation; Impact fractures; Mechanical properties; Critical distance,HIGH-TEMPERATURE; FLUIDIC HAMMER; FRACTURE; INDENTATION; MICROSTRUCTURE; PENETRATION; SIMULATION,"Rock properties near the wellbore are particularly important for the development of geothermal wells, but few people have studied them. The mechanical properties of granite rock near the wellbore after percussive drilling and abrasive water jet (AWJ) perforation are analyzed and studied in this paper. The variation of P-wave velocity, stress-strain curve, tensile strength, uniaxial compressive strength, peak strain, elastic modulus, microscopic appearances of fractures with the distance from the wellbore is studied. The purpose is to provide theoretical and technical support for fracturing and perforation in geothermal resource development. The experimental results indicate that percussive drilling can generate a large number of impact fractures near the wellbore, which can reduce the mechanical properties of granite rock near the wellbore. Compared with the granite after conventional rotary drilling, the p-wave, tensile strength, compressive strength and elastic modulus of granite after percussive drilling can be reduced by 87.3%, 55.10%, 38.32%, 66.67%, respectively. In addition, we find that AWJ perforation can only produce a few fractures, that is to say, its effect on the mechanical properties of rock is not significant. The percussive drilling effect on the mechanical properties is much more intense than AWJ perforation. Percussive drilling can affect the wellbore in a range of 1.2-1.5 times the diameter of the wellbore, while AWJ perforation can affect the wellbore in a range of 0.4-0.6 times the diameter of the wellbore. On the other hand, although AWJ perforation cannot change the mechanical properties of granite rock near the wellbore significantly, the secondary fractures produced by AWJ perforation can connect the impact fractures produced by percussive drilling, forming crushed zones. It demonstrates that the assistant technique of percussive drilling can be a potential solution for the stimulation enhancement of geothermal resources.",10,10,10
Drilling,Mechanical Properties,"Feng, Shangxin; Wang, Yujie; Zhang, Guolai; Zhao, Yufei; Wang, Shanyong; Cao, Ruilang; Xiao, Enshang",Estimation of optimal drilling efficiency and rock strength by using controllable drilling parameters in rotary non-percussive drilling,Rock drilling; Specific energy; Drilling-monitoring system; Rate of penetration; Torque; Rock strength,MECHANICAL SPECIFIC ENERGY; DRILLABILITY PREDICTION; INDEX,"Fundamental rock-drilling studies are aimed at optimizing the drilling efficiency by identifying the optimal drilling conditions and rock drillability. In this study, a field-drilling test is performed using a rotary non - percussive drilling machine equipped with a new drilling-monitoring system to investigate the effects of dril ling parameters on the specific energy (SE) and rate of penetration (ROP). During the drilling test, different thrusts (8.5-70 kN) and rotation speeds (40-400 r/min) are applied on a predrilled borehole re-injected with pure concrete. The magnitudes of the thrust, torque, ROP, and rotation speed are measured simultaneously by the new drilling-monitoring system to calculate the changes in SE. A modified SE model, which only includes a few controlled drilling parameters, is then proposed to determine the optimal drilling conditions. The results first show that torque has a linear relationship with thrust but shows no obvious changes with respect to the rotation speed. According to the energy balance principle in rock drilling and the relationship between SE and ROP, the optimal drilling efficiency with the maximum attainable ROP is then innovatively identified around the lower point of the second reduction in SE. In conclusion, the slope of the linear relationship between the thrust and penetration rate per revolution is only related to the rock properties and can be used to define the strength parameters of stratification by using the measured drilling parameters.",8,8,8
Drilling,Mechanical Properties,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Drilling,Plastic Viscosity,"Hajiabadi, Seyed Hasan; Bedrikovetsky, Pavel; Mahani, Hassan; Khoshsima, Ali; Aghaei, Hamed; Kalateh-Aghamohammadi, Mina; Habibi, Shadi",Effects of surface modified nanosilica on drilling fluid and formation damage,Functionalized nanosilica; Rheological behavior; Formation damage; Nano-drilling-fluid,CARBON NANOTUBES; BRINE SALINITY; SILICA; NANOPARTICLES; NANOFLUIDS; COMPOSITE; SIZE; WETTABILITY; VISCOSITY; RHEOLOGY,"Despite the fact that hydrophobic nanosilica can improve the stability of water/oil emulsion, there exist controversies pertaining to its influence on oil-based drilling fluid rheological behavior and the subsequent formation damage. The present study addresses the above using a surface modified nanosilica, where the particles were functionalized with different silane-based groups to alter their hydrophilicity: 3-glycidoxypropyl-triethoxy silane (GPTS) and combined GPTS and propyl silane (PGPTS). The NPs were characterized through FTIR analysis, particle size, and zeta-potential measurements followed by flow behavior experiments, core-scale mud flow tests, Computed Tomography (CT) scanning and SEM imaging techniques to determine the mud penetration depth. We found that, depending on the type of functionalized group and the size of NPs, the surface modification of NPs can enhance the rheological properties and mitigate formation-damage. The most desirable behavior, both in terms of the plastic viscosity and yield stress, was achieved with 15 nm size NPs. The functionalized NP with the 3-glycidoxypropyl-triethoxy silane (GPTS@SiO2), which is less hydrophilic compared with bare NP, improved plastic viscosity of the drilling fluid, however slightly deteriorated the yield stress. This was compensated for by adding a double amount of GPTS on the surface of NP (DGPTS@SiO2), which was shown to be more effective than merely increasing the GPTS content in the drilling fluid. Further improvement of rheological properties was made by combining GPTS and propyl silane (PGPTS@SiO2); implying the positive effect of reducing hydrophilicity on both the plastic viscosity and yield stress. It is noteworthy that surface modifications were identified to be efficient below an optimal concentration of 1 wt% of NPs due to the lack of particle agglomeration. Moreover, a decreasing trend in plastic viscosity was observed against increasing temperature as a result of lowering viscosity of the continuous phase. Meanwhile, the yield stress experienced greater changes versus temperature due to the larger dependency of the interactions between drilling fluids components on temperature. In addition, the results were further validated through a series of core-flow tests which showed that with the aid of the nano-based drilling fluids (NDFs) containing DGPTS@SiO2 and GPTS@SiO2 the penetration depth of mud, thus the degree of internal formation damage can be significantly reduced.",11,10,2
Drilling,Plastic Viscosity,"Sajjadian, Majid; Sajjadian, Vali Ahmad; Rashidi, Alimorad",Experimental evaluation of nanomaterials to improve drilling fluid properties of water-based muds HP/HT applications,Nano materials; Rheological characteristics; Filtration properties; High-pressure; And high-temperature,PERFORMANCE; NANOFLUIDS; RHEOLOGY; BEHAVIOR,"These days, significant investigations are carried out on the preparation of high qualified aqueous-based drilling fluid-structure to create the best option compared with oil-base drilling fluid at high-pressure and high-temperature situations utilizing an optimum cost approach. Nanomaterials may have the desirable possibility of using their favored utilization documented in many publications. Although high cost, due to more concentration and side undesirable effects on one or some mud properties, this situation restricts using these materials in various industries. In this experimental research, an effort was made to enhance the application of water-based drilling fluids by using three kinds of nanomaterials, called zirconium oxide, multi-walled carbon nanotubes and titanium dioxide nanohybrids, and functionalized multi-wall carbon nanotubes. Accomplishing some rheological, filtration characteristics and conductivity experiments on the experimental samples with nanomaterials mentioned manifested that the hybrids and zirconium oxide efficiently improve the drilling fluid rheological parameters including plastic viscosity, yield point and gel strength of the mud with a slow influence on the mud filtrate volume. However, by the multi-walled carbon nanotubes, the filtration properties are remarkably decreased with no undesirable side effects on rheological characteristics, particularly at the 0.5 wt% concentration. Generally, it could be concluded that using the nanomaterials at concentrations up to 0.5 wt% into the water-based mud has the possibility of enhancing rheological and filtration characteristics.",11,11,1
Drilling,Plastic Viscosity,"Ghayedi, Ali; Khosravi, Arezoo",Laboratory investigation of the effect of GO-ZnO nanocomposite on drilling fluid properties and its potential on H2S removal in oil reservoirs,Graphene oxide/ZnO; Nanocomposite; Drilling fluid; Rheological properties; Filtration rate; H2S removal,ZINC-OXIDE NANOPARTICLES; FILTRATION PROPERTIES; GRAPHENE OXIDE; RHEOLOGICAL PROPERTIES; PERFORMANCE; COMPOSITE; CUO,"Drilling fluid loss is one of the basic problems in the drilling industry, which includes 10 to 20 percent of the cost of a drilling operation. It can cause some complications, such as creation of the water in oil emulsion. Furthermore, the presence of toxic hydrogen sulfide (H2S) gas in the excavation formations and the risk of its transfer to the surface, is a hazard to the health of employees on drilling rigs and causes corrosion of surface and subsurface equipment. In this study, the effect of adding Graphene Oxide-Zinc Oxide (GO-ZnO) nanocomposite on the drilling fluid properties and H2S removal were investigated. First, the GO-ZnO nanocomposite was synthesized. After XRD, SEM and EDS characterization tests and assuring the formation of the nanocomposite, drilling fluid samples were prepared by adding different concentrations of GO-ZnO nanocomposite to the base fluid (used in a real reservoir). Then the rheology, filtration, and gas chromatography tests were performed on various fluid samples. The results indicated desirable increases in the rheological properties such as plastic viscosity (5%-28%), yield point (25%-42%) and gel strength (25%-33%) and a significant decrease in the filtration rate. Besides, the results of the chromatographic tests indicated the ability of GO-ZnO nanocomposite to entirely remove the H2S in 15 min.",9,9,2
Drilling,Plastic Viscosity,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Drilling,Contact Angle,"Paswan, Bhola K.; Mahto, Vikas",Development of environment-friendly oil-in-water emulsion based drilling fluid for shale gas formation using sunflower oil,Surfactant synthesis; Rheology; Filtration properties; Zeta potential; Contact; Angle; Interfacial tension,TRIBOLOGICAL PROPERTIES; RHEOLOGICAL PROPERTIES; SURFACTANT; POLYMER; BENTONITE; BEHAVIOR; ADSORPTION; PARTICLES; STABILITY; WEIGHT,"Mineral oils are frequently used for the making of synthetic-based drilling fluids. However, there are several downsides associated with these oils. These mineral oils are non-renewable, toxic in nature, non-biodegradable and prompting towards the incredible expense of waste treatment. In this research article, an anionic surfactant sodium methyl ester sulfonate (SMES) was synthesized using sunflower oil. SMES is then used to formulate environment-friendly oil-in-water emulsion-based drilling fluid. The synthesized surfactant is characterized by FT-IR, H-1-NMR and TGA analysis. The effect of xanthan gum (XG), bentonite, and sodium methyl ester sulfonate (SMES) on the rheology and filtration characteristics of developed emulsion based drilling fluid was analyzed thoroughly. The developed emulsion based drilling fluid had lower friction coefficient in case of oil concentration compared to SMES concentration. The zeta potential has been measured to check the emulsion stability and it has been attended that an increase in the concentration of SMES (0.3-0.7 wt/v %) and xanthan gum (0.2-0.6 wt/v %) has improved the stability of the emulsion. The contact angle and interfacial tension were analyzed and it was observed that interfacial tension was reduced from 102.5 to 25.35 mN/m and contact angle increased from 32.5 degrees to 92.3 degrees. The thermal stability of oil-in-water emulsion based drilling fluid was maintained up to 140 degrees C.",14,14,2
Drilling,Contact Angle,"He, Mingming; Li, Ning; Zhu, Jiwei; Chen, Yunsheng",Advanced prediction for field strength parameters of rock using drilling operational data from impregnated diamond bit,Analytical model; Rock strength parameters; Impregnated diamond bit; Drilling logging data,TOOTH WEAR; ROLLER-BITS; DRAG BITS; CUTTER; MODEL,"Field drilling can be a continuous, fast, and reliable technology to predict the cohesion, internal friction angle, and unconfined compressive strength (UCS) of rock in petroleum engineering. Herein, a theoretical model is established in an impregnated diamond bit considering some effective parameters including friction parameter, crushed zone, and bit geometry parameter. A novel method is proposed to determine field strength parameters including the cohesion, internal friction angle, and UCS of four types of rock using drilling logging data. Many drilling experiments in the field are conducted using a drilling process monitoring apparatus to obtain drilling logging data (thrust force, torque, penetration rate, and rotation speed). Experimental results on weak, medium-strong, and strong rock show that drilling with an impregnated diamond core bit includes two fully dependent and simultaneous processes: rock cutting and frictional contact, the dominant role of which is dependent on the cutting point. The cohesion, internal friction angle, and UCS estimated from the proposed method for the four types of rocks are close to those from standard laboratory tests. This practical method can provide practical, fast, and reliable estimation for field strength parameters of rock and should be highly beneficial to field applications in rock engineering.",11,12,11
Drilling,Contact Angle,"Tabar, Mohammad Azadi; Ghazanfari, Mohammad Hossein; Monfared, Abolfazl Dehghan",Compare numerical modeling and improved understanding of dynamic sessile drop contact angle analysis in Liquid-Solid-Gas system,Size-dependent wettability; Surface free energy; Dynamic contact angle; Calcite; Gibbs free energy; Liquid-solid-gas system,WETTABILITY ALTERATION; LINE TENSION; SIZE DEPENDENCE; RESERVOIR ROCKS; SILICA NANOPARTICLES; WETTING CONDITION; WIDE-RANGE; EVAPORATION; SURFACE; HYSTERESIS,"Dynamic contact angle measurement; as a standard method for surface wettability analysis, is usually conducted through the analysis of sessile drops formed following the low rate injection of fluid from beneath through a drilled hole via an injection needle. However, understanding/characterizing the changes of drop contact angle from the point where the flat solid surface begins is not well discussed yet. Moreover, during the evaluation of size-dependent behavior of contact angle of millimeter-scale drops, the effect of the drilled hole is ignored. In this regard, in the current study, the experimental and thermodynamic characterizations of the sessile drop advancing contact angle measurements for a liquid-solid-air system are presented. To do this, a set of dynamic contact angle experiments for a water-calcite-air system with different devised hole diameters and roughness is conducted, and Gibbs free energy analysis is then utilized to propose a modeling scheme. Experimental results revealed a transient region from zero infinite contact angle at the hole to infinite contact angle of the solid surface, which was equal to 74.61 degrees and 69.05 degrees for nanoscale, and microscale surface roughness. In addition, it was shown that with a decrease in the hole diameter, the transient region met a lower value of contact angle at different dimensionless volumes. The result of higher advancing contact angle measured for the system with smaller drilled hole diameter was attributed to higher contact-line velocity. However, the assumption of low rate advancing contact angle was not violated for the hole diameter larger than 1.4mm. Numerical studies demonstrated that in the case of zero line tension, two straight lines with positive slop could be fitted to the data; attributed to drilled hole effect. Besides, it was concluded that this behavior should not be interpreted as a negative line tension effect. The obtained values of line tension and equilibrium advancing contact angle, as matching parameters, were in agreement with those reported in the previous studies. Results of this work could help for better analyzing the size-dependent behavior of millimeter-scale drop through a suggested size-dependent model.",9,9,0
Drilling,Breakdown Pressure,"Zhu, Xiaohua; Luo, Yunxu; Liu, Weiji",On the rock-breaking mechanism of plasma channel drilling technology,Plasma channel drilling; High-voltage electric pulse; Rock-breaking mechanism; Formation pressure; Cracks; DEM,BONDED-PARTICLE MODEL; BREAKDOWN; LIBERATION; FRAGMENTATION; DESTRUCTION; ENERGY; ORES,"Plasma channel drilling (PCD), which is also known as high-voltage electric pulse drilling, is a highly efficient rock-breaking drilling technology with great development potential. This paper presents a method to study the rock-breaking mechanism of PCD technology. Then based on the predecessor's foundation, the factors affecting the development of plasma channels are explored using the dielectric breakdown model (DBM). Finally, a numerical rock-breaking model considering electric-thermal-mechanical three fields is established. This paper reveals the basic rock-breaking process of PCD and how the formation pressure affects the rock-breaking process of PCD technology. The main conclusions are: the formation law of plasma channel is related to the electrode structure and the inputting electrical parameters, the electrical properties of the rock and the type of rock; the plasma channel has an internal dynamic effect on the rock breaking process, and this internal dynamic effect of the plasma channel is sharply weakened after the channel is formed; shear cracks play a lead role in PCD, and the number of shear cracks is larger than that of conventional mechanical-rotary drilling; the formation pressure has little effect on the rock failure, the total volume of the chips, and the total number of cracks in the PCD, and the rock-breaking efficiency is not limited by the drilling depth. Finally, in order to improve the rock breaking-efficiency, it is recommended that the PCD technology be used in conjunction with slim hole drilling technology or jet drilling technology.",13,13,10
Drilling,Breakdown Pressure,"Tariq, Zeeshan; Mahmoud, Mohamed; Abdulraheem, Abdulazeez; Al-Nakhli, Ayman; BaTaweel, Mohammed",An experimental study to reduce the breakdown pressure of the unconventional carbonate rock by cyclic injection of thermochemical fluids,Unconventional formation; Breakdown pressure; Thermochemical; Cyclic fracturing; Multiple fractures,HYDRAULIC FRACTURE PROPAGATION; SIMULATION; RESERVOIR; OIL,"Commercial production from unconventional reservoirs needs massive fracturing operations. Therefore, long horizontal wells are drilled, and multi-stage fractures are created to achieve the desirable production rates from these reservoirs. One common and major problem in most of the unconventional reservoirs is the high breakdown pressure due to the reservoir tightness. When fracturing these types of rocks, the hydraulic fracturing operation becomes much more challenging and difficult. In some scenarios reaches to the maximum pumping capacity without generating any fractures. In this study, a new approach to reduce the breakdown pressure of tight rocks is introduced and compared with the conventional method of fracturing. The new method incorporates the injection of thermochemical fluid in a series of cycles to create micro- and macro-fractures. The cyclic experiments performed in this study were concluded with the recording of breakdown pressure in each case. The post-treatment analysis using medical Computerized Tomography (CT) showed that multiple fractures were created due to the pressure pulse created in the thermochemical reaction. Results showed that the breakdown pressure of the rock decreases with the increasing number of cycles. The proposed method of cyclic thermochemical fracturing reduced the breakdown pressure by 33% in one-cycle, 41% in two-cycles, 53.5% in three-cycles, and 69% in four-cycles, when compared with conventional method of fracturing. An empirical relationship is also presented between the number of cycles of thermochemical fluid injection and the breakdown pressure of the rock.",12,12,5
Drilling,Formation Damage,"Hajiabadi, Seyed Hasan; Bedrikovetsky, Pavel; Mahani, Hassan; Khoshsima, Ali; Aghaei, Hamed; Kalateh-Aghamohammadi, Mina; Habibi, Shadi",Effects of surface modified nanosilica on drilling fluid and formation damage,Functionalized nanosilica; Rheological behavior; Formation damage; Nano-drilling-fluid,CARBON NANOTUBES; BRINE SALINITY; SILICA; NANOPARTICLES; NANOFLUIDS; COMPOSITE; SIZE; WETTABILITY; VISCOSITY; RHEOLOGY,"Despite the fact that hydrophobic nanosilica can improve the stability of water/oil emulsion, there exist controversies pertaining to its influence on oil-based drilling fluid rheological behavior and the subsequent formation damage. The present study addresses the above using a surface modified nanosilica, where the particles were functionalized with different silane-based groups to alter their hydrophilicity: 3-glycidoxypropyl-triethoxy silane (GPTS) and combined GPTS and propyl silane (PGPTS). The NPs were characterized through FTIR analysis, particle size, and zeta-potential measurements followed by flow behavior experiments, core-scale mud flow tests, Computed Tomography (CT) scanning and SEM imaging techniques to determine the mud penetration depth. We found that, depending on the type of functionalized group and the size of NPs, the surface modification of NPs can enhance the rheological properties and mitigate formation-damage. The most desirable behavior, both in terms of the plastic viscosity and yield stress, was achieved with 15 nm size NPs. The functionalized NP with the 3-glycidoxypropyl-triethoxy silane (GPTS@SiO2), which is less hydrophilic compared with bare NP, improved plastic viscosity of the drilling fluid, however slightly deteriorated the yield stress. This was compensated for by adding a double amount of GPTS on the surface of NP (DGPTS@SiO2), which was shown to be more effective than merely increasing the GPTS content in the drilling fluid. Further improvement of rheological properties was made by combining GPTS and propyl silane (PGPTS@SiO2); implying the positive effect of reducing hydrophilicity on both the plastic viscosity and yield stress. It is noteworthy that surface modifications were identified to be efficient below an optimal concentration of 1 wt% of NPs due to the lack of particle agglomeration. Moreover, a decreasing trend in plastic viscosity was observed against increasing temperature as a result of lowering viscosity of the continuous phase. Meanwhile, the yield stress experienced greater changes versus temperature due to the larger dependency of the interactions between drilling fluids components on temperature. In addition, the results were further validated through a series of core-flow tests which showed that with the aid of the nano-based drilling fluids (NDFs) containing DGPTS@SiO2 and GPTS@SiO2 the penetration depth of mud, thus the degree of internal formation damage can be significantly reduced.",11,10,2
Drilling,Formation Damage,"Gamal, Hany; Elkatatny, Salaheldin; Adebayo, Abdulrauf; Bageri, Badr",Effect of exposure time on the compressive strength and formation damage of sandstone while drilling horizontal wells,Compressive strength; Formation damage; Barite-water-based drilling fluid; Exposure time; Sandstone formation; Horizontal drilling,WATER; FLUID; FIELD; MODEL; MUD,"Worldwide increase demand for oil and gas led to an evolution in drilling techniques that maximize oil and gas production such as inclined, multilateral, and long horizontal drilling. The interaction of the drilling fluid and mud filtration with the penetrated formation is very critical and very important to be evaluated especially in the case of horizontal drilling where the drilling operation may take more than 20 days. This study aims to assess the effect of exposure time on the changes of the unconfined compressive strength (UCS) while drilling horizontal sandstone formation using water-based drilling fluid. Modified high-pressure high-temperature (HPHT) filter press cell was used to soak Buff Berea sandstone cores with barite-weighted mud under 300 psi differential pressure and 200 degrees F temperature for different periods. Nuclear magnetic resonance (NMR) was used to assess the change of the porosity while the scratch test was conducted to evaluate the changes in the UCS. The obtained results showed that UCS decreased significantly with increasing exposure time. For instance, the UCS was reduced by 18% after 5 days. NMR results confirmed that there was a corresponding increase in formation damage as shown by a progressive decrease in the rock porosity and permeability with time. The exposure time was found to be a controlling factor for both reducing the rock UCS and porosity. The statistical analysis showed that there is an inverse linear relationship (with 0.92 coefficient of determination R-2) between the UCS values vs the extended exposure time. Meanwhile, an approximate logarithmic relationship (with R-2 of 0.98) for estimating the reduction in rock porosity with the exposure time was investigated.",8,8,0
Porous Media,Relative Permeability,"Alqahtani, Naif; Alzubaidi, Fatimah; Armstrong, Ryan T.; Swietojanski, Pawel; Mostaghimi, Peyman",Machine learning for predicting properties of porous media from 2d X-ray images,Machine learning; Convolutional neural network; Digital rock; Rock properties,PORE-SCALE SIMULATION; DIGITAL ROCK; REACTIVE TRANSPORT; NUMERICAL-SIMULATION; MICRO-TOMOGRAPHY; PART I; PERMEABILITY; DISSOLUTION; FLOW; MICROTOMOGRAPHY,"In this paper, Convolutional Neural Networks (CNNs) are trained to rapidly estimate several physical properties of porous media using micro-computed tomography (micro-CT) X-ray images as input data. The tomograms of three different sandstone types are subdivided to create a dataset consisting of 5,262 training images and 2,000 testing images. Porosity, specific surface area, and average pore size of each image are computed. The proposed CNN framework is trained with binary images and greyscale images separately and the corresponding computed properties. The results from testing the model are promising as the relative error in determination of porosity, surface area and average pore size is less than 6% when the model is trained with binary images and less than 7% when greyscale images are used. Other aspects related to model training and optimisation are discussed.",34,34,4
Porous Media,Relative Permeability,"Vipulanandan, C.; Mohammed, A.",Effect of drilling mud bentonite contents on the fluid loss and filter cake formation on a field clay soil formation compared to the API fluid loss method and characterized using Vipulanandan models,Fluid loss; Bentonite; Soil formation; Filter cake; Vipulanandan models,PIEZORESISTIVE BEHAVIOR; ELECTRICAL-RESISTIVITY; RHEOLOGICAL PROPERTIES; SMART,"Quantification of fluid losses and filter cake formations during the drilling operations using water-based muds (WBM) are some of the critical issues related to successful operations. In this study, short term (30 min) and long term (420 min) fluid loss tests on the drilling mud with various amounts of bentonite contents were performed using the API fluid loss device with filter paper and compared it to the field clay soil (porous media) at a pressure of 100 psi (0.69 MPa). The permeability of the saturated clay soil was 0.026 mD, representing a porous formation. Bentonite content in the drilling mud was varied from 2% to 8% (by the weight of water). The field soil and bentonite were characterized using the particle size distribution and X-ray diffraction (XRD) analyses. Bentonite particle size distribution was finer than the field clay soil. Vipulanandan correlation model predicted the changes in the permeability with time in the clay soil with the filter cake formation very well. With the API fluid loss study, the long-term (420 min) fluid losses were about 2.5-4 times greater than the standard fluid loss study of 30 min (short-term). The filter cake thickness was high with the soil formation compared to the API method. Also, the fluid loss per unit area with the API method was higher than the clay soil formation agreeing with the observed differences in the filter cake thicknesses. The Vipulanandan fluid loss model predictions were compared to the API model and it predicted both short term and long term fluid losses very well based on the root mean square error (RMSE) values. Also, the Vipulanandan fluid loss model predicted the maximum fluid losses under various testing conditions.",30,30,8
Porous Media,Relative Permeability,"Wang, Lei; Li, Yanghui; Wu, Peng; Shen, Shi; Liu, Tao; Leng, Shudong; Chang, Yuan; Zhao, Jiafei",Physical and mechanical properties of the overburden layer on gas hydrate-bearing sediments of the South China sea,Overburden; Gas hydrate-bearing sediments; Physical properties; Mechanical properties; South China sea,SURFACE SEDIMENTS; MARINE-SEDIMENTS; POROUS-MEDIA; WATER-FLOW; GEOCHEMISTRY; SLOPE; PERMEABILITY; STABILITY; RESERVOIR; PRESSURE,"Gas hydrate exploitation may trigger the destruction of the overburden structure and settlement of the overburden layer on the gas hydrate-bearing sediments. It is extremely urgent to explore the basic laws governing the physical and mechanical properties of the overburden layers before performing commercial exploitations of hydrates. However, relatively few studies have focused on the physical and mechanical properties of the overburden layer (uppermost similar to 10 m) on the gas hydrate-bearing sediments of the South China Sea. In this research, we studied the physical and mechanical properties of the overburden sediments from this area, including the particle size distribution, the specific surface area, the pore size distribution, the water content, the liquid/plastic limits, and the mineral and chemical compositions of the particles, as well as the strength and deformation characteristics. According to the results, we found that the overburden sediments of the Shenhu area are characterized as well-graded clayey silts and considered to be internally stable and self-filtering. The isothermal adsorption-desorption curve is a Type H3 hysteretic loop, indicating that the shape of the particles occurs primarily in a plate form, and most of the pores are slit-shaped. The plasticity index in this area is relatively lower than that in other areas, which suggests that there is a risk of overburden collapse during the production process of hydrates. The mineral composition of the overburden sediment particles is primarily quartz, plagioclase, calcite and some accessory clay minerals, which can provide guidance for remolding the overburden sediments in the laboratory. The sediments show strain hardening and shear contraction behavior upon shearing; in addition, the established strength criterion will contribute to the formulation of constitutive equations for the overburden sediments, which can be used as essential input parameters in gas hydrate production simulations.",18,20,15
Porous Media,Relative Permeability,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Porous Media,Relative Permeability,"Mehmani, Ayaz; Kelly, Shaina; Torres-Verdin, Carlos","Leveraging digital rock physics workflows in unconventional petrophysics: A review of opportunities, challenges, and benchmarking",Digital rock physics; Pore-scale modeling; Unconventional petrophysics; Representative elementary volume; Best practices,ENHANCED OIL-RECOVERY; PORE-SCALE; RELATIVE PERMEABILITY; POROUS-MEDIA; MULTISCALE; SHALE; FLOW; GAS; MICROPOROSITY; IMBIBITION,"Digital rock physics (DRP), via both direct numerical simulation and pore-network modeling, holds great promise in terms of probing such pore-scale controls on transport, particularly with multiphase flow and sensitivity analysis of time-intensive measurements such as relative permeability. However, despite advances in micro-computed tomography (microCT) and scanning electron microscopy (SEM) techniques, obtaining cost-effective representative elementary volumes (REV) at sufficient resolution that capture dual-scale porosity and surface textures remains a formidable challenge in establishing digital rock physics as a predictive toolset. Furthermore, implementers are faced with several options of numerical solvers such as finite element method, lattice Boltzmann method, and mass balance-based pore-network modeling. This paper reviews the current status of establishing an REV and upscaling techniques for DRP in tight and/or diagenetically-altered rocks, highlighting successful and unsuccessful pore-to-core data benchmarking examples by the authors and the greater literature in terms of static and dynamic properties. The review finds that performing DRP on a single image modality is not sufficient, even for many conventional rocks, and that it is crucial to interface with experimental data, be it core analysis deliverables or subpore-scale and Darcy-scale microfluidics. In unconventional rocks, the majority of work does not leverage mesoscale simulations, instead zooming in to a discrete pore-scale scenario that is often not benchmarked with SCAL data. Even when a simulation domain is benchmarked, the matching of a discrete case with a multivariable situation is non-unique. Benchmarking with dynamic or pseudo-dynamic core data such as MICP and single phase perm will greatly help reduce variables. Finally, this paper offers a technical roadmap for the robust application of unconventional DRP for the petrophysical and general subsurface community.",11,11,3
Porous Media,Relative Permeability,"Yang, Qianhong; Yao, Jun; Huang, Zhaoqin; Zhu, Guangpu; Liu, Lijun; Song, Wenhui",Pore-scale investigation of petro-physical fluid behaviours based on multiphase SPH method,Multiphase flow; Contact line dynamics; Porous media; Smoothed particle hydrodynamics; Enhance oil recovery,SMOOTHED PARTICLE HYDRODYNAMICS; LATTICE BOLTZMANN SIMULATION; OPEN-CHANNEL FLOWS; DELTA-PLUS-SPH; POROUS-MEDIA; RELATIVE PERMEABILITY; CONSERVATION PROPERTIES; 2-PHASE FLOW; MODEL; WETTABILITY,"In this work, a series of microscopic simulations are conducted to investigate the effect of wettability, flow rate and surface tension in porous system by using pairwise force smoothed particle hydrodynamics (PF-SPH) method. Firstly, a novel inflow and outflow boundary is introduced in the SPH framework. The overall proposed model is verified by two benchmarks. The test cases are run in the two dimensional heterogeneous porous media. The effect of wettability, flow rate and surface tension to the macroscopic parameters such as relative permeability and residual oil saturation are thoroughly examined. Through our simulations, we conclude that (i) the type of residual oil changes with contact angle; water wetting porous media has a higher level of waterless oil recovery period and the discrepancies of ultimate oil recovery efficiencies happen before water phase breaks through the outlet of porous media; the residual oil saturations present excellent linear correlations with contact angles; (ii) it's better to increase the flow rate at the high water cut stage (eg f(w) = 90%) in hydrophilic porous media and rise the flow rate at early water cut stage (eg f(w) = 0%) in lipophilic porous media; increasing the flow rate dramatically shortens the effective production time in strong oil wetting porous media; (iii) decreasing the surface tension could change the type of residual oil, which leads to the further extraction of oil film and cluster residual oil.",11,11,1
Porous Media,Relative Permeability,"Lucas-Oliveira, Everton; Araujo-Ferreira, Arthur G.; Trevizan, Willian A.; Coutinho dos Santos, Bernardo C.; Bonagamba, Tito J.",Sandstone surface relaxivity determined by NMR T-2 distribution and digital rock simulation for permeability evaluation,NMR; Surface relaxivity; Permeability; Pore size; Sandstone; Digital rock,NUCLEAR-MAGNETIC-RESONANCE; POROUS-MEDIA; DIFFUSION; POROSITY,"Many of the world's oil reservoirs are sandstones and some equations have been widely explored to estimate their permeability from NMR measurements, especially those based on the Schlumberger Doll Research (SDR) and Timur-Coates models. In both cases, the permeability is assumed to be related to pore sizes. Brownstein and Tarr showed that, under fast diffusion regime, the NMR transverse relaxation time is proportional to the pore size and the proportionality constant is defined by the interaction fluid/surface and represented by the surface relaxivity rho. However, although there are several methods in the literature to estimate rho, no standard methods have been established so far, to our knowledge. In this work, we estimated surface relaxivity by combining experimental and simulated NMR data using a recently developed computational method to emulate the NMR signal of fluids within Digital Rocks. In addition, we analyzed the correlation between the pore radii and the experimentally measured gas permeability. Comparing Schlumberger and Timur-Coates models for permeability prediction, we propose that the macro and microporosity intensities identified in the T-2 distribution are correlated with characteristics of the sandstone surface. Thus, sandstone surface relaxivity can be estimated using the ratio of macro and microporosity intensities from NMR and, consequently, the pore size distribution can be obtained using only T-2 distribution data.",10,10,11
Porous Media,Relative Permeability,"Wei, Shiming; Jin, Yan; Xia, Yang; Lin, Botao",The flowback and production analysis in sub-saturated fractured shale reservoirs,Sub-saturated shale reservoirs; Flowback; Production; Gas-water flow; Discrete fractures,DISCRETE-FRACTURE; 2-PHASE FLOW; GAS-FLOW; HYDRAULIC-FRACTURE; TRIPLE-CONTINUUM; NUMERICAL-METHOD; HORIZONTAL WELL; POROUS-MEDIA; MODEL; SIMULATION,"The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced ""skin factor"" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model.",10,10,3
Porous Media,Relative Permeability,"Hosseinzadeh, Sirous; Kadkhodaie, Ali; Yarmohammadi, Saeed",NMR derived capillary pressure and relative permeability curves as an aid in rock typing of carbonate reservoirs,Relative permeability; Capillary pressure; NMR; Hydraulic flow units; Ilam formation; Abadan plain,NUCLEAR-MAGNETIC-RESONANCE; INTELLIGENT SYSTEMS; ILAM FORMATION; POROUS-MEDIA; GAS-FIELD; FRAMEWORK; STRESS; LOGS; OIL,"Capillary pressure together with relative permeability curves are key parameters in carbonate reservoirs characterization. They serve as fundamental inputs in petrophysical and reservoir engineering studies such as rock typing, fluid contacts determination and saturation height function generation. In the current study, the NMR-T2 distribution diagrams were inverted to the synthetic capillary pressure and relative permeability curves. The results were compared to the laboratory-derived MICP and Kr curves and a satisfactory agreement was achieved between them. Afterwards, the reservoir rock types were determined from the integration of Conventional Core Analysis(CCAL) results with the NMR-derived Pc and Kr curves. Accordingly, the studied carbonate rocks were classified into four hydraulic flow units. Subsequently, a representative capillary pressure and relative permeability curve was derived for each hydraulic flow unit. The methodology is investigated through a case study of the upper Cretaceous Ilam Formation in the Abadan Plain. The results of this study demonstrated that NMR log contributes to a more precise carbonate reservoirs characterization and reducing uncertainty in reservoir rock typing. Through performing some additional computations and calibration with the core results, worthy information is extractable from NMR log.",10,9,2
Porous Media,Relative Permeability,"Andersen, Pal Ostebo; Nesvik, Eirik K.; Standnes, Dag C.",Analytical solutions for forced and spontaneous imbibition accounting for viscous coupling,Viscous coupling interactions; Spontaneous imbibition; Forced imbibition; Capillary forces; Universal time scale,MIXTURE THEORY APPROACH; 2-PHASE FLOW; POROUS-MEDIA; COUNTERCURRENT IMBIBITION; OIL-RECOVERY; COCURRENT; FLUID,"Fluid-fluid momentum transfer can cause higher flow resistance when fluids flow in opposite directions as compared to the same direction. Conventional modelling of flow in porous media using simple, saturation dependent relative permeabilities does not account for such variations. We consider a generalized theory for multiphase flow in porous media based on mixture theory, where fluid mobilities follow from water-rock, oil-rock and water-oil interaction terms defined in momentum equations. Under strictly co- or counter-current flow modes, the generalized model produces explicit relative permeability expressions dependent on the flow mode, saturations, viscosities and interaction parameters. New expressions for counter-current relative permeabilities are derived assuming zero net flux, representative of counter-current spontaneous imbibition. These functions are compared to previously derived co-current relative permeabilities (assuming equal phase pressure gradients). The functions are incorporated into analytical solutions for forced and spontaneous imbibition (FI and SI) using the theory by Buckley and Leverett (1942) and McWhorter and Sunada (1990), respectively. Our results show that when accounting for viscous coupling; Counter-current relative permeabilities are always lower than co-current ones, including the end points. Both phase curves are reduced by the same saturation dependent coefficient. Increased viscous coupling in the FI case led to a more effective displacement, seen as an increased front saturation and average water saturation behind the front. For counter-current SI, increased viscous coupling resulted in lower imbibition rate. Increased viscosities reduces both oil and water countercurrent relative permeabilities, and predict greater reduction in imbibition rate than only modifying the viscosities. The analytical solutions for SI were in agreement with numerical solutions of both a conventional and generalized model. The solutions for SI could be scaled exactly to a square root of time curve for arbitrary input parameters in the generalized model, especially including the strength of viscous coupling.",10,10,1
Porous Media,Relative Permeability,"Valdez, Andres Ricardo; Rocha, Bernardo Martins; Chapiro, Grigori; dos Santos, Rodrigo Weber",Uncertainty quantification and sensitivity analysis for relative permeability models of two-phase flow in porous media,Relative permeabilities; Uncertainty quantification; Sensitivity analysis; Polynomial chaos expansion,ACCURACY,"Computer simulations are usually employed for the prediction of oil reservoir performance under different extraction scenarios. Computational model parameters are adjusted to petrophysical properties of the reservoir and production data to forecast production profiles. However, some key features of these models, such as relative permeabilities of water and oil, are difficult to measure experimentally. As a consequence they can be considered a source of uncertainties, affecting the reliability of predictions. This work presents a study of uncertainty quantification and sensitivity analysis of different relative permeability models to assess the effects of input uncertainty on quantities of interest computed from a model of two-phase flow of water and oil. To explore different wettability regimes two different datasets were used, and two permeability models were employed. The probability distributions of parameters were estimated via the Markov Chain Monte Carlo method. Uncertainty propagation and sensitivity analyses were performed using the polynomial chaos expansion. The paper highlights output quantities that were most impacted by uncertain input data, and also the parameters which most contribute to the output variances.",10,11,1
Porous Media,Relative Permeability,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Porous Media,Relative Permeability,"Deng, Xuejing; Feng, Jianwei; Pan, Shaowei; Wang, Zhiyuan; Zhang, Jianbo; Chen, Weiqing",An improved model for the migration of fluids caused by hydrate dissociation in porous media,Methane hydrate; Nature gas hydrate; Dissociation; Multiphase flow in porous,NATURAL-GAS PRODUCTION; METHANE HYDRATE; BEARING SEDIMENTS; RELATIVE PERMEABILITY; WATER PERMEABILITY; DOMINATED SYSTEMS; PREDICTION MODEL; MASS-TRANSFER; SURFACE-AREA; DEPRESSURIZATION,"Natural gas hydrates may be the world's future resources, but extracting from the reservoirs involves accurately understanding the transport mechanism of the fluids caused by hydrate dissociation. In this paper, based on Darcy's unsaturated soil mechanics theory, we establish a coupling model of two-phase flow and heat transfer caused by hydrate dissociation, which considering methane gas compressibility and capillary force naturally. The new model is validated through Masuda's test dataset, and notably, the experimental phenomenon of the small peak in the gas pressure of the far-end boundary (Run 4) is reproduced for the first time. Additionally, an implicit function of pore pressure and time in the initial stage of hydrate dissociation is deduced to interpret the in-situ pore accumulation of the gas generated in dissociation, which leads to a more comprehensive description of the migration mechanism of hydrate reservoir fluids. Furthermore, the initial hydrate saturation of the Run 4 sample in Masuda's test is proved to be closer to 0.501 instead of 0.443 that the author reported, which can help Masuda's test dataset being a benchmark for the hydrate dissociation researching in future. Thus, this work provides further insight into the migration mechanism of the gases caused by hydrate dissociation and services practical support for efficiently and safely extracting methane gas from the hydrate reservoirs.",8,8,6
Porous Media,Relative Permeability,"Kumar, Amit; Mandal, Ajay",Core-scale modelling and numerical simulation of zwitterionic surfactant flooding: Designing of chemical slug for enhanced oil recovery,Enhanced oil recovery; Zwitterionic surfactant; Core flooding; Simulation; CMG-STARS,,"Surfactant flooding is a proven enhanced oil recovery method for the recovery of trapped crude oil from the pores of the reservoir. In the present study, the applicability of a synthesized zwitterionic surfactant as an efficient EOR agent was tested, in terms of its interfacial tension reduction capability, emulsification behavior, and wettability modification behavior. Core flooding experiments conducted in sandstone core with the injection of 0.3 pore volume of chemical slug after water flooding showed 20% of additional oil recovery. The core flooding experiment was simulated using CMG-STARS simulator and history matching of relative permeability curve and its interpolation parameters were done. The validated model closely represented the experimental core flooding with very low error of 6%. The validated model helps in understanding the movement of crude oil and its interaction with the injected surfactant slug in the porous media. The validated model was further used for optimization of injected chemical slug by varying the parameters such as the surfactant concentration in the injected slug, the volume of injected chemical slug, and the injection rate of chemical slug. Each parameter had different effects on the oil recovery efficiency and cumulative oil recovery of more than 90% OOIP was obtained using model with injection of 1 PV of chemical slug containing 100 ppm of surfactant with the injection rate of 0.3 mL/min. The simulation of core flooding helped in optimization of crude oil production by zwitterionic surfactant and its implementation on field scale production by zwitterionic surfactant flooding.",8,8,4
Porous Media,Relative Permeability,"Mehrabianfar, Parviz; Malmir, Pourya; Soulgani, Bahram Soltani; Hashemi, Abdolnabi",Study on the optimization of the performance of preformed particle gel (PPG) on the isolation of high permeable zone,Preformed particle gel (PPG); Water diversion; Fractured reservoir; Glass micromodel; Water control,WATER PRODUCTION COST; CONFORMANCE-CONTROL; TRANSPORT,"Unwanted water production is a critical problem in fractured reservoirs. Corrosion of facilities and reduction of oil relative permeability are some of the consequences of high water production. Preformed particle gel (PPG) injection is one of the conformance control methods, which initiated in 2007, has been used to control water production and increase sweep efficiency. There are several parameters which affect the performance of PPG such as stability at reservoir condition, salinity of makeup solution and PPG particle size and concentration. Although the study of the application of PPG in fracture plugging attracted a lot of attention in recent years, there are limited studies to investigate the effect of PPG physical properties on its application in water production control. In this study, the application of a super absorbent polymer on fracture plugging has been investigated. The results of swelling tests indicated that this type of PPG had significant high resistance even at high temperatures and wide range of salinities. In addition, the results of rheology tests showed that the PPG solution was stable even at high salinity and high shear rate condition. In order to study the mechanism of improvement of sweep efficiency through PPG injection, visual investigation using glass etched micromodel was performed. The results showed that the main mechanism for PPG treatment is water diversion into the low permeability zone as the consequence of fracture plugging. Also, core flooding tests were performed to check the performance of PPG in a heterogeneous carbonate porous media. According to the results, PPG was able to reduce the permeability, and this permeability reduction is related to swelling ratio which is controlled by makeup solution salinity. The results of this study revealed the potential of super absorbent polymers as preformed particle gel in unwanted water production through fracture plugging.",8,8,4
Porous Media,Water Flooding,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Water-oil interfacial tension (IFT) reduction and wettability alteration in surfactant flooding process using extracted saponin from Anabasis Setifera plant,Surfactant flooding; Saponin; Interfacial tension (IFT); Wettability alteration; Chemical enhanced oil recovery; Anabasis Setifera,DISSOLVED CARBON-DIOXIDE; LEAF-DERIVED SURFACTANTS; SMART WATER; POROUS-MEDIA; CO2 FOAM; RECOVERY; IONS; INJECTION; RESERVOIR; EMULSIFICATION,"Surfactants are known as interfacial tension (IFT) reducer additives in enhanced oil recovery (EOR) process. The use of chemical surfactants has always been a challenge due to the high cost of materials and sometimes noncompliance with the environment. Hence, researchers are looking for alternative ways to make them cheap and affordable. Herbal extracts that combine some surfactants, such as saponins, are a new source for replacing with expensive chemical surfactants. In this study, Anabasis Setifera plant was used as a source of natural surfactant supply. Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance ((HNMR)-H-1) and thermal gravimetric analysis (TGA) were performed to characterize and determine the temperature stability, as well as surface tension tests for estimating the critical micelle concentration (CMC) of saponin extracted from Anabasis Setifera. In addition, pendant drop water-oil IFT test, contact angle test, and flooding of surfactant solution at CMC and optimum salinity were performed to study the application of the natural surfactant in EOR process. The effects of NaCl, KCl, CaCl2, MgCl2, FeSO4, K2SO4 and NaHCO3 salts and formation water salinity were investigated at different concentrations on the IFT and contact angle. The results show that the surfactant is more effective than conventional plant extracts and in combination with chemical surfactants and an IFT value of 1.066 mN/m was obtained at CMC. The contact angle tests also show the capability of this surfactant to alter the wettability to a poor water-wetting (a contact angle of 56.51. Ultimately, an oil recovery of 15.4% was obtained by flooding of the surfactant solution at CMC and optimum formation water salinity.",37,37,18
Porous Media,Water Flooding,"Wang, Yanwei; Liu, Huiqing; Zhang, Qichen; Chen, Zhangxin; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Pore-scale experimental study on EOR mechanisms of combining thermal and chemical flooding in heavy oil reservoirs,Viscosity reducer; Steam flooding; Foam; Visualized experiments; Mechanisms analysis,CYCLIC STEAM STIMULATION; CRUDE-OIL; VISCOSITY REDUCTION; FOAM-GENERATION; RECOVERY; EMULSIONS; INJECTION; FLOW; ASPHALTENE; RHEOLOGY,"Steam flooding is an important method for the development of heavy oil reservoirs, but steam channeling is an inevitable serious problem in the process of steam injection, which decreases the sweep efficiency of steam and leads to low oil recovery. Viscosity reducer (VR) flooding and nitrogen foam flooding are two effective methods of enhancing heavy oil recovery with satisfactory results. In this paper, a series of experiments were conducted to evaluate the effects of various factors on the performance of the novel viscosity reducer (VR-A). On this basis, A visualized model was adopted to investigate the synergistic development effect of thermal and chemical flooding, which vividly reflected the interaction of chemical agents with crude oil and their migration characteristics in porous media, as well as the mechanisms of enhancing oil recovery on the pore-scale. The results showed that VR-A could achieve excellent viscosity reduction effect on heavy oil under the influence of various factors, which could be combined with thermal flooding to effectively recover heavy oil. As for the pore-scale level, after the VR-A solution was injected, the interfacial tension between the oil and water was decreased, the wettability of the surface of the particle was changed, and two types of oil-in-water emulsions (spherical emulsions and flocculent emulsions) with a lower viscosity were formed, which were easy to flow with the fluid in pores and throats and could temporarily block the high-permeability area. In the process of foam flooding, the phenomena of bubble coalescence and breakup occurred constantly, and bubbles trapped in the porous media could improve the sweep efficiency of the subsequent fluid. The ultimate oil recovery of the development method combining thermal and chemical flooding in the visualized displacement experiment is 76.9%, 39.7% higher than that of pure thermal flooding. This article can provide an effective method to solve the problem of poor steam flooding performance in heavy oil reservoirs.",19,20,8
Porous Media,Water Flooding,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Porous Media,Water Flooding,"Lang, Liyuan; Li, Huabin; Wang, Xiong; Liu, Ning",Experimental study and field demonstration of air-foam flooding for heavy oil EOR,Heavy oil; Foam; EOR,NITROGEN FOAM; RECOVERY; INJECTION; TEMPERATURE; BEHAVIOR,"Foam flooding is an effective oil displacement technique to improve fluid sweep efficiency and increase oil recovery. The objective of this study is to investigate the application of air-foam for heavy oil recovery under heterogeneous reservoir conditions. The paper first investigated the air-foam flow behavior in porous media and identified the effects of different factors such as gas-liquid ratio, injection rate, and crude oil saturation on air-foam resistance. Then, dual-tube sand-packs were used to evaluate the performance of air-foam for heavy oil recovery from heterogeneous reservoir conditions. The results indicated that the air-foam could divert the fluid from the high-permeability zone to the low-permeability zone, decrease the water cut and improve the oil recovery. Further studies revealed that there existed an optimal reservoir permeability contrast ratio in air-foam flooding for heavy oil recovery. The air foam performance for oil recovery would be reduced beyond or below this permeability contrast ratio. Finally, field tests on air-foam for heavy oil recover demonstrated that air foam flooding could increase heavy oil production rate and decrease the production water cut.",16,17,7
Porous Media,Water Flooding,"Lai, Nanjun; Wen, Yiping; Yang, Zhidong; Chen, Jianlin; Zhao, Xubin; Wang, Dongdong; He, Wei; Chen, Yuemei",Polymer flooding in high-temperature and high-salinity heterogeneous reservoir by using diutan gum,High-temperature; High-salinity; Strong heterogeneity; Diutan gum; Rheological properties; Oil displacement experiments,LASER-LIGHT SCATTERING; HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; WATER-SOLUBLE COPOLYMERS; RHEOLOGICAL PROPERTIES; SOLUTION BEHAVIOR; PROFILE-CONTROL; OIL-RECOVERY; ACRYLAMIDE; DISPLACEMENT; XANTHAN,"Diutan gum, a biopolymer that has been widely used in cement and concrete industries, was introduced in this work to alleviate severe viscosity loss and the poor water solubility of polyacrylamide and its modified products in high-temperature and high-salinity reservoirs. Diutan gum is an exopolysaccharide secreted by sphingomonas. The rheological properties and capacity of diutan gum to enhance oil recovery in high-temperature and highsalinity heterogeneous reservoir (T = 130 degrees C, Total salinity = 223.07 g L-(1), V-k = 0.93) was investigated and compared with those of two other kinds of biopolymer thickeners (xanthan and konjac gum), which are commonly used in oilfield development. The three biopolymers show pseudoplastic fluid properties in a steadystate rheological test: given the strong interactions in the double-helix structure of diutan gum, the number of the Newtonian zone and the shear rate of this zone are higher than the those of the two other biopolymers. The storage modulus (G') of diutan gum are higher than its loss modulus (G '') in all the concentrations and frequencies measured through viscoelasticity tests. This result indicates that diutan gum exhibits remarkable elasticity in slow displacement speed while it seeping in porous media. The capability of establish flow resistance in high-permeability porous medium in high-temperature and high-salinity environment by three biopolymers was studied, and their viscosity and microscopic properties of injected and produced fluid were investigated to understand the reason why diutan gum can have good fluidity control ability. Oil displacement efficiency can be improved by the elasticity of the diutan gum even without an increase in displacement speed. The results of the oil displacement experiments in the heterogeneity model imply that diutan gum is more effective in improving the water injection profile of each layer than xanthan and konjac gum. The water channeling in the high-permeability layer is restrained, and the sweep ability of the displacement phase is improved. Furthermore, the effect of polymer flooding can be maintained for a long time. Under high-temperature, high-salinity and strong heterogeneity, diutan gum recovers 19.34% of original oil in place (OOIP). This value is higher than the values obtained with xanthan gum (14.15% OOIP) and konjac gum (8.60% OOIP). This finding implies that the diutan gum has great application potential in the development of high-temperature and high-salinity reservoirs with strong heterogeneity.",13,12,7
Porous Media,Water Flooding,"Tangparitkul, Suparit; Saul, Alexander; Leelasukseree, Cheowchan; Yusuf, Muhammad; Kalantariasl, Azim",Fines migration and permeability decline during reservoir depletion coupled with clay swelling due to low-salinity water injection: An analytical study,Fines migration; Permeability decline; Effective stress; Reservoir depletion; Low-salinity waterflooding; Fines-assisted waterflood,EXTERNAL FILTER CAKE; OIL-RECOVERY; PORE PRESSURE; FILTRATION; MODEL; PARTICLES; MECHANISM; DETACHMENT; RETENTION; TRANSPORT,"Fines migration is crucial for reservoir permeability, involving both fine particle detachment and re-deposition along the flow channels. Fines migration behavior can either promote or obstruct fluid flow within the reservoir and is crucial for productivity optimization that needs fundamental understanding. The present work focuses on the contributions from effective stress build-up due to reservoir depletion and decreases in brine salinity from low-salinity water injection. Particle detachment is studied analytically by using the critical retention concentration function modified with stress and salinity dependents. Increase in formation effective stress leads to deformations within the reservoir configurations due to micro-cracks and reduced pore dimensions. Decreased size of the travelling channels promotes particle detachment, while the critical retention concentration decreases. A sensitivity study reveals that, under influence of effective stress, particle size and fluid velocity are dominant parameters controlling the fines migration by influencing the particle detaching forces. With decreasing brine salinity (e.g. via low-salinity water injection), clay particles that are attached on the pore surface increasingly swell, leading to reduction in effective pore space and flow channel. Decreased pore space directly obstructs travelling of suspended particles and fluids which results in permeability decline. Initial clay particle size is found to be a critical factor controlling particle detachment behavior. Small initial particle sizes are not likely to detach from the pore surface as a result of weak detaching forces, hence the analysis finds the critical retention concentration unchanged resulting in negligible permeability decline as a function of brine salinity. Considering both effects, effective stress and brine salinity, stress-dependent effects dominate salinity-dependent effects at low effective stress while the two contribute equally at high effective stress. Permeability decline is also determined from analytical results of the fine particle critical retention concentration, which emphasizes the roles of effective stress and brine salinity on the flow in reservoir porous media.",13,12,1
Porous Media,Water Flooding,"Liu, Zhao-xia; Liang, Yan; Wang, Qiang; Guo, Yong-jun; Gao, Ming; Wang, Zheng-bo; Liu, Wan-lu",Status and progress of worldwide EOR field applications,Chemical flooding; Gas injection; Thermal recovery; Smart water flooding; EOR; Field application,PREFORMED PARTICLE GEL; CONFORMANCE-CONTROL; BRINE COMPOSITION; POROUS-MEDIA; OIL-RECOVERY; CO2 PILOT; NANOTECHNOLOGY; RESERVOIR; FLOOD; NANOMATERIALS,"Nowadays, EOR has been an important research topic in oilfield development and has made greater contribution to worldwide oil production. Whereas, a few of available statistical resources and the lack of systematical analysis hinder the understanding of the latest status and progress of different EOR technologies. This work, on the basis of systematic survey and data collection, makes a latest overview and analysis of worldwide EOR field application cases and gives a systematical discussion and summary from various aspects of different EOR methods (chemical flooding, gas injection, thermal recovery and smart water flooding, etc.), involving development status, maturity, advantages and limitations and so forth. Moreover, some reservoir statistics of some EOR field application cases in China (from 2008) and other countries (from 2014) are systematically presented and discussed. The work not only is beneficial for the reservoir workers to share the successful experience and learn the lessons of failure in oilfield development plan design and operation, but also is helpful to grasp the latest development status and maturity of EOR field applications and to provide important guarantee for the future development of different EOR techniques.",12,12,10
Porous Media,Water Flooding,"Jafarbeigi, Ehsan; Kamari, Ehsan; Salimi, Farhad; Mohammadidoust, Akbar",Experimental study of the effects of a novel nanoparticle on enhanced oil recovery in carbonate porous media,Interfacial tension (IFT); Nanofluid flooding; Wettability alteration; Contact angle; Enhanced oil recovery (EOR),WETTABILITY ALTERATION; INTERFACIAL-TENSION; GRAPHENE OXIDE; SILICA NANOPARTICLES; SULFONATED GRAPHENE; WATER INJECTION; NANOFLUID; SALINITY; FUNCTIONALIZATION; ADSORPTION,"One of the effective methods in the process of enhancing the oil recovery from oil reservoirs is the use of nanotechnology. For this purpose, a new nanofluid was used to enhance the oil recovery from the reservoir at the scale of carbonate rocks. Finally, the obtained compound, in the first stage, nano-graphene oxide (NGO) were synthesized using Hummer's method and then they were subjected to surface modifications under new compounds. Finally, the obtained compound was known as (graphene oxide (N-(1-naphthyl) ethylenediamine)) (G-NEA), where G stands for graphene oxide (GO). Also, to determine the morphological characteristics and structure of the synthesized nanoparticles, Field Emission Scanning Electron Microscopy (FESEM), Fourier-transform infrared spectroscopy (FTIR), and Transmission electron microscopy (TEM) were performed. In addition, zeta-potential analysis was performed to investigate the stability of nanofluids at different pHs. In order to investigate the effect of nanofluids on oil recovery, three concentrations (200, 400, and 500 ppm) of G-NEA nanofluids were prepared. Also, the interfacial-tension (IFT) measurement and rock angle measurement in the presence of nanofluid were investigated using a pendant drop and sessile drop method, respectively. The coreflood experiment was performed to evaluate the effect of G-NEA nanofluid on carbonate plugs. The results showed that when the G-NEA nanofluid concentration increased, the IFT value of 19.34 (mN/m) for deionized water to 10.8 (mN/m) for 500 ppm G-NEA and the contact angle decreased from the initial value of 166 degrees to 40 degrees, indicating the tendency of the wettability alteration of the rock to a water-wet conditions. The results of the coreflood experiment showed that at 400 and 500 ppm concentrations, the G-NEA nanofluid enhanced the oil recovery by 23 and 15%, respectively. Therefore, this synthesized nanofluid can have an effective approach to drive the carbonate reservoir rock into a water-wet condition and enhance oil recovery.",9,9,6
Porous Media,Water Flooding,"Kumar, Amit; Mandal, Ajay",Core-scale modelling and numerical simulation of zwitterionic surfactant flooding: Designing of chemical slug for enhanced oil recovery,Enhanced oil recovery; Zwitterionic surfactant; Core flooding; Simulation; CMG-STARS,,"Surfactant flooding is a proven enhanced oil recovery method for the recovery of trapped crude oil from the pores of the reservoir. In the present study, the applicability of a synthesized zwitterionic surfactant as an efficient EOR agent was tested, in terms of its interfacial tension reduction capability, emulsification behavior, and wettability modification behavior. Core flooding experiments conducted in sandstone core with the injection of 0.3 pore volume of chemical slug after water flooding showed 20% of additional oil recovery. The core flooding experiment was simulated using CMG-STARS simulator and history matching of relative permeability curve and its interpolation parameters were done. The validated model closely represented the experimental core flooding with very low error of 6%. The validated model helps in understanding the movement of crude oil and its interaction with the injected surfactant slug in the porous media. The validated model was further used for optimization of injected chemical slug by varying the parameters such as the surfactant concentration in the injected slug, the volume of injected chemical slug, and the injection rate of chemical slug. Each parameter had different effects on the oil recovery efficiency and cumulative oil recovery of more than 90% OOIP was obtained using model with injection of 1 PV of chemical slug containing 100 ppm of surfactant with the injection rate of 0.3 mL/min. The simulation of core flooding helped in optimization of crude oil production by zwitterionic surfactant and its implementation on field scale production by zwitterionic surfactant flooding.",8,8,4
Porous Media,Water Flooding,"Wei, Bing; Liu, Jiang; Zhang, Xiang; Xiang, Hua; Zou, Peng; Cao, Jie; Bai, Mingxing",Nuclear Magnetic Resonance (NMR) mapping of remaining oil distribution during sequential rate waterflooding processes for improving oil recovery,Waterflooding; Sequential rate mode; Remaining oil saturation; NMR; Enhanced oil recovery,CHEMICAL-TRACER TESTS; SILICA NANOPARTICLES; POROSITY TYPES; POROUS-MEDIA; FLOW; DISPLACEMENT; CHALLENGES; CAPILLARY; RESERVOIR; FORCES,"At the conclusion of waterflooding phase, significant volume of oil still remains in reservoir formations. In this paper, waterflooding was performed at a designed sequential rate mode with an aim to further reduce the remaining oil saturation (S-or). Waterflooding process was monitored continuously by a low-field Nuclear Magnetic Resonance (NMR) spectrometer attempting to map pore-scale displacing behaviors and also quantify the reduction in S-or in-situ. The results showed that the main pore size of the cores ranged from 1.6 mu m to 63.0 mu m inferred by T-2 (transverse relaxation time) distributions. The value of S-or in the cores increased towards the outlet face during waterflooding because of capillary end effect, which became more significant for heavy oil. At the termination of this waterflooding process, S-or was found to be further reduced by approximately 5.0% in the presence of thief water pathways as a result of the improved viscous forces. Water fingering and capillary imbibition effects were clearly visualized in the NMR images. These observations are expected to be useful for heavy oil waterflooding operations especially in post-breakthrough phase.",8,8,4
Porous Media,Water Flooding,"Mehrabianfar, Parviz; Malmir, Pourya; Soulgani, Bahram Soltani; Hashemi, Abdolnabi",Study on the optimization of the performance of preformed particle gel (PPG) on the isolation of high permeable zone,Preformed particle gel (PPG); Water diversion; Fractured reservoir; Glass micromodel; Water control,WATER PRODUCTION COST; CONFORMANCE-CONTROL; TRANSPORT,"Unwanted water production is a critical problem in fractured reservoirs. Corrosion of facilities and reduction of oil relative permeability are some of the consequences of high water production. Preformed particle gel (PPG) injection is one of the conformance control methods, which initiated in 2007, has been used to control water production and increase sweep efficiency. There are several parameters which affect the performance of PPG such as stability at reservoir condition, salinity of makeup solution and PPG particle size and concentration. Although the study of the application of PPG in fracture plugging attracted a lot of attention in recent years, there are limited studies to investigate the effect of PPG physical properties on its application in water production control. In this study, the application of a super absorbent polymer on fracture plugging has been investigated. The results of swelling tests indicated that this type of PPG had significant high resistance even at high temperatures and wide range of salinities. In addition, the results of rheology tests showed that the PPG solution was stable even at high salinity and high shear rate condition. In order to study the mechanism of improvement of sweep efficiency through PPG injection, visual investigation using glass etched micromodel was performed. The results showed that the main mechanism for PPG treatment is water diversion into the low permeability zone as the consequence of fracture plugging. Also, core flooding tests were performed to check the performance of PPG in a heterogeneous carbonate porous media. According to the results, PPG was able to reduce the permeability, and this permeability reduction is related to swelling ratio which is controlled by makeup solution salinity. The results of this study revealed the potential of super absorbent polymers as preformed particle gel in unwanted water production through fracture plugging.",8,8,4
Porous Media,Crude Oil,"Wang, Yanwei; Liu, Huiqing; Zhang, Qichen; Chen, Zhangxin; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Pore-scale experimental study on EOR mechanisms of combining thermal and chemical flooding in heavy oil reservoirs,Viscosity reducer; Steam flooding; Foam; Visualized experiments; Mechanisms analysis,CYCLIC STEAM STIMULATION; CRUDE-OIL; VISCOSITY REDUCTION; FOAM-GENERATION; RECOVERY; EMULSIONS; INJECTION; FLOW; ASPHALTENE; RHEOLOGY,"Steam flooding is an important method for the development of heavy oil reservoirs, but steam channeling is an inevitable serious problem in the process of steam injection, which decreases the sweep efficiency of steam and leads to low oil recovery. Viscosity reducer (VR) flooding and nitrogen foam flooding are two effective methods of enhancing heavy oil recovery with satisfactory results. In this paper, a series of experiments were conducted to evaluate the effects of various factors on the performance of the novel viscosity reducer (VR-A). On this basis, A visualized model was adopted to investigate the synergistic development effect of thermal and chemical flooding, which vividly reflected the interaction of chemical agents with crude oil and their migration characteristics in porous media, as well as the mechanisms of enhancing oil recovery on the pore-scale. The results showed that VR-A could achieve excellent viscosity reduction effect on heavy oil under the influence of various factors, which could be combined with thermal flooding to effectively recover heavy oil. As for the pore-scale level, after the VR-A solution was injected, the interfacial tension between the oil and water was decreased, the wettability of the surface of the particle was changed, and two types of oil-in-water emulsions (spherical emulsions and flocculent emulsions) with a lower viscosity were formed, which were easy to flow with the fluid in pores and throats and could temporarily block the high-permeability area. In the process of foam flooding, the phenomena of bubble coalescence and breakup occurred constantly, and bubbles trapped in the porous media could improve the sweep efficiency of the subsequent fluid. The ultimate oil recovery of the development method combining thermal and chemical flooding in the visualized displacement experiment is 76.9%, 39.7% higher than that of pure thermal flooding. This article can provide an effective method to solve the problem of poor steam flooding performance in heavy oil reservoirs.",19,20,8
Porous Media,Crude Oil,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Porous Media,Crude Oil,"Lang, Liyuan; Li, Huabin; Wang, Xiong; Liu, Ning",Experimental study and field demonstration of air-foam flooding for heavy oil EOR,Heavy oil; Foam; EOR,NITROGEN FOAM; RECOVERY; INJECTION; TEMPERATURE; BEHAVIOR,"Foam flooding is an effective oil displacement technique to improve fluid sweep efficiency and increase oil recovery. The objective of this study is to investigate the application of air-foam for heavy oil recovery under heterogeneous reservoir conditions. The paper first investigated the air-foam flow behavior in porous media and identified the effects of different factors such as gas-liquid ratio, injection rate, and crude oil saturation on air-foam resistance. Then, dual-tube sand-packs were used to evaluate the performance of air-foam for heavy oil recovery from heterogeneous reservoir conditions. The results indicated that the air-foam could divert the fluid from the high-permeability zone to the low-permeability zone, decrease the water cut and improve the oil recovery. Further studies revealed that there existed an optimal reservoir permeability contrast ratio in air-foam flooding for heavy oil recovery. The air foam performance for oil recovery would be reduced beyond or below this permeability contrast ratio. Finally, field tests on air-foam for heavy oil recover demonstrated that air foam flooding could increase heavy oil production rate and decrease the production water cut.",16,17,7
Porous Media,Crude Oil,"Pu, Wanfen; Zhao, Shuai; Hu, Lingzhi; Varfolomeev, Mikhail A.; Yuan, Chengdong; Wang, Liangliang; Rodionov, Nikolay O.",Thermal effect caused by low temperature oxidation of heavy crude oil and its in-situ combustion behavior,Combustion tube; Thermal effect; Low temperature oxidation; Heavy crude oil; In-situ combustion; Porous media,AIR INJECTION; KINETICS; LIGHT; PYROLYSIS; FEASIBILITY; CALORIMETRY; COMPONENTS; RATES,"To investigate the thermal effect caused by low temperature oxidation (LTO) of one heavy crude oil in porous media, a combustion tube (CT) system coupled with a self-designed experimental scheme was adopted. Also, the in-situ combustion (ISC) performance of this heavy oil as well as alterations in oil properties before and after ISC was comprehensively evaluated. The results showed that there existed the apparent thermal effect induced by LTO within the researched ignition temperature (180-320 degrees C), and heat release became greater with the ignition temperature. It should be noted that the oxidation reaction rate of the heavy oil was rose remarkably releasing substantial heat when the ignition temperature was increased to 240 from 180 degrees C. The heavy oil was combusted under the ignition temperature of 350 degrees C, and the combustion front advanced sustainably. Some basic parameters during ISC, including apparent atomic H/C ratio, oxygen utilization, fuel consumption, etc., were determined, which made it accessible to predict field test performances. And the values of these parameters and post-mortem images of the CT test reflected the superior ISC performance of the heavy oil. The alterations in oil properties pre-ISC and post-ISC indicated that the produced oil encountered strong LTO reactions and thermal cracking reactions forming a considerable number of lighter oxygen-containing compounds. Comparison of differential scanning calorimetry (DSC) profiles of the crude oil and produced oil revealed that the ISC process made the heavy oil greatly upgrade.",14,14,3
Porous Media,Crude Oil,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Porous Media,Crude Oil,"Chen, Xiaolong; Li, Yiqiang; Gao, Wenbin; Chen, Cheng",Experimental investigation on transport property and emulsification mechanism of polymeric surfactants in porous media,Polymeric surfactants; Transport property; Viscosity; Emulsification mechanism,ENHANCED OIL-RECOVERY; POLYACRYLAMIDE; OPTIMIZATION; DISPLACEMENT; ADSORPTION; STABILITY; BEHAVIOR; FOAM,"Polymeric surfactants display different capabilities in migration rules and emulsifying crude oil as compared with that of traditional polymers attributing to the co-existence of hydrophilic and hydrophobic groups in molecular chains. To investigate the migration rules of polymeric surfactants in porous media and the matching relationship between polymeric surfactants and porous media, seepage-behavior experiments of different concentrations of polymeric surfactants in different permeability and different length cores were first carried out. The generation of emulsified oil droplets with the polymeric surfactants was then elucidated by comparing core flooding experiments with different injection rates, different saturated oil types and different polymeric surfactants concentrations. The flow characteristics of the emulsion and displacement mechanisms were evaluated by microscopic displacement experiments. The results showed that unlike polymers, when the polymeric surfactant was transported in porous medium, the pressure was difficult to reach a stable state. Based on the matching coefficient, the migration rules of polymeric surfactants in porous media could be defined as high blocking weak flow mode (lambda < 14.7), a blocking flow equalization mode (14.7< lambda < 19.7) and a smooth flow mode (lambda > 19.7). The main reasons for the formation of polymeric surfactants emulsions are a certain shearing action, the snapping action of hydrophobic microdomains on residual oil droplets and assisted effect of colloidal asphaltene. Capillary number (Nc) was used as an evaluation index to divide the emulsification action into four zones: non-emulsified zone(Nc < 2.18 x 10(-5)), high-efficiency emulsification zone (2.18 x 10(-5) < Nc < 8.7 x 10(-5)), optimal-emulsification zone (8.7 x 10(-5) < Nc < 1.46 x 10(-4)) and emulsified excess zone(Nc > 1.46 x 10(-4)). The emulsion microscopic flooding experiment showed that in the porous medium, the transport characteristics of polymeric surfactants emulsion were mainly plugging action of single large emulsion particle, stacking and plugging action of small emulsion particles, forming ""emulsion bridge"" to block super large pores and vortex action of different sizes emulsion particles.",11,11,2
Porous Media,Crude Oil,"Sulaimon, Aliyu Adebayo; De Castro, John Kevin Mendoza; Vatsa, Suyash",New correlations and deposition envelopes for predicting asphaltene stability in crude oils,Asphaltene stability; SARA analysis; Colloidal instability index; Asphaltene/resin ratio,PRECIPITATION; FLOCCULATION; SOLUBILITY; SEPARATION; DYNAMICS; POLARITY,"The precipitation and deposition of asphaltene are among the most pressing issues in the petroleum industry. This flow assurance issue may cause formation damage in porous media, the plugging and coking of wellbore and production pipelines and difficulties in the refining process. Such events lead to additional operating costs for the company. Therefore, knowing the conditions at which asphaltene may precipitate and can be stable may enable its management. Existing models of asphaltene stability are dependent on saturate, aromatic, resin and asphaltene (SARA) analysis which can be very expensive and time-consuming. Therefore, using regression analysis as well as MATLAB curve fitting and optimization procedures, a new set of correlations and asphaltene stability envelops (ASEs) based on the newly developed Density-Based Asphaltene/Resin ratio (DBAR), Density-Based Saturate/Aromatic ratio (DBSAr) and the Density-Based Colloidal Instability Index (DBCII) all as functions of oil density have been developed to consistently predict asphaltene stability. The new criteria were developed for the correlations by considering the boundary between stable and unstable regions in their respective plots. The new envelopes showed 83% reliability by accurately predicting asphaltene stability in 24 (eight stable and 16 unstable samples) out of 29 (13 stable and 16 unstable) crude oil samples. The correlation coefficient (R-2), average absolute relative error (AARE) and the root-mean-square error (RMSE) for the new DBAR correlation are 0.9456, 0.8357 and 0.1219 respectively. The DBSAr correlation resulted in R-2 of 0.9437, AARE of 0.1860 and RMSE of 0.2450. For the DBCII, the statistical indicator results were 0.9639 for the R-2, 0.1376 for the RMSE and 0.1038 for the AARE.",10,10,2
Porous Media,Crude Oil,"Kumar, Amit; Mandal, Ajay",Core-scale modelling and numerical simulation of zwitterionic surfactant flooding: Designing of chemical slug for enhanced oil recovery,Enhanced oil recovery; Zwitterionic surfactant; Core flooding; Simulation; CMG-STARS,,"Surfactant flooding is a proven enhanced oil recovery method for the recovery of trapped crude oil from the pores of the reservoir. In the present study, the applicability of a synthesized zwitterionic surfactant as an efficient EOR agent was tested, in terms of its interfacial tension reduction capability, emulsification behavior, and wettability modification behavior. Core flooding experiments conducted in sandstone core with the injection of 0.3 pore volume of chemical slug after water flooding showed 20% of additional oil recovery. The core flooding experiment was simulated using CMG-STARS simulator and history matching of relative permeability curve and its interpolation parameters were done. The validated model closely represented the experimental core flooding with very low error of 6%. The validated model helps in understanding the movement of crude oil and its interaction with the injected surfactant slug in the porous media. The validated model was further used for optimization of injected chemical slug by varying the parameters such as the surfactant concentration in the injected slug, the volume of injected chemical slug, and the injection rate of chemical slug. Each parameter had different effects on the oil recovery efficiency and cumulative oil recovery of more than 90% OOIP was obtained using model with injection of 1 PV of chemical slug containing 100 ppm of surfactant with the injection rate of 0.3 mL/min. The simulation of core flooding helped in optimization of crude oil production by zwitterionic surfactant and its implementation on field scale production by zwitterionic surfactant flooding.",8,8,4
Porous Media,Surfactant,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Water-oil interfacial tension (IFT) reduction and wettability alteration in surfactant flooding process using extracted saponin from Anabasis Setifera plant,Surfactant flooding; Saponin; Interfacial tension (IFT); Wettability alteration; Chemical enhanced oil recovery; Anabasis Setifera,DISSOLVED CARBON-DIOXIDE; LEAF-DERIVED SURFACTANTS; SMART WATER; POROUS-MEDIA; CO2 FOAM; RECOVERY; IONS; INJECTION; RESERVOIR; EMULSIFICATION,"Surfactants are known as interfacial tension (IFT) reducer additives in enhanced oil recovery (EOR) process. The use of chemical surfactants has always been a challenge due to the high cost of materials and sometimes noncompliance with the environment. Hence, researchers are looking for alternative ways to make them cheap and affordable. Herbal extracts that combine some surfactants, such as saponins, are a new source for replacing with expensive chemical surfactants. In this study, Anabasis Setifera plant was used as a source of natural surfactant supply. Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance ((HNMR)-H-1) and thermal gravimetric analysis (TGA) were performed to characterize and determine the temperature stability, as well as surface tension tests for estimating the critical micelle concentration (CMC) of saponin extracted from Anabasis Setifera. In addition, pendant drop water-oil IFT test, contact angle test, and flooding of surfactant solution at CMC and optimum salinity were performed to study the application of the natural surfactant in EOR process. The effects of NaCl, KCl, CaCl2, MgCl2, FeSO4, K2SO4 and NaHCO3 salts and formation water salinity were investigated at different concentrations on the IFT and contact angle. The results show that the surfactant is more effective than conventional plant extracts and in combination with chemical surfactants and an IFT value of 1.066 mN/m was obtained at CMC. The contact angle tests also show the capability of this surfactant to alter the wettability to a poor water-wetting (a contact angle of 56.51. Ultimately, an oil recovery of 15.4% was obtained by flooding of the surfactant solution at CMC and optimum formation water salinity.",37,37,18
Porous Media,Surfactant,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Porous Media,Surfactant,"Kumar, Ravi Shankar; Chaturvedi, Krishna Raghav; Iglauer, Stefan; Trivedi, Japan; Sharma, Tushar","Impact of anionic surfactant on stability, viscoelastic moduli, and oil recovery of silica nanofluid in saline environment",EOR; Nanofluid; Nanoparticle; Rheology; Salinity; SDS,PARTIALLY HYDROLYZED POLYACRYLAMIDE; WETTABILITY ALTERATION; RHEOLOGICAL PROPERTIES; CHARGED NANOPARTICLES; THERMAL-CONDUCTIVITY; DISPERSION STABILITY; AQUEOUS-SOLUTIONS; IONIC-STRENGTH; POLYMER FLOOD; BEHAVIOR,"Controlling nanofluid stability in saline environment has been a long-standing challenge as salt ions screen-out the surface charge of the nanoparticles (NPs), rendering them unstable. This study thus reports the use of an anionic surfactant (sodium dodecylsulfate, SDS), as co-stabilizer, that not only controls the effect of salt, but also dramatically improves nanofluid stability by controlling the agglomeration rate. Silica NPs of 0.5 wt%, SDS with concentration >= critical micelles concentration (CMC), and polymer polyacrylamide (PAM) of 1000 ppm were used while the concentration of NaCl was explored up to 5 wt%. The dispersion stability of nanofluid without salt (NaCl) was found to be similar to 4 weeks which further increased to similar to 7 weeks with increasing SDS concentration. With increasing SDS (>CMC), a reduction in NP agglomeration was observed that delayed the NP settlement. The effect of salinity was also investigated for flow properties of nanofluids and, an unstable rheological response (transition from viscoelastic to viscous) was observed with increasing NaCl concentration. However, SDS (>CMC) made nanofluid rheologically stable up to saline environment of 3 wt%, an optimum salinity was identified. SDS role on nanofluid stabilization in saline environment is also generalized for enhanced oil recovery (EOR) applications in a porous media enriched with varying salinity. With increasing salinity, the cumulative oil recovery from sand-pack reduced and reached to minimum level of 48% original oil in place (OOIP) at 3 wt% NaCl which was 58% OOIP without salinity. Oil recovery re-established to 55% OOIP in presence of increasing SDS concentration, which is remarkable for nanofluid applicability in saline environment where conventional methods typically show challenges. Even in the presence of 4 wt% NaCl, the synergy between surfactant and nanofluid enabled an improvement in oil recovery and subdued surfactant adsorption in both unconsolidated and consolidated porous media, paving future way for field implementation.",18,18,4
Porous Media,Surfactant,"Chen, Xiaolong; Li, Yiqiang; Gao, Wenbin; Chen, Cheng",Experimental investigation on transport property and emulsification mechanism of polymeric surfactants in porous media,Polymeric surfactants; Transport property; Viscosity; Emulsification mechanism,ENHANCED OIL-RECOVERY; POLYACRYLAMIDE; OPTIMIZATION; DISPLACEMENT; ADSORPTION; STABILITY; BEHAVIOR; FOAM,"Polymeric surfactants display different capabilities in migration rules and emulsifying crude oil as compared with that of traditional polymers attributing to the co-existence of hydrophilic and hydrophobic groups in molecular chains. To investigate the migration rules of polymeric surfactants in porous media and the matching relationship between polymeric surfactants and porous media, seepage-behavior experiments of different concentrations of polymeric surfactants in different permeability and different length cores were first carried out. The generation of emulsified oil droplets with the polymeric surfactants was then elucidated by comparing core flooding experiments with different injection rates, different saturated oil types and different polymeric surfactants concentrations. The flow characteristics of the emulsion and displacement mechanisms were evaluated by microscopic displacement experiments. The results showed that unlike polymers, when the polymeric surfactant was transported in porous medium, the pressure was difficult to reach a stable state. Based on the matching coefficient, the migration rules of polymeric surfactants in porous media could be defined as high blocking weak flow mode (lambda < 14.7), a blocking flow equalization mode (14.7< lambda < 19.7) and a smooth flow mode (lambda > 19.7). The main reasons for the formation of polymeric surfactants emulsions are a certain shearing action, the snapping action of hydrophobic microdomains on residual oil droplets and assisted effect of colloidal asphaltene. Capillary number (Nc) was used as an evaluation index to divide the emulsification action into four zones: non-emulsified zone(Nc < 2.18 x 10(-5)), high-efficiency emulsification zone (2.18 x 10(-5) < Nc < 8.7 x 10(-5)), optimal-emulsification zone (8.7 x 10(-5) < Nc < 1.46 x 10(-4)) and emulsified excess zone(Nc > 1.46 x 10(-4)). The emulsion microscopic flooding experiment showed that in the porous medium, the transport characteristics of polymeric surfactants emulsion were mainly plugging action of single large emulsion particle, stacking and plugging action of small emulsion particles, forming ""emulsion bridge"" to block super large pores and vortex action of different sizes emulsion particles.",11,11,2
Porous Media,Surfactant,"Al-Hajri, Sameer; Mahmood, Syed M.; Akbari, Saeed; Abdulelah, Hesham; Yekeen, Nurudeen; Saraih, Nabil",Experimental investigation and development of correlation for static and dynamic polymer adsorption in porous media,Polymer flooding; Polymer static adsorption; Polymer dynamic adsorption,ENHANCED OIL-RECOVERY; WATER-SOLUBLE POLYMERS; SURFACTANT ADSORPTION; SILICON DIOXIDE; RETENTION; PERFORMANCE; BEHAVIOR,"Part of the injected polymer during polymer flooding is lost in porous media by adsorption, mechanical entrapment, and hydrodynamic retention. Therefore, having a clear understanding of polymer losses/retention is very important for designing a technically and economically successful polymer flooding project. Polymer losses are traditionally modeled using Langmuir Isotherms, requiring costly and time-consuming dynamic corefloods to obtain fitting parameters. This research suggests a faster and low-cost method for first-order approximation of polymer adsorption in porous media without conducting corefloods. The proposed technique uses the results of polymer adsorption on the crushed core in the static test that can be used in a lookup table in the simulator instead of Langmuir Isotherms Equation. Mercury injection (MICP) was used to find a cut-off molecular size based on the hydrodynamic size of the polymer calculated using the Flory-Fox equation. Brunauer-Emmett-Teller (BET) tests are used to measure the specific surface area of the crushed core. These three tests determine the equivalent weight of crushed core to be used for static adsorption tests that would represent the specific surface area of the core. Seven high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods to determine polymer adsorption, followed by seven static adsorption tests performed at similar conditions to compare the results. Polymer adsorption tests showed that 1-h residence time, 0.5 solid-to-liquid ratio, and pre-saturating crushed core with brine before starting static adsorption were important to map static to dynamic polymer adsorption. Other important observations were the increase in polymer adsorption with increasing polymer molecular weight, polymer concentration, and NaCl salinity in order of descending significance of the effect. The proposed method gave a reasonable statistical correlation between static and dynamic polymer adsorption with a coefficient of determination (R-2) of 0.97, and Pearson's correlation coefficient (r) of 0.98. The maximum deviation between static and dynamic result was 34% for cores of similar flow zones, and 48% for cores of dissimilar flow zones.",9,9,1
Porous Media,Surfactant,"Kumar, Amit; Mandal, Ajay",Core-scale modelling and numerical simulation of zwitterionic surfactant flooding: Designing of chemical slug for enhanced oil recovery,Enhanced oil recovery; Zwitterionic surfactant; Core flooding; Simulation; CMG-STARS,,"Surfactant flooding is a proven enhanced oil recovery method for the recovery of trapped crude oil from the pores of the reservoir. In the present study, the applicability of a synthesized zwitterionic surfactant as an efficient EOR agent was tested, in terms of its interfacial tension reduction capability, emulsification behavior, and wettability modification behavior. Core flooding experiments conducted in sandstone core with the injection of 0.3 pore volume of chemical slug after water flooding showed 20% of additional oil recovery. The core flooding experiment was simulated using CMG-STARS simulator and history matching of relative permeability curve and its interpolation parameters were done. The validated model closely represented the experimental core flooding with very low error of 6%. The validated model helps in understanding the movement of crude oil and its interaction with the injected surfactant slug in the porous media. The validated model was further used for optimization of injected chemical slug by varying the parameters such as the surfactant concentration in the injected slug, the volume of injected chemical slug, and the injection rate of chemical slug. Each parameter had different effects on the oil recovery efficiency and cumulative oil recovery of more than 90% OOIP was obtained using model with injection of 1 PV of chemical slug containing 100 ppm of surfactant with the injection rate of 0.3 mL/min. The simulation of core flooding helped in optimization of crude oil production by zwitterionic surfactant and its implementation on field scale production by zwitterionic surfactant flooding.",8,8,4
Porous Media,Surfactant,"Zhao, Han; Yang, Hongbin; Kang, Xin; Jiang, Haizhuang; Li, Menglan; Kang, Wanli; Sarsenbekuly, Bauyrzhan",Study on the types and formation mechanisms of residual oil after two surfactant imbibition,Imbibition; Surfactant; Micromodel; Residual oil; Interfacial film; Emulsion,POROUS-MEDIA; PORE-SCALE; SNAP-OFF; WATER; EMULSION; RECOVERY; WET; DISPLACEMENT; VISCOELASTICITY; PERFORMANCE,"For investigating the types and formation mechanisms of residual oil after surfactant imbibition, the easyemulsifying surfactant Sodium Dodecylbenzene Sulfonate (SDBS) and ultra-low interfacial tension surfactant Sodium Oleate (SOL) were selected. The visual micromodel was adopted to observe the oil morphologies, while the rheometer and the emulsion stability analyzer were applied to analyze formation mechanisms. According to micro experiments, the main types of residual oil after SDBS imbibition are columnar, cluster, blind-end and small drop residual oil whose structure was small fragmented droplet. As for SOL solution, they are mainly blindend and island residual oil. The formation mechanism of columnar and cluster residual oil is capillary force offsetting, the direction of capillary force forms the blind-end residual oil, while the Marangoni effect and snapoff effect are responsible for island residual oil. The small drop residual oil is from emulsification, which always appears at the intersection of multiple flows. The aromatic groups of SDBS can promote the emulsion more stable by increasing the strength of interfacial film, hence the small drop residual oil only exists after SDBS imbibition.",7,6,8
Porous Media,Technique,"Hu, Xiao; Xie, Jun; Cai, Wuchao; Wang, Rui; Davarpanah, Afshin",Thermodynamic effects of cycling carbon dioxide injectivity in shale reservoirs,Carbon dioxide storage capacity; Oil recovery factor; Soaking time; Core stimulation; Shale reservoirs,ENHANCED OIL-RECOVERY; BAKKEN TIGHT OIL; N-PUFF PROCESS; GAS; STORAGE; MODEL; PERMEABILITY,"Carbon dioxide injectivity has always been considered as one of the optimum enhanced recovery techniques, especially in tight reservoirs regarding the feasible mobilization of gas through porous media. To have a better understanding of carbon dioxide injectivity performances, it would be of importance to consider crucial parameters and their effects on the carbon dioxide adsorption and oil recovery factor. In this paper, the profound impact of crucial parameters such as temperature, pressure, carbon dioxide soaking time, and core stimulation on the oil recovery enhancement were investigated. Moreover, the considerable influence of pressure and temperature on the carbon dioxide adsorption capacity storage were performed and analyzed. According to the result of this experiment, temperature increase led to reducing carbon dioxide storage capacity, which has a reverse pattern with oil recovery factor by increasing temperature. When the core samples were unstimulated, the oil recovery factor has higher than stimulated core samples. Furthermore, pressure increase resulted in the carbon dioxide storage capacity enhancement, which has a similar increase pattern with oil recovery factor by increasing pressure. The maximum carbon dioxide storage capacity is 91% and 90% at the pressure of 1500 psi and temperature of 20 degrees C respectively. Soaking time rising between oil and carbon dioxide led to producing more oil volume.",98,98,22
Porous Media,Technique,"Esmaeilzadeh, Soheil; Salehi, Amir; Hetz, Gill; Olalotiti-lawal, Feyisayo; Darabi, Hamed; Castineira, David",Multiscale modeling of compartmentalized reservoirs using a hybrid clustering-based non-local approach,machine learning; artificial intelligence; spatio-temporal clustering; non-local multi-scale flow formulation; reservoir modeling,HETEROGENEOUS RESERVOIRS; MULTIPHASE FLOW; UNCERTAINTY QUANTIFICATION; TIME-SERIES; OPTIMIZATION; ALGORITHM; FORMULATION; SIMULATION; SYSTEMS; NUMBER,"Representing the reservoir as a network of discrete compartments with neighbor and non-neighbor connections is a fast, yet accurate method for analyzing oil and gas reservoirs. Automatic and rapid detection of coarse-scale compartments with distinct static and dynamic properties is an integral part of such high-level reservoir analysis. In this work, we present a hybrid framework specific to reservoir analysis for an automatic detection of clusters in space using spatial and temporal field data, coupled with a physics-based multiscale modeling approach. A novel and rigorous non-local formulation for flow in porous media is presented, in which the reservoir is represented by an adjacency matrix describing the connectivities of comprising compartments. We automatically divide the reservoir into a number of distinct compartments, in which the direction-dependent multiphase flow communication is a function of non-local phase potential differences. Our proposed clustering framework begins with a mixed-type raw dataset which can be categorical/numerical, spatial/temporal, and discrete/continuous. The dataset can contain noisy/missing values of different data types including but not limited to well production/injection history, well location, well type, geological features, PVT measurements, perforation data, etc. Unsupervised clustering techniques suited to the input data types (e.g. k-prototypes, spectral, Gaussian Mixtures, and hierarchical clustering), and appropriate distance measures (such as Euclidean distance, soft dynamic time warping, and mode) are used. The input data is standardized, and upon convergence check, the best clustering representation is obtained. Finally, Support-Vector-Machine technique is utilized in the kernel space to trace a demarcating hyperplane for the clusters. In a specific case study reported here, the proposed workflow is applied to a major field with a couple of hundreds of wells with more than 40 years of production history. Leveraging the fast forward model, an efficient ensemble-based history matching framework is applied to reduce the uncertainty of the global reservoir parameters such as inter-blocks and aquifer-reservoir communications, fault transmissibilities, and block-based oilin-place. The ensemble of history matched models are then used to provide a probabilistic forecast for different field development scenarios. In addition, the clustering framework enables us to treat missing data and use the augmented dataset for improving the clustering accuracy. In summary, in this work a novel hybrid approach is presented in which we couple a physics-based non-local modeling framework with data-driven clustering techniques to provide a fast and accurate multiscale modeling of compartmentalized reservoirs. This research also adds to the literature by presenting a comprehensive work on spatio-temporal clustering for reservoir studies applications that well considers the clustering complexities, the intrinsic sparse and noisy nature of the data, and the interpretability of the outcome.",35,35,4
Porous Media,Technique,"Lang, Liyuan; Li, Huabin; Wang, Xiong; Liu, Ning",Experimental study and field demonstration of air-foam flooding for heavy oil EOR,Heavy oil; Foam; EOR,NITROGEN FOAM; RECOVERY; INJECTION; TEMPERATURE; BEHAVIOR,"Foam flooding is an effective oil displacement technique to improve fluid sweep efficiency and increase oil recovery. The objective of this study is to investigate the application of air-foam for heavy oil recovery under heterogeneous reservoir conditions. The paper first investigated the air-foam flow behavior in porous media and identified the effects of different factors such as gas-liquid ratio, injection rate, and crude oil saturation on air-foam resistance. Then, dual-tube sand-packs were used to evaluate the performance of air-foam for heavy oil recovery from heterogeneous reservoir conditions. The results indicated that the air-foam could divert the fluid from the high-permeability zone to the low-permeability zone, decrease the water cut and improve the oil recovery. Further studies revealed that there existed an optimal reservoir permeability contrast ratio in air-foam flooding for heavy oil recovery. The air foam performance for oil recovery would be reduced beyond or below this permeability contrast ratio. Finally, field tests on air-foam for heavy oil recover demonstrated that air foam flooding could increase heavy oil production rate and decrease the production water cut.",16,17,7
Porous Media,Technique,"Janiga, Damian; Czarnota, Robert; Kuk, Edyta; Stopa, Jerzy; Wojnarowski, Pawel",Measurement of Oil-CO2 diffusion coefficient using pulse-echo method for pressure-volume decay approach under reservoir conditions,CO2 diffusion coefficient; Mass transfer; Pressure-volume decay; Acoustically monitored separator (AMS); CO2-EOR,SATURATED POROUS-MEDIA; HEAVY-OIL; GAS DIFFUSIVITY; LIQUID HYDROCARBONS; CO2 DIFFUSION; MASS-TRANSFER; PUFF PROCESS; HUFF; RECOVERY; BITUMEN,In order to achieve synergic environmental effect CO2-EOR can be applied to improve oil production and reduce carbon dioxide emission. Greater results can be obtained by the CO2 huff-n-puff process which in the case of oil reservoirs is based mainly on the oil swelling effect. During the soaking period the primary mechanism distributing CO2 in the reservoir is molecular diffusion. To calculate mass transferred to oil phase molecular diffusion coefficient is used. Its determination can be based on direct or indirect techniques but no standard method is normed. This paper presents a pulse-echo pressure-volume decay technique to determine oil-CO2 diffusion coefficient under reservoir conditions with the use of acoustically monitored separator. In the proposed method measurements of difference between signal routing are recalculated to volume change in order to compute diffusion coefficient. Experimental procedure was conducted for three different temperatures. The obtained results are consistent with previous studies on diffusion coefficient determination. The proposed technique is more reliable and yields straightforward solution due to simultaneous binary measurements of pressure and volume system.,14,13,6
Porous Media,Technique,"Chung, Traiwit; Wang, Ying Da; Armstrong, Ryan T.; Mostaghimi, Peyman",Voxel agglomeration for accelerated estimation of permeability from micro-CT images,Flow in porous media; X-ray micro-computed tomography; Permeability estimation; Voxel agglomeration,PORE-SCALE SIMULATION; POROUS-MEDIA; REACTIVE TRANSPORT; NETWORK MODELS; FLOW; DISSOLUTION; TOMOGRAPHY,"Direct numerical methods are widely used to solve for flow on micro-computed tomography (micro-CT) images of rocks. Generally, direct numerical methods are computationally demanding, especially on large micro-CT images (1000(3) voxels and more). We develop a fast, direct numerical approach to solve the elliptic flow equation and estimate the absolute permeability of micro-CT images of rocks. The approach involves voxel agglomeration, which is a common technique in computational fluid dynamics. By allowing specific locations of the pore voxels to be agglomerated, the number of pore voxels or active cells in a sparse matrix can be reduced by approximately 60%-80% depending on the type of rock and its pore size distribution. Nevertheless, the fine details obtained from the micro-CT scan are maintained. The results compared with the Pore-scale Finite Volume Solver (PFVS) are within 1.6% difference on level 1 agglomerated grids and 1.9% for level 2 agglomerated grids without loss of the flux conservation. Moreover, the computation time reductions are at least 59% for the micro-CT images tested in this study. This approach is suitable for rapid estimation of absolute permeability from micro-CT images of rocks, particularly on large systems with high pore voxel counts.",14,14,1
Porous Media,Technique,"Liu, Zhao-xia; Liang, Yan; Wang, Qiang; Guo, Yong-jun; Gao, Ming; Wang, Zheng-bo; Liu, Wan-lu",Status and progress of worldwide EOR field applications,Chemical flooding; Gas injection; Thermal recovery; Smart water flooding; EOR; Field application,PREFORMED PARTICLE GEL; CONFORMANCE-CONTROL; BRINE COMPOSITION; POROUS-MEDIA; OIL-RECOVERY; CO2 PILOT; NANOTECHNOLOGY; RESERVOIR; FLOOD; NANOMATERIALS,"Nowadays, EOR has been an important research topic in oilfield development and has made greater contribution to worldwide oil production. Whereas, a few of available statistical resources and the lack of systematical analysis hinder the understanding of the latest status and progress of different EOR technologies. This work, on the basis of systematic survey and data collection, makes a latest overview and analysis of worldwide EOR field application cases and gives a systematical discussion and summary from various aspects of different EOR methods (chemical flooding, gas injection, thermal recovery and smart water flooding, etc.), involving development status, maturity, advantages and limitations and so forth. Moreover, some reservoir statistics of some EOR field application cases in China (from 2008) and other countries (from 2014) are systematically presented and discussed. The work not only is beneficial for the reservoir workers to share the successful experience and learn the lessons of failure in oilfield development plan design and operation, but also is helpful to grasp the latest development status and maturity of EOR field applications and to provide important guarantee for the future development of different EOR techniques.",12,12,10
Porous Media,Technique,"Mehmani, Ayaz; Kelly, Shaina; Torres-Verdin, Carlos","Leveraging digital rock physics workflows in unconventional petrophysics: A review of opportunities, challenges, and benchmarking",Digital rock physics; Pore-scale modeling; Unconventional petrophysics; Representative elementary volume; Best practices,ENHANCED OIL-RECOVERY; PORE-SCALE; RELATIVE PERMEABILITY; POROUS-MEDIA; MULTISCALE; SHALE; FLOW; GAS; MICROPOROSITY; IMBIBITION,"Digital rock physics (DRP), via both direct numerical simulation and pore-network modeling, holds great promise in terms of probing such pore-scale controls on transport, particularly with multiphase flow and sensitivity analysis of time-intensive measurements such as relative permeability. However, despite advances in micro-computed tomography (microCT) and scanning electron microscopy (SEM) techniques, obtaining cost-effective representative elementary volumes (REV) at sufficient resolution that capture dual-scale porosity and surface textures remains a formidable challenge in establishing digital rock physics as a predictive toolset. Furthermore, implementers are faced with several options of numerical solvers such as finite element method, lattice Boltzmann method, and mass balance-based pore-network modeling. This paper reviews the current status of establishing an REV and upscaling techniques for DRP in tight and/or diagenetically-altered rocks, highlighting successful and unsuccessful pore-to-core data benchmarking examples by the authors and the greater literature in terms of static and dynamic properties. The review finds that performing DRP on a single image modality is not sufficient, even for many conventional rocks, and that it is crucial to interface with experimental data, be it core analysis deliverables or subpore-scale and Darcy-scale microfluidics. In unconventional rocks, the majority of work does not leverage mesoscale simulations, instead zooming in to a discrete pore-scale scenario that is often not benchmarked with SCAL data. Even when a simulation domain is benchmarked, the matching of a discrete case with a multivariable situation is non-unique. Benchmarking with dynamic or pseudo-dynamic core data such as MICP and single phase perm will greatly help reduce variables. Finally, this paper offers a technical roadmap for the robust application of unconventional DRP for the petrophysical and general subsurface community.",11,11,3
Porous Media,Technique,"Al-Hajri, Sameer; Mahmood, Syed M.; Akbari, Saeed; Abdulelah, Hesham; Yekeen, Nurudeen; Saraih, Nabil",Experimental investigation and development of correlation for static and dynamic polymer adsorption in porous media,Polymer flooding; Polymer static adsorption; Polymer dynamic adsorption,ENHANCED OIL-RECOVERY; WATER-SOLUBLE POLYMERS; SURFACTANT ADSORPTION; SILICON DIOXIDE; RETENTION; PERFORMANCE; BEHAVIOR,"Part of the injected polymer during polymer flooding is lost in porous media by adsorption, mechanical entrapment, and hydrodynamic retention. Therefore, having a clear understanding of polymer losses/retention is very important for designing a technically and economically successful polymer flooding project. Polymer losses are traditionally modeled using Langmuir Isotherms, requiring costly and time-consuming dynamic corefloods to obtain fitting parameters. This research suggests a faster and low-cost method for first-order approximation of polymer adsorption in porous media without conducting corefloods. The proposed technique uses the results of polymer adsorption on the crushed core in the static test that can be used in a lookup table in the simulator instead of Langmuir Isotherms Equation. Mercury injection (MICP) was used to find a cut-off molecular size based on the hydrodynamic size of the polymer calculated using the Flory-Fox equation. Brunauer-Emmett-Teller (BET) tests are used to measure the specific surface area of the crushed core. These three tests determine the equivalent weight of crushed core to be used for static adsorption tests that would represent the specific surface area of the core. Seven high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods to determine polymer adsorption, followed by seven static adsorption tests performed at similar conditions to compare the results. Polymer adsorption tests showed that 1-h residence time, 0.5 solid-to-liquid ratio, and pre-saturating crushed core with brine before starting static adsorption were important to map static to dynamic polymer adsorption. Other important observations were the increase in polymer adsorption with increasing polymer molecular weight, polymer concentration, and NaCl salinity in order of descending significance of the effect. The proposed method gave a reasonable statistical correlation between static and dynamic polymer adsorption with a coefficient of determination (R-2) of 0.97, and Pearson's correlation coefficient (r) of 0.98. The maximum deviation between static and dynamic result was 34% for cores of similar flow zones, and 48% for cores of dissimilar flow zones.",9,9,1
Porous Media,Fracture Network,"Wang, Fuyong; Cheng, Hui",A fractal permeability model for 2D complex tortuous fractured porous media,Fracture; Permeability; Tortuosity; Porous media; Fractal,CARBONATE ROCK; FLUID-FLOW; NETWORKS,"The complex fracture networks are of significance to petroleum production in unconventional reservoirs, but effectively predicting its permeability is challenging due to the complex distribution and geometry of fracture networks. This paper proposes a new permeability model for 2D complex tortuous fractured porous media based on fractal theory, and two important characteristics of fractures, i.e. branching and tortuosity are considered in the developed permeability model. In this paper, the fractured porous media is assumed to be made up of a bundle of tortuous fractal-like tree fracture networks. First, the modified cubic law for describing flow rate in a fracture with fractal distribution of tortuosity is derived. Secondly, the fractal-like tree fracture network is used to represent the distribution of complex fracture networks, and then flow rate in a tortuous fractal-like tree fracture network is derived. After that, with the assumption of the fractal scaling law between fracture number and fracture apertures, the total flow rate in a bundle of tortuous fractal-like tree fracture networks is given and then the analytical expression for permeability of 2D complex tortuous fractured porous media is derived. Finally, the model reliability is verified with a case study and the key parameters influencing permeability of 2D fracture porous media are investigated with sensitivity study. The research results show that the fractal dimension of aperture distribution D-f, tortuosity fractal dimension D-T, branch level m and fracture length ratio gamma have significant influence on fracture network permeability; the effects of branch angle theta and the straight length of the zero-level fracture l(0) on fracture network permeability are insignificant.",17,18,5
Porous Media,Fracture Network,"Rao, Xiang; Cheng, Linsong; Cao, Renyi; Jia, Pin; Liu, Hao; Du, Xulin",A modified projection-based embedded discrete fracture model (pEDFM) for practical and accurate numerical simulation of fractured reservoir,Embedded discrete fracture model; Projection-based embedded discrete fracture model; Complex fracture network; Numerical simulation; Flow barriers,MULTIPHASE FLOW; POROUS-MEDIA; NETWORKS; EDFM; OIL,"pEDFM is a new numerical model which is proposed in the last three years to handle the flow simulation with complex fracture networks. Previous works show that classical EDFM has a good performance only for production or injection simulation of multistage fractured well, but pEDFM can effectively handle more general cases than EDFM. Although pEDFM has been validated by by some works, this paper points out that there are still some limitations in previous pEDFM need to be resolved, lying on lack of a practical method to select projected faces, the proficiency in the transmissibility formula of f-m connections, and poor performances in some cases. Then, corresponding modifications are presented to resolve these limitations, and these modifications include A practical algorithm called ""micro-translation method"" to select projected-faces combinations, the physical transmissibility formula of additional fracture-matrix (f-m) connections and an extended pEDFM framework by considering additional fracture-fracture (f-f) connections. Some test cases are implemented to illustrate the necessity and validity of these modifications. Besides, two examples are implemented to illustrate the robustness of the modified pEDFM workflow for practical application of a fractured reservoir.",16,18,2
Porous Media,Fracture Network,"Wei, Shiming; Jin, Yan; Xia, Yang; Lin, Botao",The flowback and production analysis in sub-saturated fractured shale reservoirs,Sub-saturated shale reservoirs; Flowback; Production; Gas-water flow; Discrete fractures,DISCRETE-FRACTURE; 2-PHASE FLOW; GAS-FLOW; HYDRAULIC-FRACTURE; TRIPLE-CONTINUUM; NUMERICAL-METHOD; HORIZONTAL WELL; POROUS-MEDIA; MODEL; SIMULATION,"The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced ""skin factor"" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model.",10,10,3
Porous Media,Fracture Network,"Berawala, Dhruvit S.; Andersen, Pal O.",Numerical investigation of Non-Darcy flow regime transitions in shale gas production,Shale gas production; Non-Darcy flow; Forchheimer equation; Fracture-matrix flow; Apparent permeability,APPARENT PERMEABILITY; STRESS-DEPENDENCE; MODEL; RESERVOIRS; ADSORPTION; IMBIBITION; DIFFUSION; TRANSPORT; NANOPORES; EVOLUTION,"Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable. The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure depletion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir isotherm and is a key production mechanism. This model is implemented in Matlab using Marcellus shale data. Scaling the model shows that recovery of gas depends on two dimensionless number that incorporates geometry relations, time scales of flow, intrinsic parameters of the porous media, non-Darcy constants, adsorption and boundary conditions. The dimensionless numbers define respectively if 1) the fracture or matrix limit the gas production rate 2) if non-Darcy flow is significant in the fracture or matrix. When one of the media limit production, the non-Darcy flow in the other medium has reduced importance and can be excluded from the model. Non-Darcy flow is important if it limits flow in the medium limiting the production. By checking the magnitude of the selected dimensionless numbers, the modelling approach can be determined in advance and significant computational time can be saved. The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.",8,8,4
Porous Media,Fracture Network,"Wei, Shiming; Jin, Yan; Xia, Yang",Predict the mud loss in natural fractured vuggy reservoir using discrete fracture and discrete vug network model,Naturally fractured reservoirs; Discrete fractures; Discrete vugs; Mud loss,FINITE-ELEMENT-METHOD; 2-PHASE FLOW; SIMULATION; FLUID; CONTINUUM; MEDIA,"In carbonate reservoirs, the leakage path is complex and the law of mud loss is not clear, which brings difficulties to the implementation of plugging measures. Carbonate reservoir is a naturally fractured vuggy media. One of the key scientific problems is that the fluid mass transfer among matrix pores, natural fractures and vugs is not well understood. In this paper, a discrete fracture and discrete vug model is presented to study the law of mud loss in the naturally fractured reservoir wherein natural fractures and vugs developed. The model solved the fluid flow in the discrete fracture and vug network, consisting of 1) Darcy flow in lowly permeable rock matrix and highly permeable natural fractures; 2) free flow in macro vugs. A physically-based boundary is applied to ensure the mass continuity on interfaces between vugs and matrix pores, vugs and natural fractures. A good agreement with analytical results for Poiseuille flow in a porous/free connected media is achieved. Two numerical examples using the commercial software COMSOL provide validation of the new model. When simulating the mud loss process, we find that as soon as vugs are connected to wellbore through natural fractures, total loss is observed. The size and number of vugs play prominent roles in increasing mud loss rate and accumulated mud loss. The numerical results show that the discrete fracture and discrete vug model provides a reliable way to model realistic fluid flow in fractured vuggy porous media. The model in this paper can not only simulate the mud loss process, but also the production process of carbonate reservoirs.",7,7,4
Porous Media,Lattice Boltzmann,"Zhou, Xiao; Xu, Zhiguo; Xia, Yulei; Li, Binfei; Qin, Jie",Pore-scale investigation on reactive flow in porous media with immiscible phase using lattice Boltzmann method,Porous media; Reactive flow; Immiscible fluid; Lattice Boltzmann method; Dissolution,WORMHOLE FORMATION; HEAT TRANSMISSION; SIMULATION; DISSOLUTION; TRANSPORT; MODEL; MULTICOMPONENT; PROPAGATION; SURFACE; ACID,"Reactive flow happens during carbonate rock acidification. In the present study, carbonate rock dissolution process is investigated by lattice Boltzmann method at pore scale. The two immiscible fluids flow, solute transport and heat transfer are solved by the Shan-Chen multiphase multicomponent lattice Boltzmann model, mass transport lattice Boltzmann model and multicomponent thermal lattice Boltzmann model, respectively. The solid phase is updated by Volume of Pixel method. The results show that the immiscible phase has negative effect on dissolution, while positive effect on acid penetration. The immiscible phase effect is influenced by the inlet velocity, porous media porosity, surface wettability and temperature. The increasing inlet velocity and temperature accelerate the dissolution rate, but decrease the degree of immiscible phase suppression on dissolution. The surface wettability impact on dissolution process is influenced by the immiscible phase distribution. The porosity affects the degree of immiscible phase suppression on dissolution process slightly.",11,11,12
Porous Media,Lattice Boltzmann,"Mehmani, Ayaz; Kelly, Shaina; Torres-Verdin, Carlos","Leveraging digital rock physics workflows in unconventional petrophysics: A review of opportunities, challenges, and benchmarking",Digital rock physics; Pore-scale modeling; Unconventional petrophysics; Representative elementary volume; Best practices,ENHANCED OIL-RECOVERY; PORE-SCALE; RELATIVE PERMEABILITY; POROUS-MEDIA; MULTISCALE; SHALE; FLOW; GAS; MICROPOROSITY; IMBIBITION,"Digital rock physics (DRP), via both direct numerical simulation and pore-network modeling, holds great promise in terms of probing such pore-scale controls on transport, particularly with multiphase flow and sensitivity analysis of time-intensive measurements such as relative permeability. However, despite advances in micro-computed tomography (microCT) and scanning electron microscopy (SEM) techniques, obtaining cost-effective representative elementary volumes (REV) at sufficient resolution that capture dual-scale porosity and surface textures remains a formidable challenge in establishing digital rock physics as a predictive toolset. Furthermore, implementers are faced with several options of numerical solvers such as finite element method, lattice Boltzmann method, and mass balance-based pore-network modeling. This paper reviews the current status of establishing an REV and upscaling techniques for DRP in tight and/or diagenetically-altered rocks, highlighting successful and unsuccessful pore-to-core data benchmarking examples by the authors and the greater literature in terms of static and dynamic properties. The review finds that performing DRP on a single image modality is not sufficient, even for many conventional rocks, and that it is crucial to interface with experimental data, be it core analysis deliverables or subpore-scale and Darcy-scale microfluidics. In unconventional rocks, the majority of work does not leverage mesoscale simulations, instead zooming in to a discrete pore-scale scenario that is often not benchmarked with SCAL data. Even when a simulation domain is benchmarked, the matching of a discrete case with a multivariable situation is non-unique. Benchmarking with dynamic or pseudo-dynamic core data such as MICP and single phase perm will greatly help reduce variables. Finally, this paper offers a technical roadmap for the robust application of unconventional DRP for the petrophysical and general subsurface community.",11,11,3
Porous Media,Lattice Boltzmann,"Yang, Qianhong; Yao, Jun; Huang, Zhaoqin; Zhu, Guangpu; Liu, Lijun; Song, Wenhui",Pore-scale investigation of petro-physical fluid behaviours based on multiphase SPH method,Multiphase flow; Contact line dynamics; Porous media; Smoothed particle hydrodynamics; Enhance oil recovery,SMOOTHED PARTICLE HYDRODYNAMICS; LATTICE BOLTZMANN SIMULATION; OPEN-CHANNEL FLOWS; DELTA-PLUS-SPH; POROUS-MEDIA; RELATIVE PERMEABILITY; CONSERVATION PROPERTIES; 2-PHASE FLOW; MODEL; WETTABILITY,"In this work, a series of microscopic simulations are conducted to investigate the effect of wettability, flow rate and surface tension in porous system by using pairwise force smoothed particle hydrodynamics (PF-SPH) method. Firstly, a novel inflow and outflow boundary is introduced in the SPH framework. The overall proposed model is verified by two benchmarks. The test cases are run in the two dimensional heterogeneous porous media. The effect of wettability, flow rate and surface tension to the macroscopic parameters such as relative permeability and residual oil saturation are thoroughly examined. Through our simulations, we conclude that (i) the type of residual oil changes with contact angle; water wetting porous media has a higher level of waterless oil recovery period and the discrepancies of ultimate oil recovery efficiencies happen before water phase breaks through the outlet of porous media; the residual oil saturations present excellent linear correlations with contact angles; (ii) it's better to increase the flow rate at the high water cut stage (eg f(w) = 90%) in hydrophilic porous media and rise the flow rate at early water cut stage (eg f(w) = 0%) in lipophilic porous media; increasing the flow rate dramatically shortens the effective production time in strong oil wetting porous media; (iii) decreasing the surface tension could change the type of residual oil, which leads to the further extraction of oil film and cluster residual oil.",11,11,1
Porous Media,Lattice Boltzmann,"Zakirov, Timur Rustamovich; Khramchenkov, Maxim Georgievich",Characterization of two-phase displacement mechanisms in porous media by capillary and viscous forces estimation using the lattice Boltzmann simulations,Two-phase flow; Displacement; Drainage; Porous media; Fingering; Lattice Boltzmann equations; Surface tension,IMMISCIBLE DISPLACEMENTS; MULTIPHASE FLOWS; HEAVY OIL; PRESSURE; PERMEABILITY; SANDSTONE; DYNAMICS; MODELS; LIQUID; BEHAVIOR,"This paper proposes a method for characterization of the two-phase displacement mechanisms (viscous fingering, capillary fingering, stable front, and crossover) in porous media. The approach is based on separate estimation of the capillary and viscous forces and subsequent calculation of the ratio between them (designated as W). The value W determines the dominance of capillary force and is essentially the inverse capillary number. The advantage of this approach consists in taking into account the scale of the samples and predicting the flow mechanisms using parameters measured in laboratory conditions. The balance between viscous and capillary forces is controlled by surface tension and fluid viscosities. For flow simulation, the lattice Boltzmann equations and the color-gradient model are applied. The values of W equal to 0.5 and 2, which define the boundary of the crossover zone and separate it from the flow mechanisms, were determined and the proposed method was successfully validated on three two-dimensional samples of porous media with different permeability coefficients. It revealed a directly proportional effect of permeability on W. As a result, the surface tensions, which determine the boundaries of viscous fingering, capillary fingering, stable front, are shifted towards smaller values with increasing permeability. Also, the effect of the permeability and displacement mechanisms on the displacement efficiency before, after and at quasi-steady regime was investigated. The tendency to efficiency decrease with increasing surface tension and decrease in viscosity ratio was revealed for quasi-steady regime. The absence of the mobile wetting fluid after breakthrough is detected for crossover and capillary fingers. No-displacement regime after breakthrough and, consequently, effectiveness drop to minimal values in quasisteady regime occurs at lower surface tensions with increasing permeability.",9,9,1
Porous Media,Machine Learning,"Esmaeilzadeh, Soheil; Salehi, Amir; Hetz, Gill; Olalotiti-lawal, Feyisayo; Darabi, Hamed; Castineira, David",Multiscale modeling of compartmentalized reservoirs using a hybrid clustering-based non-local approach,machine learning; artificial intelligence; spatio-temporal clustering; non-local multi-scale flow formulation; reservoir modeling,HETEROGENEOUS RESERVOIRS; MULTIPHASE FLOW; UNCERTAINTY QUANTIFICATION; TIME-SERIES; OPTIMIZATION; ALGORITHM; FORMULATION; SIMULATION; SYSTEMS; NUMBER,"Representing the reservoir as a network of discrete compartments with neighbor and non-neighbor connections is a fast, yet accurate method for analyzing oil and gas reservoirs. Automatic and rapid detection of coarse-scale compartments with distinct static and dynamic properties is an integral part of such high-level reservoir analysis. In this work, we present a hybrid framework specific to reservoir analysis for an automatic detection of clusters in space using spatial and temporal field data, coupled with a physics-based multiscale modeling approach. A novel and rigorous non-local formulation for flow in porous media is presented, in which the reservoir is represented by an adjacency matrix describing the connectivities of comprising compartments. We automatically divide the reservoir into a number of distinct compartments, in which the direction-dependent multiphase flow communication is a function of non-local phase potential differences. Our proposed clustering framework begins with a mixed-type raw dataset which can be categorical/numerical, spatial/temporal, and discrete/continuous. The dataset can contain noisy/missing values of different data types including but not limited to well production/injection history, well location, well type, geological features, PVT measurements, perforation data, etc. Unsupervised clustering techniques suited to the input data types (e.g. k-prototypes, spectral, Gaussian Mixtures, and hierarchical clustering), and appropriate distance measures (such as Euclidean distance, soft dynamic time warping, and mode) are used. The input data is standardized, and upon convergence check, the best clustering representation is obtained. Finally, Support-Vector-Machine technique is utilized in the kernel space to trace a demarcating hyperplane for the clusters. In a specific case study reported here, the proposed workflow is applied to a major field with a couple of hundreds of wells with more than 40 years of production history. Leveraging the fast forward model, an efficient ensemble-based history matching framework is applied to reduce the uncertainty of the global reservoir parameters such as inter-blocks and aquifer-reservoir communications, fault transmissibilities, and block-based oilin-place. The ensemble of history matched models are then used to provide a probabilistic forecast for different field development scenarios. In addition, the clustering framework enables us to treat missing data and use the augmented dataset for improving the clustering accuracy. In summary, in this work a novel hybrid approach is presented in which we couple a physics-based non-local modeling framework with data-driven clustering techniques to provide a fast and accurate multiscale modeling of compartmentalized reservoirs. This research also adds to the literature by presenting a comprehensive work on spatio-temporal clustering for reservoir studies applications that well considers the clustering complexities, the intrinsic sparse and noisy nature of the data, and the interpretability of the outcome.",35,35,4
Porous Media,Machine Learning,"Alqahtani, Naif; Alzubaidi, Fatimah; Armstrong, Ryan T.; Swietojanski, Pawel; Mostaghimi, Peyman",Machine learning for predicting properties of porous media from 2d X-ray images,Machine learning; Convolutional neural network; Digital rock; Rock properties,PORE-SCALE SIMULATION; DIGITAL ROCK; REACTIVE TRANSPORT; NUMERICAL-SIMULATION; MICRO-TOMOGRAPHY; PART I; PERMEABILITY; DISSOLUTION; FLOW; MICROTOMOGRAPHY,"In this paper, Convolutional Neural Networks (CNNs) are trained to rapidly estimate several physical properties of porous media using micro-computed tomography (micro-CT) X-ray images as input data. The tomograms of three different sandstone types are subdivided to create a dataset consisting of 5,262 training images and 2,000 testing images. Porosity, specific surface area, and average pore size of each image are computed. The proposed CNN framework is trained with binary images and greyscale images separately and the corresponding computed properties. The results from testing the model are promising as the relative error in determination of porosity, surface area and average pore size is less than 6% when the model is trained with binary images and less than 7% when greyscale images are used. Other aspects related to model training and optimisation are discussed.",34,34,4
Porous Media,Machine Learning,"Shams, Reza; Masihi, Mohsen; Boozarjomehry, Ramin Bozorgmehry; Blunt, Martin J.",Coupled generative adversarial and auto-encoder neural networks to reconstruct three-dimensional multi-scale porous media,Porous media reconstruction; Generative adversarial network; Auto-encoder neural network; Machine learning; Multi-scale reconstruction,PORE-SPACE RECONSTRUCTION; STOCHASTIC RECONSTRUCTION; SIMULATION; TRANSPORT; MODEL; IMAGE,"In this study, coupled Generative Adversarial and Auto-Encoder neural networks have been used to reconstruct realizations of three-dimensional porous media. The gradient-descent-based optimization method is used for training and stabilizing the neural networks. The multi-scale reconstruction has been conducted for both sandstone and carbonate samples from an Iranian oilfield. The sandstone contains inter and intra-grain porosity. The generative adversarial network predicts the inter-grain pores and the auto-encoder provides the generative adversarial network result with intra-grain pores (micro-porosity). Different matching criteria, including porosity, permeability, auto-correlation function, and visual interpretation have been used to investigate the performance of the models. This methodology provides researchers with a reliable method to reconstruct multi-scale realizations of porous media.",29,29,5
Porous Media,Machine Learning,"Yang, Xi; Dindoruk, Birol; Lu, Ligang",A comparative analysis of bubble point pressure prediction using advanced machine learning algorithms and classical correlations,"Bubble point pressure; PVT; Fluid properties; Machine learning methods (XGBoost, LightGBM, random forest regressor, MLP neural network, and super learner); Correlations",PVT PROPERTIES; SUPER LEARNER; MODEL,"The need for fluid properties or PVT (Pressure-Volume-Temperature) properties, is part of the entire Exploration and Production (E&P) lifecycle from exploration to mature asset management to the typical later life events such as, Improved Oil Recovery (IOR). As the projects mature, the need for such data and its integration for various discipline-specific workflows and its interpretation in the light of reservoir performance varies. Among all the key PVT properties, bubble point pressure is probably the most important parameter. Bubble point pressure is important because it is the point at which constant composition and variable composition portions of the depletion paths merge. Geometrically, bubble point pressure appears to be a discontinuity. In addition, it dictates the existence (or not) of the incipient phase (i.e., gas phase) leading to the changes in the flow characteristics both in porous media and as well as within the wellbore and the facilities. Furthermore, it is also a good indicative of a possible gas cap when the reservoir is at saturation (reservoir pressure is equal to the bubble point pressure) or near-saturated. Among the highlighted uses, there are many more used such as the determination of the elements of miscibility, gas lift design, etc. Therefore, it is very important to estimate the bubble point pressure accurately. In this study, tree-based advanced machine learning algorithm including XGBoost, LightGBM, and random forest regressor, and multi-layer perceptron (neural network) regressor are implemented to predict bubble point pressure (P-bp). A novel super learner model which is also known as stacking ensemble is used to enhance base machine learning model performance on predicting bubble point pressure. Three datasets with different predictors are prepared to study machine learning algorithms' performance for three situations: only compositional data are available; only bulk properties (Gas-Oil-Ratio, gas gravity, API gravity and reservoir Temperature) are available; both compositional data and bulk properties are available. Through literature review, there is no research on using only compositional data and temperature to predict bubble point pressure. Our super learner model offers an accurate solution for oil bubble point pressure when only compositional data and temperature are available. Machine learning models perform better than empirical correlations with limited input data (i.e., bulk properties). When compositional data and bulk properties are all used as predictors, super learner reaches about 5.146% mean absolute relative error on predicting the bubble point pressure from global samples with bubble point pressures in the range of 100 to 10,000 psi, which is a wider range compared to most ANN models published in literature.",9,9,1
Porous Media,Carbon Dioxide,"Hu, Xiao; Xie, Jun; Cai, Wuchao; Wang, Rui; Davarpanah, Afshin",Thermodynamic effects of cycling carbon dioxide injectivity in shale reservoirs,Carbon dioxide storage capacity; Oil recovery factor; Soaking time; Core stimulation; Shale reservoirs,ENHANCED OIL-RECOVERY; BAKKEN TIGHT OIL; N-PUFF PROCESS; GAS; STORAGE; MODEL; PERMEABILITY,"Carbon dioxide injectivity has always been considered as one of the optimum enhanced recovery techniques, especially in tight reservoirs regarding the feasible mobilization of gas through porous media. To have a better understanding of carbon dioxide injectivity performances, it would be of importance to consider crucial parameters and their effects on the carbon dioxide adsorption and oil recovery factor. In this paper, the profound impact of crucial parameters such as temperature, pressure, carbon dioxide soaking time, and core stimulation on the oil recovery enhancement were investigated. Moreover, the considerable influence of pressure and temperature on the carbon dioxide adsorption capacity storage were performed and analyzed. According to the result of this experiment, temperature increase led to reducing carbon dioxide storage capacity, which has a reverse pattern with oil recovery factor by increasing temperature. When the core samples were unstimulated, the oil recovery factor has higher than stimulated core samples. Furthermore, pressure increase resulted in the carbon dioxide storage capacity enhancement, which has a similar increase pattern with oil recovery factor by increasing pressure. The maximum carbon dioxide storage capacity is 91% and 90% at the pressure of 1500 psi and temperature of 20 degrees C respectively. Soaking time rising between oil and carbon dioxide led to producing more oil volume.",98,98,22
Porous Media,Carbon Dioxide,"Nowrouzi, Iman; Mohammadi, Amir H.; Manshad, Abbas Khaksar",Water-oil interfacial tension (IFT) reduction and wettability alteration in surfactant flooding process using extracted saponin from Anabasis Setifera plant,Surfactant flooding; Saponin; Interfacial tension (IFT); Wettability alteration; Chemical enhanced oil recovery; Anabasis Setifera,DISSOLVED CARBON-DIOXIDE; LEAF-DERIVED SURFACTANTS; SMART WATER; POROUS-MEDIA; CO2 FOAM; RECOVERY; IONS; INJECTION; RESERVOIR; EMULSIFICATION,"Surfactants are known as interfacial tension (IFT) reducer additives in enhanced oil recovery (EOR) process. The use of chemical surfactants has always been a challenge due to the high cost of materials and sometimes noncompliance with the environment. Hence, researchers are looking for alternative ways to make them cheap and affordable. Herbal extracts that combine some surfactants, such as saponins, are a new source for replacing with expensive chemical surfactants. In this study, Anabasis Setifera plant was used as a source of natural surfactant supply. Fourier-transform infrared spectroscopy (FTIR), proton nuclear magnetic resonance ((HNMR)-H-1) and thermal gravimetric analysis (TGA) were performed to characterize and determine the temperature stability, as well as surface tension tests for estimating the critical micelle concentration (CMC) of saponin extracted from Anabasis Setifera. In addition, pendant drop water-oil IFT test, contact angle test, and flooding of surfactant solution at CMC and optimum salinity were performed to study the application of the natural surfactant in EOR process. The effects of NaCl, KCl, CaCl2, MgCl2, FeSO4, K2SO4 and NaHCO3 salts and formation water salinity were investigated at different concentrations on the IFT and contact angle. The results show that the surfactant is more effective than conventional plant extracts and in combination with chemical surfactants and an IFT value of 1.066 mN/m was obtained at CMC. The contact angle tests also show the capability of this surfactant to alter the wettability to a poor water-wetting (a contact angle of 56.51. Ultimately, an oil recovery of 15.4% was obtained by flooding of the surfactant solution at CMC and optimum formation water salinity.",37,37,18
Porous Media,Carbon Dioxide,"Janiga, Damian; Czarnota, Robert; Kuk, Edyta; Stopa, Jerzy; Wojnarowski, Pawel",Measurement of Oil-CO2 diffusion coefficient using pulse-echo method for pressure-volume decay approach under reservoir conditions,CO2 diffusion coefficient; Mass transfer; Pressure-volume decay; Acoustically monitored separator (AMS); CO2-EOR,SATURATED POROUS-MEDIA; HEAVY-OIL; GAS DIFFUSIVITY; LIQUID HYDROCARBONS; CO2 DIFFUSION; MASS-TRANSFER; PUFF PROCESS; HUFF; RECOVERY; BITUMEN,In order to achieve synergic environmental effect CO2-EOR can be applied to improve oil production and reduce carbon dioxide emission. Greater results can be obtained by the CO2 huff-n-puff process which in the case of oil reservoirs is based mainly on the oil swelling effect. During the soaking period the primary mechanism distributing CO2 in the reservoir is molecular diffusion. To calculate mass transferred to oil phase molecular diffusion coefficient is used. Its determination can be based on direct or indirect techniques but no standard method is normed. This paper presents a pulse-echo pressure-volume decay technique to determine oil-CO2 diffusion coefficient under reservoir conditions with the use of acoustically monitored separator. In the proposed method measurements of difference between signal routing are recalculated to volume change in order to compute diffusion coefficient. Experimental procedure was conducted for three different temperatures. The obtained results are consistent with previous studies on diffusion coefficient determination. The proposed technique is more reliable and yields straightforward solution due to simultaneous binary measurements of pressure and volume system.,14,13,6
Porous Media,Effective Stress,"Tangparitkul, Suparit; Saul, Alexander; Leelasukseree, Cheowchan; Yusuf, Muhammad; Kalantariasl, Azim",Fines migration and permeability decline during reservoir depletion coupled with clay swelling due to low-salinity water injection: An analytical study,Fines migration; Permeability decline; Effective stress; Reservoir depletion; Low-salinity waterflooding; Fines-assisted waterflood,EXTERNAL FILTER CAKE; OIL-RECOVERY; PORE PRESSURE; FILTRATION; MODEL; PARTICLES; MECHANISM; DETACHMENT; RETENTION; TRANSPORT,"Fines migration is crucial for reservoir permeability, involving both fine particle detachment and re-deposition along the flow channels. Fines migration behavior can either promote or obstruct fluid flow within the reservoir and is crucial for productivity optimization that needs fundamental understanding. The present work focuses on the contributions from effective stress build-up due to reservoir depletion and decreases in brine salinity from low-salinity water injection. Particle detachment is studied analytically by using the critical retention concentration function modified with stress and salinity dependents. Increase in formation effective stress leads to deformations within the reservoir configurations due to micro-cracks and reduced pore dimensions. Decreased size of the travelling channels promotes particle detachment, while the critical retention concentration decreases. A sensitivity study reveals that, under influence of effective stress, particle size and fluid velocity are dominant parameters controlling the fines migration by influencing the particle detaching forces. With decreasing brine salinity (e.g. via low-salinity water injection), clay particles that are attached on the pore surface increasingly swell, leading to reduction in effective pore space and flow channel. Decreased pore space directly obstructs travelling of suspended particles and fluids which results in permeability decline. Initial clay particle size is found to be a critical factor controlling particle detachment behavior. Small initial particle sizes are not likely to detach from the pore surface as a result of weak detaching forces, hence the analysis finds the critical retention concentration unchanged resulting in negligible permeability decline as a function of brine salinity. Considering both effects, effective stress and brine salinity, stress-dependent effects dominate salinity-dependent effects at low effective stress while the two contribute equally at high effective stress. Permeability decline is also determined from analytical results of the fine particle critical retention concentration, which emphasizes the roles of effective stress and brine salinity on the flow in reservoir porous media.",13,12,1
Porous Media,Effective Stress,"Li, Zihao; Ripepi, Nino; Chen, Cheng",Using pressure pulse decay experiments and a novel multi-physics shale transport model to study the role of Klinkenberg effect and effective stress on the apparent permeability of shales,Apparent permeability; Klinkenberg effect; Shale gas; Biot's coefficient; Multi-physics shale transport,GAS-FLOW; POROUS-MEDIA; HETEROGENEITY; DEPENDENCE; ANISOTROPY; PIPES; ROCKS; COAL; LAW,"The confining pressure imposed on a shale formation has a significant impact on the apparent permeability of the rock. Gas flow in low-permeability shales differs significantly from liquid flow because of the Klinkenberg effect, which results from gas molecule slip at the wall surfaces inside the nanopores. This effect causes the increase of apparent permeability (i.e., the measured permeability). In this study, cores extracted from four U.S. shale formations were tested using a pulse decay permeameter (PDP) under varying combinations of confining and pore pressures. The Klinkenberg coefficient was calculated to interpret the change in the measured apparent permeability as a function of pore pressure and effective stress. Next, based on the various combinations of confining and pore pressures, the actual values of the Biot coefficient were calculated by data fitting. Moreover, the samples were cored in the directions parallel to and perpendicular to the shale bedding planes to unravel the role of bedding plane direction on the apparent permeability. Furthermore, a novel, multi-physics shale transport (MPST) model was developed to account for the coupled multi-physics processes of geomechanics, fluid dynamics, and Klinkenberg effect for gas transport in shales. In the MPST model, pore pressure and effective stress are the two independent input variables, and the measured apparent permeability is the model output. The MPST model was then used to fit the PDP experimental data, and the successful data fitting confirmed that the MPST model captures the critical multi-physics processes that regulate the apparent permeability.",12,14,1
Porous Media,Effective Stress,"Song, Wenhui; Yao, Jun; Wang, Dongying; Li, Yang; Sun, Hai; Yang, Yongfei",Dynamic pore network modelling of real gas transport in shale nanopore structure,Shale gas; Transport mechanisms; Dynamic pore network model; Gas permeability,SURFACE-DIFFUSION; POROUS-MEDIA; SLIP-FLOW; APPARENT PERMEABILITY; ADSORPTION; MICRO; RESERVOIRS; MULTISCALE; METHANE; PREDICTION,"Gas transport in shale nanopores is controlled by the complex transport mechanisms and pore structure characteristics. So far much work has been done on the single pore and regular structure based pore network but lithe is known on real gas transport behavior on a realistic shale pore structure model. In this work, a dynamic pore network model is proposed to describe single component methane transport in nano-scale porous media. Gas transport behavior takes transport mechanisms of slip flow, transition flow, surface diffusion and ad/desorption into account. Real gas effect under high pressure and temperature is considered when calculating gas properties. A three dimensional pore network model is built from a three dimensional image that is reconstructed using multi-point statistics from a small organic-rich area on a two dimensional shale SEM image. This pore network model is used to analyze dynamic gas transport and pressure drop transmission process. Our simulated results reveal that there exists a time period that gas permeability on the pore network is influenced by the pressure drop transmission process and pore structure that flows on. When pressure drop reaches outlet, gas transport turns steady state. At steady state period gas permeability becomes constant and is influenced by the effective stress, pressure, temperature and shale rock property.",11,12,6
Porous Media,Point Pressure,"Andersen, Pal Ostebo; Nesvik, Eirik K.; Standnes, Dag C.",Analytical solutions for forced and spontaneous imbibition accounting for viscous coupling,Viscous coupling interactions; Spontaneous imbibition; Forced imbibition; Capillary forces; Universal time scale,MIXTURE THEORY APPROACH; 2-PHASE FLOW; POROUS-MEDIA; COUNTERCURRENT IMBIBITION; OIL-RECOVERY; COCURRENT; FLUID,"Fluid-fluid momentum transfer can cause higher flow resistance when fluids flow in opposite directions as compared to the same direction. Conventional modelling of flow in porous media using simple, saturation dependent relative permeabilities does not account for such variations. We consider a generalized theory for multiphase flow in porous media based on mixture theory, where fluid mobilities follow from water-rock, oil-rock and water-oil interaction terms defined in momentum equations. Under strictly co- or counter-current flow modes, the generalized model produces explicit relative permeability expressions dependent on the flow mode, saturations, viscosities and interaction parameters. New expressions for counter-current relative permeabilities are derived assuming zero net flux, representative of counter-current spontaneous imbibition. These functions are compared to previously derived co-current relative permeabilities (assuming equal phase pressure gradients). The functions are incorporated into analytical solutions for forced and spontaneous imbibition (FI and SI) using the theory by Buckley and Leverett (1942) and McWhorter and Sunada (1990), respectively. Our results show that when accounting for viscous coupling; Counter-current relative permeabilities are always lower than co-current ones, including the end points. Both phase curves are reduced by the same saturation dependent coefficient. Increased viscous coupling in the FI case led to a more effective displacement, seen as an increased front saturation and average water saturation behind the front. For counter-current SI, increased viscous coupling resulted in lower imbibition rate. Increased viscosities reduces both oil and water countercurrent relative permeabilities, and predict greater reduction in imbibition rate than only modifying the viscosities. The analytical solutions for SI were in agreement with numerical solutions of both a conventional and generalized model. The solutions for SI could be scaled exactly to a square root of time curve for arbitrary input parameters in the generalized model, especially including the strength of viscous coupling.",10,10,1
Porous Media,Point Pressure,"Yang, Xi; Dindoruk, Birol; Lu, Ligang",A comparative analysis of bubble point pressure prediction using advanced machine learning algorithms and classical correlations,"Bubble point pressure; PVT; Fluid properties; Machine learning methods (XGBoost, LightGBM, random forest regressor, MLP neural network, and super learner); Correlations",PVT PROPERTIES; SUPER LEARNER; MODEL,"The need for fluid properties or PVT (Pressure-Volume-Temperature) properties, is part of the entire Exploration and Production (E&P) lifecycle from exploration to mature asset management to the typical later life events such as, Improved Oil Recovery (IOR). As the projects mature, the need for such data and its integration for various discipline-specific workflows and its interpretation in the light of reservoir performance varies. Among all the key PVT properties, bubble point pressure is probably the most important parameter. Bubble point pressure is important because it is the point at which constant composition and variable composition portions of the depletion paths merge. Geometrically, bubble point pressure appears to be a discontinuity. In addition, it dictates the existence (or not) of the incipient phase (i.e., gas phase) leading to the changes in the flow characteristics both in porous media and as well as within the wellbore and the facilities. Furthermore, it is also a good indicative of a possible gas cap when the reservoir is at saturation (reservoir pressure is equal to the bubble point pressure) or near-saturated. Among the highlighted uses, there are many more used such as the determination of the elements of miscibility, gas lift design, etc. Therefore, it is very important to estimate the bubble point pressure accurately. In this study, tree-based advanced machine learning algorithm including XGBoost, LightGBM, and random forest regressor, and multi-layer perceptron (neural network) regressor are implemented to predict bubble point pressure (P-bp). A novel super learner model which is also known as stacking ensemble is used to enhance base machine learning model performance on predicting bubble point pressure. Three datasets with different predictors are prepared to study machine learning algorithms' performance for three situations: only compositional data are available; only bulk properties (Gas-Oil-Ratio, gas gravity, API gravity and reservoir Temperature) are available; both compositional data and bulk properties are available. Through literature review, there is no research on using only compositional data and temperature to predict bubble point pressure. Our super learner model offers an accurate solution for oil bubble point pressure when only compositional data and temperature are available. Machine learning models perform better than empirical correlations with limited input data (i.e., bulk properties). When compositional data and bulk properties are all used as predictors, super learner reaches about 5.146% mean absolute relative error on predicting the bubble point pressure from global samples with bubble point pressures in the range of 100 to 10,000 psi, which is a wider range compared to most ANN models published in literature.",9,9,1
Porous Media,API,"Vipulanandan, C.; Mohammed, A.",Effect of drilling mud bentonite contents on the fluid loss and filter cake formation on a field clay soil formation compared to the API fluid loss method and characterized using Vipulanandan models,Fluid loss; Bentonite; Soil formation; Filter cake; Vipulanandan models,PIEZORESISTIVE BEHAVIOR; ELECTRICAL-RESISTIVITY; RHEOLOGICAL PROPERTIES; SMART,"Quantification of fluid losses and filter cake formations during the drilling operations using water-based muds (WBM) are some of the critical issues related to successful operations. In this study, short term (30 min) and long term (420 min) fluid loss tests on the drilling mud with various amounts of bentonite contents were performed using the API fluid loss device with filter paper and compared it to the field clay soil (porous media) at a pressure of 100 psi (0.69 MPa). The permeability of the saturated clay soil was 0.026 mD, representing a porous formation. Bentonite content in the drilling mud was varied from 2% to 8% (by the weight of water). The field soil and bentonite were characterized using the particle size distribution and X-ray diffraction (XRD) analyses. Bentonite particle size distribution was finer than the field clay soil. Vipulanandan correlation model predicted the changes in the permeability with time in the clay soil with the filter cake formation very well. With the API fluid loss study, the long-term (420 min) fluid losses were about 2.5-4 times greater than the standard fluid loss study of 30 min (short-term). The filter cake thickness was high with the soil formation compared to the API method. Also, the fluid loss per unit area with the API method was higher than the clay soil formation agreeing with the observed differences in the filter cake thicknesses. The Vipulanandan fluid loss model predictions were compared to the API model and it predicted both short term and long term fluid losses very well based on the root mean square error (RMSE) values. Also, the Vipulanandan fluid loss model predicted the maximum fluid losses under various testing conditions.",30,30,8
Porous Media,API,"Yang, Xi; Dindoruk, Birol; Lu, Ligang",A comparative analysis of bubble point pressure prediction using advanced machine learning algorithms and classical correlations,"Bubble point pressure; PVT; Fluid properties; Machine learning methods (XGBoost, LightGBM, random forest regressor, MLP neural network, and super learner); Correlations",PVT PROPERTIES; SUPER LEARNER; MODEL,"The need for fluid properties or PVT (Pressure-Volume-Temperature) properties, is part of the entire Exploration and Production (E&P) lifecycle from exploration to mature asset management to the typical later life events such as, Improved Oil Recovery (IOR). As the projects mature, the need for such data and its integration for various discipline-specific workflows and its interpretation in the light of reservoir performance varies. Among all the key PVT properties, bubble point pressure is probably the most important parameter. Bubble point pressure is important because it is the point at which constant composition and variable composition portions of the depletion paths merge. Geometrically, bubble point pressure appears to be a discontinuity. In addition, it dictates the existence (or not) of the incipient phase (i.e., gas phase) leading to the changes in the flow characteristics both in porous media and as well as within the wellbore and the facilities. Furthermore, it is also a good indicative of a possible gas cap when the reservoir is at saturation (reservoir pressure is equal to the bubble point pressure) or near-saturated. Among the highlighted uses, there are many more used such as the determination of the elements of miscibility, gas lift design, etc. Therefore, it is very important to estimate the bubble point pressure accurately. In this study, tree-based advanced machine learning algorithm including XGBoost, LightGBM, and random forest regressor, and multi-layer perceptron (neural network) regressor are implemented to predict bubble point pressure (P-bp). A novel super learner model which is also known as stacking ensemble is used to enhance base machine learning model performance on predicting bubble point pressure. Three datasets with different predictors are prepared to study machine learning algorithms' performance for three situations: only compositional data are available; only bulk properties (Gas-Oil-Ratio, gas gravity, API gravity and reservoir Temperature) are available; both compositional data and bulk properties are available. Through literature review, there is no research on using only compositional data and temperature to predict bubble point pressure. Our super learner model offers an accurate solution for oil bubble point pressure when only compositional data and temperature are available. Machine learning models perform better than empirical correlations with limited input data (i.e., bulk properties). When compositional data and bulk properties are all used as predictors, super learner reaches about 5.146% mean absolute relative error on predicting the bubble point pressure from global samples with bubble point pressures in the range of 100 to 10,000 psi, which is a wider range compared to most ANN models published in literature.",9,9,1
Porous Media,Bubble,"Wang, Yanwei; Liu, Huiqing; Zhang, Qichen; Chen, Zhangxin; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Pore-scale experimental study on EOR mechanisms of combining thermal and chemical flooding in heavy oil reservoirs,Viscosity reducer; Steam flooding; Foam; Visualized experiments; Mechanisms analysis,CYCLIC STEAM STIMULATION; CRUDE-OIL; VISCOSITY REDUCTION; FOAM-GENERATION; RECOVERY; EMULSIONS; INJECTION; FLOW; ASPHALTENE; RHEOLOGY,"Steam flooding is an important method for the development of heavy oil reservoirs, but steam channeling is an inevitable serious problem in the process of steam injection, which decreases the sweep efficiency of steam and leads to low oil recovery. Viscosity reducer (VR) flooding and nitrogen foam flooding are two effective methods of enhancing heavy oil recovery with satisfactory results. In this paper, a series of experiments were conducted to evaluate the effects of various factors on the performance of the novel viscosity reducer (VR-A). On this basis, A visualized model was adopted to investigate the synergistic development effect of thermal and chemical flooding, which vividly reflected the interaction of chemical agents with crude oil and their migration characteristics in porous media, as well as the mechanisms of enhancing oil recovery on the pore-scale. The results showed that VR-A could achieve excellent viscosity reduction effect on heavy oil under the influence of various factors, which could be combined with thermal flooding to effectively recover heavy oil. As for the pore-scale level, after the VR-A solution was injected, the interfacial tension between the oil and water was decreased, the wettability of the surface of the particle was changed, and two types of oil-in-water emulsions (spherical emulsions and flocculent emulsions) with a lower viscosity were formed, which were easy to flow with the fluid in pores and throats and could temporarily block the high-permeability area. In the process of foam flooding, the phenomena of bubble coalescence and breakup occurred constantly, and bubbles trapped in the porous media could improve the sweep efficiency of the subsequent fluid. The ultimate oil recovery of the development method combining thermal and chemical flooding in the visualized displacement experiment is 76.9%, 39.7% higher than that of pure thermal flooding. This article can provide an effective method to solve the problem of poor steam flooding performance in heavy oil reservoirs.",19,20,8
Porous Media,Bubble,"Yang, Xi; Dindoruk, Birol; Lu, Ligang",A comparative analysis of bubble point pressure prediction using advanced machine learning algorithms and classical correlations,"Bubble point pressure; PVT; Fluid properties; Machine learning methods (XGBoost, LightGBM, random forest regressor, MLP neural network, and super learner); Correlations",PVT PROPERTIES; SUPER LEARNER; MODEL,"The need for fluid properties or PVT (Pressure-Volume-Temperature) properties, is part of the entire Exploration and Production (E&P) lifecycle from exploration to mature asset management to the typical later life events such as, Improved Oil Recovery (IOR). As the projects mature, the need for such data and its integration for various discipline-specific workflows and its interpretation in the light of reservoir performance varies. Among all the key PVT properties, bubble point pressure is probably the most important parameter. Bubble point pressure is important because it is the point at which constant composition and variable composition portions of the depletion paths merge. Geometrically, bubble point pressure appears to be a discontinuity. In addition, it dictates the existence (or not) of the incipient phase (i.e., gas phase) leading to the changes in the flow characteristics both in porous media and as well as within the wellbore and the facilities. Furthermore, it is also a good indicative of a possible gas cap when the reservoir is at saturation (reservoir pressure is equal to the bubble point pressure) or near-saturated. Among the highlighted uses, there are many more used such as the determination of the elements of miscibility, gas lift design, etc. Therefore, it is very important to estimate the bubble point pressure accurately. In this study, tree-based advanced machine learning algorithm including XGBoost, LightGBM, and random forest regressor, and multi-layer perceptron (neural network) regressor are implemented to predict bubble point pressure (P-bp). A novel super learner model which is also known as stacking ensemble is used to enhance base machine learning model performance on predicting bubble point pressure. Three datasets with different predictors are prepared to study machine learning algorithms' performance for three situations: only compositional data are available; only bulk properties (Gas-Oil-Ratio, gas gravity, API gravity and reservoir Temperature) are available; both compositional data and bulk properties are available. Through literature review, there is no research on using only compositional data and temperature to predict bubble point pressure. Our super learner model offers an accurate solution for oil bubble point pressure when only compositional data and temperature are available. Machine learning models perform better than empirical correlations with limited input data (i.e., bulk properties). When compositional data and bulk properties are all used as predictors, super learner reaches about 5.146% mean absolute relative error on predicting the bubble point pressure from global samples with bubble point pressures in the range of 100 to 10,000 psi, which is a wider range compared to most ANN models published in literature.",9,9,1
Porous Media,Knudsen Diffusion,"Fianu, John; Gholinezhad, Jebraeel; Hassan, Mohamad",Thermal simulation of shale gas recovery involving the use of microwave heating,Shale gas; Adsorption; Temperature-dependent adsorption model; Thermal stimulation; Microwave heating,ADSORPTION CAPACITY; METHANE ADSORPTION; NUMERICAL-ANALYSIS; POROUS-MEDIA; TEMPERATURE; MODEL; COMBUSTION; RESERVOIRS; STRATA,"Recent technological advancement in drilling for shale gas such as hydraulic fracturing, has meant that more gas can be recovered from the ultra-tight matrix of the shale formation. However, significant quantities of adsorbed gas are still left unproduced even with this breakthrough in accessing gas previously unattainable due to the low permeability of shale. In this paper, a coupled electromagnetic-thermal model has been developed to investigate the production of adsorbed gas from shale gas reservoirs using microwave heating. A dual porosity -dual permeability model is developed for the system of shale gas with account of both viscous and Knudsen diffusion in the matrix. Results from simulation indicated that microwave heating can improve cumulative production by 25% in a period of one year by accelerating desorption of the adsorbed gas. Further results also indicated higher penetration depth for microwave frequency of 915 MHz. This study provides useful insights into microwave assisted shale gas recovery.",9,10,8
Porous Media,Knudsen Diffusion,"Berawala, Dhruvit S.; Andersen, Pal O.",Numerical investigation of Non-Darcy flow regime transitions in shale gas production,Shale gas production; Non-Darcy flow; Forchheimer equation; Fracture-matrix flow; Apparent permeability,APPARENT PERMEABILITY; STRESS-DEPENDENCE; MODEL; RESERVOIRS; ADSORPTION; IMBIBITION; DIFFUSION; TRANSPORT; NANOPORES; EVOLUTION,"Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable. The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure depletion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir isotherm and is a key production mechanism. This model is implemented in Matlab using Marcellus shale data. Scaling the model shows that recovery of gas depends on two dimensionless number that incorporates geometry relations, time scales of flow, intrinsic parameters of the porous media, non-Darcy constants, adsorption and boundary conditions. The dimensionless numbers define respectively if 1) the fracture or matrix limit the gas production rate 2) if non-Darcy flow is significant in the fracture or matrix. When one of the media limit production, the non-Darcy flow in the other medium has reduced importance and can be excluded from the model. Non-Darcy flow is important if it limits flow in the medium limiting the production. By checking the magnitude of the selected dimensionless numbers, the modelling approach can be determined in advance and significant computational time can be saved. The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.",8,8,4
Degrees C.,Crude Oil,"Al-Muntaser, Ameen A.; Varfolomeev, Mikhail A.; Suwaid, Muneer A.; Yuan, Chengdong; Chemodanov, Artem E.; Feoktistov, Dmitriy A.; Rakhmatullin, Ilfat Z.; Abbas, Mustafa; Dominguez-Alvarez, Enrique; Akhmadiyarov, Aydar A.; Klochkov, Vladimir V.; Amerkhanov, Marat I.","Hydrothermal upgrading of heavy oil in the presence of water at sub-critical, near-critical and supercritical conditions",Heavy oil; Hydrothermal upgrading; Sub-critical water; Near-critical water; Supercritical water; In-situ upgrading,CRUDE-OIL; AQUATHERMOLYSIS; NANOPARTICLES; SPECTROSCOPY; TEMPERATURE; HYDROLYSIS; CATALYST; CRACKING; BITUMEN; FTIR,"In this study, the hydrothermal upgrading (HTU) of high sulfur-content heavy oil was investigated at sub-critical (Sub-CW), near-critical (NCW) and supercritical water (SCW) conditions. Products obtained after HTU, including gases, liquid, and coke (if formed), were analyzed to understand the upgrading performance at different conditions. At Sub-CW (200, 250, and 300 degrees C), 250 degrees C is the optimum temperature where a viscosity reduction from 2073 to 1758 mPa s was achieved with a slight removal of sulfur (mainly sulfur) and the generation of a small amount of light and non-condensable hydrocarbons in gas phase (C1-C4, isoalkanes and alkenes, H2S, CO2 and H-2, etc.). At NCW (350 degrees C) and SCW (400 degrees C), heavy oil was upgraded into light oil with a significant removal of heteroatoms, an increase of saturates content, a reduction of aromatics, resins and asphaltenes contents, and a high yield of light gaseous hydrocarbons (mainly methane). Simultaneously, each SARA fraction was also greatly ameliorated: the content of light alkanes with low molecular weight in saturates was increased, diaromatics content in aromatics was increased with a reduction of polyaromatics content, aromatics-type carbon atoms in resins was increased with a decrease in aliphatic hydrocarbons. Moreover, MALDI-TOF measurements of asphaltenes show that the molecular weights of asphaltenes were reduced. All these results indicated that HTU at Sub-CW can be used for heavy oil pre-treatment (in-situ or ex-situ upgrading) considering its main effect of viscosity reduction with a small removal of heteroatoms, while HTU at NCW and SWC has a great potential in insitu and ex-situ upgrading and oil refining as it can convert heavy oil into light oil.",26,26,7
Degrees C.,Crude Oil,"Pu, Wanfen; Zhao, Shuai; Hu, Lingzhi; Varfolomeev, Mikhail A.; Yuan, Chengdong; Wang, Liangliang; Rodionov, Nikolay O.",Thermal effect caused by low temperature oxidation of heavy crude oil and its in-situ combustion behavior,Combustion tube; Thermal effect; Low temperature oxidation; Heavy crude oil; In-situ combustion; Porous media,AIR INJECTION; KINETICS; LIGHT; PYROLYSIS; FEASIBILITY; CALORIMETRY; COMPONENTS; RATES,"To investigate the thermal effect caused by low temperature oxidation (LTO) of one heavy crude oil in porous media, a combustion tube (CT) system coupled with a self-designed experimental scheme was adopted. Also, the in-situ combustion (ISC) performance of this heavy oil as well as alterations in oil properties before and after ISC was comprehensively evaluated. The results showed that there existed the apparent thermal effect induced by LTO within the researched ignition temperature (180-320 degrees C), and heat release became greater with the ignition temperature. It should be noted that the oxidation reaction rate of the heavy oil was rose remarkably releasing substantial heat when the ignition temperature was increased to 240 from 180 degrees C. The heavy oil was combusted under the ignition temperature of 350 degrees C, and the combustion front advanced sustainably. Some basic parameters during ISC, including apparent atomic H/C ratio, oxygen utilization, fuel consumption, etc., were determined, which made it accessible to predict field test performances. And the values of these parameters and post-mortem images of the CT test reflected the superior ISC performance of the heavy oil. The alterations in oil properties pre-ISC and post-ISC indicated that the produced oil encountered strong LTO reactions and thermal cracking reactions forming a considerable number of lighter oxygen-containing compounds. Comparison of differential scanning calorimetry (DSC) profiles of the crude oil and produced oil revealed that the ISC process made the heavy oil greatly upgrade.",14,14,3
Degrees C.,Crude Oil,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Degrees C.,Crude Oil,"Agarwal, Aditi; Samanta, Arunkumar; Nandi, Barun Kumar; Mandal, Ajay","Synthesis, characterization and performance studies of kaolin-fly ash-based membranes for microfiltration of oily waste water",Oily waste water; Microfiltration; Ceramic membrane; Sintering temperature; Pore blocking model,CERAMIC MEMBRANE; PARTICLE-SIZE; PORE GROWTH; SEPARATION; CORDIERITE; EMULSION; CLAY; FABRICATION; REMOVAL,"The present study deals with the synthesis, characterization, and performance evaluation of low-cost porous ceramic microfiltration membranes for separation of oily waste water. Ceramic membranes were synthesized following paste-casting method using three different ratios of kaolin to coal fly ash, in combination with a few selected suitable pore - formers and binders like calcium and sodium carbonate, boric acid, and sodium metasilicate. The synthesized membranes were characterized using the field emission scanning electron microscope (FESEM), X-ray diffraction (XRD), atomic force microscopy (AFM), thermogravimetric analysis (TGA), and water permeation tests with the objective of investigating the influence of sintering temperature (750 degrees C-900 degrees C) and precursor ratio on the microstructural evolution of the fabricated membranes. Three varying concentrations of oil-in-water (O/W) emulsions (100, 200, and 300 mg/L) prepared using a typical crude oil collected from an oil field located in Digboi, India was used as a representative sample and tested for the microfiltration studies. A fabricated membrane with a porosity (similar to 34.36-39.0%), pore size (similar to 0.65-1.81 mu m) showed an excellent separation efficiency of 96.7-99.5% with a permeate flux around similar to 24.3 x 10(-5) m(3) m(-2) s(-1). The flux decline mechanism was analyzed using the pore blocking models, and it was observed that the cake filtration model followed by the intermediate pore-blocking model were the best - fitted models as compared to others to describe the permeate flux data. The fabricated kaolin-fly ash-based membranes exhibited good permeability and separation efficiency characteristics, which suggest its suitability for microfiltration of oily waste water from oil exploration and refinery industries.",12,12,5
Degrees C.,Crude Oil,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Degrees C.,Crude Oil,"Zhang, Panfeng; Diao, Yuqian; Shan, Yu; Pei, Shufeng; Ren, Shaoran; Zhang, Liang; Yang, Hongbin",Experimental investigation of amine-surfactant CO2 foam for smart mobility control during CO2 flooding,Amine surfactant; CO2-responsive; Surface tension; Foam quality; CO2 foam; Mobility control,ENHANCED OIL-RECOVERY; HIGH-TEMPERATURE; WORMLIKE MICELLES; AQUEOUS FOAMS; CRUDE-OIL; STABILITY; PRESSURE; STORAGE; INJECTION; RESERVOIR,"Amine-surfactant can be converted to be cationic surfactant in water solution saturated with CO2, which can enhance their foaming ability and foam stability, and the foaming ability can be switched off or on by CO2 or replacing with N-2 with heating, so the amine-surfactants have great potential for smart mobility control to gas channeling during CO2 flooding. In this study, three alkyl propyl dimethylamines with different carbon chain length (R = 11, 17 and 22, named as UC(11)AMPM, UC(17)AMPM, and UC(22)AMPM, respectively), were investigated as CO2 responsive foam agent, and their foam performance under static and dynamic condition was tested up to 130 degrees C and 10.5 MPa using a visualized foam meter and a sand-pack flooding setup. The influence of carbon chain length on bulk solution viscosity, surface activity, foaming ability, and foam quality on bulk foam stability were measured and analyzed. The experimental results indicate that the three amine surfactants all demonstrate well CO2 responsibility and CO2 foaming ability, and show well switchable by CO2 and N-2 at high temperature and high pressure (HTHP) condition. With the carbon chain length increasing, the surfactant shows higher absorption on the foam films, and bulk solution has a higher viscosity, which can decrease de-foam velocity and enhance the foam stability, as a result, the surfactant shows higher mobility control ability.",9,9,7
Degrees C.,Crude Oil,"Abalkhail, Nassir; Liyanage, Pathma Jith; Upamali, Karasinghe A. N.; Pope, Gary A.; Mohanty, Kishore K.",Alkaline-surfactant-polymer formulation development for a HTHS carbonate reservoir,Surfactant flooding; Enhanced oil recovery; Carbonate reservoir; High temperature; High salinity,MICROEMULSION PHASE; OIL,"There are many HTHS (high temperature, high salinity) carbonate reservoirs where temperature (>80 degrees C) and salinity (>30,000 ppm) are high. The goal of this study was to develop an alkaline-surfactant-polymer (ASP) formulation for a high temperature (similar to 100 degrees C), high salinity (similar to 60,000 ppm) giant carbonate reservoir with low surfactant retention, an essential requirement for low chemical cost. Phase behavior tests were conducted with anionic surfactants, alkali, co-solvents, brine, and crude oil to identify chemical formulations with ultra-low IFT under reservoir conditions. Corefloods were first conducted in outcrop carbonate cores and then in reservoir cores. The effluent was analyzed for oil, surfactant, pH, salinity and viscosity. Surfactant adsorption on carbonate surfaces decreases at high pH. Ammonia and a new organic alkali ethoxylated diisopropylamine (DIPA-10EO) were studied for this application since there is both anhydrite and dolomite in the formation. Sodium carbonate cannot be used as the alkali in rocks containing anhydrite, and sodium hydroxide cannot be used as the alkali in rocks containing dolomite. Ultralow IFT (similar to 0.001 mN/m) was achieved with several ASP formulations using the reservoir oil. The first three core floods in Indiana limestone yielded excellent tertiary oil recoveries of 85.2, 89.5 and 91.8%, and very low surfactant retentions of 0.06, 0.02, and 0.11 mg/g-rock, respectively. The reservoir coreflood resulted in 93.6% tertiary oil recovery and a final oil saturation of 1.2%. The surfactant retention was 0.083 mg/g-rock. The chemical formulation developed here is applicable to this high permeability, non-fractured, HTHS carbonate reservoir. Future research should address other carbonate reservoir issues such as fractures and low permeability.",9,9,1
Degrees C.,Crude Oil,"Vahdanikia, Nabi; Divandari, Hassan; Hemmati-Sarapardeh, Abdolhossein; Amar, Menad Nait; Schaffie, Mahin; Ranjbar, Mohammad","Integrating new emerging technologies for enhanced oil recovery: Ultrasonic, microorganism, and emulsion",Enhanced oil recovery; Water in oil emulsion; Surfactants; Biosurfactants; Ultrasonic,BIOSURFACTANT-PRODUCING BACTERIA; WATER-CONTENT; STABILITY; TEMPERATURE; DROPLETS; DEMULSIFICATION; VISCOSITY; CULTURE; SOLIDS; FIELD,"Water in oil emulsions have turned into interesting and attractive resources for enhanced oil recovery (EOR). The stability of emulsions is important for its efficiency as EOR agents. The objective of this study was to investigate the simultaneous influence of ultrasound waves and microorganisms on the stability of water-in-oil emulsions. To this end, using an Iranian crude oil, two types of waters, surfactants and three types of biosurfactants producing microorganisms the impacts of temperature, ultrasonic frequency, and radiation time on the stability, viscosity and surface tension of water-in-oil emulsions were studied. From the results of this study, it can be pointed out that compared to the conventional surface-active agents; biosurfactants have a higher impact on the stability of emulsions. In addition, under the optimum conditions of this study, the surface tension decreased about 15% and the stability increased nearby 20%. Ultrasonic radiation reduces emulsion stability by about 6%. The T.F. species have the greatest effect on the emulsion stability up to 70 degrees C (more than 85%). Micromodel flooding experiments showed that injection of T.F biosurfactants emulsion provides the highest oil recovery due to their high stability, high viscosity, and low surface tension.",9,9,1
Degrees C.,Crude Oil,"Adewunmi, Ahmad A.; Amao, Abduljamiu O.; Kamal, Muhammad Shahzad; Solling, Theis Ivan",Demulsification and breaking mechanism of variable quartz concentrates obtained from sand,Demulsification; Quartz; Seawater; Oil; Size; Recycle,HEAVY CRUDE-OIL; IN-WATER EMULSIONS; MAGNETIC NANOPARTICLES; IONIC LIQUIDS; MICROWAVE; PERFORMANCE; INTERFACE; BEHAVIOR,"This study reports the efficacy of quartz particles extracted from sand for the destabilization of crude oil emulsions and efficient water removal. Demulsification performance of quartz concentrates obtained from stacked sieves with openings: 75, 125, 250 and 300 mu m and quartz quantity varying from 1% to 7% were investigated using the bottle test technique at a temperature of 90 degrees C. The breaking mechanism of emulsion driven by quartz was analyzed by rheology, Fourier Transform Infrared (FTIR) spectroscopy, X-ray diffraction (XRD), optical microscopy and scanning electron microscopy (SEM). Experimental results showed that the quartz concentrates generated from stacked sieves: 75, 125, 250, and 300 mu m had optimal demulsification efficiency (DE) of 98%, 98%, 99%, and 99%, respectively. Moreover, the quartz concentration needed to attain these DEs levels ranges from 3 to 5%. In addition, the performance of quartz as a demulsifier was compared with a commercial demulsifier (ethyl cellulose). Viscosity versus time measurements demonstrated the change in emulsion's viscosity before and after quartz addition. A drastic reduction in the emulsion's viscosity was observed after quartz addition, indicating rupture and coalescence of water droplets. The FTIR and XRD analysis buttressed the functional groups and structural pattern while optical microscope and SEM analysis exhibited the morphology of quartz particles before and after the demulsification processes. A mechanism elucidating the breaking of crude oil emulsion by quartz is proposed. The results indicated that quartz particles processed from the sand will be useful as demulsifiers in the petroleum industry.",7,7,6
Degrees C.,Crude Oil,"Mustafin, Robert; Manasrah, Abdallah D.; Vitale, Gerardo; Askari, Roohollah; Nassar, Nashaat N.",Enhanced thermal conductivity and reduced viscosity of aegirine-based VR/VGO nanofluids for enhanced thermal oil recovery application,Nanoparticles; Vacuum residue; Vacuum gas oil; Nanofluids; Thermal conductivity; Oil recovery,HEAVY OIL; OXIDE NANOPARTICLES; CUO NANOPARTICLES; CARBON NANOTUBES; VOLUME FRACTION; CRUDE OILS; ADSORPTION; ASPHALTENES; TEMPERATURE; BITUMEN,"The depleting of the available conventional energy supplies together with an industrial shift towards unconventional resources like heavy oil/bitumen has become more pronounced. The steam-based heating methods are primarily used by the oil industry for the heavy oil/bitumen recovery. However, the thermal recovery methods are energy-intensive and have limited applications, especially for both thin and deep reservoirs. Therefore, there is a high priority need to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection. Hence, the continual improvement of this technique is of utmost importance. This study aims to propose a new injecting nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading and recovery. Here we report a new type of copper-based nanofluid using a blend of vacuum gas oil (VGO) and vacuum residue (VR) as the mother solvent. The nanoparticles were prepared by low-temperature hydrothermal synthesis route. Their detailed surface, morphology and size characterizations were achieved by X-ray diffraction, dynamic light scattering and scanning electron microscopy. The stable nanofluids were prepared by dispersing copper-based nanoparticles in a mixture of VGO and VR, at different ratios and temperatures. A set of measurements to determine the thermal conductivity and viscosity of the nanofluid with different loading of nanoparticle were performed. The thermal conductivity values of nanofluid systems are substantially higher than that of the base fluids. The nanofluid for 2 wt% of copper-doped aegirine nanoparticles dispersed in VGO and VGO/VR mixture exhibits a maximum thermal conductivity of 20% and 24%, respectively. It was found that the thermal conductivity of nanofluids increases with decreasing the hydrodynamic particle size. Moreover, the presence of chemo-physical interactions between nanoparticles and base fluid further enhances the thermal conductivity. Also, the temperature augmentation in a range from 80 to 110 degrees C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. This particular nanofluid may find potential applications in enhancing heavy oil upgrading and recovery.",7,7,5
Degrees C.,High Salinity,"Jouenne, Stephane","Polymer flooding in high temperature, high salinity conditions: Selection of polymer type and polymer chemistry, thermal stability",Polymer flooding; Carbonates; AMPS copolymers (2-Acrylamido-2-methyl-1-propanesulfonate); H2S; CO2; Oxidative degradation,ENHANCED OIL-RECOVERY; MECHANICAL-DEGRADATION; ELEVATED-TEMPERATURE; SCREENING CRITERIA; FIELD APPLICATIONS; AQUEOUS-SOLUTION; OXIDATION; KINETICS; SULFIDE; INJECTION,"After 50 years of research and numerous commercial field applications around the world, polymer flooding is considered as a proven EOR technique. However, until recently, its application was limited to reservoirs with temperature not exceeding 100 degrees C. The development of polymer withstanding harsh conditions such as those encountered in Middle East carbonate reservoirs (temperature higher than 100 degrees C and salinity up to 280 g/L), would unlock a lot of reserves. In this paper, thermal stability, limits and application range of biopolymers and acrylamide-based polymers are reviewed. It appears that a new class of acrylamide-based copolymers containing high level of 2-acrylamido-2-methyl propane sulfonate (AMPS) fulfills the main criteria for massive field injection: industrial availability, moderate cost, thermal stability (we present aging tests for which 80% of the viscosity is maintained after 3 years at 120 degrees C in a hard brine) and ability to propagate in a wide range of permeabilities by tailoring the molecular weight. A viscosity model we recently developed is applied for comparing the viscosifying power of hydrolyzed polyacrylamides (HPAM) with a AMPS-rich polymer (SAV10). The latter presents a better salinity tolerance, especially when divalent cations are present and a better viscosifying power in temperature. The model is successfully applied when viscosity is predicted at high temperature from a viscosity measurement at ambient temperature. After reviewing the effect of CO2 and H2S on viscosity and degradation, it is shown that SAV10 viscosity is not sensitive to pH and should remain constant whatever the CO2 content. This insensitivity to pH is taken as an advantage: a method is proposed for minimizing oxidative degradation on solutions sampled manually on the field.",18,18,11
Degrees C.,High Salinity,"Lai, Nanjun; Wen, Yiping; Yang, Zhidong; Chen, Jianlin; Zhao, Xubin; Wang, Dongdong; He, Wei; Chen, Yuemei",Polymer flooding in high-temperature and high-salinity heterogeneous reservoir by using diutan gum,High-temperature; High-salinity; Strong heterogeneity; Diutan gum; Rheological properties; Oil displacement experiments,LASER-LIGHT SCATTERING; HYDROPHOBICALLY ASSOCIATING POLYACRYLAMIDE; WATER-SOLUBLE COPOLYMERS; RHEOLOGICAL PROPERTIES; SOLUTION BEHAVIOR; PROFILE-CONTROL; OIL-RECOVERY; ACRYLAMIDE; DISPLACEMENT; XANTHAN,"Diutan gum, a biopolymer that has been widely used in cement and concrete industries, was introduced in this work to alleviate severe viscosity loss and the poor water solubility of polyacrylamide and its modified products in high-temperature and high-salinity reservoirs. Diutan gum is an exopolysaccharide secreted by sphingomonas. The rheological properties and capacity of diutan gum to enhance oil recovery in high-temperature and highsalinity heterogeneous reservoir (T = 130 degrees C, Total salinity = 223.07 g L-(1), V-k = 0.93) was investigated and compared with those of two other kinds of biopolymer thickeners (xanthan and konjac gum), which are commonly used in oilfield development. The three biopolymers show pseudoplastic fluid properties in a steadystate rheological test: given the strong interactions in the double-helix structure of diutan gum, the number of the Newtonian zone and the shear rate of this zone are higher than the those of the two other biopolymers. The storage modulus (G') of diutan gum are higher than its loss modulus (G '') in all the concentrations and frequencies measured through viscoelasticity tests. This result indicates that diutan gum exhibits remarkable elasticity in slow displacement speed while it seeping in porous media. The capability of establish flow resistance in high-permeability porous medium in high-temperature and high-salinity environment by three biopolymers was studied, and their viscosity and microscopic properties of injected and produced fluid were investigated to understand the reason why diutan gum can have good fluidity control ability. Oil displacement efficiency can be improved by the elasticity of the diutan gum even without an increase in displacement speed. The results of the oil displacement experiments in the heterogeneity model imply that diutan gum is more effective in improving the water injection profile of each layer than xanthan and konjac gum. The water channeling in the high-permeability layer is restrained, and the sweep ability of the displacement phase is improved. Furthermore, the effect of polymer flooding can be maintained for a long time. Under high-temperature, high-salinity and strong heterogeneity, diutan gum recovers 19.34% of original oil in place (OOIP). This value is higher than the values obtained with xanthan gum (14.15% OOIP) and konjac gum (8.60% OOIP). This finding implies that the diutan gum has great application potential in the development of high-temperature and high-salinity reservoirs with strong heterogeneity.",13,12,7
Degrees C.,High Salinity,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Degrees C.,High Salinity,"Das, A.; Nguyen, N.; Farajzadeh, R.; Southwick, J. G.; Vincent-Bonnieu, S.; Khaburi, S.; Al Kindi, A.; Nguyen, Quoc P.","Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs",Enhanced oil recovery; Foam; Microemulsion; Carbonate; High salinity; Low permeability,ADSORPTION; OIL,"Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging. In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 degrees C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.",10,10,7
Degrees C.,High Salinity,"Wang, Ruolan; Pu, Wanfen; Dang, Sisi; Jiang, Feng; Zhao, Shuai",Synthesis and characterization of a graft-modified copolymer for enhanced oil recovery,Graft-modified copolymer; Antiaging performance; Welan gum; Enhanced oil recovery; Salt resistance,XANTHAN GUM; ACRYLAMIDE,"A graft-modified copolymer (cWL-g-A) was synthesized using Welan Gum (WLG), acrylamide, acrylic acid, and 0-20 via free-radical copolymerization to be well applied for enhanced oil recovery. The chemical structure of the copolymer was characterized by Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance spectroscopy (NMR), thermogravimetry (TG) and scanning electron microscopy (SEM). The long-term stability, rheology, adsorption, temperature and salt resistance of the copolymer were investigated. The cWL-g-A solution showed superior temperature and salt resistance in comparison with partially hydrolyzed polyacrylamide (HPAM), due to the hydrophobic association of main polymer chain. Particularly in high salinity (230,000 mg/L) solutions, cWL-g-A showed a better antiaging performance at three different temperatures (25, 50 and 65 degrees C). Oil recovery yielded by cWL-g-A was 14.18% higher than that yielded by HPAM, as known from polymer flooding tests. These results elucidated that cWL-g-A synthesized herein was superior to HPAM in high-salinity and medium-high temperature oil reservoirs.",10,9,4
Degrees C.,High Salinity,"Abalkhail, Nassir; Liyanage, Pathma Jith; Upamali, Karasinghe A. N.; Pope, Gary A.; Mohanty, Kishore K.",Alkaline-surfactant-polymer formulation development for a HTHS carbonate reservoir,Surfactant flooding; Enhanced oil recovery; Carbonate reservoir; High temperature; High salinity,MICROEMULSION PHASE; OIL,"There are many HTHS (high temperature, high salinity) carbonate reservoirs where temperature (>80 degrees C) and salinity (>30,000 ppm) are high. The goal of this study was to develop an alkaline-surfactant-polymer (ASP) formulation for a high temperature (similar to 100 degrees C), high salinity (similar to 60,000 ppm) giant carbonate reservoir with low surfactant retention, an essential requirement for low chemical cost. Phase behavior tests were conducted with anionic surfactants, alkali, co-solvents, brine, and crude oil to identify chemical formulations with ultra-low IFT under reservoir conditions. Corefloods were first conducted in outcrop carbonate cores and then in reservoir cores. The effluent was analyzed for oil, surfactant, pH, salinity and viscosity. Surfactant adsorption on carbonate surfaces decreases at high pH. Ammonia and a new organic alkali ethoxylated diisopropylamine (DIPA-10EO) were studied for this application since there is both anhydrite and dolomite in the formation. Sodium carbonate cannot be used as the alkali in rocks containing anhydrite, and sodium hydroxide cannot be used as the alkali in rocks containing dolomite. Ultralow IFT (similar to 0.001 mN/m) was achieved with several ASP formulations using the reservoir oil. The first three core floods in Indiana limestone yielded excellent tertiary oil recoveries of 85.2, 89.5 and 91.8%, and very low surfactant retentions of 0.06, 0.02, and 0.11 mg/g-rock, respectively. The reservoir coreflood resulted in 93.6% tertiary oil recovery and a final oil saturation of 1.2%. The surfactant retention was 0.083 mg/g-rock. The chemical formulation developed here is applicable to this high permeability, non-fractured, HTHS carbonate reservoir. Future research should address other carbonate reservoir issues such as fractures and low permeability.",9,9,1
Degrees C.,High Salinity,"Hassan, Anas M.; Ayoub, M.; Eissa, M.; Bruining, Hans; Zitha, P.",Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding,Surface complexes; DLVO theory; Enhanced oil recovery (EOR); Smart water assisted foam (SWAF) flooding; Low-salinity; Wettability alteration; Foam flooding; Foam stability; Carbonate reservoirs; PHREEQC-Software,ACTIVITY-COEFFICIENT; OSMOTIC COEFFICIENTS; THERMODYNAMICS; ELECTROLYTES; TRANSPORT; MECHANISMS; CARBONATE; ORDER; PART; IRON,"This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25 degrees C) and at the reservoir-conditions (80 degrees C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Huckel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foamlaminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25 degrees C) and at (80 degrees C) than the high-salinity case for both (25 degrees C) and (80 degrees C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of ""Smart Water Assisted Foam (SWAF) Flooding"". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.",7,7,4
Degrees C.,Mechanical Properties,"Mahanta, Bankim; Ranjith, P. G.; Vishal, Vikram; Singh, T. N.",Temperature-induced deformational responses and microstructural alteration of sandstone,Sandstone; Thermal damage; Acoustic emission; Microstructure; Micro-CT,MECHANICAL-PROPERTIES; FRACTURE-TOUGHNESS; THERMAL-PROPERTIES; ACOUSTIC-EMISSION; CRACK INITIATION; TENSILE-STRENGTH; GRANITIC-ROCKS; PERMEABILITY; BEHAVIOR; THRESHOLDS,"The high-temperature response of rock is quite useful for successful exploration and exploitation of various conventional as well as unconventional energy systems such as underground coal gasification, and geothermal energy, where the associated rocks are exposed to various temperature and pressure conditions. In this study, we have investigated the effect of temperature and thermal alteration of an Indian sandstone. An investigation using acoustic emission, digital image correlation through ARAMIS, micro-computed tomography (CT) techniques and thermogravimetric analysis was performed to study the mechanical responses of the sandstone with increasing temperatures. The results indicate that uniaxial compressive strength (UCS), tensile strength and elastic modulus of sandstone reduced significantly and aligned in an overall decreasing trend with increasing temperatures. The maximum and minimum UCS of sandstone were obtained at 400 degrees C and 700 degrees C, respectively. Acoustic emission (AE) responses of the sandstone indicated an early crack initiation and crack damage for high-temperature treated specimens. The deformation was further analysed using the ARAMIS digital image correlation technique, and strain levels were visually quantified that exhibited a widespread distribution of higher strain for thermally-treated specimens at 700 degrees C. Microstructural thermal damage and different pore-characteristics were studied using micro-CT techniques that provided valuable information about the connected and non-connected pores of the sandstone and their evolution with increasing temperatures. The outcomes suggest a heat-induced increment in porosity by nearly 40 percent upon heating the samples from 25 degrees C to 600 degrees C, which can be attributed due to the opening of new cracks that stimulated structural damage.",18,19,10
Degrees C.,Mechanical Properties,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Degrees C.,Mechanical Properties,"Mpelwa, Musa; Tang, Shanfa; Jin, Lijun; Hu, Ruizhi; Wang, Changquan; Hu, Yang",The study on the properties of the newly extended Gemini surfactants and their application potentials in the petroleum industry,Chemical EOR; Gemini surfactant; Interfacial tension; Rheological behavior; Corrosion inhibition,ENHANCED OIL-RECOVERY; ULTRALOW INTERFACIAL-TENSION; CORROSION-INHIBITORS; PERFORMANCE; BEHAVIOR; SPACER; TEMPERATURE; ADSORPTION; STEEL,"In this study, the newly extended Gemini surfactants (EGSs) were studied as potential candidates in the petroleum industry applications. The performances of EGSs with respect to variant spacer lengths were studied through surface tension, conductivity, dynamic light scattering (DLS), interfacial tension, rheological behavior, field emission electron microscopy (FESEM), core flooding, and corrosion inhibition measurements. The surface pressure (pi(CMC)), surface efficiency (pC(20)), critical micelle concentration (CMC), maximum surface excess concentration (Gamma(max)), minimum area per molecule of surfactant at the air-water interface (A(min)), average the degree of counterion binding to micelle (beta), Gibb's free energy of micellization (Delta G(mic)), and Gibb's free energy of adsorption (Delta G(ads)) of the EGSs were determined from surface tension and conductivity data. The results showed that the EGSs exhibited more surface activity properties, low CMCs, and spontaneously adsorbed at the air-water interface and micellized in the bulk aqueous phase. The surfactants reduced the oil-water interfacial tension (IFT) to ultralow values (10(-3) mN/m) at low concentration, and it decreased substantively to very ultralow values (10(-4) mN/m) due to the addition of inorganic salts. Also, they exhibited fascinating viscosifying effect and viscoelastic behavior at the experimental temperatures (30 degrees C-60 degrees C). The rheological behaviors were influenced by the formation of entangled micelles in aqueous solutions. Furthermore, through core flooding, EGS1 increased oil recovery by 12.30% which is an interesting incremental recovery. Besides, the EGSs surfactants showed high anticorrosion efficacy on A3 carbon steel in 1 M HCl aqueous solution and the inhibitive action mechanism was revealed to be by creating a protective film on the carbon steel surface through physisorption. Overall, the surface activity, interfacial activity, rheological behaviors, and anticorrosion property were dependent on the length of the spacer group. The surfactants, particularly EGS1 demonstrated a more promising interfacial activity and rheological behavior for enhanced oil recovery (EOR) in heterogeneity reservoirs as well as a remarkable anticorrosion property.",13,13,1
Degrees C.,Mechanical Properties,Deng Kuanhai; Yuan Yue; Hao Yi; Li Zhonghui; Lin Yuanhua,Experimental study on the integrity of casing-cement sheath in shale gas wells under pressure and temperature cycle loading,Casing-cement sheath; Full-scale integrity test; Temperature cycle loading; Pressure cycle loading; Interface mechanical properties; Multistage hydraulic fracturing,ZONAL ISOLATION; FAILURE; MODEL,"During large-scale multistage hydraulic fracturing in shale-gas wells, the cement sheath loses its integrity easily because of repeated temperature and pressure variations in the wellbore. This is likely to form a potential leak path, subsequently leading to the loss of zonal isolation and sustained casing pressure. To prevent such barrier failures, it is crucial to investigate and understand the failure mechanism of cement sheath. In this study, an experimental apparatus and evaluation method of the sealing integrity and mechanical integrity for casing-cement sheath under temperatures and pressures cycle loading have been presented in this paper by which sixteen groups of full-scale integrity tests of general and high-strength cement sheath have been conducted under temperature ranging from 30 to 150 degrees C and pressure ranging from 0 to 70 MPa cycling loading. The anti-channeling/sealing performance and interface mechanical behavior of casing-cement sheath are measured and characterized respectively under different loading-unloading methods. The cycle numbers required for sealing integrity failure of cement sheath under different cyclic temperatures and pressures have been obtained. The interface mechanical properties (cementing force, friction force, shearing strength and lateral bonding strength) of cement sheath have been obtained, and effects of alternating temperatures and pressures on those mechanical properties and late integrity have been analyzed. Research results can provide a very important reference for the fracturing design of shale-gas wells.",8,8,6
Degrees C.,Mechanical Properties,"Zhang, Weiqiang; Lv, Chao",Effects of mineral content on limestone properties with exposure to different temperatures,Mineral content; Limestone; Dolomite; Temperature; Physical and mechanical properties,MECHANICAL-PROPERTIES; THERMAL-DAMAGE; DOLOMITE; SANDSTONE; CALCITE; ROCK; EVOLUTION; KINETICS,"In order to study the impacts of mineral composition on physical and mechanical properties of limestone, an x-ray fluorescence experiment is carried out to examine the mineral elements content of limestone after exposure to different temperatures (up to 600 degrees C), and physical and mechanical experiments are implemented to examine the macroscopic properties of limestone. Then, the mineral composition was calculated based on the order of chemical affinity and the proportion of molecular weight, and the correlation between mineral content and macro properties is studied with a canonical correlation analysis. The results show that the dolomite slowly decomposes at temperatures over 300 degrees C and calcite is formed in the limestone instead. The argillaceous content of the limestone starts to decrease at temperatures between 200 degrees C and 300 degrees C. The changes in the mineral composition cause significant variations in the physical and mechanical properties, such as a gradual reduction in the compressive and tensile strengths, thermal conductivity and specific heat, and a lower P-wave velocity, as well as a gradual increase in the peak strain and relative solubility. The results of the canonical correlation analysis show that the changes in the limestone properties between a temperature of 25 degrees C and 600 degrees C have the highest correlation with argillaceous content, followed by calcite and dolomite.",8,9,3
Degrees C.,Mechanical Properties,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Degrees C.,Mechanical Properties,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Degrees C.,Nanoparticles,"Al-Muntaser, Ameen A.; Varfolomeev, Mikhail A.; Suwaid, Muneer A.; Yuan, Chengdong; Chemodanov, Artem E.; Feoktistov, Dmitriy A.; Rakhmatullin, Ilfat Z.; Abbas, Mustafa; Dominguez-Alvarez, Enrique; Akhmadiyarov, Aydar A.; Klochkov, Vladimir V.; Amerkhanov, Marat I.","Hydrothermal upgrading of heavy oil in the presence of water at sub-critical, near-critical and supercritical conditions",Heavy oil; Hydrothermal upgrading; Sub-critical water; Near-critical water; Supercritical water; In-situ upgrading,CRUDE-OIL; AQUATHERMOLYSIS; NANOPARTICLES; SPECTROSCOPY; TEMPERATURE; HYDROLYSIS; CATALYST; CRACKING; BITUMEN; FTIR,"In this study, the hydrothermal upgrading (HTU) of high sulfur-content heavy oil was investigated at sub-critical (Sub-CW), near-critical (NCW) and supercritical water (SCW) conditions. Products obtained after HTU, including gases, liquid, and coke (if formed), were analyzed to understand the upgrading performance at different conditions. At Sub-CW (200, 250, and 300 degrees C), 250 degrees C is the optimum temperature where a viscosity reduction from 2073 to 1758 mPa s was achieved with a slight removal of sulfur (mainly sulfur) and the generation of a small amount of light and non-condensable hydrocarbons in gas phase (C1-C4, isoalkanes and alkenes, H2S, CO2 and H-2, etc.). At NCW (350 degrees C) and SCW (400 degrees C), heavy oil was upgraded into light oil with a significant removal of heteroatoms, an increase of saturates content, a reduction of aromatics, resins and asphaltenes contents, and a high yield of light gaseous hydrocarbons (mainly methane). Simultaneously, each SARA fraction was also greatly ameliorated: the content of light alkanes with low molecular weight in saturates was increased, diaromatics content in aromatics was increased with a reduction of polyaromatics content, aromatics-type carbon atoms in resins was increased with a decrease in aliphatic hydrocarbons. Moreover, MALDI-TOF measurements of asphaltenes show that the molecular weights of asphaltenes were reduced. All these results indicated that HTU at Sub-CW can be used for heavy oil pre-treatment (in-situ or ex-situ upgrading) considering its main effect of viscosity reduction with a small removal of heteroatoms, while HTU at NCW and SWC has a great potential in insitu and ex-situ upgrading and oil refining as it can convert heavy oil into light oil.",26,26,7
Degrees C.,Nanoparticles,"Mao, Hui; Yang, Yan; Zhang, Hao; Zheng, Jie; Zhong, Ying",Conceptual design and methodology for rheological control of water-based drilling fluids in ultra-high temperature and ultra-high pressure drilling applications,Water-based drilling fluid; Rheological control methodology; Particle dense packing; Weighting particles; Deep well drilling; Ultra-high temperature and ultra-high pressure,FILTRATION PROPERTIES; SILICA NANOPARTICLES; OXIDE NANOPARTICLES; PERFORMANCE; COMPOSITE; MODIFIER; MUDS,"A new concept for the design and development of ultra-high temperature and ultra-high pressure water-based drilling fluid (ultra-HTHP WBDF), based on particle dense packing theory and suitable for ultra-HT (205-260 degrees C) and ultra-HP (138-241 MPa) drilling applications is proposed in this study. The concept for the rheological control of ultra-HTHP WBDF can be concluded as that the drilling fluid would have the highest possible density and the best fluidity when the mix of weighting agent particles of variable density, size and size distribution form the closest packing. An experimental study was conducted to verify the new concept by investigating how the weighting agent particle density, size and size distribution affect the rheological properties, filtration loss and sagging characteristics of WBDF designed for ultra-HTHP drilling applications. The ultra-high density (ultra-HD) WBDFs were formulated according to this concept by using the optimum mixtures of the weighting agents, which include industrial ferroferric oxide, barite and ultrafine barite. The laser particle size analysis technique was used to determine particle size and size distribution in different drilling fluid samples. The sagging characteristics of the drilling fluids were determined by using the Static Sagging Test method. Test results of the fluids formulated according to particles dense packing theory confirmed that rheological properties, filtration loss and sagging characteristics and density limit of the drilling fluid were all significantly influenced by the variation of the particle size, size distribution and the packing of the weighting agents, which indicated that the non-structural viscosity caused by the interactions among the weighting agent particles such as friction and collision dominantly controlled the rheological properties of ultra-HTHP WBDF. Finally, a new methodology for rheological control of ultra-HTHP WBDF was proposed, which can be summarized as using all means and methodologies to drive the dispersion state of solid weighting agent particles in ultra-HTHP WBDF to be at a more discrete state. By proper selection of the weighting agent particle size and size distribution, it was possible to form a thin, dense mud cake, which was conducive to decrease the filtration loss. Moreover, results have also shown that rheological properties, filtration loss and sagging characteristics of ultra-HT-HP WBDF can be effectively controlled by using three or even more different types of weighting agents with varying density, particle size and size distribution.",14,14,4
Degrees C.,Nanoparticles,"Zamani, Hamed; Jafari, Arezou; Mousavi, Seyyed Mohammad; Darezereshki, Esmaeel",Biosynthesis of silica nanoparticle using Saccharomyces cervisiae and its application on enhanced oil recovery,Microorganism; Enhanced oil recovery; Saccharomyces cervisiae; Precursor; Silica nanoparticles,,"Using nanotechnology to increase the recovery of oil reservoirs can be a good way to meet energy demand, in order to increase oil production and reduce production costs. Biotechnology of nanoparticles using microorganisms as an environmentally friendly research field in nanotechnology around the world is a rapid development and is considered as a substitute for conventional and physical chemical methods. Optimizing processes can lead to morphology, control of the size and speed of nanoparticle synthesis reactions. Therefore, the purpose of this research is to build a reflection on the current status and future projects, and in particular the feasibility and limitations of the biotechnology approach proposed in the oil industry. In this research, Saccharomyces cervisiae yeast has been used for biochemical production of silica nanoparticles. This yeast is cultivated in its own culture medium. This yeast solution made after the addition of Sodium Silicate Precursor placed in the proper conditions of growth, i.e., temperature of 29 degrees C, away from the types of contamination and the passage of time, reducing the silica nanoparticles from the initial precursor. In this research, after performing the silica nanoparticle production processes, identification tests such as FTIR, XRD, SEM, DLS and TGA are performed. Then, in order to investigate the effect of this nanoparticle on the production efficiency of the oil, these nanoparticles were added to injectable solutions to an oil-wet micro-model with different concentrations of 250 ppm, 500 ppm and 1000 ppm. It was observed that the difference in the effect of nanoparticles produced by the biochemical method and commercial nanoparticles purchased in the injection process and on the measurement of the production efficiency of oil was that biosynthesized nanoparticles increased oil production efficiency by about 5-7 percent relative to commercial nanoparticles.",13,13,2
Degrees C.,Nanoparticles,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Degrees C.,Nanoparticles,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Degrees C.,Nanoparticles,"Adewunmi, Ahmad A.; Amao, Abduljamiu O.; Kamal, Muhammad Shahzad; Solling, Theis Ivan",Demulsification and breaking mechanism of variable quartz concentrates obtained from sand,Demulsification; Quartz; Seawater; Oil; Size; Recycle,HEAVY CRUDE-OIL; IN-WATER EMULSIONS; MAGNETIC NANOPARTICLES; IONIC LIQUIDS; MICROWAVE; PERFORMANCE; INTERFACE; BEHAVIOR,"This study reports the efficacy of quartz particles extracted from sand for the destabilization of crude oil emulsions and efficient water removal. Demulsification performance of quartz concentrates obtained from stacked sieves with openings: 75, 125, 250 and 300 mu m and quartz quantity varying from 1% to 7% were investigated using the bottle test technique at a temperature of 90 degrees C. The breaking mechanism of emulsion driven by quartz was analyzed by rheology, Fourier Transform Infrared (FTIR) spectroscopy, X-ray diffraction (XRD), optical microscopy and scanning electron microscopy (SEM). Experimental results showed that the quartz concentrates generated from stacked sieves: 75, 125, 250, and 300 mu m had optimal demulsification efficiency (DE) of 98%, 98%, 99%, and 99%, respectively. Moreover, the quartz concentration needed to attain these DEs levels ranges from 3 to 5%. In addition, the performance of quartz as a demulsifier was compared with a commercial demulsifier (ethyl cellulose). Viscosity versus time measurements demonstrated the change in emulsion's viscosity before and after quartz addition. A drastic reduction in the emulsion's viscosity was observed after quartz addition, indicating rupture and coalescence of water droplets. The FTIR and XRD analysis buttressed the functional groups and structural pattern while optical microscope and SEM analysis exhibited the morphology of quartz particles before and after the demulsification processes. A mechanism elucidating the breaking of crude oil emulsion by quartz is proposed. The results indicated that quartz particles processed from the sand will be useful as demulsifiers in the petroleum industry.",7,7,6
Degrees C.,Nanoparticles,"Mustafin, Robert; Manasrah, Abdallah D.; Vitale, Gerardo; Askari, Roohollah; Nassar, Nashaat N.",Enhanced thermal conductivity and reduced viscosity of aegirine-based VR/VGO nanofluids for enhanced thermal oil recovery application,Nanoparticles; Vacuum residue; Vacuum gas oil; Nanofluids; Thermal conductivity; Oil recovery,HEAVY OIL; OXIDE NANOPARTICLES; CUO NANOPARTICLES; CARBON NANOTUBES; VOLUME FRACTION; CRUDE OILS; ADSORPTION; ASPHALTENES; TEMPERATURE; BITUMEN,"The depleting of the available conventional energy supplies together with an industrial shift towards unconventional resources like heavy oil/bitumen has become more pronounced. The steam-based heating methods are primarily used by the oil industry for the heavy oil/bitumen recovery. However, the thermal recovery methods are energy-intensive and have limited applications, especially for both thin and deep reservoirs. Therefore, there is a high priority need to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection. Hence, the continual improvement of this technique is of utmost importance. This study aims to propose a new injecting nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading and recovery. Here we report a new type of copper-based nanofluid using a blend of vacuum gas oil (VGO) and vacuum residue (VR) as the mother solvent. The nanoparticles were prepared by low-temperature hydrothermal synthesis route. Their detailed surface, morphology and size characterizations were achieved by X-ray diffraction, dynamic light scattering and scanning electron microscopy. The stable nanofluids were prepared by dispersing copper-based nanoparticles in a mixture of VGO and VR, at different ratios and temperatures. A set of measurements to determine the thermal conductivity and viscosity of the nanofluid with different loading of nanoparticle were performed. The thermal conductivity values of nanofluid systems are substantially higher than that of the base fluids. The nanofluid for 2 wt% of copper-doped aegirine nanoparticles dispersed in VGO and VGO/VR mixture exhibits a maximum thermal conductivity of 20% and 24%, respectively. It was found that the thermal conductivity of nanofluids increases with decreasing the hydrodynamic particle size. Moreover, the presence of chemo-physical interactions between nanoparticles and base fluid further enhances the thermal conductivity. Also, the temperature augmentation in a range from 80 to 110 degrees C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. This particular nanofluid may find potential applications in enhancing heavy oil upgrading and recovery.",7,7,5
Degrees C.,Thermal Conductivity,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Degrees C.,Thermal Conductivity,"Askarova, Aysylu; Turakhanov, Aman; Markovic, Strahinja; Popov, Evgeny; Maksakov, Kirill; Usachev, Gennady; Karpov, Valery; Cheremisin, Alexey",Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance,Hot water injection; Carbonate reservoirs; Consolidated core; Cementation; Numerical simulation; Kinetic model,IN-SITU COMBUSTION; AQUATHERMOLYSIS; MODEL,"Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100-1500 m require technology that can achieve sufficiently high fluid temperature (250-300 degrees C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling. The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called ""aquathermolysis"" to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons. A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H-2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.",10,10,3
Degrees C.,Thermal Conductivity,"Li, Ning; Zhang, Shicheng; Ma, Xinfang; Zou, Yushi; Li, Sihai; Zhang, Zhaopeng",Thermal effect on the evolution of hydraulic fracture conductivity: An experimental study of enhanced geothermal system,Geothermal energy; Hot dry rock; Micro-indentation; Thermal softening; Fracture conductivity,HOT DRY ROCK; ACOUSTIC-EMISSION RESPONSE; MECHANICAL-BEHAVIOR; HIGH-TEMPERATURE; HEAT EXTRACTION; ELASTIC-MODULUS; GRANITE; PROPPANT; INDENTATION; GROWTH,"This paper aimed to investigate the thermal effect on the evolution of hydraulic fracture conductivity during heat extraction. Meanwhile, the degradation mechanisms of fracture conductivity were analyzed in terms of the mechanical damage of fracture surfaces. Experimental results of micro-indentation tests on the studies granite show the existence of a threshold value of temperature. The Young's modulus and hardness of fracture surface significantly decreased when the thermal treatment levels were higher than 300 degrees C. Similarly, the degradation of fracture conductivity was limited (<10%) before 300 degrees C and then significantly deteriorated at 400 degrees C and 500 degrees C. Moreover, cyclic thermal treatment tended to aggregate the mechanical damages of fracture surfaces further. At the thermal treatment level of 300 degrees C, obvious thermal softening of fracture surfaces and degradation of fracture conductivity were observed only when the number of cycles was larger than 10, while both of these two phenomena became more severe with the increasing of the number of cycles at the thermal treatment level of 400 degrees C. The evolution of fracture conductivity can be accounted for by the temperature-related integrity of fracture surfaces and proppant pack. It was indicated that the thermal softening of fracture surface tended to enhance the proppant embedding, which might be beneficial for the alleviation of proppant crushing.",9,9,7
Degrees C.,Thermal Conductivity,"Liu, Peng; Shi, Lanxiang; Liu, Pengcheng; Li, Lei; Hua, Daode",Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs,Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery; Heterogeneity,ASSISTED GRAVITY DRAINAGE; RECOVERY; SOLVENT; PERFORMANCE; PRESSURE; GAS,"Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.",8,8,4
Degrees C.,Thermal Conductivity,"Zhang, Weiqiang; Lv, Chao",Effects of mineral content on limestone properties with exposure to different temperatures,Mineral content; Limestone; Dolomite; Temperature; Physical and mechanical properties,MECHANICAL-PROPERTIES; THERMAL-DAMAGE; DOLOMITE; SANDSTONE; CALCITE; ROCK; EVOLUTION; KINETICS,"In order to study the impacts of mineral composition on physical and mechanical properties of limestone, an x-ray fluorescence experiment is carried out to examine the mineral elements content of limestone after exposure to different temperatures (up to 600 degrees C), and physical and mechanical experiments are implemented to examine the macroscopic properties of limestone. Then, the mineral composition was calculated based on the order of chemical affinity and the proportion of molecular weight, and the correlation between mineral content and macro properties is studied with a canonical correlation analysis. The results show that the dolomite slowly decomposes at temperatures over 300 degrees C and calcite is formed in the limestone instead. The argillaceous content of the limestone starts to decrease at temperatures between 200 degrees C and 300 degrees C. The changes in the mineral composition cause significant variations in the physical and mechanical properties, such as a gradual reduction in the compressive and tensile strengths, thermal conductivity and specific heat, and a lower P-wave velocity, as well as a gradual increase in the peak strain and relative solubility. The results of the canonical correlation analysis show that the changes in the limestone properties between a temperature of 25 degrees C and 600 degrees C have the highest correlation with argillaceous content, followed by calcite and dolomite.",8,9,3
Degrees C.,Thermal Conductivity,"Mustafin, Robert; Manasrah, Abdallah D.; Vitale, Gerardo; Askari, Roohollah; Nassar, Nashaat N.",Enhanced thermal conductivity and reduced viscosity of aegirine-based VR/VGO nanofluids for enhanced thermal oil recovery application,Nanoparticles; Vacuum residue; Vacuum gas oil; Nanofluids; Thermal conductivity; Oil recovery,HEAVY OIL; OXIDE NANOPARTICLES; CUO NANOPARTICLES; CARBON NANOTUBES; VOLUME FRACTION; CRUDE OILS; ADSORPTION; ASPHALTENES; TEMPERATURE; BITUMEN,"The depleting of the available conventional energy supplies together with an industrial shift towards unconventional resources like heavy oil/bitumen has become more pronounced. The steam-based heating methods are primarily used by the oil industry for the heavy oil/bitumen recovery. However, the thermal recovery methods are energy-intensive and have limited applications, especially for both thin and deep reservoirs. Therefore, there is a high priority need to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection. Hence, the continual improvement of this technique is of utmost importance. This study aims to propose a new injecting nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading and recovery. Here we report a new type of copper-based nanofluid using a blend of vacuum gas oil (VGO) and vacuum residue (VR) as the mother solvent. The nanoparticles were prepared by low-temperature hydrothermal synthesis route. Their detailed surface, morphology and size characterizations were achieved by X-ray diffraction, dynamic light scattering and scanning electron microscopy. The stable nanofluids were prepared by dispersing copper-based nanoparticles in a mixture of VGO and VR, at different ratios and temperatures. A set of measurements to determine the thermal conductivity and viscosity of the nanofluid with different loading of nanoparticle were performed. The thermal conductivity values of nanofluid systems are substantially higher than that of the base fluids. The nanofluid for 2 wt% of copper-doped aegirine nanoparticles dispersed in VGO and VGO/VR mixture exhibits a maximum thermal conductivity of 20% and 24%, respectively. It was found that the thermal conductivity of nanofluids increases with decreasing the hydrodynamic particle size. Moreover, the presence of chemo-physical interactions between nanoparticles and base fluid further enhances the thermal conductivity. Also, the temperature augmentation in a range from 80 to 110 degrees C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. This particular nanofluid may find potential applications in enhancing heavy oil upgrading and recovery.",7,7,5
Degrees C.,Drilling Fluid,"Mao, Hui; Yang, Yan; Zhang, Hao; Zheng, Jie; Zhong, Ying",Conceptual design and methodology for rheological control of water-based drilling fluids in ultra-high temperature and ultra-high pressure drilling applications,Water-based drilling fluid; Rheological control methodology; Particle dense packing; Weighting particles; Deep well drilling; Ultra-high temperature and ultra-high pressure,FILTRATION PROPERTIES; SILICA NANOPARTICLES; OXIDE NANOPARTICLES; PERFORMANCE; COMPOSITE; MODIFIER; MUDS,"A new concept for the design and development of ultra-high temperature and ultra-high pressure water-based drilling fluid (ultra-HTHP WBDF), based on particle dense packing theory and suitable for ultra-HT (205-260 degrees C) and ultra-HP (138-241 MPa) drilling applications is proposed in this study. The concept for the rheological control of ultra-HTHP WBDF can be concluded as that the drilling fluid would have the highest possible density and the best fluidity when the mix of weighting agent particles of variable density, size and size distribution form the closest packing. An experimental study was conducted to verify the new concept by investigating how the weighting agent particle density, size and size distribution affect the rheological properties, filtration loss and sagging characteristics of WBDF designed for ultra-HTHP drilling applications. The ultra-high density (ultra-HD) WBDFs were formulated according to this concept by using the optimum mixtures of the weighting agents, which include industrial ferroferric oxide, barite and ultrafine barite. The laser particle size analysis technique was used to determine particle size and size distribution in different drilling fluid samples. The sagging characteristics of the drilling fluids were determined by using the Static Sagging Test method. Test results of the fluids formulated according to particles dense packing theory confirmed that rheological properties, filtration loss and sagging characteristics and density limit of the drilling fluid were all significantly influenced by the variation of the particle size, size distribution and the packing of the weighting agents, which indicated that the non-structural viscosity caused by the interactions among the weighting agent particles such as friction and collision dominantly controlled the rheological properties of ultra-HTHP WBDF. Finally, a new methodology for rheological control of ultra-HTHP WBDF was proposed, which can be summarized as using all means and methodologies to drive the dispersion state of solid weighting agent particles in ultra-HTHP WBDF to be at a more discrete state. By proper selection of the weighting agent particle size and size distribution, it was possible to form a thin, dense mud cake, which was conducive to decrease the filtration loss. Moreover, results have also shown that rheological properties, filtration loss and sagging characteristics of ultra-HT-HP WBDF can be effectively controlled by using three or even more different types of weighting agents with varying density, particle size and size distribution.",14,14,4
Degrees C.,Drilling Fluid,"Zhu, Wenxi; Zheng, Xiuhua; Li, Guomin","Micro-bubbles size, rheological and filtration characteristics of Colloidal Gas Aphron (CGA) drilling fluids for high temperature well: Role of attapulgite",Attapulgite; colloidal gas aphron drilling fluid; Aphron size distribution; Rheology; Filtration loss; Fluid loss control mechanism,STABILITY; SURFACTANT; BEHAVIOR; SYSTEM,"Colloidal Gas Aphron drilling fluids have been successfully applied in petroleum industry to drill low pressure formations and depleted reservoirs. As the increase of drilling depth and reservoir temperature, characteristics of CGA drilling fluids at high temperature are more concerned, yet less investigated. In this paper, attapulgite with better performance at high temperatures was selected to prepare CGA drilling fluids and the bubbles size distribution, rheological and fluid loss performance at 25 degrees C/90 degrees C/120 degrees C/150 degrees C/180 degrees C were studied. CGA fluid with Xanthan gum and 3% bentonite were prepared and tested as control group. Result indicates that: 1) The addition of attapulgite significantly reduces the average diameter of aphrons and improves the bubble size distribution of CGA fluids, which is conducive to the stability of CGA fluids; 2) Attapulgite effectively increases low shear rate viscosity (LSRV) of CGA fluid at room temperature, which will help to carry cuttings and seal formation. Power law model is the optimal model to describe the rheological behaviors of attapulgite-based CGA drilling fluids. Rheological parameters of Power law model show that the tested fluids have a shear thinning behavior at all temperatures and the flow behavior index can be controlled to an appropriate range by adjusting the amount of attapulgite; 3) Attapulgite greatly reduces the fluid loss of CGA drilling fluid, especially at high temperature. The attapulgite-based CGA drilling fluids can maintain an acceptable fluid loss (within 15 mL) for drilling operations at 120 degrees C. At 150/180 degrees C, 3% attapulgite exhibited the lowest fluid loss volume, which is reduced by 46.7%/25% as compared to 3% bentonite. In addition, the mechanism of attapulgite-based CGA fluid loss control was studied and can be concluded as the ""embedded"" mud cake structure composed by aphrons and attapulgite.",14,15,3
Degrees C.,Drilling Fluid,"Paswan, Bhola K.; Mahto, Vikas",Development of environment-friendly oil-in-water emulsion based drilling fluid for shale gas formation using sunflower oil,Surfactant synthesis; Rheology; Filtration properties; Zeta potential; Contact; Angle; Interfacial tension,TRIBOLOGICAL PROPERTIES; RHEOLOGICAL PROPERTIES; SURFACTANT; POLYMER; BENTONITE; BEHAVIOR; ADSORPTION; PARTICLES; STABILITY; WEIGHT,"Mineral oils are frequently used for the making of synthetic-based drilling fluids. However, there are several downsides associated with these oils. These mineral oils are non-renewable, toxic in nature, non-biodegradable and prompting towards the incredible expense of waste treatment. In this research article, an anionic surfactant sodium methyl ester sulfonate (SMES) was synthesized using sunflower oil. SMES is then used to formulate environment-friendly oil-in-water emulsion-based drilling fluid. The synthesized surfactant is characterized by FT-IR, H-1-NMR and TGA analysis. The effect of xanthan gum (XG), bentonite, and sodium methyl ester sulfonate (SMES) on the rheology and filtration characteristics of developed emulsion based drilling fluid was analyzed thoroughly. The developed emulsion based drilling fluid had lower friction coefficient in case of oil concentration compared to SMES concentration. The zeta potential has been measured to check the emulsion stability and it has been attended that an increase in the concentration of SMES (0.3-0.7 wt/v %) and xanthan gum (0.2-0.6 wt/v %) has improved the stability of the emulsion. The contact angle and interfacial tension were analyzed and it was observed that interfacial tension was reduced from 102.5 to 25.35 mN/m and contact angle increased from 32.5 degrees to 92.3 degrees. The thermal stability of oil-in-water emulsion based drilling fluid was maintained up to 140 degrees C.",14,14,2
Degrees C.,Drilling Fluid,"Reinoso, D.; Martin-Alfonso, M. J.; Luckham, P. F.; Martinez-Boza, F. J.",Flow behavior and thermal resistance of xanthan gum in formate brine,Xanthan gum; Formate brine; Flow behavior; Thermal resistance,RHEOLOGY; VISCOSITY; POLYSACCHARIDES; TEMPERATURE; DEGRADATION; GELS,"Drilling and completion operations in HP/HT environments demand the use of environmentally friendly fluids with suitable properties such as solid-free high-density and pseudoplastic behavior. Xanthan gum solutions in different brines may be an interesting alternative to ensure a suitable thermo-rheological behavior and biodegradability. Nevertheless, xanthan exposed at high temperature experiences thermal degradation that can modify the flow properties over time and limits the ceiling temperature of oilfield applications. To gain insight on this issue, this paper characterizes the flow behavior of low concentration XT solutions in calcium and potassium brines, evaluating the effect that potassium formate exerts on both the flow properties and the resistance to thermal degradation of xanthan solutions as a function of the biopolymer concentration. Xanthan in formate brine retains the pseudoplastic behavior up to 190 degrees C, however, low concentrate solutions undergo a thermal degradation that decreases the recovery of pseudoplasticity after being exposed to high temperature.",9,9,1
Degrees C.,Drilling Fluid,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Degrees C.,Interfacial Tension,"Paswan, Bhola K.; Mahto, Vikas",Development of environment-friendly oil-in-water emulsion based drilling fluid for shale gas formation using sunflower oil,Surfactant synthesis; Rheology; Filtration properties; Zeta potential; Contact; Angle; Interfacial tension,TRIBOLOGICAL PROPERTIES; RHEOLOGICAL PROPERTIES; SURFACTANT; POLYMER; BENTONITE; BEHAVIOR; ADSORPTION; PARTICLES; STABILITY; WEIGHT,"Mineral oils are frequently used for the making of synthetic-based drilling fluids. However, there are several downsides associated with these oils. These mineral oils are non-renewable, toxic in nature, non-biodegradable and prompting towards the incredible expense of waste treatment. In this research article, an anionic surfactant sodium methyl ester sulfonate (SMES) was synthesized using sunflower oil. SMES is then used to formulate environment-friendly oil-in-water emulsion-based drilling fluid. The synthesized surfactant is characterized by FT-IR, H-1-NMR and TGA analysis. The effect of xanthan gum (XG), bentonite, and sodium methyl ester sulfonate (SMES) on the rheology and filtration characteristics of developed emulsion based drilling fluid was analyzed thoroughly. The developed emulsion based drilling fluid had lower friction coefficient in case of oil concentration compared to SMES concentration. The zeta potential has been measured to check the emulsion stability and it has been attended that an increase in the concentration of SMES (0.3-0.7 wt/v %) and xanthan gum (0.2-0.6 wt/v %) has improved the stability of the emulsion. The contact angle and interfacial tension were analyzed and it was observed that interfacial tension was reduced from 102.5 to 25.35 mN/m and contact angle increased from 32.5 degrees to 92.3 degrees. The thermal stability of oil-in-water emulsion based drilling fluid was maintained up to 140 degrees C.",14,14,2
Degrees C.,Interfacial Tension,"Mpelwa, Musa; Tang, Shanfa; Jin, Lijun; Hu, Ruizhi; Wang, Changquan; Hu, Yang",The study on the properties of the newly extended Gemini surfactants and their application potentials in the petroleum industry,Chemical EOR; Gemini surfactant; Interfacial tension; Rheological behavior; Corrosion inhibition,ENHANCED OIL-RECOVERY; ULTRALOW INTERFACIAL-TENSION; CORROSION-INHIBITORS; PERFORMANCE; BEHAVIOR; SPACER; TEMPERATURE; ADSORPTION; STEEL,"In this study, the newly extended Gemini surfactants (EGSs) were studied as potential candidates in the petroleum industry applications. The performances of EGSs with respect to variant spacer lengths were studied through surface tension, conductivity, dynamic light scattering (DLS), interfacial tension, rheological behavior, field emission electron microscopy (FESEM), core flooding, and corrosion inhibition measurements. The surface pressure (pi(CMC)), surface efficiency (pC(20)), critical micelle concentration (CMC), maximum surface excess concentration (Gamma(max)), minimum area per molecule of surfactant at the air-water interface (A(min)), average the degree of counterion binding to micelle (beta), Gibb's free energy of micellization (Delta G(mic)), and Gibb's free energy of adsorption (Delta G(ads)) of the EGSs were determined from surface tension and conductivity data. The results showed that the EGSs exhibited more surface activity properties, low CMCs, and spontaneously adsorbed at the air-water interface and micellized in the bulk aqueous phase. The surfactants reduced the oil-water interfacial tension (IFT) to ultralow values (10(-3) mN/m) at low concentration, and it decreased substantively to very ultralow values (10(-4) mN/m) due to the addition of inorganic salts. Also, they exhibited fascinating viscosifying effect and viscoelastic behavior at the experimental temperatures (30 degrees C-60 degrees C). The rheological behaviors were influenced by the formation of entangled micelles in aqueous solutions. Furthermore, through core flooding, EGS1 increased oil recovery by 12.30% which is an interesting incremental recovery. Besides, the EGSs surfactants showed high anticorrosion efficacy on A3 carbon steel in 1 M HCl aqueous solution and the inhibitive action mechanism was revealed to be by creating a protective film on the carbon steel surface through physisorption. Overall, the surface activity, interfacial activity, rheological behaviors, and anticorrosion property were dependent on the length of the spacer group. The surfactants, particularly EGS1 demonstrated a more promising interfacial activity and rheological behavior for enhanced oil recovery (EOR) in heterogeneity reservoirs as well as a remarkable anticorrosion property.",13,13,1
Degrees C.,Interfacial Tension,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Degrees C.,Interfacial Tension,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Degrees C.,Interfacial Tension,"Das, A.; Nguyen, N.; Farajzadeh, R.; Southwick, J. G.; Vincent-Bonnieu, S.; Khaburi, S.; Al Kindi, A.; Nguyen, Quoc P.","Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs",Enhanced oil recovery; Foam; Microemulsion; Carbonate; High salinity; Low permeability,ADSORPTION; OIL,"Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging. In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 degrees C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.",10,10,7
Degrees C.,Emulsion,"Paswan, Bhola K.; Mahto, Vikas",Development of environment-friendly oil-in-water emulsion based drilling fluid for shale gas formation using sunflower oil,Surfactant synthesis; Rheology; Filtration properties; Zeta potential; Contact; Angle; Interfacial tension,TRIBOLOGICAL PROPERTIES; RHEOLOGICAL PROPERTIES; SURFACTANT; POLYMER; BENTONITE; BEHAVIOR; ADSORPTION; PARTICLES; STABILITY; WEIGHT,"Mineral oils are frequently used for the making of synthetic-based drilling fluids. However, there are several downsides associated with these oils. These mineral oils are non-renewable, toxic in nature, non-biodegradable and prompting towards the incredible expense of waste treatment. In this research article, an anionic surfactant sodium methyl ester sulfonate (SMES) was synthesized using sunflower oil. SMES is then used to formulate environment-friendly oil-in-water emulsion-based drilling fluid. The synthesized surfactant is characterized by FT-IR, H-1-NMR and TGA analysis. The effect of xanthan gum (XG), bentonite, and sodium methyl ester sulfonate (SMES) on the rheology and filtration characteristics of developed emulsion based drilling fluid was analyzed thoroughly. The developed emulsion based drilling fluid had lower friction coefficient in case of oil concentration compared to SMES concentration. The zeta potential has been measured to check the emulsion stability and it has been attended that an increase in the concentration of SMES (0.3-0.7 wt/v %) and xanthan gum (0.2-0.6 wt/v %) has improved the stability of the emulsion. The contact angle and interfacial tension were analyzed and it was observed that interfacial tension was reduced from 102.5 to 25.35 mN/m and contact angle increased from 32.5 degrees to 92.3 degrees. The thermal stability of oil-in-water emulsion based drilling fluid was maintained up to 140 degrees C.",14,14,2
Degrees C.,Emulsion,"Agarwal, Aditi; Samanta, Arunkumar; Nandi, Barun Kumar; Mandal, Ajay","Synthesis, characterization and performance studies of kaolin-fly ash-based membranes for microfiltration of oily waste water",Oily waste water; Microfiltration; Ceramic membrane; Sintering temperature; Pore blocking model,CERAMIC MEMBRANE; PARTICLE-SIZE; PORE GROWTH; SEPARATION; CORDIERITE; EMULSION; CLAY; FABRICATION; REMOVAL,"The present study deals with the synthesis, characterization, and performance evaluation of low-cost porous ceramic microfiltration membranes for separation of oily waste water. Ceramic membranes were synthesized following paste-casting method using three different ratios of kaolin to coal fly ash, in combination with a few selected suitable pore - formers and binders like calcium and sodium carbonate, boric acid, and sodium metasilicate. The synthesized membranes were characterized using the field emission scanning electron microscope (FESEM), X-ray diffraction (XRD), atomic force microscopy (AFM), thermogravimetric analysis (TGA), and water permeation tests with the objective of investigating the influence of sintering temperature (750 degrees C-900 degrees C) and precursor ratio on the microstructural evolution of the fabricated membranes. Three varying concentrations of oil-in-water (O/W) emulsions (100, 200, and 300 mg/L) prepared using a typical crude oil collected from an oil field located in Digboi, India was used as a representative sample and tested for the microfiltration studies. A fabricated membrane with a porosity (similar to 34.36-39.0%), pore size (similar to 0.65-1.81 mu m) showed an excellent separation efficiency of 96.7-99.5% with a permeate flux around similar to 24.3 x 10(-5) m(3) m(-2) s(-1). The flux decline mechanism was analyzed using the pore blocking models, and it was observed that the cake filtration model followed by the intermediate pore-blocking model were the best - fitted models as compared to others to describe the permeate flux data. The fabricated kaolin-fly ash-based membranes exhibited good permeability and separation efficiency characteristics, which suggest its suitability for microfiltration of oily waste water from oil exploration and refinery industries.",12,12,5
Degrees C.,Emulsion,"Vahdanikia, Nabi; Divandari, Hassan; Hemmati-Sarapardeh, Abdolhossein; Amar, Menad Nait; Schaffie, Mahin; Ranjbar, Mohammad","Integrating new emerging technologies for enhanced oil recovery: Ultrasonic, microorganism, and emulsion",Enhanced oil recovery; Water in oil emulsion; Surfactants; Biosurfactants; Ultrasonic,BIOSURFACTANT-PRODUCING BACTERIA; WATER-CONTENT; STABILITY; TEMPERATURE; DROPLETS; DEMULSIFICATION; VISCOSITY; CULTURE; SOLIDS; FIELD,"Water in oil emulsions have turned into interesting and attractive resources for enhanced oil recovery (EOR). The stability of emulsions is important for its efficiency as EOR agents. The objective of this study was to investigate the simultaneous influence of ultrasound waves and microorganisms on the stability of water-in-oil emulsions. To this end, using an Iranian crude oil, two types of waters, surfactants and three types of biosurfactants producing microorganisms the impacts of temperature, ultrasonic frequency, and radiation time on the stability, viscosity and surface tension of water-in-oil emulsions were studied. From the results of this study, it can be pointed out that compared to the conventional surface-active agents; biosurfactants have a higher impact on the stability of emulsions. In addition, under the optimum conditions of this study, the surface tension decreased about 15% and the stability increased nearby 20%. Ultrasonic radiation reduces emulsion stability by about 6%. The T.F. species have the greatest effect on the emulsion stability up to 70 degrees C (more than 85%). Micromodel flooding experiments showed that injection of T.F biosurfactants emulsion provides the highest oil recovery due to their high stability, high viscosity, and low surface tension.",9,9,1
Degrees C.,Emulsion,"Tiwari, Roshan; Kumar, Saket; Husein, Maen M.; Rane, Pranali M.; Kumar, Nitesh",Environmentally benign invert emulsion mud with optimized performance for shale drilling,Shale; Instability; Swelling; Fluid loss; Drilling; Shear thinning,WELLBORE STABILITY; OIL,"Drilling muds having less environmental footprint are highly desired, especially for drilling into sensitive formation. In this research, an environmentally benign invert emulsion mud having Indian mango methyl ester (IMME) continuous phase was developed for shale drilling. The properties of the mud were tuned using nanoclay and gum acacia in order to minimize shale instability associated with rock-fluid interactions. The effect of nanoclay and gum acacia content on the rheological behavior and fluid loss of the developed mud was assessed. Furthermore, the thermal and mechanical stability of the mud were estimated. Results obtained with nanoclay and gum acacia were compared with the conventional bentonite and carboxymethyl cellulose additives. Muds containing nanoclay and gum acacia outperformed conventional additive-containing muds in all measures. The rheological properties, such as apparent and plastic viscosities, yield point and gel strength, of the mud formulated with gum acacia and nanoclay were remarkably enhanced. Moreover, the mud containing nanoclay and gum acacia was mechanically and thermally stable up to 100 degrees C. Particle size analysis of this mud confirmed the suitability of the additives toward shale plugging. The invert emulsion with the nanoclay and gum acacia achieved 95% weight recovery comparing with the conventionally used bentonite and CMC, which only achieved 64% weight recovery. Overall, the 40:60 (W/O) invert emulsion with IMME continuous phase and nanoclay and gum acacia additives portrayed ideal viscosity, rheology, fluid loss, particle size distribution and stability suited for shale drilling.",8,8,0
Degrees C.,Emulsion,"Adewunmi, Ahmad A.; Amao, Abduljamiu O.; Kamal, Muhammad Shahzad; Solling, Theis Ivan",Demulsification and breaking mechanism of variable quartz concentrates obtained from sand,Demulsification; Quartz; Seawater; Oil; Size; Recycle,HEAVY CRUDE-OIL; IN-WATER EMULSIONS; MAGNETIC NANOPARTICLES; IONIC LIQUIDS; MICROWAVE; PERFORMANCE; INTERFACE; BEHAVIOR,"This study reports the efficacy of quartz particles extracted from sand for the destabilization of crude oil emulsions and efficient water removal. Demulsification performance of quartz concentrates obtained from stacked sieves with openings: 75, 125, 250 and 300 mu m and quartz quantity varying from 1% to 7% were investigated using the bottle test technique at a temperature of 90 degrees C. The breaking mechanism of emulsion driven by quartz was analyzed by rheology, Fourier Transform Infrared (FTIR) spectroscopy, X-ray diffraction (XRD), optical microscopy and scanning electron microscopy (SEM). Experimental results showed that the quartz concentrates generated from stacked sieves: 75, 125, 250, and 300 mu m had optimal demulsification efficiency (DE) of 98%, 98%, 99%, and 99%, respectively. Moreover, the quartz concentration needed to attain these DEs levels ranges from 3 to 5%. In addition, the performance of quartz as a demulsifier was compared with a commercial demulsifier (ethyl cellulose). Viscosity versus time measurements demonstrated the change in emulsion's viscosity before and after quartz addition. A drastic reduction in the emulsion's viscosity was observed after quartz addition, indicating rupture and coalescence of water droplets. The FTIR and XRD analysis buttressed the functional groups and structural pattern while optical microscope and SEM analysis exhibited the morphology of quartz particles before and after the demulsification processes. A mechanism elucidating the breaking of crude oil emulsion by quartz is proposed. The results indicated that quartz particles processed from the sand will be useful as demulsifiers in the petroleum industry.",7,7,6
Degrees C.,Wettability Alteration,"Shaik, I. K.; Song, J.; Biswal, S. L.; Hirasaki, G. J.; Bikkina, P. K.; Aichele, C. P.",Effect of brine type and ionic strength on the wettability alteration of naphthenic-acid-adsorbed calcite surfaces,Low salinity; Carbonate reservoir; Enhanced oil recovery; Contact angle; Calcite surface; Naphthenic acid,DROP BUBBLE SIZE; OIL-RECOVERY; CONTACT ANGLES; FATTY-ACIDS; SPONTANEOUS IMBIBITION; BENZOIC-ACID; SESSILE-DROP; SULFATE-IONS; SMART WATER; ADSORPTION,"Low-salinity/smart waterflooding is a technique, used in oil reservoirs, where the salinity and/or ionic composition of the injection water is tuned to improve oil recovery. It has been observed by many researchers that low-salinity waterflooding can enhance oil recovery by altering the wettability of carbonate rock surfaces from oil-wet to water-wet. Though wettability alteration is generally agreed to be the main mechanism for the improved oil recovery, the contributing parameters and necessary conditions for wettability alteration are not clearly understood. Hence, it is essential to decouple the effects of salinity, ionic composition, and oil composition on wettability alteration of the solid surface. In this work, we systematically investigated smart-water induced wettability alteration of naphthenic-acid-adsorbed oil-wet calcite surfaces. Well-characterized model systems were used to understand the effects of individual monovalent and divalent ions (Na+, Cl-, Mg2+ and SO42-), and salinity on the calcite surface wettability. Contact angle measurements were performed on smooth Iceland Spar calcite surfaces that were aged at 120 degrees C in 5M NaCl brine, acid number 1.5 model oil, and single-electrolyte-based brine solutions of different salinity and ionic composition. The extent of wettability alteration was assessed based on ACA values, which are more relevant during waterflooding, using a goniometer customized for obtaining multiple advancing and receding contact angles along the surface by the tilting plate method. The results indicate that, for 0.164 M ionic strength (equivalent to 4-times diluted seawater concentration) brine solutions, the wettability of calcite surfaces was changed from oil-wet state to water-wet state irrespective of the salt type. The lowest advancing contact angle (ACA) values (20 degrees-30 degrees range) were obtained for 0.164 M ionic strength NaCl and Na2SO4 solutions, indicating the presence of SO42- ions or reduction in NaCl concentration act in favor of wettability alteration towards water-wet. At this ionic strength, the relative merit of divalent SO42 ions over monovalent Cl ions was not observed. Upon comparison of ACA values for 0.164 M ionic strength Na2SO4 and MgSO4 (SO42 ion is common) solutions, we concluded that the extent of wettability alteration is lower in the presence of Mg2+ ions. A similar conclusion was made by comparing ACA values for 0.164 M ionic strength NaCl and MgCl2 solutions (Cl ion is common). The calcite surfaces aged in 0.656 M (equivalent to seawater concentration) NaCl solution demonstrated intermediate-wet state indicating the extent of wettability alteration towards water-wet state increases with a decrease in salinity.",14,14,1
Degrees C.,Wettability Alteration,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Degrees C.,Wettability Alteration,"Keykhosravi, Amin; Simjoo, Mohammad",Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis,Gamma-alumina nanoparticles; Enhanced oil recovery; Capillary imbibition; Wettability alteration; Scaling analysis,OIL-WET CARBONATE; METAL-OXIDE NANOPARTICLES; WETTABILITY ALTERATION; SILICA NANOPARTICLES; SANDSTONE CORES; INTERFACIAL-TENSION; POROUS-MEDIA; RECOVERY; WATER; NANOFLUIDS,"Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina ((sic)-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 degrees C. The underlying mechanisms of (sic)-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/(sic)-Al nanofluid, size distribution of (sic)-Al NPs and the inverse bond number. Results showed that (sic)-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of (sic)-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which (sic)-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% (sic)-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of (sic)-Al NPs on the carbonate surface. It was found that (sic)-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of (sic)-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.",12,12,4
Degrees C.,Wettability Alteration,"Hassan, Anas M.; Ayoub, M.; Eissa, M.; Bruining, Hans; Zitha, P.",Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding,Surface complexes; DLVO theory; Enhanced oil recovery (EOR); Smart water assisted foam (SWAF) flooding; Low-salinity; Wettability alteration; Foam flooding; Foam stability; Carbonate reservoirs; PHREEQC-Software,ACTIVITY-COEFFICIENT; OSMOTIC COEFFICIENTS; THERMODYNAMICS; ELECTROLYTES; TRANSPORT; MECHANISMS; CARBONATE; ORDER; PART; IRON,"This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25 degrees C) and at the reservoir-conditions (80 degrees C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Huckel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foamlaminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25 degrees C) and at (80 degrees C) than the high-salinity case for both (25 degrees C) and (80 degrees C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of ""Smart Water Assisted Foam (SWAF) Flooding"". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.",7,7,4
Degrees C.,Damage,"Li, Bobo; Ren, Chonghong; Wang, Zhihe; Li, Jianhua; Yang, Kang; Xu, Jiang",Experimental study on damage and the permeability evolution process of methane-containing coal under different temperature conditions,Coal; Damage; Constitutive model; Permeability; Temperature,RELATIVE PERMEABILITY; MECHANICAL-BEHAVIOR; EFFECTIVE STRESS; ANTHRACITE COAL; THERMAL-DAMAGE; GAS; MODEL; IMPACT; RESERVOIR; GRANITE,"Temperature change in coal will lead to the expansion and propagation of micro-cracks, and this progressive temperature-induced failure is defined as thermal damage. Understanding coal permeability as impacted by thermal damage is crucial to the detection of coal and gas hazards in deep coal mining. In this study, tri-axial compression experiments were performed to examine the damage and the permeability evolution process of methane-containing coal under different temperatures (30 degrees C, 50 degrees C and 70 degrees C). The results demonstrate that under a low external stress, the overall coal permeability decreases with the rise of temperature. More specifically, in the linear elastic stage, the coal elasticity modulus drops as the temperature becomes higher while the permeability remains nearly constant. In the yielding and post-failure stages, the tri-axial compressive strength of coal weakens with the rise of temperature, whereas the permeability increases slowly first and then jumps sharply. A coal damage constitutive model considering the temperature effect and a coal permeability model incorporating the thermal damage in the complete stress-strain process was developed. It is found that results from the coal damage model and the proposed coal permeability model agree well with the experimental results. The proposed coal permeability model can be used to characterize coal permeability variation from the plastic state to the post-failure state in areas adjacent to the underground coal excavation face under different temperature conditions.",20,23,10
Degrees C.,Damage,"Mahanta, Bankim; Ranjith, P. G.; Vishal, Vikram; Singh, T. N.",Temperature-induced deformational responses and microstructural alteration of sandstone,Sandstone; Thermal damage; Acoustic emission; Microstructure; Micro-CT,MECHANICAL-PROPERTIES; FRACTURE-TOUGHNESS; THERMAL-PROPERTIES; ACOUSTIC-EMISSION; CRACK INITIATION; TENSILE-STRENGTH; GRANITIC-ROCKS; PERMEABILITY; BEHAVIOR; THRESHOLDS,"The high-temperature response of rock is quite useful for successful exploration and exploitation of various conventional as well as unconventional energy systems such as underground coal gasification, and geothermal energy, where the associated rocks are exposed to various temperature and pressure conditions. In this study, we have investigated the effect of temperature and thermal alteration of an Indian sandstone. An investigation using acoustic emission, digital image correlation through ARAMIS, micro-computed tomography (CT) techniques and thermogravimetric analysis was performed to study the mechanical responses of the sandstone with increasing temperatures. The results indicate that uniaxial compressive strength (UCS), tensile strength and elastic modulus of sandstone reduced significantly and aligned in an overall decreasing trend with increasing temperatures. The maximum and minimum UCS of sandstone were obtained at 400 degrees C and 700 degrees C, respectively. Acoustic emission (AE) responses of the sandstone indicated an early crack initiation and crack damage for high-temperature treated specimens. The deformation was further analysed using the ARAMIS digital image correlation technique, and strain levels were visually quantified that exhibited a widespread distribution of higher strain for thermally-treated specimens at 700 degrees C. Microstructural thermal damage and different pore-characteristics were studied using micro-CT techniques that provided valuable information about the connected and non-connected pores of the sandstone and their evolution with increasing temperatures. The outcomes suggest a heat-induced increment in porosity by nearly 40 percent upon heating the samples from 25 degrees C to 600 degrees C, which can be attributed due to the opening of new cracks that stimulated structural damage.",18,19,10
Degrees C.,Damage,"Wang, Jie; Huang, Yixiao; Zhou, Fujian; Song, Ziyu; Liang, Xingyuan",Study on reservoir damage during acidizing for high-temperature and ultra-deep tight sandstone,High-temperature and ultra-deep; Tight sandstone; Acidizing; Formation damage; Fines migration,ACID; GAS,"Acidizing treatment for conventional sandstone reservoir is a common method to relieve skin damage near the wells. However, this method is not suitable in ultra-deep and high-temperature tight sandstone reservoir, which usually causes greater damage. Therefore, experimental studies on the damage mechanism of low-permeability sandstone reservoir were performed to obtain the main factors causing damage in this paper. First, the reaction mechanism of clay minerals with hydrochloric acid was investigated by corrosion experiment. Then, based on the core-flooding experimental setup, the damage mechanisms of pre-flush acidizing and mud acidizing were also studied under the condition of high-temperature. Finally, chelate acid instead of hydrochloric acid is selected as preflush to prevent and control the migration damage of acidified particles. The results show that: (1) The order of reaction speed of hydrochloric acid solution with four clay minerals is chlorite > montmorillonite > illite > kaolinite; after the reaction of four clay minerals with hydrochloric acid solution at 150 degrees C, the complete mineral structure was damaged to varying degrees, and it was easy to produce fragmentary or broken granular solids. (2) During mud acidizing for tight sandstone, some acidizing secondary products with low solubility will be produced. The secondary products such as sodium fluorosilicate, sodium fluoroaluminate, potassium fluorosilicate, calcium fluorosilicate and calcium fluoride were deduced by SEM and EDS analysis. During displacement, these particles moved and blocked the pore throat, resulting in permeability decline and reservoir damage. (3) With a low rate of dissolution of clay minerals, chelate acid can be used as pad-acid to reduce the crystal structure damage of clay minerals. This research provides a reference for the study of acidizing damage in Tarim oilfield and other ultra-deep and high temperature tight sandstone reservoirs.",10,10,4
Degrees C.,Damage,"Li, Ning; Zhang, Shicheng; Ma, Xinfang; Zou, Yushi; Li, Sihai; Zhang, Zhaopeng",Thermal effect on the evolution of hydraulic fracture conductivity: An experimental study of enhanced geothermal system,Geothermal energy; Hot dry rock; Micro-indentation; Thermal softening; Fracture conductivity,HOT DRY ROCK; ACOUSTIC-EMISSION RESPONSE; MECHANICAL-BEHAVIOR; HIGH-TEMPERATURE; HEAT EXTRACTION; ELASTIC-MODULUS; GRANITE; PROPPANT; INDENTATION; GROWTH,"This paper aimed to investigate the thermal effect on the evolution of hydraulic fracture conductivity during heat extraction. Meanwhile, the degradation mechanisms of fracture conductivity were analyzed in terms of the mechanical damage of fracture surfaces. Experimental results of micro-indentation tests on the studies granite show the existence of a threshold value of temperature. The Young's modulus and hardness of fracture surface significantly decreased when the thermal treatment levels were higher than 300 degrees C. Similarly, the degradation of fracture conductivity was limited (<10%) before 300 degrees C and then significantly deteriorated at 400 degrees C and 500 degrees C. Moreover, cyclic thermal treatment tended to aggregate the mechanical damages of fracture surfaces further. At the thermal treatment level of 300 degrees C, obvious thermal softening of fracture surfaces and degradation of fracture conductivity were observed only when the number of cycles was larger than 10, while both of these two phenomena became more severe with the increasing of the number of cycles at the thermal treatment level of 400 degrees C. The evolution of fracture conductivity can be accounted for by the temperature-related integrity of fracture surfaces and proppant pack. It was indicated that the thermal softening of fracture surface tended to enhance the proppant embedding, which might be beneficial for the alleviation of proppant crushing.",9,9,7
Degrees C.,Carbon Dioxide,"Hu, Xiao; Xie, Jun; Cai, Wuchao; Wang, Rui; Davarpanah, Afshin",Thermodynamic effects of cycling carbon dioxide injectivity in shale reservoirs,Carbon dioxide storage capacity; Oil recovery factor; Soaking time; Core stimulation; Shale reservoirs,ENHANCED OIL-RECOVERY; BAKKEN TIGHT OIL; N-PUFF PROCESS; GAS; STORAGE; MODEL; PERMEABILITY,"Carbon dioxide injectivity has always been considered as one of the optimum enhanced recovery techniques, especially in tight reservoirs regarding the feasible mobilization of gas through porous media. To have a better understanding of carbon dioxide injectivity performances, it would be of importance to consider crucial parameters and their effects on the carbon dioxide adsorption and oil recovery factor. In this paper, the profound impact of crucial parameters such as temperature, pressure, carbon dioxide soaking time, and core stimulation on the oil recovery enhancement were investigated. Moreover, the considerable influence of pressure and temperature on the carbon dioxide adsorption capacity storage were performed and analyzed. According to the result of this experiment, temperature increase led to reducing carbon dioxide storage capacity, which has a reverse pattern with oil recovery factor by increasing temperature. When the core samples were unstimulated, the oil recovery factor has higher than stimulated core samples. Furthermore, pressure increase resulted in the carbon dioxide storage capacity enhancement, which has a similar increase pattern with oil recovery factor by increasing pressure. The maximum carbon dioxide storage capacity is 91% and 90% at the pressure of 1500 psi and temperature of 20 degrees C respectively. Soaking time rising between oil and carbon dioxide led to producing more oil volume.",98,98,22
Degrees C.,Carbon Dioxide,"Yekeen, Nurudeen; Malik, Azlinda Abdul; Idris, Ahmad Kamal; Reepei, Nadia Izwani; Ganie, Kenny","Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions",Saponin; Foaming properties; Wettability alteration; Interfacial tension (IFT); High temperature; High pressure,SURFACTANT CONCENTRATION; NONIONIC SURFACTANTS; NATURAL SURFACTANT; TEMPERATURE; OIL; NANOPARTICLES; ADSORPTION; STABILITY; SALINITY; RECOVERY,"In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 degrees C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRUSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 degrees C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 degrees C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 degrees C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.",12,13,7
Degrees C.,Carbon Dioxide,"Hassan, Anas M.; Ayoub, M.; Eissa, M.; Bruining, Hans; Zitha, P.",Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding,Surface complexes; DLVO theory; Enhanced oil recovery (EOR); Smart water assisted foam (SWAF) flooding; Low-salinity; Wettability alteration; Foam flooding; Foam stability; Carbonate reservoirs; PHREEQC-Software,ACTIVITY-COEFFICIENT; OSMOTIC COEFFICIENTS; THERMODYNAMICS; ELECTROLYTES; TRANSPORT; MECHANISMS; CARBONATE; ORDER; PART; IRON,"This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO2) and an aqueous phase that contains both carbon dioxide (CO2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25 degrees C) and at the reservoir-conditions (80 degrees C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Huckel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO2) on the stability of low-salinity foamlaminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25 degrees C) and at (80 degrees C) than the high-salinity case for both (25 degrees C) and (80 degrees C). Moreover, high carbon dioxide (CO2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of ""Smart Water Assisted Foam (SWAF) Flooding"". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.",7,7,4
Degrees C.,Tight Sandstone,"Wang, Enze; Liu, Guoyong; Pang, Xiongqi; Wu, Zhuoya; Li, Changrong; Bai, Hua; Zhang, Zehan","Sedimentology, diagenetic evolution, and sweet spot prediction of tight sandstone reservoirs: A case study of the third member of the Upper Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, China",Tight sandstone; Diagenesis; Controlling factors; Nanpu Sag,PETROLEUM SYSTEM; GAS SANDSTONES; SICHUAN BASIN; QUALITY; OIL; FIELD; EXPLORATION; RESOURCES; GRABEN; MIDDLE,"Substantial progress has been made in the exploration of the tight petroleum resources in Bohai Bay Basin, as a series of tight oil reservoirs were discovered. Among these reservoirs, a new breakthrough was achieved in the Nanpu Sag, proving a previously unconfirmed prospect of tight oil. Mineralogical, petrographic and fluid inclusions analyses were performed to investigate physical properties (composition, pore system, porosity, and permeability), controlling factors, and features of tight sandstones of the Upper Paleogene Es3 (the third member of the Shahejie Formation) in the Gaoshangpu Structural Belt of the Nanpu Sag. Our study indicates that the Es3 tight sandstones are mainly feldspathic litharenites and had low values for porosity (average value 10.1%) and permeability (average value 0.8 mD). The pore system is dominated by secondary dissolution pores (average thin porosity 3.1%). The deterioration of porosity is greater due to compaction (average compaction rate 68.8%) rather than cementation (average cementation rate 16.3%). Two peaks in the homogenization temperature were observed; the first ranges from 116 degrees C to 136 degrees C and exhibits yellow fluorescence, while the other peak varies from 156 degrees C to 165 degrees C, showing blue fluorescence, which indicates two stages of hydrocarbon charging at 26 Ma and 3 Ma, respectively. Tight sandstone is identified during the Mesodiagenesis phase. Eodiagenesis included compaction, precipitation of calcite cements and quartz overgrowth. Mesodiagenesis mainly exhibited compaction and grain dissolution (mainly feldspar). The main controlling factors can be summarized as follows, with the second factor being the most important: (a) a high energy deposition environment (distributary channels); (b) intense dissolution; and (c) early hydrocarbon charging and overpressure. This study provides a new prospect of the tight sandstone petroleum system in northeastern China.",21,21,8
Degrees C.,Tight Sandstone,"Wang, Jie; Huang, Yixiao; Zhou, Fujian; Song, Ziyu; Liang, Xingyuan",Study on reservoir damage during acidizing for high-temperature and ultra-deep tight sandstone,High-temperature and ultra-deep; Tight sandstone; Acidizing; Formation damage; Fines migration,ACID; GAS,"Acidizing treatment for conventional sandstone reservoir is a common method to relieve skin damage near the wells. However, this method is not suitable in ultra-deep and high-temperature tight sandstone reservoir, which usually causes greater damage. Therefore, experimental studies on the damage mechanism of low-permeability sandstone reservoir were performed to obtain the main factors causing damage in this paper. First, the reaction mechanism of clay minerals with hydrochloric acid was investigated by corrosion experiment. Then, based on the core-flooding experimental setup, the damage mechanisms of pre-flush acidizing and mud acidizing were also studied under the condition of high-temperature. Finally, chelate acid instead of hydrochloric acid is selected as preflush to prevent and control the migration damage of acidified particles. The results show that: (1) The order of reaction speed of hydrochloric acid solution with four clay minerals is chlorite > montmorillonite > illite > kaolinite; after the reaction of four clay minerals with hydrochloric acid solution at 150 degrees C, the complete mineral structure was damaged to varying degrees, and it was easy to produce fragmentary or broken granular solids. (2) During mud acidizing for tight sandstone, some acidizing secondary products with low solubility will be produced. The secondary products such as sodium fluorosilicate, sodium fluoroaluminate, potassium fluorosilicate, calcium fluorosilicate and calcium fluoride were deduced by SEM and EDS analysis. During displacement, these particles moved and blocked the pore throat, resulting in permeability decline and reservoir damage. (3) With a low rate of dissolution of clay minerals, chelate acid can be used as pad-acid to reduce the crystal structure damage of clay minerals. This research provides a reference for the study of acidizing damage in Tarim oilfield and other ultra-deep and high temperature tight sandstone reservoirs.",10,10,4
Degrees C.,Tight Sandstone,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
Degrees C.,Hot Water Injection,"Askarova, Aysylu; Turakhanov, Aman; Markovic, Strahinja; Popov, Evgeny; Maksakov, Kirill; Usachev, Gennady; Karpov, Valery; Cheremisin, Alexey",Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance,Hot water injection; Carbonate reservoirs; Consolidated core; Cementation; Numerical simulation; Kinetic model,IN-SITU COMBUSTION; AQUATHERMOLYSIS; MODEL,"Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100-1500 m require technology that can achieve sufficiently high fluid temperature (250-300 degrees C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling. The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called ""aquathermolysis"" to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons. A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H-2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.",10,10,3
Degrees C.,Hot Water Injection,"Liu, Peng; Shi, Lanxiang; Liu, Pengcheng; Li, Lei; Hua, Daode",Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs,Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery; Heterogeneity,ASSISTED GRAVITY DRAINAGE; RECOVERY; SOLVENT; PERFORMANCE; PRESSURE; GAS,"Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.",8,8,4
Degrees C.,Mobility Control,"Das, A.; Nguyen, N.; Farajzadeh, R.; Southwick, J. G.; Vincent-Bonnieu, S.; Khaburi, S.; Al Kindi, A.; Nguyen, Quoc P.","Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs",Enhanced oil recovery; Foam; Microemulsion; Carbonate; High salinity; Low permeability,ADSORPTION; OIL,"Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging. In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 degrees C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.",10,10,7
Degrees C.,Mobility Control,"Zhang, Panfeng; Diao, Yuqian; Shan, Yu; Pei, Shufeng; Ren, Shaoran; Zhang, Liang; Yang, Hongbin",Experimental investigation of amine-surfactant CO2 foam for smart mobility control during CO2 flooding,Amine surfactant; CO2-responsive; Surface tension; Foam quality; CO2 foam; Mobility control,ENHANCED OIL-RECOVERY; HIGH-TEMPERATURE; WORMLIKE MICELLES; AQUEOUS FOAMS; CRUDE-OIL; STABILITY; PRESSURE; STORAGE; INJECTION; RESERVOIR,"Amine-surfactant can be converted to be cationic surfactant in water solution saturated with CO2, which can enhance their foaming ability and foam stability, and the foaming ability can be switched off or on by CO2 or replacing with N-2 with heating, so the amine-surfactants have great potential for smart mobility control to gas channeling during CO2 flooding. In this study, three alkyl propyl dimethylamines with different carbon chain length (R = 11, 17 and 22, named as UC(11)AMPM, UC(17)AMPM, and UC(22)AMPM, respectively), were investigated as CO2 responsive foam agent, and their foam performance under static and dynamic condition was tested up to 130 degrees C and 10.5 MPa using a visualized foam meter and a sand-pack flooding setup. The influence of carbon chain length on bulk solution viscosity, surface activity, foaming ability, and foam quality on bulk foam stability were measured and analyzed. The experimental results indicate that the three amine surfactants all demonstrate well CO2 responsibility and CO2 foaming ability, and show well switchable by CO2 and N-2 at high temperature and high pressure (HTHP) condition. With the carbon chain length increasing, the surfactant shows higher absorption on the foam films, and bulk solution has a higher viscosity, which can decrease de-foam velocity and enhance the foam stability, as a result, the surfactant shows higher mobility control ability.",9,9,7
Heavy Oil,Water Flooding,"Wang, Yanwei; Liu, Huiqing; Zhang, Qichen; Chen, Zhangxin; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Pore-scale experimental study on EOR mechanisms of combining thermal and chemical flooding in heavy oil reservoirs,Viscosity reducer; Steam flooding; Foam; Visualized experiments; Mechanisms analysis,CYCLIC STEAM STIMULATION; CRUDE-OIL; VISCOSITY REDUCTION; FOAM-GENERATION; RECOVERY; EMULSIONS; INJECTION; FLOW; ASPHALTENE; RHEOLOGY,"Steam flooding is an important method for the development of heavy oil reservoirs, but steam channeling is an inevitable serious problem in the process of steam injection, which decreases the sweep efficiency of steam and leads to low oil recovery. Viscosity reducer (VR) flooding and nitrogen foam flooding are two effective methods of enhancing heavy oil recovery with satisfactory results. In this paper, a series of experiments were conducted to evaluate the effects of various factors on the performance of the novel viscosity reducer (VR-A). On this basis, A visualized model was adopted to investigate the synergistic development effect of thermal and chemical flooding, which vividly reflected the interaction of chemical agents with crude oil and their migration characteristics in porous media, as well as the mechanisms of enhancing oil recovery on the pore-scale. The results showed that VR-A could achieve excellent viscosity reduction effect on heavy oil under the influence of various factors, which could be combined with thermal flooding to effectively recover heavy oil. As for the pore-scale level, after the VR-A solution was injected, the interfacial tension between the oil and water was decreased, the wettability of the surface of the particle was changed, and two types of oil-in-water emulsions (spherical emulsions and flocculent emulsions) with a lower viscosity were formed, which were easy to flow with the fluid in pores and throats and could temporarily block the high-permeability area. In the process of foam flooding, the phenomena of bubble coalescence and breakup occurred constantly, and bubbles trapped in the porous media could improve the sweep efficiency of the subsequent fluid. The ultimate oil recovery of the development method combining thermal and chemical flooding in the visualized displacement experiment is 76.9%, 39.7% higher than that of pure thermal flooding. This article can provide an effective method to solve the problem of poor steam flooding performance in heavy oil reservoirs.",19,20,8
Heavy Oil,Water Flooding,"Betancur, Stefania; Olmos, Carol M.; Perez, Maximiliano; Lerner, Betiana; Franco, Camilo A.; Riazi, Masoud; Gallego, Jaime; Carrasco-Marin, Francisco; Cortes, Farid B.",A microfluidic study to investigate the effect of magnetic iron core-carbon shell nanoparticles on displacement mechanisms of crude oil for chemical enhanced oil recovery,Microfluidic; Enhanced oil recovery; Nanoparticles; Surfactant,HEAVY OIL; POROUS-MEDIA; STABLE EMULSIONS; WETTABILITY; SURFACTANTS; BEHAVIOR; FLOW; POLYMER; ADSORPTION; EFFICIENCY,"The main objective of this work is to evaluate the effect of the simultaneous use of a surfactant mixture and magnetic iron core-carbon shell nanoparticles on oil recovery via a microfluidic study based on the rock-on-achip technology. The surfactant solution used for all experiments was prepared based on a field formulation and consisted of a mixture of a hydrophilic and a lipophilic surfactant. Magnetic iron core-carbon shell nanoparticles with a mean particle size of 60 nm and a surface area of 123 m(2)g(-1) were employed. The displacement experiments consisted of waterflooding, surfactant flooding and nanoparticle-surfactant flooding and were performed using PDMS (polydimethylsiloxane)-glass microdevices type random network. The characteristics and design of the microfluidic device allowed to emulate a mixed wettability of a porous medium. Then, the oil was displaced by injecting the solution at a constant injection rate, until steady-state conditions were obtained. Furthermore, the effect of three injection rates corresponding to 0.1 ft day(-1), 1 ft day(-1), and 10 ft day(-1) was investigated. The increase in the injection rate favored the oil recovery percentage. In addition, for all injection rates, the oil recovery decreased in the following order: nanoparticle-surfactant flooding > surfactant flooding > waterflooding. The nanoparticle-surfactant system at the injection rate of 1.9 mu L min(-1) presented the highest oil recovery (i.e., 84%). Likewise, nanoparticle-surfactant flooding showed a more stable displacement front and consequently, the highest capillary number among the injection fluids. Oil recovery by waterflooding was the lowest among the evaluated systems due to the viscous fingering phenomena under different injection rates. In addition, it can be observed that for all injection rates, the presence of the surfactant mixture and nanoparticles reduce the viscous fingering effect. The results can be used to visually and quantitatively analyze the role of the simultaneous use of nanoparticles with surfactants in enhanced oil recovery processes.",18,18,5
Heavy Oil,Water Flooding,"Lang, Liyuan; Li, Huabin; Wang, Xiong; Liu, Ning",Experimental study and field demonstration of air-foam flooding for heavy oil EOR,Heavy oil; Foam; EOR,NITROGEN FOAM; RECOVERY; INJECTION; TEMPERATURE; BEHAVIOR,"Foam flooding is an effective oil displacement technique to improve fluid sweep efficiency and increase oil recovery. The objective of this study is to investigate the application of air-foam for heavy oil recovery under heterogeneous reservoir conditions. The paper first investigated the air-foam flow behavior in porous media and identified the effects of different factors such as gas-liquid ratio, injection rate, and crude oil saturation on air-foam resistance. Then, dual-tube sand-packs were used to evaluate the performance of air-foam for heavy oil recovery from heterogeneous reservoir conditions. The results indicated that the air-foam could divert the fluid from the high-permeability zone to the low-permeability zone, decrease the water cut and improve the oil recovery. Further studies revealed that there existed an optimal reservoir permeability contrast ratio in air-foam flooding for heavy oil recovery. The air foam performance for oil recovery would be reduced beyond or below this permeability contrast ratio. Finally, field tests on air-foam for heavy oil recover demonstrated that air foam flooding could increase heavy oil production rate and decrease the production water cut.",16,17,7
Heavy Oil,Water Flooding,"Chen, Meng; Dai, Jiacai; Liu, Xiangjun; Kuang, Yan; Wang, Zhongtao; Gou, Shunchao; Qin, Minjun; Li, Min",Effect of displacement rates on fluid distributions and dynamics during water flooding in tight oil sandstone cores from nuclear magnetic resonance (NMR),Tight oil sandstone cores; Water flooding; Displacement rate; Nuclear magnetic resonance; Oil distribution,CRITICAL CAPILLARY NUMBER; HUFF-N-PUFF; PERFORMANCE EVALUATION; SPONTANEOUS IMBIBITION; CO2 INJECTION; RECOVERY; RESERVOIR; BAKKEN; STATE; FLOW,"Water flooding is widely used as an economical and recyclable method to improve oil recovery in unconventional reservoirs. In this study, the effects of injection rates on oil distribution, the seepage dynamics and the contributions of increasing injection rates on enhancing oil recovery during water flooding are investigated. Typical tight oil sandstone cores with different permeabilities are obtained from Junggar Basin, Northwest China, for experimental studies that incorporate nuclear magnetic resonance analyses. Synthetic kerosene (viscosity = 11.2 mPa s) and heavy water (D2O) are used to simulate crude oil and formation water under formation conditions. The samples are first saturated with simulation water and thereafter displaced by synthetic oil until no water is produced to simulate the fully oil-saturated condition. To simulate the water flooding process, the samples are stably displaced by simulation water at injection rates increasing from 0.01 mL/min until no oil is produced. The T-2 spectra, injection pressures, and produced oil at different injection rates and water injection volumes are measured simultaneously. The transverse relaxation time (T-2) is converted for the corresponding pore-throat radius (r) by combining pore-throat size distributions (obtained from constant-rate mercury injection) and the fully oil saturated T-2 spectra. It indicates that the amplitude of T-2 spectra for macropore (>100 mu m) and mesopore (10-100 mu m) spaces decreases more rapidly than those for the micropore spaces (0-10 mu m) as injection rate increases. The classical capillary number theory is introduced to represent the effect of injection rate and characterize the dynamics of seepage processes. Results show that the oil recovery factor can be considerably improved by increasing the injection rate in tight oil cores, and this significant improvement is primarily attributed to mesopores and micropores.",15,15,7
Heavy Oil,Water Flooding,"Arab, Danial; Kantzas, Apostolos; Bryant, Steven L.",Water flooding of oil reservoirs: Effect of oil viscosity and injection velocity on the interplay between capillary and viscous forces,Unconventional heavy oil; Conventional light oil; Water flooding; Instability analysis; Viscous fingering,HEAVY-OIL; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSION; EXPERIMENTAL-VERIFICATION; INSTABILITY THEORY; WETTABILITY; RECOVERY; DISPLACEMENT; SATURATION; PERMEABILITY,"Water flooding is the most widely applied recovery process in both conventional and heavy oil reservoirs. It is generally accepted that theories explaining water flooding performance in light oil reservoirs are not applicable to heavy oil reservoirs. Nonetheless, there is a lack of a systematic study discussing the underlying mechanisms of water flooding in heavy oil systems. This article presents findings of water flooding experiments and discusses the interplay between viscous and capillary forces as a function of oil viscosity and injection velocity. Experimental data of 178 core floods were used to develop a new dimensionless capillary number, N-Ca = (mu V-w(w)/sigma Cos theta phi)(0.26) (mu(w)/mu(o))(0.50) (K/LD)(0.18), which is useful in predicting water flood performance for a wide range of oil to water viscosity ratio up to 15,000. This scaling parameter along with the Peters and Flock's (Peters and Flock, 1981) instability number were used to map the interplay between capillary and viscous forces. It was found that there is a critical oil to water viscosity ratio (<= 20) below which the flow is stable (having instability numbers below a critical value) and viscous-dominant. In these cases, breakthrough oil recovery monotonically increases with increasing injection velocity. For viscous oils with viscosity of greater than 160 mPa s, flow is identified as pseudo-stable flow with instability numbers above a critical instability number. In these cases, breakthrough oil recovery is almost independent of injection velocity. In intermediate oil to water viscosity ratio of 20-160, breakthrough oil recovery increases with decreasing injection velocity, suggesting the flow regime is capillary-dominant. In these cases, imbibition activated at slower velocities has been identified as the main mechanism responsible for incremental oil recovery. In viscous oil systems (160 < mu(o) < 15,000), late time oil recovery monotonically increases with decreasing injection velocity. This increase in oil recovery is more pronounced in more viscous oil systems suggesting the importance of capillary forces in these systems. Results of this study suggest some new insights on the mechanisms of water flooding as a cost effective non-thermal EOR technique and how this can be very different in light oil systems compared to heavy oil reservoirs.",11,11,5
Heavy Oil,Water Flooding,"Zhao, Yan",Laboratory experiment and field application of high pressure and high quality steam flooding,Heavy oil; Steam flooding; Pressure; Steam quality; Recovery factor,,"Steam flooding is an effective way to improve oil recovery after steam huff and puff for heavy oil reservoirs. The typical screening criteria for steam flooding requires reservoir pressure to be less than 5 MPa, the steam quality of conventional steam flooding in bottom hole is about 30%, heavy oil reservoir in Shengli Oilfield with character of deep burial depth, active edge and bottom water and high formation pressure (7-8 MPa), the increase of oil recovery using conventional steam flooding is not obvious, Therefore, the formation and development of steam chamber during steam flooding are studied by indoor physical simulation experiments, the feasibility of high-quality steam flooding under high pressure is analyzed. The experimental results show that the quality of steam injection has obvious influence on the expansion of steam chamber. As the steam quality increases under high pressure, the specific volume of underground steam increases, the formation time of steam chamber is shortened, the expansion distance of steam chamber increases, the effective steam flooding time is prolonged, and recovery rate improves obviously. Field tests of high-quality steam flooding under high pressure were carried out in Gudao Zhongerbei heavy oil reservoir of Shengli Oilfield, the result shows that the bottom-hole steam quality of steam injection wells is 50% and above (20% higher than conventional steam flooding), the steam chamber was effectively expanded and the performance of producing rate for production wells improves obviously. The recovery rate of the test area reached 52.1%, which was 16.8% higher than that of steam huff and puff. High-quality steam flooding technology was an effective way to improve the recovery rate of high-pressure heavy oil reservoirs.",9,9,5
Heavy Oil,Water Flooding,"Liu, Peng; Shi, Lanxiang; Liu, Pengcheng; Li, Lei; Hua, Daode",Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs,Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery; Heterogeneity,ASSISTED GRAVITY DRAINAGE; RECOVERY; SOLVENT; PERFORMANCE; PRESSURE; GAS,"Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.",8,8,4
Heavy Oil,Water Flooding,"Wei, Bing; Liu, Jiang; Zhang, Xiang; Xiang, Hua; Zou, Peng; Cao, Jie; Bai, Mingxing",Nuclear Magnetic Resonance (NMR) mapping of remaining oil distribution during sequential rate waterflooding processes for improving oil recovery,Waterflooding; Sequential rate mode; Remaining oil saturation; NMR; Enhanced oil recovery,CHEMICAL-TRACER TESTS; SILICA NANOPARTICLES; POROSITY TYPES; POROUS-MEDIA; FLOW; DISPLACEMENT; CHALLENGES; CAPILLARY; RESERVOIR; FORCES,"At the conclusion of waterflooding phase, significant volume of oil still remains in reservoir formations. In this paper, waterflooding was performed at a designed sequential rate mode with an aim to further reduce the remaining oil saturation (S-or). Waterflooding process was monitored continuously by a low-field Nuclear Magnetic Resonance (NMR) spectrometer attempting to map pore-scale displacing behaviors and also quantify the reduction in S-or in-situ. The results showed that the main pore size of the cores ranged from 1.6 mu m to 63.0 mu m inferred by T-2 (transverse relaxation time) distributions. The value of S-or in the cores increased towards the outlet face during waterflooding because of capillary end effect, which became more significant for heavy oil. At the termination of this waterflooding process, S-or was found to be further reduced by approximately 5.0% in the presence of thief water pathways as a result of the improved viscous forces. Water fingering and capillary imbibition effects were clearly visualized in the NMR images. These observations are expected to be useful for heavy oil waterflooding operations especially in post-breakthrough phase.",8,8,4
Heavy Oil,Degrees C,"Al-Muntaser, Ameen A.; Varfolomeev, Mikhail A.; Suwaid, Muneer A.; Yuan, Chengdong; Chemodanov, Artem E.; Feoktistov, Dmitriy A.; Rakhmatullin, Ilfat Z.; Abbas, Mustafa; Dominguez-Alvarez, Enrique; Akhmadiyarov, Aydar A.; Klochkov, Vladimir V.; Amerkhanov, Marat I.","Hydrothermal upgrading of heavy oil in the presence of water at sub-critical, near-critical and supercritical conditions",Heavy oil; Hydrothermal upgrading; Sub-critical water; Near-critical water; Supercritical water; In-situ upgrading,CRUDE-OIL; AQUATHERMOLYSIS; NANOPARTICLES; SPECTROSCOPY; TEMPERATURE; HYDROLYSIS; CATALYST; CRACKING; BITUMEN; FTIR,"In this study, the hydrothermal upgrading (HTU) of high sulfur-content heavy oil was investigated at sub-critical (Sub-CW), near-critical (NCW) and supercritical water (SCW) conditions. Products obtained after HTU, including gases, liquid, and coke (if formed), were analyzed to understand the upgrading performance at different conditions. At Sub-CW (200, 250, and 300 degrees C), 250 degrees C is the optimum temperature where a viscosity reduction from 2073 to 1758 mPa s was achieved with a slight removal of sulfur (mainly sulfur) and the generation of a small amount of light and non-condensable hydrocarbons in gas phase (C1-C4, isoalkanes and alkenes, H2S, CO2 and H-2, etc.). At NCW (350 degrees C) and SCW (400 degrees C), heavy oil was upgraded into light oil with a significant removal of heteroatoms, an increase of saturates content, a reduction of aromatics, resins and asphaltenes contents, and a high yield of light gaseous hydrocarbons (mainly methane). Simultaneously, each SARA fraction was also greatly ameliorated: the content of light alkanes with low molecular weight in saturates was increased, diaromatics content in aromatics was increased with a reduction of polyaromatics content, aromatics-type carbon atoms in resins was increased with a decrease in aliphatic hydrocarbons. Moreover, MALDI-TOF measurements of asphaltenes show that the molecular weights of asphaltenes were reduced. All these results indicated that HTU at Sub-CW can be used for heavy oil pre-treatment (in-situ or ex-situ upgrading) considering its main effect of viscosity reduction with a small removal of heteroatoms, while HTU at NCW and SWC has a great potential in insitu and ex-situ upgrading and oil refining as it can convert heavy oil into light oil.",26,26,7
Heavy Oil,Degrees C,"Ma, Weijiao; Hou, Lianhua; Luo, Xia; Liu, Jinzhong; Tao, Shizhen; Guan, Ping; Cai, Yuwen",Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature -based semi -open pyrolysis: Implications for in -situ conversion process,Chang 7 oil shale; In-situ conversion process; Temperature-based semi-open pyrolysis; Hydrocarbon generation process; Hydrocarbon expulsion process,TRIASSIC YANCHANG FORMATION; ORGANIC-MATTER; HYDROUS PYROLYSIS; GAS GENERATION; CHINA IMPLICATIONS; SOURCE-ROCK; II KEROGEN; PETROLEUM; EVOLUTION; SYSTEM,"There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300-320 degrees C, 0.53-0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320-380 degrees C, 0.55-1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380-420 degrees C, 1.09-1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 degrees C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24-1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.",16,19,10
Heavy Oil,Degrees C,"Pu, Wanfen; Zhao, Shuai; Hu, Lingzhi; Varfolomeev, Mikhail A.; Yuan, Chengdong; Wang, Liangliang; Rodionov, Nikolay O.",Thermal effect caused by low temperature oxidation of heavy crude oil and its in-situ combustion behavior,Combustion tube; Thermal effect; Low temperature oxidation; Heavy crude oil; In-situ combustion; Porous media,AIR INJECTION; KINETICS; LIGHT; PYROLYSIS; FEASIBILITY; CALORIMETRY; COMPONENTS; RATES,"To investigate the thermal effect caused by low temperature oxidation (LTO) of one heavy crude oil in porous media, a combustion tube (CT) system coupled with a self-designed experimental scheme was adopted. Also, the in-situ combustion (ISC) performance of this heavy oil as well as alterations in oil properties before and after ISC was comprehensively evaluated. The results showed that there existed the apparent thermal effect induced by LTO within the researched ignition temperature (180-320 degrees C), and heat release became greater with the ignition temperature. It should be noted that the oxidation reaction rate of the heavy oil was rose remarkably releasing substantial heat when the ignition temperature was increased to 240 from 180 degrees C. The heavy oil was combusted under the ignition temperature of 350 degrees C, and the combustion front advanced sustainably. Some basic parameters during ISC, including apparent atomic H/C ratio, oxygen utilization, fuel consumption, etc., were determined, which made it accessible to predict field test performances. And the values of these parameters and post-mortem images of the CT test reflected the superior ISC performance of the heavy oil. The alterations in oil properties pre-ISC and post-ISC indicated that the produced oil encountered strong LTO reactions and thermal cracking reactions forming a considerable number of lighter oxygen-containing compounds. Comparison of differential scanning calorimetry (DSC) profiles of the crude oil and produced oil revealed that the ISC process made the heavy oil greatly upgrade.",14,14,3
Heavy Oil,Degrees C,"Alade, Olalekan S.; Hamdy, Mohamed; Mahmoud, Mohamed; Al Shehri, Dhafer A.; Mokheimer, Esmail; Patil, Shirish; Al-Nakhli, Ayman",A preliminary assessment of thermochemical fluid for heavy oil recovery,Enhanced oil recovery; Heavy oil; Thermal methods; Insitu heat generation; Thermochemical fluids,INJECTION; EXTRACTION; BITUMEN,"Commercial production of heavy oil has heavily relied upon steam injection method due to its effectiveness to reduce the viscosity and improved mobility. However, due to uncertainty of oil price, high energy cost, water requirement, heat loss, and environmental issues, attention is being given to new thermal EOR technologies such as insitu steam generation using thermochemical fluid (TCF) injection. This technology essentially involves downhole generation of heat and pressure from exothermic chemical reaction. In this investigation, thermochemical reactants were injected, at different temperatures (100, 50, and 30 degrees C) and constant rate of 0.5 ml/mln, into Berea sandstone core samples saturated with heavy oil (18 %wt./wt. asphaltene content and 11 degrees API) and brine. It was observed that the pressure generated at the inlet of the core due to 100, 50, and 30 degrees C injection temperatures of the thermochemical fluids rose to 1600, 1200, and 280 psi, respectively; while the recovery factor was 83%, 66% and 54% OOIP, respectively. In comparison, from the injection of steam generated at 250 degrees C, the pressure at the inlet of the core was 212 psi and the recovery factor was 71% OOIP. These results therefore confirm increase in interest in the application of the TCF injection technology in heavy oil production.",11,11,0
Heavy Oil,Degrees C,"Askarova, Aysylu; Turakhanov, Aman; Markovic, Strahinja; Popov, Evgeny; Maksakov, Kirill; Usachev, Gennady; Karpov, Valery; Cheremisin, Alexey",Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance,Hot water injection; Carbonate reservoirs; Consolidated core; Cementation; Numerical simulation; Kinetic model,IN-SITU COMBUSTION; AQUATHERMOLYSIS; MODEL,"Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100-1500 m require technology that can achieve sufficiently high fluid temperature (250-300 degrees C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling. The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called ""aquathermolysis"" to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons. A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H-2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.",10,10,3
Heavy Oil,Degrees C,"Liu, Peng; Shi, Lanxiang; Liu, Pengcheng; Li, Lei; Hua, Daode",Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs,Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery; Heterogeneity,ASSISTED GRAVITY DRAINAGE; RECOVERY; SOLVENT; PERFORMANCE; PRESSURE; GAS,"Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.",8,8,4
Heavy Oil,Degrees C,"Adewunmi, Ahmad A.; Amao, Abduljamiu O.; Kamal, Muhammad Shahzad; Solling, Theis Ivan",Demulsification and breaking mechanism of variable quartz concentrates obtained from sand,Demulsification; Quartz; Seawater; Oil; Size; Recycle,HEAVY CRUDE-OIL; IN-WATER EMULSIONS; MAGNETIC NANOPARTICLES; IONIC LIQUIDS; MICROWAVE; PERFORMANCE; INTERFACE; BEHAVIOR,"This study reports the efficacy of quartz particles extracted from sand for the destabilization of crude oil emulsions and efficient water removal. Demulsification performance of quartz concentrates obtained from stacked sieves with openings: 75, 125, 250 and 300 mu m and quartz quantity varying from 1% to 7% were investigated using the bottle test technique at a temperature of 90 degrees C. The breaking mechanism of emulsion driven by quartz was analyzed by rheology, Fourier Transform Infrared (FTIR) spectroscopy, X-ray diffraction (XRD), optical microscopy and scanning electron microscopy (SEM). Experimental results showed that the quartz concentrates generated from stacked sieves: 75, 125, 250, and 300 mu m had optimal demulsification efficiency (DE) of 98%, 98%, 99%, and 99%, respectively. Moreover, the quartz concentration needed to attain these DEs levels ranges from 3 to 5%. In addition, the performance of quartz as a demulsifier was compared with a commercial demulsifier (ethyl cellulose). Viscosity versus time measurements demonstrated the change in emulsion's viscosity before and after quartz addition. A drastic reduction in the emulsion's viscosity was observed after quartz addition, indicating rupture and coalescence of water droplets. The FTIR and XRD analysis buttressed the functional groups and structural pattern while optical microscope and SEM analysis exhibited the morphology of quartz particles before and after the demulsification processes. A mechanism elucidating the breaking of crude oil emulsion by quartz is proposed. The results indicated that quartz particles processed from the sand will be useful as demulsifiers in the petroleum industry.",7,7,6
Heavy Oil,Degrees C,"Mustafin, Robert; Manasrah, Abdallah D.; Vitale, Gerardo; Askari, Roohollah; Nassar, Nashaat N.",Enhanced thermal conductivity and reduced viscosity of aegirine-based VR/VGO nanofluids for enhanced thermal oil recovery application,Nanoparticles; Vacuum residue; Vacuum gas oil; Nanofluids; Thermal conductivity; Oil recovery,HEAVY OIL; OXIDE NANOPARTICLES; CUO NANOPARTICLES; CARBON NANOTUBES; VOLUME FRACTION; CRUDE OILS; ADSORPTION; ASPHALTENES; TEMPERATURE; BITUMEN,"The depleting of the available conventional energy supplies together with an industrial shift towards unconventional resources like heavy oil/bitumen has become more pronounced. The steam-based heating methods are primarily used by the oil industry for the heavy oil/bitumen recovery. However, the thermal recovery methods are energy-intensive and have limited applications, especially for both thin and deep reservoirs. Therefore, there is a high priority need to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection. Hence, the continual improvement of this technique is of utmost importance. This study aims to propose a new injecting nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading and recovery. Here we report a new type of copper-based nanofluid using a blend of vacuum gas oil (VGO) and vacuum residue (VR) as the mother solvent. The nanoparticles were prepared by low-temperature hydrothermal synthesis route. Their detailed surface, morphology and size characterizations were achieved by X-ray diffraction, dynamic light scattering and scanning electron microscopy. The stable nanofluids were prepared by dispersing copper-based nanoparticles in a mixture of VGO and VR, at different ratios and temperatures. A set of measurements to determine the thermal conductivity and viscosity of the nanofluid with different loading of nanoparticle were performed. The thermal conductivity values of nanofluid systems are substantially higher than that of the base fluids. The nanofluid for 2 wt% of copper-doped aegirine nanoparticles dispersed in VGO and VGO/VR mixture exhibits a maximum thermal conductivity of 20% and 24%, respectively. It was found that the thermal conductivity of nanofluids increases with decreasing the hydrodynamic particle size. Moreover, the presence of chemo-physical interactions between nanoparticles and base fluid further enhances the thermal conductivity. Also, the temperature augmentation in a range from 80 to 110 degrees C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. This particular nanofluid may find potential applications in enhancing heavy oil upgrading and recovery.",7,7,5
Heavy Oil,Steam,"Wang, Yanwei; Liu, Huiqing; Zhang, Qichen; Chen, Zhangxin; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Pore-scale experimental study on EOR mechanisms of combining thermal and chemical flooding in heavy oil reservoirs,Viscosity reducer; Steam flooding; Foam; Visualized experiments; Mechanisms analysis,CYCLIC STEAM STIMULATION; CRUDE-OIL; VISCOSITY REDUCTION; FOAM-GENERATION; RECOVERY; EMULSIONS; INJECTION; FLOW; ASPHALTENE; RHEOLOGY,"Steam flooding is an important method for the development of heavy oil reservoirs, but steam channeling is an inevitable serious problem in the process of steam injection, which decreases the sweep efficiency of steam and leads to low oil recovery. Viscosity reducer (VR) flooding and nitrogen foam flooding are two effective methods of enhancing heavy oil recovery with satisfactory results. In this paper, a series of experiments were conducted to evaluate the effects of various factors on the performance of the novel viscosity reducer (VR-A). On this basis, A visualized model was adopted to investigate the synergistic development effect of thermal and chemical flooding, which vividly reflected the interaction of chemical agents with crude oil and their migration characteristics in porous media, as well as the mechanisms of enhancing oil recovery on the pore-scale. The results showed that VR-A could achieve excellent viscosity reduction effect on heavy oil under the influence of various factors, which could be combined with thermal flooding to effectively recover heavy oil. As for the pore-scale level, after the VR-A solution was injected, the interfacial tension between the oil and water was decreased, the wettability of the surface of the particle was changed, and two types of oil-in-water emulsions (spherical emulsions and flocculent emulsions) with a lower viscosity were formed, which were easy to flow with the fluid in pores and throats and could temporarily block the high-permeability area. In the process of foam flooding, the phenomena of bubble coalescence and breakup occurred constantly, and bubbles trapped in the porous media could improve the sweep efficiency of the subsequent fluid. The ultimate oil recovery of the development method combining thermal and chemical flooding in the visualized displacement experiment is 76.9%, 39.7% higher than that of pure thermal flooding. This article can provide an effective method to solve the problem of poor steam flooding performance in heavy oil reservoirs.",19,20,8
Heavy Oil,Steam,"Chen, Hailong; Wang, Zhuangzhuang; Wang, Kai; Li, Zhaomin; Li, Songyan",Investigation of EOR mechanism for flue gas assisted SAGD,,RESIDUAL OIL SATURATION; GRAVITY DRAINAGE SAGD; HEAVY-OIL; STEAM CHAMBER; CONDENSATION; PRESSURE; RECOVERY; CO2; VISUALIZATION; PERFORMANCE,,15,15,6
Heavy Oil,Steam,"Bruns, Fritjof; Babadagli, Tayfun",Heavy-oil recovery improvement by additives to steam injection: Identifying underlying mechanisms and chemical selection through visual experiments,Steam additives; Surfactants and solvents; Nanofluids and ionic liquids; Gravity and viscous displacement; Visual 2D experiments,,"To mimic the gravity assisted drainage and flooding type, steam displacement tests we performed previously (Bruns and Babadagli, 2017) on cores saturated with 27,000 cP heavy-crude-oil; a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. The majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, anionic surfactant (linear toluene sulfonate), non-ionic surfactants, biodiesel (thermally stable surface active agents), solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at a constant rate and pressure after being vaporized in an oven along with steam; the whole process was recorded with a camera. The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface and were observed to be the main reason for positive contribution of chemicals. Biodiesel exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the linear toluene sulfonate (LTS) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep). Non-ionic surfactants showed different emulsion capabilities and high efficiency in steam/condensate displacement with a higher HLB (hydrophile - lipophile balance) value.",12,12,3
Heavy Oil,Steam,"Alade, Olalekan S.; Hamdy, Mohamed; Mahmoud, Mohamed; Al Shehri, Dhafer A.; Mokheimer, Esmail; Patil, Shirish; Al-Nakhli, Ayman",A preliminary assessment of thermochemical fluid for heavy oil recovery,Enhanced oil recovery; Heavy oil; Thermal methods; Insitu heat generation; Thermochemical fluids,INJECTION; EXTRACTION; BITUMEN,"Commercial production of heavy oil has heavily relied upon steam injection method due to its effectiveness to reduce the viscosity and improved mobility. However, due to uncertainty of oil price, high energy cost, water requirement, heat loss, and environmental issues, attention is being given to new thermal EOR technologies such as insitu steam generation using thermochemical fluid (TCF) injection. This technology essentially involves downhole generation of heat and pressure from exothermic chemical reaction. In this investigation, thermochemical reactants were injected, at different temperatures (100, 50, and 30 degrees C) and constant rate of 0.5 ml/mln, into Berea sandstone core samples saturated with heavy oil (18 %wt./wt. asphaltene content and 11 degrees API) and brine. It was observed that the pressure generated at the inlet of the core due to 100, 50, and 30 degrees C injection temperatures of the thermochemical fluids rose to 1600, 1200, and 280 psi, respectively; while the recovery factor was 83%, 66% and 54% OOIP, respectively. In comparison, from the injection of steam generated at 250 degrees C, the pressure at the inlet of the core was 212 psi and the recovery factor was 71% OOIP. These results therefore confirm increase in interest in the application of the TCF injection technology in heavy oil production.",11,11,0
Heavy Oil,Steam,"Askarova, Aysylu; Turakhanov, Aman; Markovic, Strahinja; Popov, Evgeny; Maksakov, Kirill; Usachev, Gennady; Karpov, Valery; Cheremisin, Alexey",Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance,Hot water injection; Carbonate reservoirs; Consolidated core; Cementation; Numerical simulation; Kinetic model,IN-SITU COMBUSTION; AQUATHERMOLYSIS; MODEL,"Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100-1500 m require technology that can achieve sufficiently high fluid temperature (250-300 degrees C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling. The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called ""aquathermolysis"" to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons. A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H-2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.",10,10,3
Heavy Oil,Steam,"Chen, Hailong; Li, Haifeng; Li, Zhaomin; Li, Songyan; Wang, Yujun; Wang, Jian; Li, Binfei",Effects of matrix permeability and fracture on production characteristics and residual oil distribution during flue gas flooding in low permeability/tight reservoirs,Flue gas flooding; Matrix permeability; Fracture; Residual oil distribution; Gas channeling point,HUFF-N-PUFF; HEAVY OIL; CO2; RECOVERY; TIGHT; STEAM; STORAGE; FOAM; INJECTION; DRIVE,"The effects of matrix permeability and fracture on production characteristics and residual oil distribution of flue gas flooding in low permeability/tight conditions are analyzed systematically by laboratory physical simulation experiments and low-field nuclear magnetic resonance (LFNMR) system. T2 spectra results show that the crude oil is mainly distributed in the corresponding macropores of 100-1000 ms before and after the flue gas injection, and the crude oil in macropores is produced in large quantities after the flue gas injection in both fracture and fracture-free low permeability/tight cores. Additionally, oil production performance indicates that matrix permeability has a remarkable effect in fracture-free low permeability/tight cores. T2 spectra combined with slice scanned images show the migration from the macropores to the medium and fine pores is more obvious in the core with high matrix permeability and the final residual oil distribution is more uniform compared to those of the core with low matrix permeability. Matrix permeability is inversely proportional to the gas channeling point and it has a linear relationships with the gas channeling point in a log-log plot in fracture-free low permeability/tight cores. Besides, fracture can significantly reduce the effect of matrix permeability on oil recovery. The presence of fracture weakens the migration of crude oil in low permeability/tight fracture cores, and the residual oil spreads throughout the core. Fracture plays a dominating role in the gas channeling points for different permeability cores.",9,9,15
Heavy Oil,Steam,"Zhao, Yan",Laboratory experiment and field application of high pressure and high quality steam flooding,Heavy oil; Steam flooding; Pressure; Steam quality; Recovery factor,,"Steam flooding is an effective way to improve oil recovery after steam huff and puff for heavy oil reservoirs. The typical screening criteria for steam flooding requires reservoir pressure to be less than 5 MPa, the steam quality of conventional steam flooding in bottom hole is about 30%, heavy oil reservoir in Shengli Oilfield with character of deep burial depth, active edge and bottom water and high formation pressure (7-8 MPa), the increase of oil recovery using conventional steam flooding is not obvious, Therefore, the formation and development of steam chamber during steam flooding are studied by indoor physical simulation experiments, the feasibility of high-quality steam flooding under high pressure is analyzed. The experimental results show that the quality of steam injection has obvious influence on the expansion of steam chamber. As the steam quality increases under high pressure, the specific volume of underground steam increases, the formation time of steam chamber is shortened, the expansion distance of steam chamber increases, the effective steam flooding time is prolonged, and recovery rate improves obviously. Field tests of high-quality steam flooding under high pressure were carried out in Gudao Zhongerbei heavy oil reservoir of Shengli Oilfield, the result shows that the bottom-hole steam quality of steam injection wells is 50% and above (20% higher than conventional steam flooding), the steam chamber was effectively expanded and the performance of producing rate for production wells improves obviously. The recovery rate of the test area reached 52.1%, which was 16.8% higher than that of steam huff and puff. High-quality steam flooding technology was an effective way to improve the recovery rate of high-pressure heavy oil reservoirs.",9,9,5
Heavy Oil,Steam,"Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Cheng, Gang; Yu, Xiaogang",Experiments and analysis on development methods for horizontal well cyclic steam stimulation in heavy oil reservoir with edge water,Heavy oil; Edge water; Cyclic steam stimulation; Physical simulation; Experiment,MULTI-THERMAL FLUID; RELATIVE PERMEABILITIES; RECOVERY; PERFORMANCE; PREDICTION; OIL/WATER; FLOW; TEMPERATURE; PARAMETERS; EFFICIENCY,"In the world, the reserves are very huge in heavy oil reservoirs with edge water. Therefore, the effective development of such reservoirs is of great significance for the petroleum supply. In this paper, in order to transfer aquifer energy from actual reservoir to 3D model, a novel method is established based on the elastic principle to achieve simulation of heavy oil reservoir with edge water. Then the oil-water or oil-steam relative permeability curves are measured to analyze flowing characteristics of oil and water under high temperatures. Finally, three kinds of development methods are studied experimentally including the conventional cyclic steam stimulation (CCSS), the water production at oil-water contact (WPOWC) and the water production for post steam stimulation (WPPSS). The results show that the oil viscosity and the water mobility both reduce at higher temperature; moreover, the residual oil saturation decreases but the mobile water saturation increases during temperature rising. For heavy oil reservoirs with edge water, all these characteristics are advantageous to increase oil production and decrease water production. According to the results of 3D experiments, in the process of steam injection, the heating range mainly concentrates near the wellbore and an obvious steam overlap can be observed. The oil recovery factor (ORF) of WPPSS is 8.21%, which is slightly higher than that of CCSS, however the cumulative oil steam ratio (COSR) of WPPSS is 0.96, which is obvious larger than that of CCSS. Comparing the three development methods, for WPPSS method, the same steam injection can make more oil production and the water channeling can be effectively restrained in the late cycle of CSS. The method of WPPSS can be chosen to develop heavy oil reservoirs with edge water.",9,9,5
Heavy Oil,Nuclear Magnetic Resonance,"Chen, Meng; Dai, Jiacai; Liu, Xiangjun; Kuang, Yan; Wang, Zhongtao; Gou, Shunchao; Qin, Minjun; Li, Min",Effect of displacement rates on fluid distributions and dynamics during water flooding in tight oil sandstone cores from nuclear magnetic resonance (NMR),Tight oil sandstone cores; Water flooding; Displacement rate; Nuclear magnetic resonance; Oil distribution,CRITICAL CAPILLARY NUMBER; HUFF-N-PUFF; PERFORMANCE EVALUATION; SPONTANEOUS IMBIBITION; CO2 INJECTION; RECOVERY; RESERVOIR; BAKKEN; STATE; FLOW,"Water flooding is widely used as an economical and recyclable method to improve oil recovery in unconventional reservoirs. In this study, the effects of injection rates on oil distribution, the seepage dynamics and the contributions of increasing injection rates on enhancing oil recovery during water flooding are investigated. Typical tight oil sandstone cores with different permeabilities are obtained from Junggar Basin, Northwest China, for experimental studies that incorporate nuclear magnetic resonance analyses. Synthetic kerosene (viscosity = 11.2 mPa s) and heavy water (D2O) are used to simulate crude oil and formation water under formation conditions. The samples are first saturated with simulation water and thereafter displaced by synthetic oil until no water is produced to simulate the fully oil-saturated condition. To simulate the water flooding process, the samples are stably displaced by simulation water at injection rates increasing from 0.01 mL/min until no oil is produced. The T-2 spectra, injection pressures, and produced oil at different injection rates and water injection volumes are measured simultaneously. The transverse relaxation time (T-2) is converted for the corresponding pore-throat radius (r) by combining pore-throat size distributions (obtained from constant-rate mercury injection) and the fully oil saturated T-2 spectra. It indicates that the amplitude of T-2 spectra for macropore (>100 mu m) and mesopore (10-100 mu m) spaces decreases more rapidly than those for the micropore spaces (0-10 mu m) as injection rate increases. The classical capillary number theory is introduced to represent the effect of injection rate and characterize the dynamics of seepage processes. Results show that the oil recovery factor can be considerably improved by increasing the injection rate in tight oil cores, and this significant improvement is primarily attributed to mesopores and micropores.",15,15,7
Heavy Oil,Nuclear Magnetic Resonance,"Mukhamatdinov, I. I.; Salih, I. Sh S.; Rakhmatullin, I. Z.; Sitnov, S. A.; Laikov, A., V; Klochkov, V. V.; Vakhin, A. V.",Influence of Co-based catalyst on subfractional composition of heavy oil asphaltenes during aquathermolysis,Asphaltenes; Subfractions; Heavy oil; Hydrothermal catalytic conversion; IR-Spectroscopy; Nuclear magnetic resonance,PETROLEUM RESINS; CRUDE OILS; STABILITY; FRACTIONATION; SPECTROSCOPY; THERMOLYSIS; SOLUBILITY; ADSORPTION; TATARSTAN; SOLVENTS,"The chemical changes in the composition of asphaltene subfractions of heavy oil under the influence of oil-soluble Co-based catalyst were investigated. The results of SARA-analysis and MALDI-spectroscopy revealed a decrease in absolute content of asphaltenes and their molecular masses in the presence of catalyst. Moreover, the sulfur content was decreased under the catalyst influence and it was mostly observed in the subfraction with the highest molecular weight (A5). The main catalytic reaction was a destructive hydrogenation, directed to break the -C-S-C- bonds in the asphaltene molecules. The C-13 NMR spectra revealed the decrease in average length of chain (MCL) after catalytic treatment by 15 times in A1 subfraction, which was accepted as a solvate layer and almost by 13 times in A2 subfraction. The C-O and C-S bonds break in the side chains of aromatic and alicyclic hydrocarbons. The content of primary (C-p) and the sum of secondary and quaternary (C-sq) carbons was increased, while the content of tertiary (C-t) and aromatic carbons (C-ar) declined. The high-molecular poly-alicyclic and polyaromatic components had lost the straight and branched aliphatic hydrocarbons, and then were transformed into coke like substance - carbene-carboids.",13,13,1
Heavy Oil,Nuclear Magnetic Resonance,"Taheri-Shakib, Jaber; Zojaji, Iman; Saadati, Nastaran; Kazemzadeh, Ezzatallah; Esfandiarian, Ali; Rajabi-Kochi, Mahyar",Investigating molecular interaction between wax and asphaltene: Accounting for wax appearance temperature and crystallization,Wax appearance temperature; Asphaltene; Crystal; FTIR spectra; NMR,NUCLEAR-MAGNETIC-RESONANCE; MATHEMATICAL-MODEL EVALUATION; HEAVY CRUDE-OIL; HEATING TIME; PART 1.; AGGREGATION; DEPOSITION; ADSORPTION; PRECIPITATION; SPECTROSCOPY,"Three modes will improve the interaction of the wax-asphaltene molecules that eventually increase wax appearance temperature (WAT) within crude oil. The first mode takes place when the wax is composed of long-chain alkanes, and its aromatic compounds are low, and adjacent hydrogens in its constituent aromatic rings are substituted with long-chain paraffin. The second condition is when the wax is formed from low carbon number alkanes. In this case, the lower the asphaltene aromaticity and the carbon number of side alkyl chain, the higher its interaction with wax would be. The third approach occurs if naphthenic or aromatic structures exist in wax, and asphaltene aromatic rings are arranged as peri-condenses. Higher interaction of wax and asphaltene reduces wax crystals' size. The presence of polar compounds in the molecular structure of the wax and asphaltene does not affect WAT, but the size and morphology of crystals alter in microscopic images.",11,11,4
Heavy Oil,Nuclear Magnetic Resonance,"Li, Tianjun; Huang, Zhilong; Feng, Yue; Chen, Xuan; Ma, Qiang; Liu, Bo; Guo, Xiaobo","Reservoir characteristics and evaluation of fluid mobility in organic-rich mixed siliciclastic-carbonate sediments: A case study of the lacustrine Qiketai Formation in Shengbei Sag, Turpan-Hami Basin, Northwest China",Lacustrine mixed siliciclastic-carbonate sediments reservoir; Fluid mobility; 2D NMR T-1-T-2 map; Pore distribution; Turpan-Hami basin,PETROPHYSICAL CHARACTERIZATION; ADSORPTION CAPACITY; THERMAL MATURITY; PORE SYSTEM; SHALE; OIL; NUCLEAR; POROSITY; FIELD; RELAXOMETRY,"Organic matter-rich mixed siliciclastic-carbonate sediments is a special type of tight oil reservoir in the Turpan-Hami basin, which is characterized by complex fluid type, mineral composition and pore structure. By using casting thin sections, scanning electron microscopy (SEM) and whole rock X diffraction (XRD), pore types and petrological characterization of reservoirs are analyzed. Combined with the result of the physical property, nuclear magnetic resonance (NMR) experiments, the effects of the porosity, permeability, and pore size distribution on the movable fluid distribution in the tight reservoir were evaluated. The results showed that there are four types of mixed siliciclastic-carbonate sediments reservoir, which have high TOC. The reservoirs are characterized by low porosity range from 2% to 10% and extra low permeability mainly less than 0.1 x 10(-3) mu m(2). Nanometer scale intergranular pores and micro-fractures were the main reservoir pore types, we further divided the pore sizes distribution into two categories based on their water-saturated NMR T-2 spectra: Type I (bimodal pattern) and Type II (left unimodal, micropores with a diameter less than 100 nm). The fluid components in the reservoir including water in nano-pores, movable light oil, non-movable heavy oil and bound water were analyzed using advanced NMR T1-T2 maps. The mobile light oil content in the silt-bearing argillaceous arenaceous limestone and silt-bearing lime micritic dolomite is higher than that of other lithological reservoirs. The movable light oil content exhibited a strong correlation with permeability, and the proportion of large pores, indicating that the large pores, which are mainly supplied by the intergranular pores in dolomite, substantially contributed to mobility of the hydrocarbon fluid. The non-movable heavy oil fluid component is impacted the small pores ratio and solid organic matter, while water the in nano-pores is greatly affected by clay minerals.",10,10,6
Heavy Oil,Nuclear Magnetic Resonance,"Chen, Hailong; Li, Haifeng; Li, Zhaomin; Li, Songyan; Wang, Yujun; Wang, Jian; Li, Binfei",Effects of matrix permeability and fracture on production characteristics and residual oil distribution during flue gas flooding in low permeability/tight reservoirs,Flue gas flooding; Matrix permeability; Fracture; Residual oil distribution; Gas channeling point,HUFF-N-PUFF; HEAVY OIL; CO2; RECOVERY; TIGHT; STEAM; STORAGE; FOAM; INJECTION; DRIVE,"The effects of matrix permeability and fracture on production characteristics and residual oil distribution of flue gas flooding in low permeability/tight conditions are analyzed systematically by laboratory physical simulation experiments and low-field nuclear magnetic resonance (LFNMR) system. T2 spectra results show that the crude oil is mainly distributed in the corresponding macropores of 100-1000 ms before and after the flue gas injection, and the crude oil in macropores is produced in large quantities after the flue gas injection in both fracture and fracture-free low permeability/tight cores. Additionally, oil production performance indicates that matrix permeability has a remarkable effect in fracture-free low permeability/tight cores. T2 spectra combined with slice scanned images show the migration from the macropores to the medium and fine pores is more obvious in the core with high matrix permeability and the final residual oil distribution is more uniform compared to those of the core with low matrix permeability. Matrix permeability is inversely proportional to the gas channeling point and it has a linear relationships with the gas channeling point in a log-log plot in fracture-free low permeability/tight cores. Besides, fracture can significantly reduce the effect of matrix permeability on oil recovery. The presence of fracture weakens the migration of crude oil in low permeability/tight fracture cores, and the residual oil spreads throughout the core. Fracture plays a dominating role in the gas channeling points for different permeability cores.",9,9,15
Heavy Oil,Nuclear Magnetic Resonance,"Wei, Bing; Liu, Jiang; Zhang, Xiang; Xiang, Hua; Zou, Peng; Cao, Jie; Bai, Mingxing",Nuclear Magnetic Resonance (NMR) mapping of remaining oil distribution during sequential rate waterflooding processes for improving oil recovery,Waterflooding; Sequential rate mode; Remaining oil saturation; NMR; Enhanced oil recovery,CHEMICAL-TRACER TESTS; SILICA NANOPARTICLES; POROSITY TYPES; POROUS-MEDIA; FLOW; DISPLACEMENT; CHALLENGES; CAPILLARY; RESERVOIR; FORCES,"At the conclusion of waterflooding phase, significant volume of oil still remains in reservoir formations. In this paper, waterflooding was performed at a designed sequential rate mode with an aim to further reduce the remaining oil saturation (S-or). Waterflooding process was monitored continuously by a low-field Nuclear Magnetic Resonance (NMR) spectrometer attempting to map pore-scale displacing behaviors and also quantify the reduction in S-or in-situ. The results showed that the main pore size of the cores ranged from 1.6 mu m to 63.0 mu m inferred by T-2 (transverse relaxation time) distributions. The value of S-or in the cores increased towards the outlet face during waterflooding because of capillary end effect, which became more significant for heavy oil. At the termination of this waterflooding process, S-or was found to be further reduced by approximately 5.0% in the presence of thief water pathways as a result of the improved viscous forces. Water fingering and capillary imbibition effects were clearly visualized in the NMR images. These observations are expected to be useful for heavy oil waterflooding operations especially in post-breakthrough phase.",8,8,4
Heavy Oil,Determination,"Ma, Weijiao; Hou, Lianhua; Luo, Xia; Liu, Jinzhong; Tao, Shizhen; Guan, Ping; Cai, Yuwen",Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature -based semi -open pyrolysis: Implications for in -situ conversion process,Chang 7 oil shale; In-situ conversion process; Temperature-based semi-open pyrolysis; Hydrocarbon generation process; Hydrocarbon expulsion process,TRIASSIC YANCHANG FORMATION; ORGANIC-MATTER; HYDROUS PYROLYSIS; GAS GENERATION; CHINA IMPLICATIONS; SOURCE-ROCK; II KEROGEN; PETROLEUM; EVOLUTION; SYSTEM,"There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300-320 degrees C, 0.53-0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320-380 degrees C, 0.55-1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380-420 degrees C, 1.09-1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 degrees C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24-1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.",16,19,10
Heavy Oil,Determination,"Janiga, Damian; Czarnota, Robert; Kuk, Edyta; Stopa, Jerzy; Wojnarowski, Pawel",Measurement of Oil-CO2 diffusion coefficient using pulse-echo method for pressure-volume decay approach under reservoir conditions,CO2 diffusion coefficient; Mass transfer; Pressure-volume decay; Acoustically monitored separator (AMS); CO2-EOR,SATURATED POROUS-MEDIA; HEAVY-OIL; GAS DIFFUSIVITY; LIQUID HYDROCARBONS; CO2 DIFFUSION; MASS-TRANSFER; PUFF PROCESS; HUFF; RECOVERY; BITUMEN,In order to achieve synergic environmental effect CO2-EOR can be applied to improve oil production and reduce carbon dioxide emission. Greater results can be obtained by the CO2 huff-n-puff process which in the case of oil reservoirs is based mainly on the oil swelling effect. During the soaking period the primary mechanism distributing CO2 in the reservoir is molecular diffusion. To calculate mass transferred to oil phase molecular diffusion coefficient is used. Its determination can be based on direct or indirect techniques but no standard method is normed. This paper presents a pulse-echo pressure-volume decay technique to determine oil-CO2 diffusion coefficient under reservoir conditions with the use of acoustically monitored separator. In the proposed method measurements of difference between signal routing are recalculated to volume change in order to compute diffusion coefficient. Experimental procedure was conducted for three different temperatures. The obtained results are consistent with previous studies on diffusion coefficient determination. The proposed technique is more reliable and yields straightforward solution due to simultaneous binary measurements of pressure and volume system.,14,13,6
Heavy Oil,Determination,"Pu, Wanfen; Zhao, Shuai; Hu, Lingzhi; Varfolomeev, Mikhail A.; Yuan, Chengdong; Wang, Liangliang; Rodionov, Nikolay O.",Thermal effect caused by low temperature oxidation of heavy crude oil and its in-situ combustion behavior,Combustion tube; Thermal effect; Low temperature oxidation; Heavy crude oil; In-situ combustion; Porous media,AIR INJECTION; KINETICS; LIGHT; PYROLYSIS; FEASIBILITY; CALORIMETRY; COMPONENTS; RATES,"To investigate the thermal effect caused by low temperature oxidation (LTO) of one heavy crude oil in porous media, a combustion tube (CT) system coupled with a self-designed experimental scheme was adopted. Also, the in-situ combustion (ISC) performance of this heavy oil as well as alterations in oil properties before and after ISC was comprehensively evaluated. The results showed that there existed the apparent thermal effect induced by LTO within the researched ignition temperature (180-320 degrees C), and heat release became greater with the ignition temperature. It should be noted that the oxidation reaction rate of the heavy oil was rose remarkably releasing substantial heat when the ignition temperature was increased to 240 from 180 degrees C. The heavy oil was combusted under the ignition temperature of 350 degrees C, and the combustion front advanced sustainably. Some basic parameters during ISC, including apparent atomic H/C ratio, oxygen utilization, fuel consumption, etc., were determined, which made it accessible to predict field test performances. And the values of these parameters and post-mortem images of the CT test reflected the superior ISC performance of the heavy oil. The alterations in oil properties pre-ISC and post-ISC indicated that the produced oil encountered strong LTO reactions and thermal cracking reactions forming a considerable number of lighter oxygen-containing compounds. Comparison of differential scanning calorimetry (DSC) profiles of the crude oil and produced oil revealed that the ISC process made the heavy oil greatly upgrade.",14,14,3
Heavy Oil,Determination,"Zakirov, Timur Rustamovich; Khramchenkov, Maxim Georgievich",Characterization of two-phase displacement mechanisms in porous media by capillary and viscous forces estimation using the lattice Boltzmann simulations,Two-phase flow; Displacement; Drainage; Porous media; Fingering; Lattice Boltzmann equations; Surface tension,IMMISCIBLE DISPLACEMENTS; MULTIPHASE FLOWS; HEAVY OIL; PRESSURE; PERMEABILITY; SANDSTONE; DYNAMICS; MODELS; LIQUID; BEHAVIOR,"This paper proposes a method for characterization of the two-phase displacement mechanisms (viscous fingering, capillary fingering, stable front, and crossover) in porous media. The approach is based on separate estimation of the capillary and viscous forces and subsequent calculation of the ratio between them (designated as W). The value W determines the dominance of capillary force and is essentially the inverse capillary number. The advantage of this approach consists in taking into account the scale of the samples and predicting the flow mechanisms using parameters measured in laboratory conditions. The balance between viscous and capillary forces is controlled by surface tension and fluid viscosities. For flow simulation, the lattice Boltzmann equations and the color-gradient model are applied. The values of W equal to 0.5 and 2, which define the boundary of the crossover zone and separate it from the flow mechanisms, were determined and the proposed method was successfully validated on three two-dimensional samples of porous media with different permeability coefficients. It revealed a directly proportional effect of permeability on W. As a result, the surface tensions, which determine the boundaries of viscous fingering, capillary fingering, stable front, are shifted towards smaller values with increasing permeability. Also, the effect of the permeability and displacement mechanisms on the displacement efficiency before, after and at quasi-steady regime was investigated. The tendency to efficiency decrease with increasing surface tension and decrease in viscosity ratio was revealed for quasi-steady regime. The absence of the mobile wetting fluid after breakthrough is detected for crossover and capillary fingers. No-displacement regime after breakthrough and, consequently, effectiveness drop to minimal values in quasisteady regime occurs at lower surface tensions with increasing permeability.",9,9,1
Heavy Oil,Determination,"Castellanos, Mauricio Barrios; Serpa, Alberto Luiz; Biazussi, Jorge Luiz; Verde, William Monte; Dias Arrifano Sassim, Natache do Socorro",Fault identification using a chain of decision trees in an electrical submersible pump operating in a liquid-gas flow,Decision tree classifier; Fault detection; Electrical submersible pump; Machine learning,DIAGNOSIS,"The monitoring of centrifugal pumps is essential for the suitable operation of several industrial applications. The reliability of petroleum artificial lifting systems that use Electrical Submersible Pumps (ESP) depends substantially on the performance of these pumps. ESP can operate subjected to severe operating conditions such as viscous and two-phase flow. In recent years, real-time technologies based on machine learning algorithms have gained importance due to the capability to take advantage of historical data for future predictions. The present work proposes a particular assembly of Classification and Regression Trees (CART) for the detection and classification of incipient faults in a pumping system. Experiments were carried out on a ten-stage ESP to simulate, monitor and label the faults. The pump worked at 1800, 2400, 3000 and 3500 rpm, with a two-phase liquid-gas mixture. The gas-phase was nitrogen, and the liquid-phase was a heavy oil with a viscosity between 200 and 1000 cP. The proposed methodology, named here as Chain of Decision Trees, observe the system behavior based on the monitoring of the pressure, flow, torque, and temperature only. The algorithm has two steps. The first determines whether the system is in a fault state; if it is, the second determines the type of fault. The failures considered were the unexpected closure of the choke valve, the input pressure decreasing, the fluid viscosity increasing and the gas flow rate increasing. The proposed approach intends to improve the balance in classification and the interpretation of the cause of failure. The Chain of Decision Trees and the Decision Tree were compared regarding the overall accuracy and the individual fault misclassification getting a reduction in individual misclassification and better comprehensibility for the Chain of Decision Tree.",8,8,4
Heavy Oil,Determination,"Pablo Valdes, Juan; Becerra, Deisy; Rozo, Daniel; Cediel, Alexandra; Torres, Felipe; Asuaje, Miguel; Ratkovich, Nicolas",Comparative analysis of an electrical submersible pump's performance handling viscous Newtonian and non-Newtonian fluids through experimental and CFD approaches,Turbomachinery; Non-Newtonian liquid; CFD; Electrical Submersible Pumps (ESP); Shear-thinning,CENTRIFUGAL PUMPS; FLOW; VISCOSITY; IMPELLER; RHEOLOGY; PHASE,"Electrical Submersible Pumps (ESPs) are among the most common artificial lifting methods employed nowadays in the O&G industry. This work aims to carry out an exhaustive analysis of the performance and flow features of a multistage ESP when handling Shear-Thinning non-Newtonian fluids, which are commonly found in mature, heavy oil wells. Currently, no studies have been conducted for multistage centrifugal pumps operating under such conditions. In this study, water, two Newtonian oils of different viscosities, and two non-Newtonian fluids, consisting of two CMC solutions in water (0.5% and 1% w/w), were tested. The testing facility consisted of a four-stage ESP located in a closed-loop arrangement in which the flowrate could be freely manipulated. Experimental measurements were taken to determine the pressure rise and power consumption by the ESP's motor. The CFD model was validated against experimental data collected in this study. The CFD head rise was in excellent agreement against the experimental data for water, with MSE of 4.91%. Good agreement was also observed, with a slight overprediction, for the pump's efficiency, with an MSE of 10.6%. The non-Newtonian fluids best fitted the Cross viscosity model. CMC 0.5% obtained a 12% higher average head rise than that of CMC 1%, despite the latter exhibiting a more pronounced Shear-Thinning trend (higher Cross time constant). It was found that the non-Newtonian fluids tested out-performed, in terms of head rise, the Newtonian oils by an average of 23.5%, and 11.4% against the heavier and the lighter oil, respectively. This improved performance was observed despite the non-Newtonian range of effective viscosities being over one or more orders of magnitude higher than the oils' dynamic viscosities. Furthermore, it was noted that the pump's performance with both non-Newtonian fluids did not deteriorate as rapidly as it did for the viscous oils. This lead to a shift in the BEP towards higher flowrates for the non-Newtonian fluids. This observation was supported by the CFD effective viscosity profiles, which showed a decline in the viscosity as the flowrate increased. CFD proved to be a valuable tool to analyze and understand in depth the viscosity variations and flow features throughout the pump's domain and their connection with the global performance observed for the ESP.",8,8,2
Heavy Oil,Determination,"Mustafin, Robert; Manasrah, Abdallah D.; Vitale, Gerardo; Askari, Roohollah; Nassar, Nashaat N.",Enhanced thermal conductivity and reduced viscosity of aegirine-based VR/VGO nanofluids for enhanced thermal oil recovery application,Nanoparticles; Vacuum residue; Vacuum gas oil; Nanofluids; Thermal conductivity; Oil recovery,HEAVY OIL; OXIDE NANOPARTICLES; CUO NANOPARTICLES; CARBON NANOTUBES; VOLUME FRACTION; CRUDE OILS; ADSORPTION; ASPHALTENES; TEMPERATURE; BITUMEN,"The depleting of the available conventional energy supplies together with an industrial shift towards unconventional resources like heavy oil/bitumen has become more pronounced. The steam-based heating methods are primarily used by the oil industry for the heavy oil/bitumen recovery. However, the thermal recovery methods are energy-intensive and have limited applications, especially for both thin and deep reservoirs. Therefore, there is a high priority need to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection. Hence, the continual improvement of this technique is of utmost importance. This study aims to propose a new injecting nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading and recovery. Here we report a new type of copper-based nanofluid using a blend of vacuum gas oil (VGO) and vacuum residue (VR) as the mother solvent. The nanoparticles were prepared by low-temperature hydrothermal synthesis route. Their detailed surface, morphology and size characterizations were achieved by X-ray diffraction, dynamic light scattering and scanning electron microscopy. The stable nanofluids were prepared by dispersing copper-based nanoparticles in a mixture of VGO and VR, at different ratios and temperatures. A set of measurements to determine the thermal conductivity and viscosity of the nanofluid with different loading of nanoparticle were performed. The thermal conductivity values of nanofluid systems are substantially higher than that of the base fluids. The nanofluid for 2 wt% of copper-doped aegirine nanoparticles dispersed in VGO and VGO/VR mixture exhibits a maximum thermal conductivity of 20% and 24%, respectively. It was found that the thermal conductivity of nanofluids increases with decreasing the hydrodynamic particle size. Moreover, the presence of chemo-physical interactions between nanoparticles and base fluid further enhances the thermal conductivity. Also, the temperature augmentation in a range from 80 to 110 degrees C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. This particular nanofluid may find potential applications in enhancing heavy oil upgrading and recovery.",7,7,5
Heavy Oil,Liquid,"Al-Muntaser, Ameen A.; Varfolomeev, Mikhail A.; Suwaid, Muneer A.; Yuan, Chengdong; Chemodanov, Artem E.; Feoktistov, Dmitriy A.; Rakhmatullin, Ilfat Z.; Abbas, Mustafa; Dominguez-Alvarez, Enrique; Akhmadiyarov, Aydar A.; Klochkov, Vladimir V.; Amerkhanov, Marat I.","Hydrothermal upgrading of heavy oil in the presence of water at sub-critical, near-critical and supercritical conditions",Heavy oil; Hydrothermal upgrading; Sub-critical water; Near-critical water; Supercritical water; In-situ upgrading,CRUDE-OIL; AQUATHERMOLYSIS; NANOPARTICLES; SPECTROSCOPY; TEMPERATURE; HYDROLYSIS; CATALYST; CRACKING; BITUMEN; FTIR,"In this study, the hydrothermal upgrading (HTU) of high sulfur-content heavy oil was investigated at sub-critical (Sub-CW), near-critical (NCW) and supercritical water (SCW) conditions. Products obtained after HTU, including gases, liquid, and coke (if formed), were analyzed to understand the upgrading performance at different conditions. At Sub-CW (200, 250, and 300 degrees C), 250 degrees C is the optimum temperature where a viscosity reduction from 2073 to 1758 mPa s was achieved with a slight removal of sulfur (mainly sulfur) and the generation of a small amount of light and non-condensable hydrocarbons in gas phase (C1-C4, isoalkanes and alkenes, H2S, CO2 and H-2, etc.). At NCW (350 degrees C) and SCW (400 degrees C), heavy oil was upgraded into light oil with a significant removal of heteroatoms, an increase of saturates content, a reduction of aromatics, resins and asphaltenes contents, and a high yield of light gaseous hydrocarbons (mainly methane). Simultaneously, each SARA fraction was also greatly ameliorated: the content of light alkanes with low molecular weight in saturates was increased, diaromatics content in aromatics was increased with a reduction of polyaromatics content, aromatics-type carbon atoms in resins was increased with a decrease in aliphatic hydrocarbons. Moreover, MALDI-TOF measurements of asphaltenes show that the molecular weights of asphaltenes were reduced. All these results indicated that HTU at Sub-CW can be used for heavy oil pre-treatment (in-situ or ex-situ upgrading) considering its main effect of viscosity reduction with a small removal of heteroatoms, while HTU at NCW and SWC has a great potential in insitu and ex-situ upgrading and oil refining as it can convert heavy oil into light oil.",26,26,7
Heavy Oil,Liquid,"Javadian, Soheila; Sadrpoor, S. Morteza",Demulsification of water in oil emulsion by surface modified SiO2 nanoparticle,Demulsification; SiO2 surface modification; Water in oil emulsion,HEAVY CRUDE-OIL; GRAPHENE OXIDE; MAGNETIC DEMULSIFIER; IONIC LIQUIDS; ASPHALTENES; OPTIMIZATION; TEMPERATURE; ADSORPTION; INTERFACE; STABILIZATION,"In the present study, SiO2 nanoparticles (NP) were used for dehydration of crude oil. Also, in order to enhance the hydrophobicity and hydmphilicity of the nanoparticles, they were functionalized respectively with oleic acid (OA) and sodium dodecyl benzene sulfonate (SDBS) surfactant. Furthermore, graphene oxide (GO) was employed to synthesis GO-SiO2 nanocomposite as a superhydmphilic demulsifier. Nanodemulsifiers were characterized with scanning electron microscopy (SEM), field-emission scanning electron microscopy (FESEM), Brunauer-Emmett-Teller method (BET), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), and zeta potential. Additionally, the performance of nanodemulsifiers was evaluated with bottle test. The results of bottle test revealed that GO-SiO2 nanocomposite has the best performance among all nanodemulsifiers and dehydration of crude oil was completed during 90 min (while dehydration of crude oil with SiO2 nanoparticle was done at 110 min). Moreover, the effects of temperature and salt were surveyed and the results demonstrated that both factors influence the stability of water in oil emulsion. The outcomes of the interfacial tension (IFT) at the water/crude oil interface displayed GO-SiO2 nanocomposite has interface active property and can decrease IFT from 14.38 mN m(-1) to 2.44 mN m(-1).",18,18,3
Heavy Oil,Liquid,"Janiga, Damian; Czarnota, Robert; Kuk, Edyta; Stopa, Jerzy; Wojnarowski, Pawel",Measurement of Oil-CO2 diffusion coefficient using pulse-echo method for pressure-volume decay approach under reservoir conditions,CO2 diffusion coefficient; Mass transfer; Pressure-volume decay; Acoustically monitored separator (AMS); CO2-EOR,SATURATED POROUS-MEDIA; HEAVY-OIL; GAS DIFFUSIVITY; LIQUID HYDROCARBONS; CO2 DIFFUSION; MASS-TRANSFER; PUFF PROCESS; HUFF; RECOVERY; BITUMEN,In order to achieve synergic environmental effect CO2-EOR can be applied to improve oil production and reduce carbon dioxide emission. Greater results can be obtained by the CO2 huff-n-puff process which in the case of oil reservoirs is based mainly on the oil swelling effect. During the soaking period the primary mechanism distributing CO2 in the reservoir is molecular diffusion. To calculate mass transferred to oil phase molecular diffusion coefficient is used. Its determination can be based on direct or indirect techniques but no standard method is normed. This paper presents a pulse-echo pressure-volume decay technique to determine oil-CO2 diffusion coefficient under reservoir conditions with the use of acoustically monitored separator. In the proposed method measurements of difference between signal routing are recalculated to volume change in order to compute diffusion coefficient. Experimental procedure was conducted for three different temperatures. The obtained results are consistent with previous studies on diffusion coefficient determination. The proposed technique is more reliable and yields straightforward solution due to simultaneous binary measurements of pressure and volume system.,14,13,6
Heavy Oil,Liquid,"Bruns, Fritjof; Babadagli, Tayfun",Heavy-oil recovery improvement by additives to steam injection: Identifying underlying mechanisms and chemical selection through visual experiments,Steam additives; Surfactants and solvents; Nanofluids and ionic liquids; Gravity and viscous displacement; Visual 2D experiments,,"To mimic the gravity assisted drainage and flooding type, steam displacement tests we performed previously (Bruns and Babadagli, 2017) on cores saturated with 27,000 cP heavy-crude-oil; a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. The majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, anionic surfactant (linear toluene sulfonate), non-ionic surfactants, biodiesel (thermally stable surface active agents), solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at a constant rate and pressure after being vaporized in an oven along with steam; the whole process was recorded with a camera. The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface and were observed to be the main reason for positive contribution of chemicals. Biodiesel exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the linear toluene sulfonate (LTS) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep). Non-ionic surfactants showed different emulsion capabilities and high efficiency in steam/condensate displacement with a higher HLB (hydrophile - lipophile balance) value.",12,12,3
Heavy Oil,Liquid,"Zakirov, Timur Rustamovich; Khramchenkov, Maxim Georgievich",Characterization of two-phase displacement mechanisms in porous media by capillary and viscous forces estimation using the lattice Boltzmann simulations,Two-phase flow; Displacement; Drainage; Porous media; Fingering; Lattice Boltzmann equations; Surface tension,IMMISCIBLE DISPLACEMENTS; MULTIPHASE FLOWS; HEAVY OIL; PRESSURE; PERMEABILITY; SANDSTONE; DYNAMICS; MODELS; LIQUID; BEHAVIOR,"This paper proposes a method for characterization of the two-phase displacement mechanisms (viscous fingering, capillary fingering, stable front, and crossover) in porous media. The approach is based on separate estimation of the capillary and viscous forces and subsequent calculation of the ratio between them (designated as W). The value W determines the dominance of capillary force and is essentially the inverse capillary number. The advantage of this approach consists in taking into account the scale of the samples and predicting the flow mechanisms using parameters measured in laboratory conditions. The balance between viscous and capillary forces is controlled by surface tension and fluid viscosities. For flow simulation, the lattice Boltzmann equations and the color-gradient model are applied. The values of W equal to 0.5 and 2, which define the boundary of the crossover zone and separate it from the flow mechanisms, were determined and the proposed method was successfully validated on three two-dimensional samples of porous media with different permeability coefficients. It revealed a directly proportional effect of permeability on W. As a result, the surface tensions, which determine the boundaries of viscous fingering, capillary fingering, stable front, are shifted towards smaller values with increasing permeability. Also, the effect of the permeability and displacement mechanisms on the displacement efficiency before, after and at quasi-steady regime was investigated. The tendency to efficiency decrease with increasing surface tension and decrease in viscosity ratio was revealed for quasi-steady regime. The absence of the mobile wetting fluid after breakthrough is detected for crossover and capillary fingers. No-displacement regime after breakthrough and, consequently, effectiveness drop to minimal values in quasisteady regime occurs at lower surface tensions with increasing permeability.",9,9,1
Heavy Oil,Liquid,"Pablo Valdes, Juan; Becerra, Deisy; Rozo, Daniel; Cediel, Alexandra; Torres, Felipe; Asuaje, Miguel; Ratkovich, Nicolas",Comparative analysis of an electrical submersible pump's performance handling viscous Newtonian and non-Newtonian fluids through experimental and CFD approaches,Turbomachinery; Non-Newtonian liquid; CFD; Electrical Submersible Pumps (ESP); Shear-thinning,CENTRIFUGAL PUMPS; FLOW; VISCOSITY; IMPELLER; RHEOLOGY; PHASE,"Electrical Submersible Pumps (ESPs) are among the most common artificial lifting methods employed nowadays in the O&G industry. This work aims to carry out an exhaustive analysis of the performance and flow features of a multistage ESP when handling Shear-Thinning non-Newtonian fluids, which are commonly found in mature, heavy oil wells. Currently, no studies have been conducted for multistage centrifugal pumps operating under such conditions. In this study, water, two Newtonian oils of different viscosities, and two non-Newtonian fluids, consisting of two CMC solutions in water (0.5% and 1% w/w), were tested. The testing facility consisted of a four-stage ESP located in a closed-loop arrangement in which the flowrate could be freely manipulated. Experimental measurements were taken to determine the pressure rise and power consumption by the ESP's motor. The CFD model was validated against experimental data collected in this study. The CFD head rise was in excellent agreement against the experimental data for water, with MSE of 4.91%. Good agreement was also observed, with a slight overprediction, for the pump's efficiency, with an MSE of 10.6%. The non-Newtonian fluids best fitted the Cross viscosity model. CMC 0.5% obtained a 12% higher average head rise than that of CMC 1%, despite the latter exhibiting a more pronounced Shear-Thinning trend (higher Cross time constant). It was found that the non-Newtonian fluids tested out-performed, in terms of head rise, the Newtonian oils by an average of 23.5%, and 11.4% against the heavier and the lighter oil, respectively. This improved performance was observed despite the non-Newtonian range of effective viscosities being over one or more orders of magnitude higher than the oils' dynamic viscosities. Furthermore, it was noted that the pump's performance with both non-Newtonian fluids did not deteriorate as rapidly as it did for the viscous oils. This lead to a shift in the BEP towards higher flowrates for the non-Newtonian fluids. This observation was supported by the CFD effective viscosity profiles, which showed a decline in the viscosity as the flowrate increased. CFD proved to be a valuable tool to analyze and understand in depth the viscosity variations and flow features throughout the pump's domain and their connection with the global performance observed for the ESP.",8,8,2
Heavy Oil,Liquid,"Adewunmi, Ahmad A.; Amao, Abduljamiu O.; Kamal, Muhammad Shahzad; Solling, Theis Ivan",Demulsification and breaking mechanism of variable quartz concentrates obtained from sand,Demulsification; Quartz; Seawater; Oil; Size; Recycle,HEAVY CRUDE-OIL; IN-WATER EMULSIONS; MAGNETIC NANOPARTICLES; IONIC LIQUIDS; MICROWAVE; PERFORMANCE; INTERFACE; BEHAVIOR,"This study reports the efficacy of quartz particles extracted from sand for the destabilization of crude oil emulsions and efficient water removal. Demulsification performance of quartz concentrates obtained from stacked sieves with openings: 75, 125, 250 and 300 mu m and quartz quantity varying from 1% to 7% were investigated using the bottle test technique at a temperature of 90 degrees C. The breaking mechanism of emulsion driven by quartz was analyzed by rheology, Fourier Transform Infrared (FTIR) spectroscopy, X-ray diffraction (XRD), optical microscopy and scanning electron microscopy (SEM). Experimental results showed that the quartz concentrates generated from stacked sieves: 75, 125, 250, and 300 mu m had optimal demulsification efficiency (DE) of 98%, 98%, 99%, and 99%, respectively. Moreover, the quartz concentration needed to attain these DEs levels ranges from 3 to 5%. In addition, the performance of quartz as a demulsifier was compared with a commercial demulsifier (ethyl cellulose). Viscosity versus time measurements demonstrated the change in emulsion's viscosity before and after quartz addition. A drastic reduction in the emulsion's viscosity was observed after quartz addition, indicating rupture and coalescence of water droplets. The FTIR and XRD analysis buttressed the functional groups and structural pattern while optical microscope and SEM analysis exhibited the morphology of quartz particles before and after the demulsification processes. A mechanism elucidating the breaking of crude oil emulsion by quartz is proposed. The results indicated that quartz particles processed from the sand will be useful as demulsifiers in the petroleum industry.",7,7,6
Heavy Oil,Surface Tension,"Wang, Yanwei; Liu, Huiqing; Zhang, Qichen; Chen, Zhangxin; Wang, Jing; Dong, Xiaohu; Chen, Fangxuan",Pore-scale experimental study on EOR mechanisms of combining thermal and chemical flooding in heavy oil reservoirs,Viscosity reducer; Steam flooding; Foam; Visualized experiments; Mechanisms analysis,CYCLIC STEAM STIMULATION; CRUDE-OIL; VISCOSITY REDUCTION; FOAM-GENERATION; RECOVERY; EMULSIONS; INJECTION; FLOW; ASPHALTENE; RHEOLOGY,"Steam flooding is an important method for the development of heavy oil reservoirs, but steam channeling is an inevitable serious problem in the process of steam injection, which decreases the sweep efficiency of steam and leads to low oil recovery. Viscosity reducer (VR) flooding and nitrogen foam flooding are two effective methods of enhancing heavy oil recovery with satisfactory results. In this paper, a series of experiments were conducted to evaluate the effects of various factors on the performance of the novel viscosity reducer (VR-A). On this basis, A visualized model was adopted to investigate the synergistic development effect of thermal and chemical flooding, which vividly reflected the interaction of chemical agents with crude oil and their migration characteristics in porous media, as well as the mechanisms of enhancing oil recovery on the pore-scale. The results showed that VR-A could achieve excellent viscosity reduction effect on heavy oil under the influence of various factors, which could be combined with thermal flooding to effectively recover heavy oil. As for the pore-scale level, after the VR-A solution was injected, the interfacial tension between the oil and water was decreased, the wettability of the surface of the particle was changed, and two types of oil-in-water emulsions (spherical emulsions and flocculent emulsions) with a lower viscosity were formed, which were easy to flow with the fluid in pores and throats and could temporarily block the high-permeability area. In the process of foam flooding, the phenomena of bubble coalescence and breakup occurred constantly, and bubbles trapped in the porous media could improve the sweep efficiency of the subsequent fluid. The ultimate oil recovery of the development method combining thermal and chemical flooding in the visualized displacement experiment is 76.9%, 39.7% higher than that of pure thermal flooding. This article can provide an effective method to solve the problem of poor steam flooding performance in heavy oil reservoirs.",19,20,8
Heavy Oil,Surface Tension,"Javadian, Soheila; Sadrpoor, S. Morteza",Demulsification of water in oil emulsion by surface modified SiO2 nanoparticle,Demulsification; SiO2 surface modification; Water in oil emulsion,HEAVY CRUDE-OIL; GRAPHENE OXIDE; MAGNETIC DEMULSIFIER; IONIC LIQUIDS; ASPHALTENES; OPTIMIZATION; TEMPERATURE; ADSORPTION; INTERFACE; STABILIZATION,"In the present study, SiO2 nanoparticles (NP) were used for dehydration of crude oil. Also, in order to enhance the hydrophobicity and hydmphilicity of the nanoparticles, they were functionalized respectively with oleic acid (OA) and sodium dodecyl benzene sulfonate (SDBS) surfactant. Furthermore, graphene oxide (GO) was employed to synthesis GO-SiO2 nanocomposite as a superhydmphilic demulsifier. Nanodemulsifiers were characterized with scanning electron microscopy (SEM), field-emission scanning electron microscopy (FESEM), Brunauer-Emmett-Teller method (BET), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), and zeta potential. Additionally, the performance of nanodemulsifiers was evaluated with bottle test. The results of bottle test revealed that GO-SiO2 nanocomposite has the best performance among all nanodemulsifiers and dehydration of crude oil was completed during 90 min (while dehydration of crude oil with SiO2 nanoparticle was done at 110 min). Moreover, the effects of temperature and salt were surveyed and the results demonstrated that both factors influence the stability of water in oil emulsion. The outcomes of the interfacial tension (IFT) at the water/crude oil interface displayed GO-SiO2 nanocomposite has interface active property and can decrease IFT from 14.38 mN m(-1) to 2.44 mN m(-1).",18,18,3
Heavy Oil,Surface Tension,"Bruns, Fritjof; Babadagli, Tayfun",Heavy-oil recovery improvement by additives to steam injection: Identifying underlying mechanisms and chemical selection through visual experiments,Steam additives; Surfactants and solvents; Nanofluids and ionic liquids; Gravity and viscous displacement; Visual 2D experiments,,"To mimic the gravity assisted drainage and flooding type, steam displacement tests we performed previously (Bruns and Babadagli, 2017) on cores saturated with 27,000 cP heavy-crude-oil; a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. The majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, anionic surfactant (linear toluene sulfonate), non-ionic surfactants, biodiesel (thermally stable surface active agents), solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at a constant rate and pressure after being vaporized in an oven along with steam; the whole process was recorded with a camera. The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface and were observed to be the main reason for positive contribution of chemicals. Biodiesel exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the linear toluene sulfonate (LTS) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep). Non-ionic surfactants showed different emulsion capabilities and high efficiency in steam/condensate displacement with a higher HLB (hydrophile - lipophile balance) value.",12,12,3
Heavy Oil,Surface Tension,"Zakirov, Timur Rustamovich; Khramchenkov, Maxim Georgievich",Characterization of two-phase displacement mechanisms in porous media by capillary and viscous forces estimation using the lattice Boltzmann simulations,Two-phase flow; Displacement; Drainage; Porous media; Fingering; Lattice Boltzmann equations; Surface tension,IMMISCIBLE DISPLACEMENTS; MULTIPHASE FLOWS; HEAVY OIL; PRESSURE; PERMEABILITY; SANDSTONE; DYNAMICS; MODELS; LIQUID; BEHAVIOR,"This paper proposes a method for characterization of the two-phase displacement mechanisms (viscous fingering, capillary fingering, stable front, and crossover) in porous media. The approach is based on separate estimation of the capillary and viscous forces and subsequent calculation of the ratio between them (designated as W). The value W determines the dominance of capillary force and is essentially the inverse capillary number. The advantage of this approach consists in taking into account the scale of the samples and predicting the flow mechanisms using parameters measured in laboratory conditions. The balance between viscous and capillary forces is controlled by surface tension and fluid viscosities. For flow simulation, the lattice Boltzmann equations and the color-gradient model are applied. The values of W equal to 0.5 and 2, which define the boundary of the crossover zone and separate it from the flow mechanisms, were determined and the proposed method was successfully validated on three two-dimensional samples of porous media with different permeability coefficients. It revealed a directly proportional effect of permeability on W. As a result, the surface tensions, which determine the boundaries of viscous fingering, capillary fingering, stable front, are shifted towards smaller values with increasing permeability. Also, the effect of the permeability and displacement mechanisms on the displacement efficiency before, after and at quasi-steady regime was investigated. The tendency to efficiency decrease with increasing surface tension and decrease in viscosity ratio was revealed for quasi-steady regime. The absence of the mobile wetting fluid after breakthrough is detected for crossover and capillary fingers. No-displacement regime after breakthrough and, consequently, effectiveness drop to minimal values in quasisteady regime occurs at lower surface tensions with increasing permeability.",9,9,1
Heavy Oil,Hot Water Injection,"Askarova, Aysylu; Turakhanov, Aman; Markovic, Strahinja; Popov, Evgeny; Maksakov, Kirill; Usachev, Gennady; Karpov, Valery; Cheremisin, Alexey",Thermal enhanced oil recovery in deep heavy oil carbonates: Experimental and numerical study on a hot water injection performance,Hot water injection; Carbonate reservoirs; Consolidated core; Cementation; Numerical simulation; Kinetic model,IN-SITU COMBUSTION; AQUATHERMOLYSIS; MODEL,"Currently, thermal methods of enhanced oil recovery are based on the use of heat transfer mediums (steam, hot water) and in-situ combustion, which are the most efficient methods in the development of heavy oil reservoirs. In this study, experimental and numerical modeling was carried out to estimate the efficiency of hot water injection to engage in the active development of high-viscosity oil reserves in a deep carbonate reservoir. There is a limited amount of published experimental studies on carbonates, in comparison with sandstones, shale, or oil sands. Oil-bearing formations at depths of 1100-1500 m require technology that can achieve sufficiently high fluid temperature (250-300 degrees C) in the bottom-hole zone to be successful. The performance of the implemented technique on a field greatly depends on the quality of the experimental data and numerical simulation. Particularly, the hydrodynamic model, reaction kinetics, and operational parameters are crucial parameters for future upscaling. The hot water injection experiment was conducted using a medium pressure combustion tube assembly on the reservoir rock model made of consolidated carbonate samples. Moreover, a new numerical model was constructed to simulate the experiment with a reproduction of the fluid models, properties of the oil and rock samples, and full geometry of the core holders where chemical interactions occur. What makes this model authentic is the calibration of reaction kinetics called ""aquathermolysis"" to hot water injection process, which replicate the most prevalent thermal process during the interaction of hot water and hydrocarbons. A close correlation between experimental and numerical results was obtained in terms of cumulative water and oil recovery and temperature profiles. The developed numerical model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a proportionate increase in oil recovery. The achieved recovery factor for the experiment was 63%. Lastly, a good match of cumulative gases (CH4, H-2, H2S, CO2, and HMWG) was obtained for the hot water injection experiment. Adapted fluid model, relative permeability, kinetic model, and operational parameters are necessary for the upscaling to the field. The improved efficiency of oil displacement at this site is confirmed by numerical simulation.",10,10,3
Heavy Oil,Hot Water Injection,"Liu, Peng; Shi, Lanxiang; Liu, Pengcheng; Li, Lei; Hua, Daode",Experimental study of high-temperature CO2 foam flooding after hot-water injection in developing heavy oil reservoirs,Heavy oil reservoirs; CO2; Foam flooding; Hot water flooding; Enhanced oil recovery; Heterogeneity,ASSISTED GRAVITY DRAINAGE; RECOVERY; SOLVENT; PERFORMANCE; PRESSURE; GAS,"Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.",8,8,4
Heavy Oil,Submersible Pump,"Castellanos, Mauricio Barrios; Serpa, Alberto Luiz; Biazussi, Jorge Luiz; Verde, William Monte; Dias Arrifano Sassim, Natache do Socorro",Fault identification using a chain of decision trees in an electrical submersible pump operating in a liquid-gas flow,Decision tree classifier; Fault detection; Electrical submersible pump; Machine learning,DIAGNOSIS,"The monitoring of centrifugal pumps is essential for the suitable operation of several industrial applications. The reliability of petroleum artificial lifting systems that use Electrical Submersible Pumps (ESP) depends substantially on the performance of these pumps. ESP can operate subjected to severe operating conditions such as viscous and two-phase flow. In recent years, real-time technologies based on machine learning algorithms have gained importance due to the capability to take advantage of historical data for future predictions. The present work proposes a particular assembly of Classification and Regression Trees (CART) for the detection and classification of incipient faults in a pumping system. Experiments were carried out on a ten-stage ESP to simulate, monitor and label the faults. The pump worked at 1800, 2400, 3000 and 3500 rpm, with a two-phase liquid-gas mixture. The gas-phase was nitrogen, and the liquid-phase was a heavy oil with a viscosity between 200 and 1000 cP. The proposed methodology, named here as Chain of Decision Trees, observe the system behavior based on the monitoring of the pressure, flow, torque, and temperature only. The algorithm has two steps. The first determines whether the system is in a fault state; if it is, the second determines the type of fault. The failures considered were the unexpected closure of the choke valve, the input pressure decreasing, the fluid viscosity increasing and the gas flow rate increasing. The proposed approach intends to improve the balance in classification and the interpretation of the cause of failure. The Chain of Decision Trees and the Decision Tree were compared regarding the overall accuracy and the individual fault misclassification getting a reduction in individual misclassification and better comprehensibility for the Chain of Decision Tree.",8,8,4
Heavy Oil,Submersible Pump,"Pablo Valdes, Juan; Becerra, Deisy; Rozo, Daniel; Cediel, Alexandra; Torres, Felipe; Asuaje, Miguel; Ratkovich, Nicolas",Comparative analysis of an electrical submersible pump's performance handling viscous Newtonian and non-Newtonian fluids through experimental and CFD approaches,Turbomachinery; Non-Newtonian liquid; CFD; Electrical Submersible Pumps (ESP); Shear-thinning,CENTRIFUGAL PUMPS; FLOW; VISCOSITY; IMPELLER; RHEOLOGY; PHASE,"Electrical Submersible Pumps (ESPs) are among the most common artificial lifting methods employed nowadays in the O&G industry. This work aims to carry out an exhaustive analysis of the performance and flow features of a multistage ESP when handling Shear-Thinning non-Newtonian fluids, which are commonly found in mature, heavy oil wells. Currently, no studies have been conducted for multistage centrifugal pumps operating under such conditions. In this study, water, two Newtonian oils of different viscosities, and two non-Newtonian fluids, consisting of two CMC solutions in water (0.5% and 1% w/w), were tested. The testing facility consisted of a four-stage ESP located in a closed-loop arrangement in which the flowrate could be freely manipulated. Experimental measurements were taken to determine the pressure rise and power consumption by the ESP's motor. The CFD model was validated against experimental data collected in this study. The CFD head rise was in excellent agreement against the experimental data for water, with MSE of 4.91%. Good agreement was also observed, with a slight overprediction, for the pump's efficiency, with an MSE of 10.6%. The non-Newtonian fluids best fitted the Cross viscosity model. CMC 0.5% obtained a 12% higher average head rise than that of CMC 1%, despite the latter exhibiting a more pronounced Shear-Thinning trend (higher Cross time constant). It was found that the non-Newtonian fluids tested out-performed, in terms of head rise, the Newtonian oils by an average of 23.5%, and 11.4% against the heavier and the lighter oil, respectively. This improved performance was observed despite the non-Newtonian range of effective viscosities being over one or more orders of magnitude higher than the oils' dynamic viscosities. Furthermore, it was noted that the pump's performance with both non-Newtonian fluids did not deteriorate as rapidly as it did for the viscous oils. This lead to a shift in the BEP towards higher flowrates for the non-Newtonian fluids. This observation was supported by the CFD effective viscosity profiles, which showed a decline in the viscosity as the flowrate increased. CFD proved to be a valuable tool to analyze and understand in depth the viscosity variations and flow features throughout the pump's domain and their connection with the global performance observed for the ESP.",8,8,2
Neural Network,Artificial Neural-networks,"Song, Xuanyi; Liu, Yuetian; Xue, Liang; Wang, Jun; Zhang, Jingzhe; Wang, Junqiang; Jiang, Long; Cheng, Ziyan",Time-series well performance prediction based on Long Short-Term Memory (LSTM) neural network model,Deep learning; LSTM; Time sequence data; PSO; Production forecasting,PARTICLE SWARM OPTIMIZATION; ALGORITHM; DESIGN; WIND,"Oil production forecasting is one of the most critical issues during the exploitation phase of the oilfield. The limitations of traditional approaches make time-series production prediction still challenging. With the development of artificial intelligence, high-performance algorithms make reliable production prediction possible from the data perspective. This study proposes a Long Short-Term Memory (LSTM) neural network based model to infer the production of fractured horizontal wells in a volcanic reservoir, which addresses the limitations of traditional method and shows accurate predictions. The LSTM neural network enables to capture the dependencies of the oil rate time sequence data and incorporate the production constraints. Particle Swarm Optimization algorithm (PSO) is employed to optimize the essential configuration of the LSTM model. For evaluation purpose, two case studies are carried out with the production dynamics from synthetic model and from the Xinjiang oilfield, China. Towards a fair evaluation, the performance of the proposed approach is compared with traditional neural networks, time-series forecasting approaches, and conventional decline curves. The experiment results show that the proposed LSTM model outperforms other approaches.",70,73,35
Neural Network,Artificial Neural-networks,"Moayedi, Hossein; Aghel, Babak; Vaferi, Behzad; Foong, Loke Kok; Dieu Tien Bui",The feasibility of Levenberg-Marquardt algorithm combined with imperialist competitive computational method predicting drag reduction in crude oil pipelines,Drag reduction; Artificial intelligence; Levenberg-Marquardt; Imperialist competition algorithm; Comparative study,ARTIFICIAL NEURAL-NETWORKS; REDUCING POLYMERS; FLOW; MODEL; PERFORMANCE,"Adding small amounts of drag-reducing agents (DRA) to the crude oil can effectively reduce energy losses and its associated pressure drop in transportation pipelines. They do their roles by reducing the turbulent friction factor of the flowing liquids in the pipeline. In this study, the artificial neural networks (ANN) are utilized for estimation of drag reduction (DR) in crude oil pipelines as a function of Reynolds number, concentration, and type of drag-reducing agents, temperature, and type of pipe. Two different training algorithms, i.e. Levenberg-Marquardt (LM) and imperialist competition algorithm (ICA) are used for adjustment of parameters of multilayer perceptron (MLP) networks. Predictive accuracies of trained MLP by Levenberg-Marquardt (LM-MLP) and imperialist competition algorithm (ICA-MLP) for estimating drag reduction in crude oil pipelines were compared. The comparisons were done by three statistical criteria, i.e. root mean square error (RMSE), the coefficient of determination (R-2), and mean absolute error (MAE). The obtained results show that replacing LM by ICA evolutionary algorithm for adjustment of parameters of MLP leads to increasing R-2 from 0.9585 to 0.9791 in the training phase, and from 0.9310 to 0.9698 in the testing phase. Furthermore, ICA has reduced the RMSE and MAE of testing group from 3.0396 to 2.2616 to the 2.0080 and 1.5579, respectively. Finally, a simple ANN-based formulation is provided for using our developed ICA-MLP model to estimate DR in the crude oil pipelines.",25,26,5
Neural Network,Artificial Neural-networks,"Miah, Mohammad Islam; Zendehboudi, Sohrab; Ahmed, Salim",Log data-driven model and feature ranking for water saturation prediction using machine learning approach,MLP-ANN; LS-SVM; Model accuracy; Log variables; Feature ranking; Water saturation,ARTIFICIAL NEURAL-NETWORKS; FEATURE-SELECTION; PERMEABILITY PREDICTION; RESERVOIR CHARACTERIZATION; OIL; POROSITY; PETROLEUM; SANDSTONE; IDENTIFICATION; OPTIMIZATION,"Log-based reservoir characterization is one of the widely used techniques to estimate the reservoir properties and make decisions about future plans for hydrocarbon production. Use of the machine learning tools is becoming a more accessible approach for predictive model development in oil and gas engineering. The objective of this research is to identify and rank the most contributing log variables for estimation of water saturation using the machine learning tools. The multilayer perception artificial neural network (MLP-ANN) and kernel function-based least-squares support vector machine (LS-SVM) techniques are employed to develop predictive models for water saturation. The model can capture the non-linear behaviors and high-dimensional complex relationships among field log data variables. Based on the prediction performance of the models, the Levenberg-Marquardt algorithm-based MLP-ANN and the radial kernel function-based LS-SVM model optimized with coupled simulated annealing optimization technique were found to perform better compared to other models. The MLP-ANN and radial kernel function-based LS-SVM approaches lead to the same feature ranking of predictor variables. It was found that the significance order (higher to lower) of influential log variables are the true resistivity, bulk density, neutron porosity, photoelectric factor, gamma-ray, and sonic travel time based on their relative contribution to the water saturation. The strategy introduced in this study assists to forecast water saturation with a relatively few number of log variables, and thus, reduces the number of necessary logs to run during exploration stage, considerably lowering the exploration costs.",17,17,0
Neural Network,Artificial Neural-networks,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Neural Network,Artificial Neural-networks,"Haji-Savameri, Mohammad; Menad, Nait Amar; Norouzi-Apourvari, Saeid; Hemmati-Sarapardeh, Abdolhossein","Modeling dew point pressure of gas condensate reservoirs: Comparison of hybrid soft computing approaches, correlations, and thermodynamic models",Gas condensate reservoir; Pd; EOS; Soft computing; CMIS,NEURAL-NETWORK; GENERALIZED MODELS; WELL PRODUCTIVITY; DEWPOINT PRESSURE; PHASE-BEHAVIOR; CRUDE-OIL; PREDICTION; EQUATIONS; OPTIMIZATION; REGRESSION,"Optimal future management of gas condensate reservoirs requires reliable estimation of the dew point pressure (Pd). Due to the limitations of the available Pd determination methods, such as cost and the prohibitive time for experimental approaches, and inaccuracies and lack of generalization for predictive approaches, it is still necessary to establish more accurate and user friendly Pd paradigms. In this study, various methodologies based on soft computing (SC) techniques, optimization algorithms, and generalized reduced gradient (GRG) method were implemented to develop Pd models based on a widespread databank. Two types of artificial neural networks, namely radial basis function (RBF) neural networks and Multilayer perceptron (MLP) are the employed SC methods. To improve the prediction capability of the latter, Levenberg-Marquardt (LM), Bayesian Regularization (BR), and Scaled Conjugate Gradient (SCG) algorithms were used in the training phase of MLP, while three nature-inspired algorithms, namely Genetic Algorithm (GA), Bat Algorithm (BA), and Salp Swarm Algorithm (SSA) were first considered in the RBF learning phase. Then, the four best-found models were assembled beneath a unified paradigm utilizing a committee machine intelligent system (CMIS). Also, a correlation was developed using GRG. The developed CMIS and GRG correlation were compared with four empirical correlations as well as seven equations of state (EOSs). Based on the results obtained, CMIS model exhibits very satisfactory Pd predictions with an overall average absolute percent relative error (AAPRE) of 5.28%, and outperforms largely the other existing predictive approaches. Furthermore, the developed correlation provided more accurate results compared to existing correlations and EOSs.",14,14,1
Neural Network,Artificial Neural-networks,"Mamudu, Abbas; Khan, Faisal; Zendehboudi, Sohrab; Adedigba, Sunday",Dynamic risk assessment of reservoir production using data-driven probabilistic approach,Artificial neural network; Bayesian network; Oil production forecast; Reservoir simulation; Dynamic risk assessment,WELL LOG DATA; ARTIFICIAL NEURAL-NETWORK; SHEAR-WAVE VELOCITY; DRILLING OPERATIONS; PREDICTION; INTELLIGENCE; SYSTEMS; PERMEABILITY; PETROLEUM; MODELS,"Oil and gas companies use the reservoir simulation approach to history match and forecast reservoir production. While this strategy is easy and often effective, it has inherent setbacks, including a limited ability to capture temporal and spatial variability of the data, uncertainty in the data and reservoir models, and most importantly, impacts of these factors/parameters on the overall production risk profile. This paper presents a hybrid method to forecast the production rate and risks attributed to oilfield development. The hybrid connectionist strategy integrates a data-driven model to capture variability with a probabilistic model to capture uncertainties and associated risks. The multilayer perceptron artificial neural network (ANN) is built on the basis of geological realizations and used as a substitute for the commercial simulator (e.g., CMG) to model reservoir production behaviour for the effective facilitation of the production prediction. The model has a generalization capability and captures the temporal-spatial dependency and non-linear complex relationships. The Bayesian network model is developed to assess the production risks. It employs the concept of the early warning index system. The results show that the predicted oil production profile closely matches the history matched data from the simulator, and the assessed dynamic risks conform with the field reality. The hybrid modeling strategy leads to the minimum and average percentage errors of 0.02% and 5.28% respectively in the reservoir production forecast. The application of the proposed approach would assist in effective reservoir management decision making, enabling a risk-based optimal field performance of reservoir.",13,13,3
Neural Network,Artificial Neural-networks,"Sun, Qian; Ertekin, Turgay",Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies,Artificial neural network; Polymer injection; Optimization; EOR screening; EOR project design,ALGORITHM,"Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.",11,11,2
Neural Network,Artificial Neural-networks,"Osarogiagbon, Augustine Uhunoma; Oloruntobi, Olalere; Khan, Faisal; Venkatesan, Ramachandran; Butt, Stephen",Gamma ray log generation from drilling parameters using deep learning,Deep learning; Logging while drilling; Measurement while drilling; Lithology; Drilling parameters; Gamma ray log; NARX; RNN; TCN; LSTM; GRU; ANN,NEURAL-NETWORKS; PREDICTION,"Lithology identification plays a vital role in defining the petroleum reservoir. Although well logging represents the traditional means of obtaining petrophysical data for lithology identification, there could be cases where logging while drilling instruments may fail during drilling. This paper presents an approach that utilizes drilling parameters obtained from mud logging and measurement while drilling (MWD) for real-time prediction of gamma ray log which is used as a lithology identifier. In this work, several machine learning methodologies, such as simple recurrent neural network (RNN), long short-term memory recurrent neural network (LSTM-RNN), temporal convolution network (TCN), gated recurrent unit (GRU) network, nonlinear autoregressive network with exogenous inputs (NARX) and simple artificial neural network (ANN) were tested for their ability to capture the relationship between hydro-mechanical specific energy (computed from drilling parameters) and gamma ray log. A recently drilled exploration gas well in the tertiary deltaic system of the Niger delta basin was used as the case study. Based on the field data, the results show the TCN and simple RNN performed best. The receptive field of the TCN played a significant role in its performance, and therefore, the LSTM-RNN can be made to perform comparable to that of TCN/simple RNN if the LSTM-RNN is manually made to work with an optimal window of input data points for each output data point. The size and nature of the data (volume, velocity, variety, and veracity) is likely a significant factor in the performance of the machine learning methodologies. Thus, it is recommended to focus on obtaining the best receptive field of the data during the machine learning development phase.",9,9,8
Neural Network,Artificial Neural-networks,"Muojeke, Somadina; Venkatesan, Ramachandran; Khan, Faisal",Supervised data-driven approach to early kick detection during drilling operation,Artificial neural network; Downhole monitoring; Early kick detection; Supervised learning,ARTIFICIAL NEURAL-NETWORKS; DEVELOPING LEADING INDICATORS; PREDICTING RATE; WELL; PENETRATION; MODELS,"The margin between pore pressure and fracture gradient in new offshore discoveries continues to get narrower. This poses greater risks and higher cost of ensuring safety of lives, facilities and the environment. The 2010 Macondo blowout has fueled increased interests in monitoring downhole parameter for early kick detection. Early detection of kick is important part of the process safety. It provides opportunity to activate safety measures. This work investigates the simplest supervised learning-based kick detection system to ensure higher reliability using experimental data. It combines an Artificial Neural Network (ANN), binary classifier and downhole monitoring of drilling flow parameters to build data-driven kick detection models. Data was generated from experiment that monitors downhole parameters when kick occurs. Recorded parameters such as mud flow-out rate, conductivity, density and downhole pressure are combined to build the model capable of detecting kick events. Abnormal pressure and flow regimes in the wellbore provide early warnings and was shown to be more significant parameters than others, however relying on them alone could increase susceptibility to a false alarm. The model has been tested on data from two different laboratory scale drilling simulator.",9,9,0
Neural Network,Log Data,"Miah, Mohammad Islam; Zendehboudi, Sohrab; Ahmed, Salim",Log data-driven model and feature ranking for water saturation prediction using machine learning approach,MLP-ANN; LS-SVM; Model accuracy; Log variables; Feature ranking; Water saturation,ARTIFICIAL NEURAL-NETWORKS; FEATURE-SELECTION; PERMEABILITY PREDICTION; RESERVOIR CHARACTERIZATION; OIL; POROSITY; PETROLEUM; SANDSTONE; IDENTIFICATION; OPTIMIZATION,"Log-based reservoir characterization is one of the widely used techniques to estimate the reservoir properties and make decisions about future plans for hydrocarbon production. Use of the machine learning tools is becoming a more accessible approach for predictive model development in oil and gas engineering. The objective of this research is to identify and rank the most contributing log variables for estimation of water saturation using the machine learning tools. The multilayer perception artificial neural network (MLP-ANN) and kernel function-based least-squares support vector machine (LS-SVM) techniques are employed to develop predictive models for water saturation. The model can capture the non-linear behaviors and high-dimensional complex relationships among field log data variables. Based on the prediction performance of the models, the Levenberg-Marquardt algorithm-based MLP-ANN and the radial kernel function-based LS-SVM model optimized with coupled simulated annealing optimization technique were found to perform better compared to other models. The MLP-ANN and radial kernel function-based LS-SVM approaches lead to the same feature ranking of predictor variables. It was found that the significance order (higher to lower) of influential log variables are the true resistivity, bulk density, neutron porosity, photoelectric factor, gamma-ray, and sonic travel time based on their relative contribution to the water saturation. The strategy introduced in this study assists to forecast water saturation with a relatively few number of log variables, and thus, reduces the number of necessary logs to run during exploration stage, considerably lowering the exploration costs.",17,17,0
Neural Network,Log Data,"Mamudu, Abbas; Khan, Faisal; Zendehboudi, Sohrab; Adedigba, Sunday",Dynamic risk assessment of reservoir production using data-driven probabilistic approach,Artificial neural network; Bayesian network; Oil production forecast; Reservoir simulation; Dynamic risk assessment,WELL LOG DATA; ARTIFICIAL NEURAL-NETWORK; SHEAR-WAVE VELOCITY; DRILLING OPERATIONS; PREDICTION; INTELLIGENCE; SYSTEMS; PERMEABILITY; PETROLEUM; MODELS,"Oil and gas companies use the reservoir simulation approach to history match and forecast reservoir production. While this strategy is easy and often effective, it has inherent setbacks, including a limited ability to capture temporal and spatial variability of the data, uncertainty in the data and reservoir models, and most importantly, impacts of these factors/parameters on the overall production risk profile. This paper presents a hybrid method to forecast the production rate and risks attributed to oilfield development. The hybrid connectionist strategy integrates a data-driven model to capture variability with a probabilistic model to capture uncertainties and associated risks. The multilayer perceptron artificial neural network (ANN) is built on the basis of geological realizations and used as a substitute for the commercial simulator (e.g., CMG) to model reservoir production behaviour for the effective facilitation of the production prediction. The model has a generalization capability and captures the temporal-spatial dependency and non-linear complex relationships. The Bayesian network model is developed to assess the production risks. It employs the concept of the early warning index system. The results show that the predicted oil production profile closely matches the history matched data from the simulator, and the assessed dynamic risks conform with the field reality. The hybrid modeling strategy leads to the minimum and average percentage errors of 0.02% and 5.28% respectively in the reservoir production forecast. The application of the proposed approach would assist in effective reservoir management decision making, enabling a risk-based optimal field performance of reservoir.",13,13,3
Neural Network,Log Data,"Dias, Luciana Olivia; Bom, Clecio R.; Faria, Elisangela L.; Valentin, Manuel Blanco; Correia, Maury Duarte; de Albuquerque, Marcio P.; de Albuquerque, Marcelo P.; Coelho, Juliana M.",Automatic detection of fractures and breakouts patterns in acoustic borehole image logs using fast-region convolutional neural networks,Borehole; Image; Deep learning; Breakouts; Geological fractures; Classification,MECHANICS,"Borehole acoustic image logs present meaningful information about some petrophysical properties of a reservoir. The identification of these features, in addition to several supplementary data are very important to achieve a valid characterization of the reservoir itself. Among the different patterns that image logs could show, it can be mentioned fractures and breakouts occurrences, which are very important for the experts in the field. These occurrences usually appear on borehole acoustic image logs. Its study can provide some insights about petrophysical properties of the reservoir, such as the mechanical stresses borne by the geology of the site, and this, for example, can be linked to the dynamics of the fluids retained inside the reservoir itself (i.e., hydrocarbon, gas or water). Usually, the workflow used to identify these structures requires experts to manually identify them. In this work, we propose a novel methodology for automatic detection in Borehole acoustic image logs of such structures using a single Fast Region-based Convolutional Neural Network (fast-RCNN), which could easily be incorporated into the analysis workflow carried out by petrophysicists, contributing to the characterization process. Due to the high number of samples that this type of neural network require, we trained our algorithm simulating pattern breakouts and fractures and after we test it in real and simulated images. Our model reported the area under the Receiver Operating Characteristic curve (AUC) of 98% and 90% for detecting fractures and breakouts, respectively, in simulated data. The algorithms commonly reported in the literature to identify fractures and breakouts, only achieve around 81% and 73% of AUC, respectively. Finally, for real images, the fast-RCNN detected efficiently the fractures and parts of breakouts. Thus, our data suggest that deep learning can improve significantly the accuracy on automatic detection of geological formations in acoustic borehole image logs. Available repository at Fast-Rcnn-Geo.",13,14,3
Neural Network,Log Data,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Neural Network,Log Data,"Osarogiagbon, Augustine Uhunoma; Oloruntobi, Olalere; Khan, Faisal; Venkatesan, Ramachandran; Butt, Stephen",Gamma ray log generation from drilling parameters using deep learning,Deep learning; Logging while drilling; Measurement while drilling; Lithology; Drilling parameters; Gamma ray log; NARX; RNN; TCN; LSTM; GRU; ANN,NEURAL-NETWORKS; PREDICTION,"Lithology identification plays a vital role in defining the petroleum reservoir. Although well logging represents the traditional means of obtaining petrophysical data for lithology identification, there could be cases where logging while drilling instruments may fail during drilling. This paper presents an approach that utilizes drilling parameters obtained from mud logging and measurement while drilling (MWD) for real-time prediction of gamma ray log which is used as a lithology identifier. In this work, several machine learning methodologies, such as simple recurrent neural network (RNN), long short-term memory recurrent neural network (LSTM-RNN), temporal convolution network (TCN), gated recurrent unit (GRU) network, nonlinear autoregressive network with exogenous inputs (NARX) and simple artificial neural network (ANN) were tested for their ability to capture the relationship between hydro-mechanical specific energy (computed from drilling parameters) and gamma ray log. A recently drilled exploration gas well in the tertiary deltaic system of the Niger delta basin was used as the case study. Based on the field data, the results show the TCN and simple RNN performed best. The receptive field of the TCN played a significant role in its performance, and therefore, the LSTM-RNN can be made to perform comparable to that of TCN/simple RNN if the LSTM-RNN is manually made to work with an optimal window of input data points for each output data point. The size and nature of the data (volume, velocity, variety, and veracity) is likely a significant factor in the performance of the machine learning methodologies. Thus, it is recommended to focus on obtaining the best receptive field of the data during the machine learning development phase.",9,9,8
Neural Network,Log Data,"Wang, Jun; Cao, Junxing; Yuan, Shan",Shear wave velocity prediction based on adaptive particle swarm optimization optimized recurrent neural network,Deep learning; Grey relational analysis; Adaptive particle swarm optimization; Long short term memory networks; Shear wave velocity; Petrophysical logs,WELL LOG DATA; EMPIRICAL RELATIONS; PETROPHYSICAL DATA; RESERVOIR; POROSITY; REGRESSION; MODEL; FIELD; PERMEABILITY; PARAMETERS,"Shear wave velocity (Vs) is an important parameter for reservoir description and fluid identification and is extensively applied in study of oil and gas reservoir geomechanics and rock physics. However, due to high cost of Vs log, actual well log data generally lacks information about Vs, which doesn't meet the requirements of practical work. Therefore, it is very important to estimate the Vs by using conventional logs. In this study, according to the new achievements in deep learning, a novel hybrid Vs prediction model is established based on long short term memory (LSTM) recurrent neutral network optimized by particle swarm optimization (PSO) algorithm with adaptive learning strategy. For this purpose, firstly, the grey relational analysis method was employed to reduce data dimensions, the sensitive logs were chosen among the inputs to predict Vs. Next, LSTM network is applied to model the nonlinear relationship between the selected sensitive logs and Vs, and through finding the key hyper-parameters in LSTM model by the PSO algorithm with adaptive learning strategy, the log data feature matches the network topology structure, and the model's prediction ccuracy of Vs is improved. Finally, the superiority is verified through real petrophysical log data, and compared with other prediction methods. By this method, Vs can be predicted from series of input log data with consideration of variation trend and context information with depth. It is more suitable for the problem with multiple series data such as Vs prediction. Results of processing real petrophysical log data indicate that compare with conventional methods, the PSO algorithm with adaptive learning strategy based LSTM network model may not only provide higher predictive accuracy and robustness, but also has a promising application prospect in Vs prediction study.",9,9,6
Neural Network,Log Data,"He, Mei; Gu, Hanming; Wan, Huan",Log interpretation for lithology and fluid identification using deep neural network combined with MAHAKIL in a tight sandstone reservoir,Lithology and fluid identification; Deep neural network; Log interpretation; Class imbalance; Tight sandstone gas reservoir,SEISMIC FACIES ANALYSIS; MACHINE; MODEL; PERMEABILITY; LITHOFACIES; SMOTE,"As an important source of unconventional natural gas, tight sandstone reservoirs have attracted considerable attention. The accurate identification of lithological and fluid-bearing zones is a limiting factor for exploring such reservoirs effectively. Log data, which provide abundant and high precision geological information, are always used for this task. Here, we combined a deep neural network with an oversampling approach named MAHAKIL for lithology and fluid identification using log data from a tight sandstone gas reservoir. MAHAKIL was adopted to solve the class imbalance problem resulting from imbalanced training samples, and the outputs were then fed into a deep neural network to learn the complex and abstract geological patterns related to the lithology and fluid in a layer-by-layer manner. We first demonstrated the unsatisfactory performance of a typical classification algorithm on a simulated data which conforms to the normal distribution and is imbalanced. Then, the performance of our method was compared with that of a support vector machine and a deep neural network on the imbalanced actual data, and the F-beta score which is the weighted harmonic mean of precision and recall was used as the evaluation criterion. The results show that the F-beta score of our method was generally higher than that of the other two methods, which indicates the superiority of the proposed method for lithology and fluid identification of tight sandstone gas reservoirs when the learning samples are imbalanced.",8,9,12
Neural Network,Production Forecasts,"Song, Xuanyi; Liu, Yuetian; Xue, Liang; Wang, Jun; Zhang, Jingzhe; Wang, Junqiang; Jiang, Long; Cheng, Ziyan",Time-series well performance prediction based on Long Short-Term Memory (LSTM) neural network model,Deep learning; LSTM; Time sequence data; PSO; Production forecasting,PARTICLE SWARM OPTIMIZATION; ALGORITHM; DESIGN; WIND,"Oil production forecasting is one of the most critical issues during the exploitation phase of the oilfield. The limitations of traditional approaches make time-series production prediction still challenging. With the development of artificial intelligence, high-performance algorithms make reliable production prediction possible from the data perspective. This study proposes a Long Short-Term Memory (LSTM) neural network based model to infer the production of fractured horizontal wells in a volcanic reservoir, which addresses the limitations of traditional method and shows accurate predictions. The LSTM neural network enables to capture the dependencies of the oil rate time sequence data and incorporate the production constraints. Particle Swarm Optimization algorithm (PSO) is employed to optimize the essential configuration of the LSTM model. For evaluation purpose, two case studies are carried out with the production dynamics from synthetic model and from the Xinjiang oilfield, China. Towards a fair evaluation, the performance of the proposed approach is compared with traditional neural networks, time-series forecasting approaches, and conventional decline curves. The experiment results show that the proposed LSTM model outperforms other approaches.",70,73,35
Neural Network,Production Forecasts,"Liu, Wei; Liu, Wei David; Gu, Jianwei",Forecasting oil production using ensemble empirical model decomposition based Long Short-Term Memory neural network,Time series forecasting; Deep learning; Ensemble empirical mode decomposition; Long short-term memory; Oil production forecasting,SUPPORT VECTOR REGRESSION; PRICE; PREDICTION,"Oil production forecasting is an important means of understanding and effectively developing reservoirs. Reservoir numerical simulation is the most mature and effective method for production forecasting, but its accuracy mostly depends on high-quality history matching and accurate geological models. In order to achieve fast and accurate production predicting, an ensemble empirical mode decomposition (EEMD) based Long Short-Term Memory (LSTM) learning paradigm is proposed for oil production forecasting. In this paper, the original oil production series are first split into training set and test set. The data of test set is gradually added to the training set and decomposed by EEMD to obtain multiple intrinsic mode functions (IMFs). The stability of IMFs is analyzed by its Means and curve similarity computed by Dynamic time warping (DTW). Then proper number of stable IMFs are selected as predictor variables for machine learning. Considering the variation trend and context information of production series, LSTM is utilized to establish predictive model for production forecasting. The optimal hyper-parameters of LSTM are determined by Genetic algorithm (GA). For evaluation and verification purpose, the proposed model is applied to two actual oilfields from China. Empirical results demonstrated that the proposed approach is capable of giving almost perfect production forecasting.",30,30,7
Neural Network,Production Forecasts,"Miah, Mohammad Islam; Zendehboudi, Sohrab; Ahmed, Salim",Log data-driven model and feature ranking for water saturation prediction using machine learning approach,MLP-ANN; LS-SVM; Model accuracy; Log variables; Feature ranking; Water saturation,ARTIFICIAL NEURAL-NETWORKS; FEATURE-SELECTION; PERMEABILITY PREDICTION; RESERVOIR CHARACTERIZATION; OIL; POROSITY; PETROLEUM; SANDSTONE; IDENTIFICATION; OPTIMIZATION,"Log-based reservoir characterization is one of the widely used techniques to estimate the reservoir properties and make decisions about future plans for hydrocarbon production. Use of the machine learning tools is becoming a more accessible approach for predictive model development in oil and gas engineering. The objective of this research is to identify and rank the most contributing log variables for estimation of water saturation using the machine learning tools. The multilayer perception artificial neural network (MLP-ANN) and kernel function-based least-squares support vector machine (LS-SVM) techniques are employed to develop predictive models for water saturation. The model can capture the non-linear behaviors and high-dimensional complex relationships among field log data variables. Based on the prediction performance of the models, the Levenberg-Marquardt algorithm-based MLP-ANN and the radial kernel function-based LS-SVM model optimized with coupled simulated annealing optimization technique were found to perform better compared to other models. The MLP-ANN and radial kernel function-based LS-SVM approaches lead to the same feature ranking of predictor variables. It was found that the significance order (higher to lower) of influential log variables are the true resistivity, bulk density, neutron porosity, photoelectric factor, gamma-ray, and sonic travel time based on their relative contribution to the water saturation. The strategy introduced in this study assists to forecast water saturation with a relatively few number of log variables, and thus, reduces the number of necessary logs to run during exploration stage, considerably lowering the exploration costs.",17,17,0
Neural Network,Production Forecasts,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Neural Network,Production Forecasts,"Zhong, Zhi; Sun, Alexander Y.; Wang, Yanyong; Ren, Bo",Predicting field production rates for waterflooding using a machine learning-based proxy model,Machine learning; Conditional deep convolutional generative adversarial neural network; Data-driven proxy model; Waterflooding; Field production rate,RESPONSE-SURFACE METHODOLOGY; ALTERNATING-GAS-INJECTION; RELATIVE PERMEABILITY; OIL-FIELD; WORK FLOW; OPTIMIZATION; PRESSURE; DESIGN,"Waterflooding, during which water is injected in the reservoir to increase pressure and therefore boost oil production, is extensively used as a secondary oil recovery technology. Tracking the extent and efficacy of waterflooding (i.e., fluid distributions) is a primary task of reservoir engineers and is traditionally achieved by running full reservoir models. In this work, we design and implement a proxy model using a conditional deep convolutional generative neural network (cDC-GAN), which can be used to quickly calculate the dynamic fluid distribution of a heterogeneous reservoir under waterflooding. Zero-sum game theory is the basis for the cDC-GAN, which includes a pair of generative discriminative models. The generative model tries to learn the relationship between input and output and makes the generated output as close as possible to the training data, while the discriminative model tries to distinguish the fake output and the real data used for training, such that the cDC-GAN learns the real data distribution at the end. In our cDC-GAN formulation, the reservoir properties (permeability distribution in this research) and forecast time information are treated as input, and water saturation is the desired output. The reservoir fluid production rate can be calculated based on the material balance principle. The most significant contribution of this work resides in training a cDC-GAN proxy model to accurately predict fluid saturation. A cDC-GAN has several advantages over the traditional full-model based workflow. First, the model parameters estimated from history matching help to improve reservoir characterization. Second, this proposed proxy model can predict the water and oil saturation distributions simultaneously, which can be used to calculate the water and oil flow rates. Third, this proposed proxy model can be used for waterflooding optimization and uncertainty analysis with far less computational effort than with the traditional method, which uses a reservoir simulator.",13,13,9
Neural Network,Production Forecasts,"Mamudu, Abbas; Khan, Faisal; Zendehboudi, Sohrab; Adedigba, Sunday",Dynamic risk assessment of reservoir production using data-driven probabilistic approach,Artificial neural network; Bayesian network; Oil production forecast; Reservoir simulation; Dynamic risk assessment,WELL LOG DATA; ARTIFICIAL NEURAL-NETWORK; SHEAR-WAVE VELOCITY; DRILLING OPERATIONS; PREDICTION; INTELLIGENCE; SYSTEMS; PERMEABILITY; PETROLEUM; MODELS,"Oil and gas companies use the reservoir simulation approach to history match and forecast reservoir production. While this strategy is easy and often effective, it has inherent setbacks, including a limited ability to capture temporal and spatial variability of the data, uncertainty in the data and reservoir models, and most importantly, impacts of these factors/parameters on the overall production risk profile. This paper presents a hybrid method to forecast the production rate and risks attributed to oilfield development. The hybrid connectionist strategy integrates a data-driven model to capture variability with a probabilistic model to capture uncertainties and associated risks. The multilayer perceptron artificial neural network (ANN) is built on the basis of geological realizations and used as a substitute for the commercial simulator (e.g., CMG) to model reservoir production behaviour for the effective facilitation of the production prediction. The model has a generalization capability and captures the temporal-spatial dependency and non-linear complex relationships. The Bayesian network model is developed to assess the production risks. It employs the concept of the early warning index system. The results show that the predicted oil production profile closely matches the history matched data from the simulator, and the assessed dynamic risks conform with the field reality. The hybrid modeling strategy leads to the minimum and average percentage errors of 0.02% and 5.28% respectively in the reservoir production forecast. The application of the proposed approach would assist in effective reservoir management decision making, enabling a risk-based optimal field performance of reservoir.",13,13,3
Neural Network,Production Forecasts,"Sun, Qian; Ertekin, Turgay",Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies,Artificial neural network; Polymer injection; Optimization; EOR screening; EOR project design,ALGORITHM,"Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.",11,11,2
Neural Network,Convolutional Neural Network,"Alqahtani, Naif; Alzubaidi, Fatimah; Armstrong, Ryan T.; Swietojanski, Pawel; Mostaghimi, Peyman",Machine learning for predicting properties of porous media from 2d X-ray images,Machine learning; Convolutional neural network; Digital rock; Rock properties,PORE-SCALE SIMULATION; DIGITAL ROCK; REACTIVE TRANSPORT; NUMERICAL-SIMULATION; MICRO-TOMOGRAPHY; PART I; PERMEABILITY; DISSOLUTION; FLOW; MICROTOMOGRAPHY,"In this paper, Convolutional Neural Networks (CNNs) are trained to rapidly estimate several physical properties of porous media using micro-computed tomography (micro-CT) X-ray images as input data. The tomograms of three different sandstone types are subdivided to create a dataset consisting of 5,262 training images and 2,000 testing images. Porosity, specific surface area, and average pore size of each image are computed. The proposed CNN framework is trained with binary images and greyscale images separately and the corresponding computed properties. The results from testing the model are promising as the relative error in determination of porosity, surface area and average pore size is less than 6% when the model is trained with binary images and less than 7% when greyscale images are used. Other aspects related to model training and optimisation are discussed.",34,34,4
Neural Network,Convolutional Neural Network,"Zhong, Zhi; Sun, Alexander Y.; Wang, Yanyong; Ren, Bo",Predicting field production rates for waterflooding using a machine learning-based proxy model,Machine learning; Conditional deep convolutional generative adversarial neural network; Data-driven proxy model; Waterflooding; Field production rate,RESPONSE-SURFACE METHODOLOGY; ALTERNATING-GAS-INJECTION; RELATIVE PERMEABILITY; OIL-FIELD; WORK FLOW; OPTIMIZATION; PRESSURE; DESIGN,"Waterflooding, during which water is injected in the reservoir to increase pressure and therefore boost oil production, is extensively used as a secondary oil recovery technology. Tracking the extent and efficacy of waterflooding (i.e., fluid distributions) is a primary task of reservoir engineers and is traditionally achieved by running full reservoir models. In this work, we design and implement a proxy model using a conditional deep convolutional generative neural network (cDC-GAN), which can be used to quickly calculate the dynamic fluid distribution of a heterogeneous reservoir under waterflooding. Zero-sum game theory is the basis for the cDC-GAN, which includes a pair of generative discriminative models. The generative model tries to learn the relationship between input and output and makes the generated output as close as possible to the training data, while the discriminative model tries to distinguish the fake output and the real data used for training, such that the cDC-GAN learns the real data distribution at the end. In our cDC-GAN formulation, the reservoir properties (permeability distribution in this research) and forecast time information are treated as input, and water saturation is the desired output. The reservoir fluid production rate can be calculated based on the material balance principle. The most significant contribution of this work resides in training a cDC-GAN proxy model to accurately predict fluid saturation. A cDC-GAN has several advantages over the traditional full-model based workflow. First, the model parameters estimated from history matching help to improve reservoir characterization. Second, this proposed proxy model can predict the water and oil saturation distributions simultaneously, which can be used to calculate the water and oil flow rates. Third, this proposed proxy model can be used for waterflooding optimization and uncertainty analysis with far less computational effort than with the traditional method, which uses a reservoir simulator.",13,13,9
Neural Network,Convolutional Neural Network,"Dias, Luciana Olivia; Bom, Clecio R.; Faria, Elisangela L.; Valentin, Manuel Blanco; Correia, Maury Duarte; de Albuquerque, Marcio P.; de Albuquerque, Marcelo P.; Coelho, Juliana M.",Automatic detection of fractures and breakouts patterns in acoustic borehole image logs using fast-region convolutional neural networks,Borehole; Image; Deep learning; Breakouts; Geological fractures; Classification,MECHANICS,"Borehole acoustic image logs present meaningful information about some petrophysical properties of a reservoir. The identification of these features, in addition to several supplementary data are very important to achieve a valid characterization of the reservoir itself. Among the different patterns that image logs could show, it can be mentioned fractures and breakouts occurrences, which are very important for the experts in the field. These occurrences usually appear on borehole acoustic image logs. Its study can provide some insights about petrophysical properties of the reservoir, such as the mechanical stresses borne by the geology of the site, and this, for example, can be linked to the dynamics of the fluids retained inside the reservoir itself (i.e., hydrocarbon, gas or water). Usually, the workflow used to identify these structures requires experts to manually identify them. In this work, we propose a novel methodology for automatic detection in Borehole acoustic image logs of such structures using a single Fast Region-based Convolutional Neural Network (fast-RCNN), which could easily be incorporated into the analysis workflow carried out by petrophysicists, contributing to the characterization process. Due to the high number of samples that this type of neural network require, we trained our algorithm simulating pattern breakouts and fractures and after we test it in real and simulated images. Our model reported the area under the Receiver Operating Characteristic curve (AUC) of 98% and 90% for detecting fractures and breakouts, respectively, in simulated data. The algorithms commonly reported in the literature to identify fractures and breakouts, only achieve around 81% and 73% of AUC, respectively. Finally, for real images, the fast-RCNN detected efficiently the fractures and parts of breakouts. Thus, our data suggest that deep learning can improve significantly the accuracy on automatic detection of geological formations in acoustic borehole image logs. Available repository at Fast-Rcnn-Geo.",13,14,3
Neural Network,Convolutional Neural Network,"Chu, Min-gon; Min, Baehyun; Kwon, Seoyoon; Park, Gayoung; Kim, Sungil; Nguyen Xuan Huy",Determination of an infill well placement using a data-driven multi-modal convolutional neural network,Infill well; Convolutional neural network; Multi-modal learning; Productivity,OPTIMIZATION,"This study determines the optimal placement for a vertical infill well using a multi-modal convolutional neural network (CNN). 3D arrays composed of static and dynamic reservoir properties near a candidate infill well are inputted to the convolution stage of CNN. Multi-modal learning is applied to CNN for feature extraction of inputs. The features are compressed via fully connected layers for evaluating the productivity of every candidate infill scenario. The proposed CNN is applied to a channelized oil reservoir, and its performance is compared to that of a feedforward neural network. Dataset for the neural networks is obtained by running full-physics simulations for selected scenarios. CNN outperforms the feedforward neural network for the test scenarios of single- and dualmodal cases. Both neural networks yield comparable predictability for a quad-modal case. Results of the quad-modal CNN are in agreement with reservoir simulation results at cheaper computational costs. The results highlight the potential of data-driven machine learning in expediting the optimal well placement by partially replacing expensive simulation runs.",12,12,1
Neural Network,Convolutional Neural Network,"Yang, Liuxin; Sun, Sam Zandong",Seismic horizon tracking using a deep convolutional neural network,Horizon tracking; Convolutional neural network; Deep learning; Image classification; Seismic interpretation,PICKING,"Seismic horizons are essential for structural analysis, inversion, time-to-depth conversion, and seismic attribution analysis. However, seismic horizons are obtained commonly by manual tracking or a combination of manual tracking and traditional auto-tracking techniques, which is a time consuming and error-prone process. Although many conventional auto-tracking techniques have been proposed to improve the efficiency of horizon tracking, there are still many challenges to track seismic horizons with complex seismic reflection signatures. A deep convolutional neural network (CNN) method, a typical kind of deep neural networks in the field of deep learning, was proposed in this paper to solve the problems. Seismic horizon tracking is formulated as an image classification task. CNN can take full advantage of the high flexibility in network architecture and hierarchical feature extraction ability to track horizons from seismic volumes in which discontinuities, lateral variations and faults are apparent. We designed a CNN structure for horizon tracking and trained CNN models by using only 1% and 1.5% of the seismic volume to perform a single horizon and multiple horizon tracking. The root mean square error (RMSE) and the coefficient of determination (R-2) between the horizon tracked by CNN model and the manual-tracking are 1.78 and 0.998 in single horizon tracking, respectively. The average RMSE and R-2 are 2.68 and 0.992 in multiple horizon tracking, respectively. The research we have done suggests that the proposed method can track seismic horizons from 3-D seismic volumes much more accurately and efficiently than conventional methods.",9,9,1
Neural Network,Convolutional Neural Network,"Liu, Xuliang; Li, Daolun; Yang, Jinghai; Zha, Wenshu; Zhou, Ziqi; Gao, Liping; Han, Jiahang",Automatic well test interpretation based on convolutional neural network for infinite reservoir,Well testing; Convolutional neural network; Automatic interpretation; Infinite reservoir,ANN,"The well testing technique is an important tool in estimating well and reservoir characteristics, such as permeability, skin factor and so on. For a long time, researchers have been searching for automatic well testing interpretation tools, but the results are disappointing. This paper proposes using convolutional neural network (CNN) as an automatic well test interpretation approach for infinite acting reservoirs. The CNN takes pressure change and pressure derivative data of the log-log plot for inputs. The wellbore storage coefficient, skin factor and reservoir permeability are redefined into a dimensionless group C(D)e(2S) as the output of the CNN. In this method, the best trained CNN structure is obtained by minimizing mean square error (MSE) and mean relative error (MRE). This new method is tested for its effectiveness and accuracy in Daqing oil field, China. It demonstrates that, for wells in infinite reservoir, CNN could be an effective automatic well test interpretation technique. CNN also shows the potential for more complicated scenarios.",8,8,1
Neural Network,Reliability,"Song, Xuanyi; Liu, Yuetian; Xue, Liang; Wang, Jun; Zhang, Jingzhe; Wang, Junqiang; Jiang, Long; Cheng, Ziyan",Time-series well performance prediction based on Long Short-Term Memory (LSTM) neural network model,Deep learning; LSTM; Time sequence data; PSO; Production forecasting,PARTICLE SWARM OPTIMIZATION; ALGORITHM; DESIGN; WIND,"Oil production forecasting is one of the most critical issues during the exploitation phase of the oilfield. The limitations of traditional approaches make time-series production prediction still challenging. With the development of artificial intelligence, high-performance algorithms make reliable production prediction possible from the data perspective. This study proposes a Long Short-Term Memory (LSTM) neural network based model to infer the production of fractured horizontal wells in a volcanic reservoir, which addresses the limitations of traditional method and shows accurate predictions. The LSTM neural network enables to capture the dependencies of the oil rate time sequence data and incorporate the production constraints. Particle Swarm Optimization algorithm (PSO) is employed to optimize the essential configuration of the LSTM model. For evaluation purpose, two case studies are carried out with the production dynamics from synthetic model and from the Xinjiang oilfield, China. Towards a fair evaluation, the performance of the proposed approach is compared with traditional neural networks, time-series forecasting approaches, and conventional decline curves. The experiment results show that the proposed LSTM model outperforms other approaches.",70,73,35
Neural Network,Reliability,"Shams, Reza; Masihi, Mohsen; Boozarjomehry, Ramin Bozorgmehry; Blunt, Martin J.",Coupled generative adversarial and auto-encoder neural networks to reconstruct three-dimensional multi-scale porous media,Porous media reconstruction; Generative adversarial network; Auto-encoder neural network; Machine learning; Multi-scale reconstruction,PORE-SPACE RECONSTRUCTION; STOCHASTIC RECONSTRUCTION; SIMULATION; TRANSPORT; MODEL; IMAGE,"In this study, coupled Generative Adversarial and Auto-Encoder neural networks have been used to reconstruct realizations of three-dimensional porous media. The gradient-descent-based optimization method is used for training and stabilizing the neural networks. The multi-scale reconstruction has been conducted for both sandstone and carbonate samples from an Iranian oilfield. The sandstone contains inter and intra-grain porosity. The generative adversarial network predicts the inter-grain pores and the auto-encoder provides the generative adversarial network result with intra-grain pores (micro-porosity). Different matching criteria, including porosity, permeability, auto-correlation function, and visual interpretation have been used to investigate the performance of the models. This methodology provides researchers with a reliable method to reconstruct multi-scale realizations of porous media.",29,29,5
Neural Network,Reliability,"Jin, Zhaoyang Larry; Liu, Yimin; Durlofsky, Louis J.",Deep-learning-based surrogate model for reservoir simulation with time-varying well controls,Reservoir simulation; Reduced-order model; Deep learning; Physics-informed neural network; Auto-encoder; Embed-to-control; E2C,ENCODER-DECODER NETWORKS; REDUCED-ORDER MODELS; SUBSURFACE FLOW; UNCERTAINTY QUANTIFICATION; FLUID-DYNAMICS; REDUCTION; IMPLEMENTATION; PROJECTION; FRAMEWORK,"A new deep-learning-based reduced-order modeling (ROM) framework is proposed for application in subsurface flow simulation. The reduced-order model is based on an existing embed-to-control (E2C) framework and includes an auto-encoder, which projects the system to a low-dimensional subspace, and a linear transition model, which approximates the evolution of the system states in low dimension. In addition to the loss function for data mismatch considered in the original E2C framework, we introduce a physics-based loss function that penalizes predictions that are inconsistent with the governing flow equations. The loss function is also modified to emphasize accuracy in key well quantities of interest (e.g., fluid production rates). The E2C ROM is shown to be analogous to an existing ROM, POD-TPWL, which has been extensively developed for subsurface flow simulation. The new ROM is applied to oil-water flow in a heterogeneous reservoir, with flow driven by nine wells operating under time-varying control specifications. A total of 300 high-fidelity training simulations are performed in the offline stage, and the network training requires 10-12 minutes on a Tesla V100 GPU node. Online (runtime) computations achieve speedups of over a factor of 1000 relative to full-order simulations. Extensive test case results, with well controls varied over large ranges, are presented. Accurate ROM predictions are achieved for global saturation and pressure fields at particular times, and for injection and production well responses as a function of time. Error is shown to increase when 100 or 200 (rather than 300) training runs are used to construct the E2C ROM. Overall the E2C ROM is shown to provide reliable predictions with levels of perturbations in the well controls that are much larger than those used with existing POD-TPWL treatments. The current model is however limited to 2D systems, and the required number of training simulations is much larger than that for POD-based ROMs.",22,22,6
Neural Network,Reliability,"Haji-Savameri, Mohammad; Menad, Nait Amar; Norouzi-Apourvari, Saeid; Hemmati-Sarapardeh, Abdolhossein","Modeling dew point pressure of gas condensate reservoirs: Comparison of hybrid soft computing approaches, correlations, and thermodynamic models",Gas condensate reservoir; Pd; EOS; Soft computing; CMIS,NEURAL-NETWORK; GENERALIZED MODELS; WELL PRODUCTIVITY; DEWPOINT PRESSURE; PHASE-BEHAVIOR; CRUDE-OIL; PREDICTION; EQUATIONS; OPTIMIZATION; REGRESSION,"Optimal future management of gas condensate reservoirs requires reliable estimation of the dew point pressure (Pd). Due to the limitations of the available Pd determination methods, such as cost and the prohibitive time for experimental approaches, and inaccuracies and lack of generalization for predictive approaches, it is still necessary to establish more accurate and user friendly Pd paradigms. In this study, various methodologies based on soft computing (SC) techniques, optimization algorithms, and generalized reduced gradient (GRG) method were implemented to develop Pd models based on a widespread databank. Two types of artificial neural networks, namely radial basis function (RBF) neural networks and Multilayer perceptron (MLP) are the employed SC methods. To improve the prediction capability of the latter, Levenberg-Marquardt (LM), Bayesian Regularization (BR), and Scaled Conjugate Gradient (SCG) algorithms were used in the training phase of MLP, while three nature-inspired algorithms, namely Genetic Algorithm (GA), Bat Algorithm (BA), and Salp Swarm Algorithm (SSA) were first considered in the RBF learning phase. Then, the four best-found models were assembled beneath a unified paradigm utilizing a committee machine intelligent system (CMIS). Also, a correlation was developed using GRG. The developed CMIS and GRG correlation were compared with four empirical correlations as well as seven equations of state (EOSs). Based on the results obtained, CMIS model exhibits very satisfactory Pd predictions with an overall average absolute percent relative error (AAPRE) of 5.28%, and outperforms largely the other existing predictive approaches. Furthermore, the developed correlation provided more accurate results compared to existing correlations and EOSs.",14,14,1
Neural Network,Reliability,"Zhang, Tao; Li, Yiteng; Sun, Shuyu; Bai, Hua",Accelerating flash calculations in unconventional reservoirs considering capillary pressure using an optimized deep learning algorithm,Phase equilibrium; NVT Flash calculation; Capillary pressure; Deep learning algorithm,MULTICOMPONENT MIXTURES; STABILITY ANALYSIS; PHASE-BEHAVIOR; EQUILIBRIUM CALCULATIONS; CUBIC EQUATIONS; 2-PHASE FLOWS; TEMPERATURE; VOLUME; MINIMIZATION; TRANSPORT,"An increasing focus was placed in the past few decades on accelerating flash calculations and a variety of acceleration strategies have been developed to improve its efficiency without serious compromise in accuracy and reliability. Recently, as machine learning becomes a powerful tool to handle complicated and time-consuming problems, it is increasingly appealing to replace the iterative flash algorithm, due to the strong nonlinearity of flash problem, by a neural network model. In this study, an NVT flash calculation scheme is established with a thermodynamically stable evolution algorithm to generate training and testing data for the proposed deep neural network. With a modified network structure, the deep learning algorithm is optimized by carefully tuning neural network hyperparameters. Numerical tests indicate that the trained model is capable of accurately estimating phase compositions and states for complex reservoir fluids under a wide range of environmental conditions, while the effect of capillary pressure can be captured well. Thermodynamic rules are preserved well through our algorithm, and the trained model can be used for various fluid mixtures, which significantly accelerates flash calculations in unconventional reservoirs.",13,14,1
Neural Network,Reliability,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Neural Network,Reliability,"Kim, Jaejun; Kim, Sungil; Park, Changhyup; Lee, Kyungbook",Construction of prior models for ES-MDA by a deep neural network with a stacked autoencoder for predicting reservoir production,Deep neural network (DNN); Stacked autoencoder (SAE); Ensemble smoother with multiple data; assimilation (ES-MDA); History matching; Egg model,ITERATIVE ENSEMBLE SMOOTHER; CHANNELIZED RESERVOIRS; UNCERTAINTY QUANTIFICATION; WELL PLACEMENT; KALMAN FILTER; ALGORITHM,"The design of prior models has continued to receive research attention because of their importance for ensemble-based methods. There are two approaches to ensemble design: selection and regeneration. Both strategies try to utilize dynamic data in a qualified prior model. The regeneration approach has a higher degree of freedom than the selection approach because the latter is selected among given initial models. However, previous regeneration methods are still sensitive to prior models because these methods create new models based on the priors' statistics. In this study, a deep neural network (DNN) was implemented to build new prior models. If there is a data pair for a reservoir model and its production, the production data and model parameters become the input and output data, respectively, for training the DNN. The trained DNN can generate new prior models according to the observed production history. For the output layer of the DNN, the main information of the permeability field is extracted by a stacked autoencoder (SAE) to improve the DNN performance. New prior models from DNN with SAE become the qualified prior set for ensemble-based methods because they already reflect observed dynamic data. For validation, an ensemble smoother with multiple data assimilation (ES-MDA) was applied to an Egg model. The proposed method (i.e., prior models designed with DNN-SAE) gave reliable posterior permeability fields and future reservoir performances. Compared with the two control groups (i.e., prior models and prior models with DNN), the proposed method mitigated the overshooting problem and found channel connectivity in the reference field. In a comparison with reliable posterior models, the simulation results of the proposed method not only matched observed production data but also reliably predicted future production. This study is an example of the successful application of a machine learning algorithm to history matching.",9,9,0
Neural Network,Reliability,"Muojeke, Somadina; Venkatesan, Ramachandran; Khan, Faisal",Supervised data-driven approach to early kick detection during drilling operation,Artificial neural network; Downhole monitoring; Early kick detection; Supervised learning,ARTIFICIAL NEURAL-NETWORKS; DEVELOPING LEADING INDICATORS; PREDICTING RATE; WELL; PENETRATION; MODELS,"The margin between pore pressure and fracture gradient in new offshore discoveries continues to get narrower. This poses greater risks and higher cost of ensuring safety of lives, facilities and the environment. The 2010 Macondo blowout has fueled increased interests in monitoring downhole parameter for early kick detection. Early detection of kick is important part of the process safety. It provides opportunity to activate safety measures. This work investigates the simplest supervised learning-based kick detection system to ensure higher reliability using experimental data. It combines an Artificial Neural Network (ANN), binary classifier and downhole monitoring of drilling flow parameters to build data-driven kick detection models. Data was generated from experiment that monitors downhole parameters when kick occurs. Recorded parameters such as mud flow-out rate, conductivity, density and downhole pressure are combined to build the model capable of detecting kick events. Abnormal pressure and flow regimes in the wellbore provide early warnings and was shown to be more significant parameters than others, however relying on them alone could increase susceptibility to a false alarm. The model has been tested on data from two different laboratory scale drilling simulator.",9,9,0
Neural Network,Point Pressure,"Haji-Savameri, Mohammad; Menad, Nait Amar; Norouzi-Apourvari, Saeid; Hemmati-Sarapardeh, Abdolhossein","Modeling dew point pressure of gas condensate reservoirs: Comparison of hybrid soft computing approaches, correlations, and thermodynamic models",Gas condensate reservoir; Pd; EOS; Soft computing; CMIS,NEURAL-NETWORK; GENERALIZED MODELS; WELL PRODUCTIVITY; DEWPOINT PRESSURE; PHASE-BEHAVIOR; CRUDE-OIL; PREDICTION; EQUATIONS; OPTIMIZATION; REGRESSION,"Optimal future management of gas condensate reservoirs requires reliable estimation of the dew point pressure (Pd). Due to the limitations of the available Pd determination methods, such as cost and the prohibitive time for experimental approaches, and inaccuracies and lack of generalization for predictive approaches, it is still necessary to establish more accurate and user friendly Pd paradigms. In this study, various methodologies based on soft computing (SC) techniques, optimization algorithms, and generalized reduced gradient (GRG) method were implemented to develop Pd models based on a widespread databank. Two types of artificial neural networks, namely radial basis function (RBF) neural networks and Multilayer perceptron (MLP) are the employed SC methods. To improve the prediction capability of the latter, Levenberg-Marquardt (LM), Bayesian Regularization (BR), and Scaled Conjugate Gradient (SCG) algorithms were used in the training phase of MLP, while three nature-inspired algorithms, namely Genetic Algorithm (GA), Bat Algorithm (BA), and Salp Swarm Algorithm (SSA) were first considered in the RBF learning phase. Then, the four best-found models were assembled beneath a unified paradigm utilizing a committee machine intelligent system (CMIS). Also, a correlation was developed using GRG. The developed CMIS and GRG correlation were compared with four empirical correlations as well as seven equations of state (EOSs). Based on the results obtained, CMIS model exhibits very satisfactory Pd predictions with an overall average absolute percent relative error (AAPRE) of 5.28%, and outperforms largely the other existing predictive approaches. Furthermore, the developed correlation provided more accurate results compared to existing correlations and EOSs.",14,14,1
Neural Network,Point Pressure,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Neural Network,Point Pressure,"Yang, Xi; Dindoruk, Birol; Lu, Ligang",A comparative analysis of bubble point pressure prediction using advanced machine learning algorithms and classical correlations,"Bubble point pressure; PVT; Fluid properties; Machine learning methods (XGBoost, LightGBM, random forest regressor, MLP neural network, and super learner); Correlations",PVT PROPERTIES; SUPER LEARNER; MODEL,"The need for fluid properties or PVT (Pressure-Volume-Temperature) properties, is part of the entire Exploration and Production (E&P) lifecycle from exploration to mature asset management to the typical later life events such as, Improved Oil Recovery (IOR). As the projects mature, the need for such data and its integration for various discipline-specific workflows and its interpretation in the light of reservoir performance varies. Among all the key PVT properties, bubble point pressure is probably the most important parameter. Bubble point pressure is important because it is the point at which constant composition and variable composition portions of the depletion paths merge. Geometrically, bubble point pressure appears to be a discontinuity. In addition, it dictates the existence (or not) of the incipient phase (i.e., gas phase) leading to the changes in the flow characteristics both in porous media and as well as within the wellbore and the facilities. Furthermore, it is also a good indicative of a possible gas cap when the reservoir is at saturation (reservoir pressure is equal to the bubble point pressure) or near-saturated. Among the highlighted uses, there are many more used such as the determination of the elements of miscibility, gas lift design, etc. Therefore, it is very important to estimate the bubble point pressure accurately. In this study, tree-based advanced machine learning algorithm including XGBoost, LightGBM, and random forest regressor, and multi-layer perceptron (neural network) regressor are implemented to predict bubble point pressure (P-bp). A novel super learner model which is also known as stacking ensemble is used to enhance base machine learning model performance on predicting bubble point pressure. Three datasets with different predictors are prepared to study machine learning algorithms' performance for three situations: only compositional data are available; only bulk properties (Gas-Oil-Ratio, gas gravity, API gravity and reservoir Temperature) are available; both compositional data and bulk properties are available. Through literature review, there is no research on using only compositional data and temperature to predict bubble point pressure. Our super learner model offers an accurate solution for oil bubble point pressure when only compositional data and temperature are available. Machine learning models perform better than empirical correlations with limited input data (i.e., bulk properties). When compositional data and bulk properties are all used as predictors, super learner reaches about 5.146% mean absolute relative error on predicting the bubble point pressure from global samples with bubble point pressures in the range of 100 to 10,000 psi, which is a wider range compared to most ANN models published in literature.",9,9,1
Neural Network,Reservoir Volume,"Zhang, Tao; Li, Yiteng; Sun, Shuyu; Bai, Hua",Accelerating flash calculations in unconventional reservoirs considering capillary pressure using an optimized deep learning algorithm,Phase equilibrium; NVT Flash calculation; Capillary pressure; Deep learning algorithm,MULTICOMPONENT MIXTURES; STABILITY ANALYSIS; PHASE-BEHAVIOR; EQUILIBRIUM CALCULATIONS; CUBIC EQUATIONS; 2-PHASE FLOWS; TEMPERATURE; VOLUME; MINIMIZATION; TRANSPORT,"An increasing focus was placed in the past few decades on accelerating flash calculations and a variety of acceleration strategies have been developed to improve its efficiency without serious compromise in accuracy and reliability. Recently, as machine learning becomes a powerful tool to handle complicated and time-consuming problems, it is increasingly appealing to replace the iterative flash algorithm, due to the strong nonlinearity of flash problem, by a neural network model. In this study, an NVT flash calculation scheme is established with a thermodynamically stable evolution algorithm to generate training and testing data for the proposed deep neural network. With a modified network structure, the deep learning algorithm is optimized by carefully tuning neural network hyperparameters. Numerical tests indicate that the trained model is capable of accurately estimating phase compositions and states for complex reservoir fluids under a wide range of environmental conditions, while the effect of capillary pressure can be captured well. Thermodynamic rules are preserved well through our algorithm, and the trained model can be used for various fluid mixtures, which significantly accelerates flash calculations in unconventional reservoirs.",13,14,1
Neural Network,Reservoir Volume,"Lin, Botao; Guo, Jiancheng; Liu, Xing; Xiang, Jianhua; Zhong, Hua",Prediction of flowback ratio and production in Sichuan shale gas reservoirs and their relationships with stimulated reservoir volume,Flowback ratio; Productivity; Shale gas reservoir; Neural network; Stimulated reservoir volume,WATER; IMBIBITION,"Good flowback management in shale gas reservoirs not only preserves the conductivity of the flow paths created by the fracture network but also assists the subsequent production by minimizing the damage of the fracturing fluid to the fluid-sensitive formation. However, a quantitative prediction of its behavior and impact on the productivity of a reservoir is not available yet. This study proposed a mathematical approach to predict the flowback behavior concerning flow back ratio (FBR), and the productivity represented by first-month production (PROD), of the Changning-Weiyuan shale gas reserve in Sichuan basin, southwest China. First, a BP (Back Propagation) neural network model was established to filter out the controlling factors given the actual FBRs and the geological and engineering characteristics of seventy-six sample wells. Secondly, a correlation was generated between the FBR, the geological index g, and the engineering index e by non-linear fitting. In subsequence, the PROD was predicted based on the field recorded FBR and the comprehensive index c that combines the influences of both geological and engineering parameters. Finally, the stimulated reservoir volumes (SRVs) of twelve wells were estimated using the K-means clustering and Delaunay triangulation to assess their impact on the FBR and PROD data. It was found that the associated FBR and PROD diagrams can provide accurate predictions for the sixteen additional wells. Meanwhile, there exists an optimum FBR range of 20-40% for the shale gas region of concern where the productivity of the formation can be maximized. It is also observed that the FBR and PROD fail to display any specific trend with the value of the SRV magnitude. In general, the proposed approach can be used in shale gas reservoirs to examine the favorable FBR and guide the engineering designs to enhance production if adequate reservoir data are accessible.",10,10,6
Neural Network,Reservoir Volume,"Osarogiagbon, Augustine Uhunoma; Oloruntobi, Olalere; Khan, Faisal; Venkatesan, Ramachandran; Butt, Stephen",Gamma ray log generation from drilling parameters using deep learning,Deep learning; Logging while drilling; Measurement while drilling; Lithology; Drilling parameters; Gamma ray log; NARX; RNN; TCN; LSTM; GRU; ANN,NEURAL-NETWORKS; PREDICTION,"Lithology identification plays a vital role in defining the petroleum reservoir. Although well logging represents the traditional means of obtaining petrophysical data for lithology identification, there could be cases where logging while drilling instruments may fail during drilling. This paper presents an approach that utilizes drilling parameters obtained from mud logging and measurement while drilling (MWD) for real-time prediction of gamma ray log which is used as a lithology identifier. In this work, several machine learning methodologies, such as simple recurrent neural network (RNN), long short-term memory recurrent neural network (LSTM-RNN), temporal convolution network (TCN), gated recurrent unit (GRU) network, nonlinear autoregressive network with exogenous inputs (NARX) and simple artificial neural network (ANN) were tested for their ability to capture the relationship between hydro-mechanical specific energy (computed from drilling parameters) and gamma ray log. A recently drilled exploration gas well in the tertiary deltaic system of the Niger delta basin was used as the case study. Based on the field data, the results show the TCN and simple RNN performed best. The receptive field of the TCN played a significant role in its performance, and therefore, the LSTM-RNN can be made to perform comparable to that of TCN/simple RNN if the LSTM-RNN is manually made to work with an optimal window of input data points for each output data point. The size and nature of the data (volume, velocity, variety, and veracity) is likely a significant factor in the performance of the machine learning methodologies. Thus, it is recommended to focus on obtaining the best receptive field of the data during the machine learning development phase.",9,9,8
Neural Network,Reservoir Volume,"Yang, Liuxin; Sun, Sam Zandong",Seismic horizon tracking using a deep convolutional neural network,Horizon tracking; Convolutional neural network; Deep learning; Image classification; Seismic interpretation,PICKING,"Seismic horizons are essential for structural analysis, inversion, time-to-depth conversion, and seismic attribution analysis. However, seismic horizons are obtained commonly by manual tracking or a combination of manual tracking and traditional auto-tracking techniques, which is a time consuming and error-prone process. Although many conventional auto-tracking techniques have been proposed to improve the efficiency of horizon tracking, there are still many challenges to track seismic horizons with complex seismic reflection signatures. A deep convolutional neural network (CNN) method, a typical kind of deep neural networks in the field of deep learning, was proposed in this paper to solve the problems. Seismic horizon tracking is formulated as an image classification task. CNN can take full advantage of the high flexibility in network architecture and hierarchical feature extraction ability to track horizons from seismic volumes in which discontinuities, lateral variations and faults are apparent. We designed a CNN structure for horizon tracking and trained CNN models by using only 1% and 1.5% of the seismic volume to perform a single horizon and multiple horizon tracking. The root mean square error (RMSE) and the coefficient of determination (R-2) between the horizon tracked by CNN model and the manual-tracking are 1.78 and 0.998 in single horizon tracking, respectively. The average RMSE and R-2 are 2.68 and 0.992 in multiple horizon tracking, respectively. The research we have done suggests that the proposed method can track seismic horizons from 3-D seismic volumes much more accurately and efficiently than conventional methods.",9,9,1
Neural Network,ROP,"Mehrad, Mohammad; Bajolvand, Mahdi; Ramezanzadeh, Ahmad; Neycharan, Jalil Ghavidel",Developing a new rigorous drilling rate prediction model using a machine learning technique,Rate of penetration (ROP) modeling; NSGA-II; Physic-based models; Data-driven methods; Hybrid algorithms,OIL; BOURGOYNE; ALGORITHM; TUTORIAL; SYSTEMS,"Drilling rate of penetration (ROP) prediction is an enormously important step to optimize drilling controllable parameters. Therefore, numerous efforts have been done in order to present a more precise estimator model that is still ongoing. The results of the literature review indicated that, between the two approaches followed for ROP modeling, namely physic-based models and data-driven methods, the use of the data-driven methods has grown significantly. The literature review made two points clear: (1) the geomechanical parameters were not considered adequately, and (2) no previous research had applied a combination of least-squares support-vector machines (LSSVM) with cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithms (GA). This led us to use hybrid algorithms for ROP modeling at vertical wells drilled in the southwestern Iran. For this purpose, mud logging parameters (including depth (Depth), mud density (MD), torque (Tor), standpipe pressure (SPP), equivalent circulating density (ECD), weight on bit (WOB), revolutions per minute (RPM), flow rate (FR), and ROP) and geomechanical parameters (including gamma ray (GR), porosity (NPHI), density (RHOB), and uniaxial compressive strength (UCS)) were collected along the studied wells. Histogram analysis and pairwise evaluation of the studied features indicated the presence of outliers among the data points. Accordingly, the Tukey's method was used to omit the outliers. Subsequently, the most relevant features in the ROP prediction were selected using a combination of the non-dominated sorting genetic algorithm II (NSGA-II) with multilayer perceptron (MLP) neural network. The results showed that one could attenuate the modeling error by increasing the number of input parameters into the ROP estimation model. However, the improvement was very subtle when the number of input parameters exceeded six. Therefore, six parameters (UCS, FR, WOB, Depth, MD, and RPM) were used for ROP modeling using LSSVM-COA, LSSVM-PSO, and LSSVM-GA hybrid algorithms. Results of applying these hybrid algorithms indicated that the LSSVM-COA outperformed the other two algorithms in terms of accuracy and the coefficient of determination. In a next step, the LSSVM-COA was trained on both the outlier-omitted and raw datasets, indicating the important role of the outlier omission step in achieving a highly accurate and reliable model. Continuing with the work, in order to evaluate the performance of the LSSVM-COA hybrid model, the model was compared to support-vector regression (SVR)-COA, MLP-COA, Motahhari's, linear multivariate regression (LMR), and nonlinear multivariate regression (NLMR) models. The results confirmed superior accuracy of the LSSVM-COA model over the examined models. The small difference between the obtained levels of error in the training and testing stages with the LSSVM-COA model, as compared to the other models, revealed that the model can be used to predict the ROP at other wells across the field reliably and accurately provided the model be developed with larger sets of data across the field. Predicting ROP with high accuracy at the test Well clearly proved this claim.",12,12,1
Neural Network,ROP,"Hegde, Chiranth; Pyrcz, Michael; Millwater, Harry; Daigle, Hugh; Gray, Ken",Fully coupled end-to-end drilling optimization model using machine learning,ROP; Data-driven; Machine learning; Drilling; Optimization; Vibration,PREDICTION; EFFICIENCY,"Drilling optimization has been studied extensively given its impact on an oil and gas project - especially in a low-price environment. This is generally approached by optimizing the rate of penetration (ROP) of the well, which may not always be the best strategy. Additionally, optimization strategies rarely include the effect of torsional drilling vibrations (stick-slip) - the biggest ROP inhibitor. As such, most optimization studies have attempted to optimize only one drilling metric - ROP, mechanical specific energy (MSE) or vibrations - independent of the other, despite their interaction downhole. This does not represent bottom hole conditions accurately. This paper introduces a method of coupling several downhole parameters using machine learning algorithms. Individual models for ROP, torque on bit (TOB), MSE, and stick-slip are built using a data-driven modeling approach using the random forests algorithm. The random forest algorithm is used given its lower error rate in modeling ROP (11%), TOB (13%), and classifying drilling vibrations (F-1 score of 0.94) as compared to other machine learning algorithms evaluated in this paper (linear regression, k nearest neighbors, bagging, and neural networks). The models are coupled by building them conjointly during training. The model uses weight-on-bit (WOB), rotary speed, flowrate, and rock strength as inputs to provide an optimal set of these input parameters to use ahead of the bit for optimal drilling. The coupled model was evaluated to optimize ROP and MSE on validation data. ROP increased by 31% and MSE decreased by 49% on average with the use of this optimization model. A case study from the Williston Basin is discussed to illustrate the practical application of this model.",9,9,6
Neural Network,Capillary Pressure,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Neural Network,Capillary Pressure,"Zhang, Tao; Li, Yiteng; Sun, Shuyu; Bai, Hua",Accelerating flash calculations in unconventional reservoirs considering capillary pressure using an optimized deep learning algorithm,Phase equilibrium; NVT Flash calculation; Capillary pressure; Deep learning algorithm,MULTICOMPONENT MIXTURES; STABILITY ANALYSIS; PHASE-BEHAVIOR; EQUILIBRIUM CALCULATIONS; CUBIC EQUATIONS; 2-PHASE FLOWS; TEMPERATURE; VOLUME; MINIMIZATION; TRANSPORT,"An increasing focus was placed in the past few decades on accelerating flash calculations and a variety of acceleration strategies have been developed to improve its efficiency without serious compromise in accuracy and reliability. Recently, as machine learning becomes a powerful tool to handle complicated and time-consuming problems, it is increasingly appealing to replace the iterative flash algorithm, due to the strong nonlinearity of flash problem, by a neural network model. In this study, an NVT flash calculation scheme is established with a thermodynamically stable evolution algorithm to generate training and testing data for the proposed deep neural network. With a modified network structure, the deep learning algorithm is optimized by carefully tuning neural network hyperparameters. Numerical tests indicate that the trained model is capable of accurately estimating phase compositions and states for complex reservoir fluids under a wide range of environmental conditions, while the effect of capillary pressure can be captured well. Thermodynamic rules are preserved well through our algorithm, and the trained model can be used for various fluid mixtures, which significantly accelerates flash calculations in unconventional reservoirs.",13,14,1
Neural Network,Calculation,"Zhong, Zhi; Sun, Alexander Y.; Wang, Yanyong; Ren, Bo",Predicting field production rates for waterflooding using a machine learning-based proxy model,Machine learning; Conditional deep convolutional generative adversarial neural network; Data-driven proxy model; Waterflooding; Field production rate,RESPONSE-SURFACE METHODOLOGY; ALTERNATING-GAS-INJECTION; RELATIVE PERMEABILITY; OIL-FIELD; WORK FLOW; OPTIMIZATION; PRESSURE; DESIGN,"Waterflooding, during which water is injected in the reservoir to increase pressure and therefore boost oil production, is extensively used as a secondary oil recovery technology. Tracking the extent and efficacy of waterflooding (i.e., fluid distributions) is a primary task of reservoir engineers and is traditionally achieved by running full reservoir models. In this work, we design and implement a proxy model using a conditional deep convolutional generative neural network (cDC-GAN), which can be used to quickly calculate the dynamic fluid distribution of a heterogeneous reservoir under waterflooding. Zero-sum game theory is the basis for the cDC-GAN, which includes a pair of generative discriminative models. The generative model tries to learn the relationship between input and output and makes the generated output as close as possible to the training data, while the discriminative model tries to distinguish the fake output and the real data used for training, such that the cDC-GAN learns the real data distribution at the end. In our cDC-GAN formulation, the reservoir properties (permeability distribution in this research) and forecast time information are treated as input, and water saturation is the desired output. The reservoir fluid production rate can be calculated based on the material balance principle. The most significant contribution of this work resides in training a cDC-GAN proxy model to accurately predict fluid saturation. A cDC-GAN has several advantages over the traditional full-model based workflow. First, the model parameters estimated from history matching help to improve reservoir characterization. Second, this proposed proxy model can predict the water and oil saturation distributions simultaneously, which can be used to calculate the water and oil flow rates. Third, this proposed proxy model can be used for waterflooding optimization and uncertainty analysis with far less computational effort than with the traditional method, which uses a reservoir simulator.",13,13,9
Neural Network,Calculation,"Zhang, Tao; Li, Yiteng; Sun, Shuyu; Bai, Hua",Accelerating flash calculations in unconventional reservoirs considering capillary pressure using an optimized deep learning algorithm,Phase equilibrium; NVT Flash calculation; Capillary pressure; Deep learning algorithm,MULTICOMPONENT MIXTURES; STABILITY ANALYSIS; PHASE-BEHAVIOR; EQUILIBRIUM CALCULATIONS; CUBIC EQUATIONS; 2-PHASE FLOWS; TEMPERATURE; VOLUME; MINIMIZATION; TRANSPORT,"An increasing focus was placed in the past few decades on accelerating flash calculations and a variety of acceleration strategies have been developed to improve its efficiency without serious compromise in accuracy and reliability. Recently, as machine learning becomes a powerful tool to handle complicated and time-consuming problems, it is increasingly appealing to replace the iterative flash algorithm, due to the strong nonlinearity of flash problem, by a neural network model. In this study, an NVT flash calculation scheme is established with a thermodynamically stable evolution algorithm to generate training and testing data for the proposed deep neural network. With a modified network structure, the deep learning algorithm is optimized by carefully tuning neural network hyperparameters. Numerical tests indicate that the trained model is capable of accurately estimating phase compositions and states for complex reservoir fluids under a wide range of environmental conditions, while the effect of capillary pressure can be captured well. Thermodynamic rules are preserved well through our algorithm, and the trained model can be used for various fluid mixtures, which significantly accelerates flash calculations in unconventional reservoirs.",13,14,1
Neural Network,Unconventional Reservoirs,"Zhang, Tao; Li, Yiteng; Sun, Shuyu; Bai, Hua",Accelerating flash calculations in unconventional reservoirs considering capillary pressure using an optimized deep learning algorithm,Phase equilibrium; NVT Flash calculation; Capillary pressure; Deep learning algorithm,MULTICOMPONENT MIXTURES; STABILITY ANALYSIS; PHASE-BEHAVIOR; EQUILIBRIUM CALCULATIONS; CUBIC EQUATIONS; 2-PHASE FLOWS; TEMPERATURE; VOLUME; MINIMIZATION; TRANSPORT,"An increasing focus was placed in the past few decades on accelerating flash calculations and a variety of acceleration strategies have been developed to improve its efficiency without serious compromise in accuracy and reliability. Recently, as machine learning becomes a powerful tool to handle complicated and time-consuming problems, it is increasingly appealing to replace the iterative flash algorithm, due to the strong nonlinearity of flash problem, by a neural network model. In this study, an NVT flash calculation scheme is established with a thermodynamically stable evolution algorithm to generate training and testing data for the proposed deep neural network. With a modified network structure, the deep learning algorithm is optimized by carefully tuning neural network hyperparameters. Numerical tests indicate that the trained model is capable of accurately estimating phase compositions and states for complex reservoir fluids under a wide range of environmental conditions, while the effect of capillary pressure can be captured well. Thermodynamic rules are preserved well through our algorithm, and the trained model can be used for various fluid mixtures, which significantly accelerates flash calculations in unconventional reservoirs.",13,14,1
Neural Network,Unconventional Reservoirs,"He, Mei; Gu, Hanming; Wan, Huan",Log interpretation for lithology and fluid identification using deep neural network combined with MAHAKIL in a tight sandstone reservoir,Lithology and fluid identification; Deep neural network; Log interpretation; Class imbalance; Tight sandstone gas reservoir,SEISMIC FACIES ANALYSIS; MACHINE; MODEL; PERMEABILITY; LITHOFACIES; SMOTE,"As an important source of unconventional natural gas, tight sandstone reservoirs have attracted considerable attention. The accurate identification of lithological and fluid-bearing zones is a limiting factor for exploring such reservoirs effectively. Log data, which provide abundant and high precision geological information, are always used for this task. Here, we combined a deep neural network with an oversampling approach named MAHAKIL for lithology and fluid identification using log data from a tight sandstone gas reservoir. MAHAKIL was adopted to solve the class imbalance problem resulting from imbalanced training samples, and the outputs were then fed into a deep neural network to learn the complex and abstract geological patterns related to the lithology and fluid in a layer-by-layer manner. We first demonstrated the unsatisfactory performance of a typical classification algorithm on a simulated data which conforms to the normal distribution and is imbalanced. Then, the performance of our method was compared with that of a support vector machine and a deep neural network on the imbalanced actual data, and the F-beta score which is the weighted harmonic mean of precision and recall was used as the evaluation criterion. The results show that the F-beta score of our method was generally higher than that of the other two methods, which indicates the superiority of the proposed method for lithology and fluid identification of tight sandstone gas reservoirs when the learning samples are imbalanced.",8,9,12
Neural Network,Screening,"Temirchev, P.; Simonov, M.; Kostoev, R.; Burnaev, E.; Oseledets, I; Akhmetov, A.; Margarit, A.; Sitnikov, A.; Koroteev, D.",Deep neural networks predicting oil movement in a development unit,Metamodel; Reservoir model; Reduced order model; Neural network; Machine learning,,"We present a novel technique for assessing the dynamics of multiphase fluid flow in the oil reservoir. We demonstrate an efficient workflow for handling the 3D reservoir simulation data in a way which is orders of magnitude faster than the conventional routine. The workflow (we call it ""Metamodel"") is based on a projection of the system dynamics into a latent variable space, using Variational Autoencoder model, where Recurrent Neural Network predicts the dynamics. We show that being trained on multiple results of the conventional reservoir modelling, the Metamodel does not compromise the accuracy of the reservoir dynamics reconstruction in a significant way. It allows forecasting not only the flow rates from the wells, but also the dynamics of pressure and fluid saturations within the reservoir. The results open a new perspective in the optimization of oilfield development as the scenario screening could be accelerated sufficiently.",25,26,1
Neural Network,Screening,"Sun, Qian; Ertekin, Turgay",Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies,Artificial neural network; Polymer injection; Optimization; EOR screening; EOR project design,ALGORITHM,"Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.",11,11,2
ORDOS BASIN,"Coalbed Methane,Coal","Yan, Jiwei; Meng, Zhaoping; Zhang, Kun; Yao, Huifang; Hao, Haijin",Pore distribution characteristics of various rank coals matrix and their influences on gas adsorption,Various rank coals; Pore size distribution; Controlling mechanism; Methane adsorption,MERCURY INTRUSION POROSIMETRY; SOUTHERN SICHUAN BASIN; X-RAY-SCATTERING; METHANE ADSORPTION; NANOPORE STRUCTURE; ORDOS BASIN; CO2; POROSITY; SORPTION; RESERVOIRS,"Methane is primarily stored in coal matrix pores and pore size distribution has an important effect on gas adsorption/desorption. Investigation of the relationship between pore size distribution and adsorption performance of coal is of significance for the understanding of the evolution of coalbed methane reservoirs. In this study, a series of laboratory experiments (nitrogen, carbon dioxide and methane adsorption) were carried out to determine the pore size distribution and adsorption capacity of coal samples of various coal ranks. The relationship between pore size distribution, Langmuir volume and the metamorphic degree of coals were established. The factors influencing methane adsorption of coals were also analyzed. The results show that the matrix pores are mainly cylindrical, thin bottleneck-, ink bottleneck- and parallel plate-shaped. With the increase in coal rank, both the total pore volume and the specific surface area initially decrease and then increase. Matrix pores, including micro-, transitional- and mesopores, show a similar asymmetric U-shaped trend in the pore volume and the specific surface area with an increase in coal rank. The percentages by volume and by specific surface area increase for the micropores and declines for the transitional pores and mesopores. In the low-pressure zone, micro- and transitional pores play a dominant role in methane adsorption; however, in the high-pressure zone, the influence of mesopores on methane adsorption is pronounced.",22,24,17
ORDOS BASIN,"Coalbed Methane,Coal","Hou, Xiaowei; Zhu, Yanming; Chen, Shangbin; Wang, Yang; Liu, Yu",Investigation on pore structure and multifractal of tight sandstone reservoirs in coal bearing strata using LF-NMR measurements,Tight sandstone; Pore structure; Multifractal characteristics; LF-NMR measurements; Qinshui Basin,TRIASSIC YANCHANG FORMATION; PRESSURE MERCURY INTRUSION; CLAY BOUND WATER; FRACTAL ANALYSIS; OIL-RESERVOIRS; SONGLIAO BASIN; QINSHUI BASIN; PETROPHYSICAL PROPERTIES; CONTROLLED POROSIMETRY; NITROGEN ADSORPTION,"In this study, pore structures of tight sandstone reservoirs in coal bearing strata were evaluated by combining the low field nuclear magnetic resonance (LF-NMR) measurements with multifractal theory. The effects of petro-physical properties, pore structure parameters, and reservoir components on multifractal parameters in different probability measure areas were then discussed. The results show that tight sandstone reservoirs in coal bearing strata have complex pore structure, low porosity (2.43%-5.18%), low permeability (0.0005-0.0125 mD), and poor pore connectivity with significant multifractal characteristics. Multifractal characteristics are well correlated with petrophysical property, pore structure, and lithology, which is useful for evaluating pore structure heterogeneity of such tight sandstone reservoirs. Moreover, the multifractal parameters of different probability measure areas are strongly associated with petrophysical parameter porosity, whereas the multifractal parameters of low probability measure areas alpha(max), (D-min-D-0) are weakly related to the characteristics of pore structure parameters and reservoir components. This suggests that the multifractal parameters of the high probability measure areas are more sensitive than other multifractal parameters to the pore structure, and therefore can be chosen for effective pore structure characterization. Additionally, other parameters A, (D-0-D-1), and (D-0-D-2) can also reflect the property of pore structure to a certain extent.",20,20,14
ORDOS BASIN,"Coalbed Methane,Coal","Zhang, Jiyuan; Feng, Qihong; Zhang, Xianmin; Hu, Qiujia; Wen, Shengming; Chen, Dong; Zhai, Yuyang; Yan, Xia","Multi-fractured horizontal well for improved coalbed methane production in eastern Ordos basin, China: Field observations and numerical simulations",Coalbed methane; Multi-fractured horizontal well; Numerical simulation; Improved recovery; Producibility comparison,RATE-TRANSIENT ANALYSIS; PERMEABILITY CHANGES; RESERVOIR SIMULATION; PREDICTION; EVOLUTION; SEAM; PERFORMANCE,"Eastern margin of Ordos basin has been an active commercial coalbed methane (CBM) production area in China, where coal seams are typically characterized with thin layers, low permeability and high gas content. Hydraulically fractured vertical wells (HFVWs) are the primary means for recovery of CBM in this area, which however are usually subject to low gas production and unpromising economics. Although the multi-fractured horizontal well (MFHW) has proven as an effective solution for producing hydrocarbon resources from both tight and shale reservoirs, its applicability in efficient development of CBM reservoirs remains yet unclear. This paper presents a pilot field application of MFHW to improve CBM recovery in eastern Ordos basin. A horizontal well stimulated with 6 stages of hydraulic fractures was observed to significantly outperform HFVWs in terms of depressurization efficiency, gas production and ultimate recovery factor. Peak gas rate of the MFHW is more than five times higher than an HFVW. History matches of the MFHW and representative HFVWs were conducted to obtain key reservoir properties that are subsequently used for production predictions. Numerical simulation predicts that cumulative gas production for the MFHW is 3-15 times as that for each of the HFVWs during a production duration of 15 years. A total of 500 stochastic geological scenarios for the study area were simulated to analyze the effect of geological parameters on the superiority of an MFHW over a group of four HFVWs (which are at equivalent well construction outlays) in terms of cumulative gas production. A correlation was then developed using the alternating conditional expectation (ACE) regression method, resulting in a linear relationship between an indicator of the superiority with permeability and desorption pressure in a log-log coordinate system. This correlation can be potentially used as a criterion for fast determination of the optimal completion option in the target CBM seams. The regression results also show that the superiority of an MFHW over HFVWs is especially highlighted in thin coal seams with low permeability and low gas content. Finally, the effect of the size and spacing of stimulated area (SA) on MFHW producibility was analyzed, showing that increasing the spacing between SAs is an economically viable option when the budget for fracturing operations is limited.",13,13,10
ORDOS BASIN,"Coalbed Methane,Coal","Guo, Chen; Qin, Yong; Wu, Caifang; Lu, Lingling","Hydrogeological control and productivity modes of coalbed methane commingled production in multi-seam areas: A case study of the Bide-Santang Basin, western Guizhou, South China",Multi-seam; Superimposed coalbed methane system; Commingled production; Hydrogeology; Productivity modes,IN-SITU STRESS; CO-PRODUCED WATER; QINSHUI BASIN; SHIZHUANGNAN BLOCK; ORDOS BASIN; CBM WELLS; RESERVOIR PROPERTIES; SEDIMENTARY CONTROL; EASTERN MARGIN; BEARING SYSTEM,"Coalbed methane (CBM) commingled production is an important measure to increase the CBM productivity in multi-seam areas. However, multiple superimposed CBM systems are widely developed in multi-seam areas and the difference in the hydrogeological conditions between CBM systems significantly influences the CBM commingled production. In this study, the Bide-Santang Basin in South China was used as an example and hydrogeological data analysis, production data analysis, and rock and coal sample tests were used to investigate variable hydrogeological conditions of superimposed CBM systems and their implications for the CBM production. The hydrogeochemical closed index (HCI) is proposed based on the ion compositions of the groundwater in the coal-bearing strata, which is a new parameter that can be used for the quantitative discrimination and description of superimposed CBM systems based on the determination of the groundwater environment. The hydrodynamics of the upper CBM system are stronger at a lower HCI value, and thus susceptible to shallow groundwater interference during the CBM production. The predicted daily water production based on the unit water inflow of the pumping test boreholes is generally lower than 1 m(3) /(d.m) when the median depth of the coal seam group exceeds 150 m. When the daily water production per unit drawdown (DWPPUD) of the producing fluid level in the CBM well is less than 1 m(3) /(d.m), high CBM production can be achieved in the well due to the absence of shallow groundwater interference in the Zhucang Syncline. Finally, three productivity modes of CBM commingled production wells in the Bide-Santang Basin were discriminated: shallow groundwater interference wells, high production wells, and fracturing fluid-contaminated wells. Numerical simulation shows that upper CBM system limits the production of middle and lower CBM systems. Suggestions are made for the CBM development in the Bide-Santang Basin based on the variable hydrogeological conditions and in situ stress of the superimposed CBM systems.",13,14,7
ORDOS BASIN,"Coalbed Methane,Coal","Cheng, Guoxi; Jiang, Bo; Li, Ming; Li, Fengli; Song, Yu",Effects of pore-fracture structure of ductile tectonically deformed coals on their permeability: An experimental study based on raw coal cores,Ductile tectonically deformed coal; Pore-fracture structure; Surface fractal characteristics; Permeability; Suxian mining area,CH4 ADSORPTION CAPACITY; STRESS SENSITIVITY; FINES GENERATION; ORDOS BASIN; RANK COAL; DIMENSION; COMPRESSIBILITY; ROUGHNESS; PARTICLES; RESERVOIR,"The distribution area of ductile tectonically deformed coals (TDCs) usually coincides with the forbidden zones for coalbed methane (CBM) development. Permeability of coal reservoirs, an important indicator to evaluate the energy potential of CBM, is directly affected by the pore-fracture structures. To study the controlling mechanism of pore-fracture structures on permeability, we investigated the micropore - micro-fracture structures of various ductile TDCs by adopting mercury intrusion porosimetry (MIP) and low-pressure gas adsorption. The permeability and the pressure sensitivity of the standard TDC cores were tested by the pressure pulse decay method. The results showed that the total pore volume of ductile TDCs, especially the mesopores and macropores, significantly increased from that of primary structure coals (PSCs), while the volume of transitional pores only slightly increased in strongly crumpled and mylonitized coals, and thus, the dominant pores in coals gradually changed from micro-fractures to mesopores and macropores. The pore-fracture structure of ductile TDCs showed a poorer connectivity and a higher roughness than PSCs. The permeability of typical ductile TDCs obviously decreased, the permeability heterogeneity significantly increased, and the pressure sensitivity of permeability generally showed a pattern of ""weakly crumpled - > PSCs > strongly crumpled - and mylonitized coals"". Correlation analysis showed that the weakly crumpled coals that contain well-developed and well-connected microfractures and fewer <10 mu m coal particles usually display high permeability. In strongly crumpled - and mylonitized coals, the connected pore-fracture structures were damaged and many pore throats and flask-shaped pores formed, which is the main reason for the reduced permeability and the high permeability damage rate.",11,10,4
ORDOS BASIN,"Coalbed Methane,Coal","Yu, Kun; Ju, Yiwen; Zhang, Baoxin","Modeling of tectono-thermal evolution of Permo-Carboniferous source rocks in the southern Qinshui Basin, China: Consequences for hydrocarbon generation",,BOHAI BAY BASIN; EASTERN NORTH CHINA; COALBED METHANE RESERVOIRS; TECTONIC THERMAL HISTORY; VITRINITE REFLECTANCE; MATURITY HISTORY; BURIAL HISTORY; ORDOS BASIN; TEMPERATURE; BEARING,,9,9,4
ORDOS BASIN,"Coalbed Methane,Coal","Wang, Qian; Su, Xianbo; Su, Linan; Zhou, Fengde","CBM geological characteristics and exploration potential in the Sunan Syncline block, southern north China basin",Coalbed methane; Geological characteristic; Sunan syncline block; Gas content; CBM exploration potential,COMBINED STIMULATION TECHNOLOGY; COALBED METHANE RESERVOIRS; EASTERN ORDOS BASIN; QINSHUI BASIN; ADSORPTION CAPACITY; ACCUMULATION; COALFIELD; WELLS; MIDDLE; FIELD,"The Permian coal-bearing strata in the Sunan Syncline block contains abundant coalbed methane (CBM) resources. However, systematic studies of CBM geological characteristics in the block are still lacking which severely hinders the CBM development. This paper presents a synthetic study of the CBM geological characteristics in the block from the aspects of gas accumulation conditions and geological controls. Results show that the coal seams are dominated by medium-to high-volatile bituminous coals with the coal structure of normal and cataclastic, possessing relatively high fracability and permeability. The total thickness and gas content of the main coal seams are 9-12 m and 2-21 m(3)/t, respectively. The CBM in the shallow and deep parts of the block shows the feature of secondary bacterial gas and thermogenic gas, respectively. The roof lithologies of the coal seams and the structure types in the block provide good gas sealing conditions for CBM. In addition, the groundwater migration from the flanks to the axial region of the Sunan Syncline leads to relatively high gas content in the deep part of the block. Based on the CBM geological characteristics, the CBM exploration potential in the block was evaluated, and 2 zones were selected as favorable targets for CBM exploration.",8,9,3
ORDOS BASIN,Organic Matter,"Fan, Cunhui; Li, Hu; Qin, Qirong; He, Shun; Zhong, Cheng","Geological conditions and exploration potential of shale gas reservoir in Wufeng and Longmaxi Formation of southeastern Sichuan Basin, China",Shale gas; Geological conditions; Tectonic uplift; Preservation conditions; Longmaxi Formation; Southeastern Sichuan Basin,TIGHT SANDSTONE RESERVOIRS; PERMIAN LUCAOGOU FORMATION; ORDOS BASIN; UPPER ORDOVICIAN; TECTONIC FRACTURES; DINGSHAN AREA; SOUTH CHINA; OIL-SHALE; GEOCHEMICAL CHARACTERISTICS; PRESERVATION CONDITIONS,"The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R-o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration.",39,40,8
ORDOS BASIN,Organic Matter,"Han, Hui; Guo, Chen; Zhong, Ning-ning; Pang, Peng; Gao, Yuan","A study on fractal characteristics of lacustrine shales of Qingshankou Formation in the Songliao Basin, northeast China using nitrogen adsorption and mercury injection methods",Songliao basin; Lacustrine shales; Fractal dimension; Low-pressure N-2 adsorption; Mercury injection; Pore structure,PORE STRUCTURE CHARACTERIZATION; CHANG 7 MEMBER; GAS-ADSORPTION; ORGANIC-MATTER; SICHUAN BASIN; YANCHANG FORMATION; LONGMAXI SHALE; ORDOS BASIN; ACCUMULATION; AREA,"In order to research the fractal characteristics of lacustrine shale, we conducted low-pressure N-2 adsorption and mercury injection measurements on 35 shale samples of Cretaceous Qingshankou Formation in the Songliao Basin, northeast China. The fractal dimensions (D-1, D-2, and D-3) were obtained from N-2 adsorption (P/P-o < 0.5 and P/P-o > 0.5) and mercury injection data, respectively. Accordingly, we analyzed the relationships between fractal dimensions and petmphysical and geochemical parameters. The results show that the fractal dimensions (D-1, D-2, and D-3) are in the ranges of 2.0174-2.5705, 2.5589-2.8425, and 2.1461-2.9728, respectively. There exists a positive relationship between D-1 and D-2, suggesting that micmpores and mesopores have similar surface characteristics. The poor correlations between D-3 and D-1 or D-2 may be related to the different principles of low-pressure N-2 adsorption and mercury injection. The fractal dimensions (D-1 and D-2) correlate positively with pore volumes and surface areas, which indicates that the fractal dimensions can well reflect the pore structure and surface characteristics. The fractal dimensions (D-1 and D-2) decreased with the increasing TOC content, which may be aroused by the low abundance of pores in organic matters. The fractal dimensions (D-1 and D-2) decreased firstly and then increased with the increasing maturity, which is aroused by liquid hydrocarbons generation and cracking. And the fractal dimension D-3 decreased during maturation, which may be induced by compaction. The fractal dimensions (D-1 and D-2) decreased with the increasing Rock-Eval pyrolysis parameters S-1 and S-1/TOC, which suggests that the fractal dimensions can be indicators of oil content of shales.",17,16,7
ORDOS BASIN,Organic Matter,"Ma, Weijiao; Hou, Lianhua; Luo, Xia; Liu, Jinzhong; Tao, Shizhen; Guan, Ping; Cai, Yuwen",Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature -based semi -open pyrolysis: Implications for in -situ conversion process,Chang 7 oil shale; In-situ conversion process; Temperature-based semi-open pyrolysis; Hydrocarbon generation process; Hydrocarbon expulsion process,TRIASSIC YANCHANG FORMATION; ORGANIC-MATTER; HYDROUS PYROLYSIS; GAS GENERATION; CHINA IMPLICATIONS; SOURCE-ROCK; II KEROGEN; PETROLEUM; EVOLUTION; SYSTEM,"There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300-320 degrees C, 0.53-0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320-380 degrees C, 0.55-1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380-420 degrees C, 1.09-1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 degrees C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24-1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.",16,19,10
ORDOS BASIN,Organic Matter,"Wang, Yang; Liu, Luofu; Cheng, Hongfei","Pore structure of Triassic Yanchang mudstone, Ordos Basin: Insights into the impact of solvent extraction on porosity in lacustrine mudstone within the oil window",Pore structure; Solvent extraction; Nitrogen adsorption; Lacustrine mudstone; Oil window,CONTINENTAL TRANSITIONAL SHALE; ORGANIC-MATTER; SICHUAN BASIN; MARINE SHALE; GEOCHEMICAL CHARACTERISTICS; CHINA IMPLICATIONS; NETWORK EVOLUTION; THERMAL MATURITY; LONGMAXI SHALE; GAS,"Low-pressure nitrogen physisorption was performed on Triassic Yanchang mudstones before and after solvent extraction to characterize the extractable organic matter (EOM) occurrence and ascertain the impact of extracts on the nanoporosity of lacustrine mudstone within the oil window. Organic-rich Yanchang mudstones are currently thermally mature (vitrinite reflectance of 0.48%-0.92%). SEM-observed pore types chiefly comprise interparticle and intraparticle pores related to inorganic minerals, with organic matter pores less developed. Pore volume (PV) of the original mudstones is 0.35-2.15 cm(3)/100 g and the specific surface area (SSA) is 1.22-7.77 m(2)/g. Brittle minerals (quartz + feldspar + carbonates) and I/S mixed layer jointly show the positive effect on the pore space development in the Yanchang mudstone. Four groups of mudstones with obvious differences in pore structure properties were identified, which probably result from the various development degrees of interparticle pores at the edge of brittle minerals, and intraparticle pores associated with I/S aggregates. Generally, solvent extraction will result in a noticeable increase in the volume of N-2 adsorbed due to the reopening of pore space blocked by EOM, which is related to increases in PV an SSA. A declining case, probably caused by the progressive shift of the enlarged open pore space to the larger macropore range (d > 200 nm) which is not detected by N-2 adsorption and counteracts the increased porosity by extraction, however, was also observed in the current study. Overall, the infilling degree of EOM increased with increasing thermal evolution degree of shales within the oil window, which mainly blocks minor pores in lower mature samples but larger pores in higher mature samples.",13,13,6
ORDOS BASIN,Organic Matter,"Han, Hui; Pang, Peng; Zhong, Ningning; Luo, Qingyong; Ma, Yong; Gao, Yuan","The pore characteristics and gas potential of the Jurassic continental shales in the middle-small basins, northwest China",Continental shales; Type III organic matters; Northwest China; Shale gas; Pore,MISSISSIPPIAN BARNETT SHALE; TRIASSIC YANCHANG FORMATION; THRUST-FOLD BELT; BOHAI BAY BASIN; CHANG 7 MEMBER; ORDOS BASIN; SICHUAN BASIN; LACUSTRINE SHALES; ORGANIC-MATTER; FRACTAL CHARACTERISTICS,"Jurassic continental shales were extensively developed in the northwest of China. To characterize and analyze the pores and gas potential of these shales, geochemical, mineralogical, petmphysical, and methane adsorption capacity (MAC) experiments were performed on 10 samples. The results indicated that these shales have a high total organic carbon (TOC) content, low porosity and permeability. Interparticle pores between clay platelets are dominant. Organic matter (OM) pores cannot be observed using scanning electron microscope. The methane adsorption capacity is strong, and it is controlled by TOC content. Strong MAC indicated the shales have an excellent capacity of storing gas. In addition, type III organic matters can generate amount of gas at a lowly mature stage. Therefore, it is speculated that the studied shales have a good gas potential, which is supported by canister desorption results.",12,12,4
ORDOS BASIN,Organic Matter,"Shan, Changan; Zhao, Weiwei; Wang, Fengqin; Zhang, Kun; Feng, Zhao; Guo, Liulinbo; Ma, Xueli; Liao, Tian","Nanoscale pore structure heterogeneity and its quantitative characterization in Chang7 lacustrine shale of the southeastern Ordos Basin, China",Nanoscale pore structure heterogeneity; Quantitative characterization; Chang7 lacustrine shale; Fractal characteristic,TRIASSIC YANCHANG FORMATION; SOUTHERN SICHUAN BASIN; CH4 ADSORPTION CAPACITY; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; LONGMAXI SHALE; GEOCHEMICAL CHARACTERISTICS; ELECTRON-MICROSCOPY; MERCURY-INTRUSION; RESERVOIR,"To gain a better understanding of nanoscale pore structure characteristics in Chang7 lacustrine shale, Ordos Basin, China, 33 shale samples from 15 wells are examined and analyzed by total organic carbon (TOC), X-ray diffraction (XRD), mercury porosimetry, helium pycnometry, low-pressure N-2 adsorption experiments and fractal method. The results show that Chang7 lacustrine shale pores diameter is mainly from 1.5 to 5 nm, and mesopores give the largest contribution to the total pore specific surface area (S-BET) and volume (V-BJH), and micropores have the second contribution to S-BET but little contribution to V-BJH, macropores have very little contribution to S-BET but make a good contribution to V-BJH. According to the occurrence and origin of shale pores, micro-pores can be divided into mineral intragranular pore, minera intercrystalline pore and organic pore. Two fractal dimensions (D1 and D2) are obtained from N-2 adsorption isotherms analysis using FHH method. Relationships between fractal dimensions and shale compositions, pore structure parameters are investigated, which show that both D1 and D2 have good positive relationships with S-BET and V-BJH, but obvious negative correlations with the average pore diameter. That is, the smaller the pore diameter, the more complex the pore structure is, resulting in the larger pore surface and volume. D1 and D2 are both positively correlated with total clay, illite, mixed-layer of illite-smectite, whereas no obvious relationships with chlorite, indicating that the layer and flocculent structure increase the complexity of nanoscale pore structure. TOC content has positive correlation with D1 but no obvious relationship with D2, indicating that the pores in organic matter are mostly micropores. Fractal dimensions are negatively correlated with total brittle mineral, quartz and feldspar content, that is because the surface of brittle minerals is smoother and more homogenous than that of clay minerals.",7,7,10
ORDOS BASIN,Chang 7,"Guo, Ruiliang; Xie, Qichao; Qu, Xuefeng; Chu, Meijuan; Li, Shutong; Ma, Dongxu; Ma, Xiaofeng","Fractal characteristics of pore-throat structure and permeability estimation of tight sandstone reservoirs: A case study of Chang 7 of the Upper Triassic Yanchang Formation in Longdong area, Ordos Basin, China",Fractal dimension; Tight sandstone reservoirs; Yanchang Formation; Permeability estimation; Mercury intrusion capillary pressure,CAPILLARY-PRESSURE; OIL; POROSITY; MICROGEOMETRY; EXPLORATION; PARAMETERS; INSIGHT; IMPACT; SHALES,"Permeability estimation and quantitative evaluation of pore microstructure have always been hotspots and difficulties in tight sandstone reservoirs research. Taking the fractal dimension as the breakthrough, 10 core samples of Chang 7 section in the Upper Triassic Yanchang Formation were collected from different wells in Longdong area of Ordos Basin. The fractal dimension was calculated by mercury intrusion capillary pressure curve which can be obtained from high pressure mercury injection experiment, and samples were divided into four groups as group I, II, III and IV according to the value of fractal dimension estimated. The observation of casting thin sections and field emission scanning electron microscope show that group I mainly has dissolved-intergranular pores and original intergranular pores, group II is mainly dissolved-intergranular pores, group III mainly has dissolved-intragranular pores, and group IV is mainly micropores in clay matrix. Meanwhile, there is a highly correlation between the fractal dimension and the reservoir physical properties. With the fractal dimension of tight sandstone samples approaching 3, the compaction and cementation show a gradual increase, while the pore sorting, physical parameters and percolation capacity display a gradual decrease. Through multiple regression analysis, a set of empirical equations based on the fractal dimension and different pore throat radius were constructed, in which the equation based on maximum permeability contribution radius has the highest correlation. It shows that micropore (0.1-0.2 mu m) contributes most to permeability in tight sandstone reservoir. 10 blind samples were included in regression analysis to improve the prediction accuracy of the new model. A total of 28 samples, including 8 referenced data, were used to verify the predictive accuracy of the new model. The new empirical equation can predict the permeability of tight sandstone relatively accurate. Thus, the fractal dimension can effectively predict the permeability and evaluate the quality of tight sandstone reservoirs.",29,29,7
ORDOS BASIN,Chang 7,"Han, Hui; Guo, Chen; Zhong, Ning-ning; Pang, Peng; Gao, Yuan","A study on fractal characteristics of lacustrine shales of Qingshankou Formation in the Songliao Basin, northeast China using nitrogen adsorption and mercury injection methods",Songliao basin; Lacustrine shales; Fractal dimension; Low-pressure N-2 adsorption; Mercury injection; Pore structure,PORE STRUCTURE CHARACTERIZATION; CHANG 7 MEMBER; GAS-ADSORPTION; ORGANIC-MATTER; SICHUAN BASIN; YANCHANG FORMATION; LONGMAXI SHALE; ORDOS BASIN; ACCUMULATION; AREA,"In order to research the fractal characteristics of lacustrine shale, we conducted low-pressure N-2 adsorption and mercury injection measurements on 35 shale samples of Cretaceous Qingshankou Formation in the Songliao Basin, northeast China. The fractal dimensions (D-1, D-2, and D-3) were obtained from N-2 adsorption (P/P-o < 0.5 and P/P-o > 0.5) and mercury injection data, respectively. Accordingly, we analyzed the relationships between fractal dimensions and petmphysical and geochemical parameters. The results show that the fractal dimensions (D-1, D-2, and D-3) are in the ranges of 2.0174-2.5705, 2.5589-2.8425, and 2.1461-2.9728, respectively. There exists a positive relationship between D-1 and D-2, suggesting that micmpores and mesopores have similar surface characteristics. The poor correlations between D-3 and D-1 or D-2 may be related to the different principles of low-pressure N-2 adsorption and mercury injection. The fractal dimensions (D-1 and D-2) correlate positively with pore volumes and surface areas, which indicates that the fractal dimensions can well reflect the pore structure and surface characteristics. The fractal dimensions (D-1 and D-2) decreased with the increasing TOC content, which may be aroused by the low abundance of pores in organic matters. The fractal dimensions (D-1 and D-2) decreased firstly and then increased with the increasing maturity, which is aroused by liquid hydrocarbons generation and cracking. And the fractal dimension D-3 decreased during maturation, which may be induced by compaction. The fractal dimensions (D-1 and D-2) decreased with the increasing Rock-Eval pyrolysis parameters S-1 and S-1/TOC, which suggests that the fractal dimensions can be indicators of oil content of shales.",17,16,7
ORDOS BASIN,Chang 7,"Ma, Weijiao; Hou, Lianhua; Luo, Xia; Liu, Jinzhong; Tao, Shizhen; Guan, Ping; Cai, Yuwen",Generation and expulsion process of the Chang 7 oil shale in the Ordos Basin based on temperature -based semi -open pyrolysis: Implications for in -situ conversion process,Chang 7 oil shale; In-situ conversion process; Temperature-based semi-open pyrolysis; Hydrocarbon generation process; Hydrocarbon expulsion process,TRIASSIC YANCHANG FORMATION; ORGANIC-MATTER; HYDROUS PYROLYSIS; GAS GENERATION; CHINA IMPLICATIONS; SOURCE-ROCK; II KEROGEN; PETROLEUM; EVOLUTION; SYSTEM,"There is a substantial amount of oil shale resources in the seventh member of the Triassic Yanchang Formation (abbreviated as Chang 7) in the Ordos Basin, and its geological and geochemical characteristics are highly suitable for in-situ conversion process (ICP). A comprehensive characterization of its hydrocarbon generation, expulsion and retention features will help determine the optimum conditions for future field tests. However, typical thermal simulation experiments based on either open-system or closed-system are not applicable to provide data to construct the models. Therefore, in this study, eight parallel thermal simulation experiments, which were based on the newly designed temperature-based semi-open pyrolysis experiments were performed on the Chang 7 oil shale. The yields (including cumulative yields and net incremental yields) and compositional characteristics of the expelled oil, expelled gas, and retained oil were analyzed. Results show that the hydrocarbon expulsion has a coupling relationship with hydrocarbon generation that can be divided into four stages: (1) Slow hydrocarbon generation stage (300-320 degrees C, 0.53-0.55 %Ro). Minimal amounts of oil and gas are generated in this stage. The hydrocarbon expulsion efficiency increases rapidly. (2) Quick oil-generation stage (320-380 degrees C, 0.55-1.09 %Ro). The fast cracking of kerogen and thermal bitumen generates a large amount of oil. The hydrocarbon expulsion efficiency remains relatively stable. (3) The secondary oil cracking and quick gas-generation stage (380-420 degrees C, 1.09-1.66 %Ro). The oil yield begins to decrease after reaching its maximum and a large amount of hydrocarbon gas is generated. The oil generation capability of kerogen is basically exhausted. The hydrocarbon expulsion efficiency and gas/oil ratio increase rapidly at this stage. (4) The heavy hydrocarbon gas cracking stage (after 420 degrees C, 1.66 %Ro). The oil yield continues to decline, accompanied by the onset decline in the gas yield (except methane). At this time, the hydrocarbon expulsion efficiency continues to increase but at a rather low speed. Under the experimental conditions in this study, 1.24-1.66% Ro is considered a favorable thermal maturity interval, in which maximum oil production with relatively light components can be obtained and the hydrocarbon gas is abundant.",16,19,10
ORDOS BASIN,Chang 7,"Ju, Wei; Niu, Xiaobing; Feng, Shengbin; You, Yuan; Xu, Ke; Wang, Geoff; Xu, Haoran","Present-day in-situ stress field within the Yanchang Formation tight oil reservoir of Ordos Basin, central China",In-situ stress field; Tight oil reservoir; Yanchang formation; Stress regime; Natural fracture; Ordos basin,SEDIMENTARY-ROCKS; LOW-PERMEABILITY; TECTONIC STRESS; STATE; AREA; EXPLORATION; FRACTURES; PATTERN; REGION; ORIENTATIONS,"The present-day in-situ stress field has many important and practical applications during the exploration and development of hydrocarbon resources. The Ordos Basin is a significant petroliferous basin in China, within which, the Yanchang Formation serves as the most significant tight oil reservoir. However, an overview of previous studies indicates that little was known as to the present-day stress state in the Yanchang Formation. Therefore, the present-day stress field in the Yanchang Formation tight oil reservoir of the Ordos Basin is systematically analyzed in this study. The orientation of horizontal maximum principal stress (S-Hmax) within the Yanchang Formation of Ordos Basin ranges between north-northeast-south-southwest-trending (NNE-SSW) and east-northeast-west-southwest-trending (ENE-WSW) based on interpretations of borehole breakouts and drilling-induced fractures from borehole imaging logs. The S-Hmax orientation shows various tendencies in different wells, which may result from differential development in lithology, natural fracture and bedding plane over various regions. The estimated magnitudes of vertical stress (S-v), S-Hmax and horizontal minimum principal stress (S-hmin) in the studied wells indicate that the normal faulting stress regime is dominant within the Yanchang Formation. In addition, the geomechanical assessments of wellbore stability and natural fracture reactivation are also performed. Natural fractures in the Yanchang Formation Chang 7 tight oil reservoir of Ordos Basin are developed striking mainly in the northeast-southwest-trending (NE-SW) and west-northwest-east-southeast-trending (WNW-ESE). Among them, those fractures with NE-SW-trending strikes are more conductive with reference to the present-day stress state, contributing more to tight oil production in the Ordos Basin. In addition, within the Yanchang Formation, if horizontal wells are drilled towards the NNE-SSW-trending to ENE-WSW-trending, they are more likely to have wellbore instability issues. The results in this study provide important geological information for tight oil production in the Yanchang Formation of Ordos Basin.",13,14,3
ORDOS BASIN,Chang 7,"Han, Hui; Pang, Peng; Zhong, Ningning; Luo, Qingyong; Ma, Yong; Gao, Yuan","The pore characteristics and gas potential of the Jurassic continental shales in the middle-small basins, northwest China",Continental shales; Type III organic matters; Northwest China; Shale gas; Pore,MISSISSIPPIAN BARNETT SHALE; TRIASSIC YANCHANG FORMATION; THRUST-FOLD BELT; BOHAI BAY BASIN; CHANG 7 MEMBER; ORDOS BASIN; SICHUAN BASIN; LACUSTRINE SHALES; ORGANIC-MATTER; FRACTAL CHARACTERISTICS,"Jurassic continental shales were extensively developed in the northwest of China. To characterize and analyze the pores and gas potential of these shales, geochemical, mineralogical, petmphysical, and methane adsorption capacity (MAC) experiments were performed on 10 samples. The results indicated that these shales have a high total organic carbon (TOC) content, low porosity and permeability. Interparticle pores between clay platelets are dominant. Organic matter (OM) pores cannot be observed using scanning electron microscope. The methane adsorption capacity is strong, and it is controlled by TOC content. Strong MAC indicated the shales have an excellent capacity of storing gas. In addition, type III organic matters can generate amount of gas at a lowly mature stage. Therefore, it is speculated that the studied shales have a good gas potential, which is supported by canister desorption results.",12,12,4
ORDOS BASIN,Mu M,"Guo, Ruiliang; Xie, Qichao; Qu, Xuefeng; Chu, Meijuan; Li, Shutong; Ma, Dongxu; Ma, Xiaofeng","Fractal characteristics of pore-throat structure and permeability estimation of tight sandstone reservoirs: A case study of Chang 7 of the Upper Triassic Yanchang Formation in Longdong area, Ordos Basin, China",Fractal dimension; Tight sandstone reservoirs; Yanchang Formation; Permeability estimation; Mercury intrusion capillary pressure,CAPILLARY-PRESSURE; OIL; POROSITY; MICROGEOMETRY; EXPLORATION; PARAMETERS; INSIGHT; IMPACT; SHALES,"Permeability estimation and quantitative evaluation of pore microstructure have always been hotspots and difficulties in tight sandstone reservoirs research. Taking the fractal dimension as the breakthrough, 10 core samples of Chang 7 section in the Upper Triassic Yanchang Formation were collected from different wells in Longdong area of Ordos Basin. The fractal dimension was calculated by mercury intrusion capillary pressure curve which can be obtained from high pressure mercury injection experiment, and samples were divided into four groups as group I, II, III and IV according to the value of fractal dimension estimated. The observation of casting thin sections and field emission scanning electron microscope show that group I mainly has dissolved-intergranular pores and original intergranular pores, group II is mainly dissolved-intergranular pores, group III mainly has dissolved-intragranular pores, and group IV is mainly micropores in clay matrix. Meanwhile, there is a highly correlation between the fractal dimension and the reservoir physical properties. With the fractal dimension of tight sandstone samples approaching 3, the compaction and cementation show a gradual increase, while the pore sorting, physical parameters and percolation capacity display a gradual decrease. Through multiple regression analysis, a set of empirical equations based on the fractal dimension and different pore throat radius were constructed, in which the equation based on maximum permeability contribution radius has the highest correlation. It shows that micropore (0.1-0.2 mu m) contributes most to permeability in tight sandstone reservoir. 10 blind samples were included in regression analysis to improve the prediction accuracy of the new model. A total of 28 samples, including 8 referenced data, were used to verify the predictive accuracy of the new model. The new empirical equation can predict the permeability of tight sandstone relatively accurate. Thus, the fractal dimension can effectively predict the permeability and evaluate the quality of tight sandstone reservoirs.",29,29,7
ORDOS BASIN,Mu M,"Cheng, Guoxi; Jiang, Bo; Li, Ming; Li, Fengli; Song, Yu",Effects of pore-fracture structure of ductile tectonically deformed coals on their permeability: An experimental study based on raw coal cores,Ductile tectonically deformed coal; Pore-fracture structure; Surface fractal characteristics; Permeability; Suxian mining area,CH4 ADSORPTION CAPACITY; STRESS SENSITIVITY; FINES GENERATION; ORDOS BASIN; RANK COAL; DIMENSION; COMPRESSIBILITY; ROUGHNESS; PARTICLES; RESERVOIR,"The distribution area of ductile tectonically deformed coals (TDCs) usually coincides with the forbidden zones for coalbed methane (CBM) development. Permeability of coal reservoirs, an important indicator to evaluate the energy potential of CBM, is directly affected by the pore-fracture structures. To study the controlling mechanism of pore-fracture structures on permeability, we investigated the micropore - micro-fracture structures of various ductile TDCs by adopting mercury intrusion porosimetry (MIP) and low-pressure gas adsorption. The permeability and the pressure sensitivity of the standard TDC cores were tested by the pressure pulse decay method. The results showed that the total pore volume of ductile TDCs, especially the mesopores and macropores, significantly increased from that of primary structure coals (PSCs), while the volume of transitional pores only slightly increased in strongly crumpled and mylonitized coals, and thus, the dominant pores in coals gradually changed from micro-fractures to mesopores and macropores. The pore-fracture structure of ductile TDCs showed a poorer connectivity and a higher roughness than PSCs. The permeability of typical ductile TDCs obviously decreased, the permeability heterogeneity significantly increased, and the pressure sensitivity of permeability generally showed a pattern of ""weakly crumpled - > PSCs > strongly crumpled - and mylonitized coals"". Correlation analysis showed that the weakly crumpled coals that contain well-developed and well-connected microfractures and fewer <10 mu m coal particles usually display high permeability. In strongly crumpled - and mylonitized coals, the connected pore-fracture structures were damaged and many pore throats and flask-shaped pores formed, which is the main reason for the reduced permeability and the high permeability damage rate.",11,10,4
ORDOS BASIN,Mu M,"Du, Shuheng","Characteristics and the formation mechanism of the heterogeneous microfractures in the tight oil reservoir of Ordos Basin, China",Microfracture; Formation mechanism; Tight oil; Sandstone; Characterization,SANDSTONE RESERVOIR; FRACTURE NETWORK; PERMEABILITY; INSPIRATION; SIMULATION; ANISOTROPY; MODELS; SHALE; FLOW,"This study aims to investigate the characteristics and the formation mechanism of the heterogeneous microfractures in the upper Triassic Yanchang Formation tight oil reservoir of Ordos Basin, China with some new perspectives. In this paper, we define two sets of parameters describing the size and geometry of microfractures by using Feret diameter calculation and Legendre ellipse fitting. Then the unidirectional fracture zone and multidirectional fracture zone are also be defined. Results of the microfractures characterization show that when the lengths of microfractures are less than 600 mu m (and the widths are less than 90 mu m), the above two set of data show a good linear positive correlation, but when the lengths of microfractures continue to increase, the widths of microfractures begin to deviate from the linear relationship and gradually diverge. This indicates that the lengths and widths of microfractures are not strictly and steadily correlated, but their correlation has a threshold value. If the lengths of microfractures increase due to the change of internal or external stress, when the length value is higher than a certain value, the opening process of microfractures will begin to lose stability, and the widths will change gradually irregularly. Once the compaction process reach a certain extent, some of the microfractures opened previously will be temporarily closed, which will greatly promote the process of pressure-solution, and thus increase the microfracture tortuosity. The length, width, solidity and boundary tortuosity of microfractures could be used to distinguish two zones include the multi-directional fracture zone from the unidirectional fracture zone. The conclusion would provide the important scientific basis for the EOR applications of tight oil.",11,11,1
ORDOS BASIN,Mu M,"Cai, Laixing; Guo, Xingwei; Zhang, Xunhua; Zeng, Zhigang; Xiao, Guolin; Pang, Yumao; Wang, Shuping","Pore-throat structures of the Permian Longtan Formation tight sandstones in the South Yellow Sea Basin, China: A case study from borehole CSDP-2",Pore-throat structure; Reservoir quality; Formation mechanism; Tight sandstone; Longtan formation; Borehole CSDP-2; South Yellow Sea Basin,UNCONVENTIONAL HYDROCARBON RESOURCES; RATE-CONTROLLED POROSIMETRY; PRESSURE MERCURY INTRUSION; SICHUAN BASIN; YANCHANG FORMATION; OIL-RESERVOIRS; ORDOS BASIN; CENTRAL UPLIFT; FRACTAL CHARACTERISTICS; LOW PERMEABILITY,"With good exploration prospects and proven source rocks in Permian, reservoir evaluation has become the main bottleneck hindering petroleum exploration in the South Yellow Sea Basin, China, where the pore-throat structures, which are particularly important for the reservoir quality of tight sandstones, have never been characterized. To solve this, tight sandstones taken from borehole CSDP-2 of the Permian Longtan (P(2)l) Formation were systemically investigated with high-precision pore-throat characterization methods. The results show that pore-throat structures of tight sandstones in the Longtan Formation can be classified into three categories with synthesis considerations of pore-throat type, size, and connectivity; these pore-throats are denoted lattice-like, tubular, and isolated, respectively. The lattice-like pore throats with relatively larger radii (>0.1 mu m) and higher connectivity exhibit the best performance for reservoir quality, followed by tubular pore-throat structures, while isolated pore throats have almost no capacity to migrate or store fluids. In the formation mechanism of various pore-throat structures, both the plastic component content and complex diagenesis play a significant role. Strong compaction results in a loss of nearly half of the initial porosity (av. 49.81%) during the initial diagenetic stage. Then, clay mineral cements partially occlude pores and throats, which are the dominant factors in the transition of pore-throat structures from lattice-like to tubular. Silica and carbonate cementation are the key processes that fill the primary pore throats, secondary dissolution pores, and microfractures, leading to the formation of isolated pore-throat structures and low-porosity, ultra-low-permeability reservoirs. Feldspar dissolution cannot take place on a large scale due to the early densification of the sandstone, and it does not significantly improve the reservoir quality; it increases the porosity by less than 4.0%. This research provides constructive insights into the coupled evolution of pore-throat structures and diagenetic processes, which can aid in further understanding the formation mechanism of tight sandstones. In practice, this work also provides a scientific basis for identifying effective reservoirs, and promotes petroleum exploration in the South Yellow Sea Basin, China.",10,11,4
ORDOS BASIN,Mu M,"Li, Sihai; Zhang, Shicheng; Zou, Yushi; Ma, Xinfang; Ding, Yao; Li, Ning; Zhang, Xi; Kasperczyk, Dane",Pore structure alteration induced by CO2-brine-rock interaction during CO2 energetic fracturing in tight oil reservoirs,CO2-brine-rock interaction; Pore structure; CO2 energetic fracturing; Tight oil,SUPERCRITICAL CO2; NMR RELAXATION; ORDOS BASIN; SHALE GAS; WATER; SEQUESTRATION; FLUIDS; EXPLORATION; REACTIVITY; RECOVERY,"CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2-brine-rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2-brine-rock interaction generated many large pores (10-50 mu m) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1-6 mu m) and some microfractures in clays. The T-2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2-brine-rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T-2 distributions transformed into apparent dual-peak T-2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 degrees C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 mu m to 0.166 mu m, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.",7,9,6
ORDOS BASIN,Reservoir Quality,"Guo, Ruiliang; Xie, Qichao; Qu, Xuefeng; Chu, Meijuan; Li, Shutong; Ma, Dongxu; Ma, Xiaofeng","Fractal characteristics of pore-throat structure and permeability estimation of tight sandstone reservoirs: A case study of Chang 7 of the Upper Triassic Yanchang Formation in Longdong area, Ordos Basin, China",Fractal dimension; Tight sandstone reservoirs; Yanchang Formation; Permeability estimation; Mercury intrusion capillary pressure,CAPILLARY-PRESSURE; OIL; POROSITY; MICROGEOMETRY; EXPLORATION; PARAMETERS; INSIGHT; IMPACT; SHALES,"Permeability estimation and quantitative evaluation of pore microstructure have always been hotspots and difficulties in tight sandstone reservoirs research. Taking the fractal dimension as the breakthrough, 10 core samples of Chang 7 section in the Upper Triassic Yanchang Formation were collected from different wells in Longdong area of Ordos Basin. The fractal dimension was calculated by mercury intrusion capillary pressure curve which can be obtained from high pressure mercury injection experiment, and samples were divided into four groups as group I, II, III and IV according to the value of fractal dimension estimated. The observation of casting thin sections and field emission scanning electron microscope show that group I mainly has dissolved-intergranular pores and original intergranular pores, group II is mainly dissolved-intergranular pores, group III mainly has dissolved-intragranular pores, and group IV is mainly micropores in clay matrix. Meanwhile, there is a highly correlation between the fractal dimension and the reservoir physical properties. With the fractal dimension of tight sandstone samples approaching 3, the compaction and cementation show a gradual increase, while the pore sorting, physical parameters and percolation capacity display a gradual decrease. Through multiple regression analysis, a set of empirical equations based on the fractal dimension and different pore throat radius were constructed, in which the equation based on maximum permeability contribution radius has the highest correlation. It shows that micropore (0.1-0.2 mu m) contributes most to permeability in tight sandstone reservoir. 10 blind samples were included in regression analysis to improve the prediction accuracy of the new model. A total of 28 samples, including 8 referenced data, were used to verify the predictive accuracy of the new model. The new empirical equation can predict the permeability of tight sandstone relatively accurate. Thus, the fractal dimension can effectively predict the permeability and evaluate the quality of tight sandstone reservoirs.",29,29,7
ORDOS BASIN,Reservoir Quality,"Cai, Laixing; Guo, Xingwei; Zhang, Xunhua; Zeng, Zhigang; Xiao, Guolin; Pang, Yumao; Wang, Shuping","Pore-throat structures of the Permian Longtan Formation tight sandstones in the South Yellow Sea Basin, China: A case study from borehole CSDP-2",Pore-throat structure; Reservoir quality; Formation mechanism; Tight sandstone; Longtan formation; Borehole CSDP-2; South Yellow Sea Basin,UNCONVENTIONAL HYDROCARBON RESOURCES; RATE-CONTROLLED POROSIMETRY; PRESSURE MERCURY INTRUSION; SICHUAN BASIN; YANCHANG FORMATION; OIL-RESERVOIRS; ORDOS BASIN; CENTRAL UPLIFT; FRACTAL CHARACTERISTICS; LOW PERMEABILITY,"With good exploration prospects and proven source rocks in Permian, reservoir evaluation has become the main bottleneck hindering petroleum exploration in the South Yellow Sea Basin, China, where the pore-throat structures, which are particularly important for the reservoir quality of tight sandstones, have never been characterized. To solve this, tight sandstones taken from borehole CSDP-2 of the Permian Longtan (P(2)l) Formation were systemically investigated with high-precision pore-throat characterization methods. The results show that pore-throat structures of tight sandstones in the Longtan Formation can be classified into three categories with synthesis considerations of pore-throat type, size, and connectivity; these pore-throats are denoted lattice-like, tubular, and isolated, respectively. The lattice-like pore throats with relatively larger radii (>0.1 mu m) and higher connectivity exhibit the best performance for reservoir quality, followed by tubular pore-throat structures, while isolated pore throats have almost no capacity to migrate or store fluids. In the formation mechanism of various pore-throat structures, both the plastic component content and complex diagenesis play a significant role. Strong compaction results in a loss of nearly half of the initial porosity (av. 49.81%) during the initial diagenetic stage. Then, clay mineral cements partially occlude pores and throats, which are the dominant factors in the transition of pore-throat structures from lattice-like to tubular. Silica and carbonate cementation are the key processes that fill the primary pore throats, secondary dissolution pores, and microfractures, leading to the formation of isolated pore-throat structures and low-porosity, ultra-low-permeability reservoirs. Feldspar dissolution cannot take place on a large scale due to the early densification of the sandstone, and it does not significantly improve the reservoir quality; it increases the porosity by less than 4.0%. This research provides constructive insights into the coupled evolution of pore-throat structures and diagenetic processes, which can aid in further understanding the formation mechanism of tight sandstones. In practice, this work also provides a scientific basis for identifying effective reservoirs, and promotes petroleum exploration in the South Yellow Sea Basin, China.",10,11,4
ORDOS BASIN,Reservoir Quality,"Liu, Longlong; Li, Yang; Dong, Hongzhi; Sun, Zhongqiang","Diagenesis and reservoir quality of Paleocene tight sandstones, Lishui Sag, East China Sea Shelf Basin",Diagenesis; Tight sandstones; Reservoir quality; Controlling factors; Lishui Sag,ZHENJING AREA; ORDOS BASIN; COMPACTION PROCESSES; RELATIVE IMPORTANCE; BEARING SANDSTONES; OIL SANDSTONES; QUARTZ CEMENT; MASS-TRANSFER; POROSITY; IMPACT,"The Lishui Sag in the East China Sea Shelf Basin (ECSSB) has significant potential hydrocarbon resources, with Paleocene sandstones as its main oil and gas-bearing reservoir. The sandstones in the Paleocene formations are mainly composed of medium-grained, moderately sorted litharenite. In this study, distributions of the porosity and permeability reveal that the Paleocene sandstones have the characteristics of medium porosity and low permeability. The sedimentary microfacies, primary texture, diagenesis, and bioturbation jointly control the reservoir quality. Sandstones with distributary channel and sand bar sedimentary microfacies as well as better sorting tend to exhibit a higher quality. Compaction and carbonate cementation are the major determinants to reductions in porosity and permeability. Grain-coating chlorites within a certain content range may play a positive role in the preservation of porosity in eodiagenesis. Early dissolution has a constructive effect on the reservoir quality. In contrast, the dissolution products such as kaolinite and dawsonite cannot move over a long distance and precipitate nearby to block the intergranular pores when reservoir closure increases. Therefore, dissolution in a relatively closed geochemical reservoir system may contribute little to porosity. Contrastingly, the permeability of the Paleocene reservoir may be reduced by the conversion of the pore network. In the Lishui Sag, the bioturbation plays a role in the deterioration of reservoir quality in a limited scale by decreasing reservoir sorting and increasing compaction.",8,8,7
ORDOS BASIN,Reservoir Quality,"Qiao, Juncheng; Zeng, Jianhui; Ma, Yong; Jiang, Shu; Feng, Sen; Hu, Huiting",Effects of mineralogy on pore structure and fluid flow capacity of deeply buried sandstone reservoirs with a case study in the Junggar Basin,Deeply buried sandstone; Mineralogy; Pore structure; Fluid flow capacity,ANOMALOUSLY HIGH-POROSITY; TIGHT GAS SANDSTONES; CAPILLARY-PRESSURE; ORDOS BASIN; PETROPHYSICAL PROPERTIES; FRACTAL ANALYSIS; SONGLIAO BASIN; QUALITY PREDICTION; THROAT STRUCTURE; CARBONATE ROCKS,"Integrated experiments including porosity, permeability, casting thin section (CTS), scanning electron microscopy (SEM), pressure-controlled mercury porosimetry (PCP), rate-controlled mercury porosimetry (RCP), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) are conducted to investigate the impacts of mineralogy on the pore structure and fluid flow capacity of the deeply buried sandstone in the Jurassic Sangonghe Formation of the Junggar Basin. The results indicate that the heterogeneous deeply buried sandstone is rich in quartz (54.2%), feldspar (25.1%), and clay (14.2%), with dominant kaolinite and chlorite cementation. The reservoir has a variable overall pore-throat diameter distribution with three peaks in the ranges 0.01-1, 10-80, and 200-1000 mu m. Pores are tri-fractal and can be divided into micropores, mesopores, and macropores. The movable porosity is primarily contributed by intergranular and intragranular pores and widely ranges from 1.75 to 8.24%. Most of the fluids are movable in intergranular pores but are irreducible in intragranular pores. Correlation analyses indicate that quartz benefits the intergranular porosity preservation, increasing pore size and macropores porosity, and reducing heterogeneities of the macropores, micropores, and pore system. Feldspar exhibits poorly opposite influences due to the simultaneous clay precipitation and complex roles of feldspar dissolution in the microporosity. All of the clay minerals act as destructions to intergranular porosity, enhancing the mesopores and micropores porosities, reducing the pore size, and increasing the heterogeneities of the macropores, micropores, and pore system. Quartz is favorable for the fluid flow capacity of deeply buried sandstone, but feldspar and clay play negative roles. The reversed impacts of quartz and feldspar lay in their opposite controls on pore size. Both pore size and hydrophilia should be taken into account when considering the effects of clay. This negative effect is associated with types, contents, hydrophilic degrees of clay minerals, in which I/S and illite exhibit the strongest influences. The fluid flow in the intergranular and intragranular pores is generally enhanced by higher quartz content, and reduced by higher clay content.",7,7,6
ORDOS BASIN,Controlling Factors,"Liu, Bo; Yang, Yuqi; Li, Jiangtao; Chi, Yaao; Li, Junhui; Fu, Xiaofei","Stress sensitivity of tight reservoirs and its effect on oil saturation: A case study of Lower Cretaceous tight clastic reservoirs in the Hailar Basin, Northeast China",Stress sensitivity; Seepage characteristics; Pore structure; Tight oil; Hailar Basin,TRIASSIC YANCHANG FORMATION; SANDSTONE RESERVOIR; ORDOS BASIN; PERMEABILITY; GAS; DIAGENESIS; EVOLUTION; ROCKS; AREA,"To analyze stress sensitivity of tight reservoirs and the boundary conditions for oil filling, core samples of tight clastic reservoirs in the Lower Cretaceous Nantun Formation in the Hailar Basin were selected. The measurements include optical observation of thin sections, changes of porosity and permeability under overburden pressure, together with physical simulation experiments of oil filling. The results show that the stress sensitivity coefficient of permeability is a product of two parameters including the power exponent of porosity-permeability and pore compressibility, which reflect the geometric and mechanical characteristics of pores. The stress sensitivity and pore geometry of tight reservoirs of different lithologies vary greatly. Medium-coarse sandstones-conglomerates have relatively small stress sensitivity coefficient and large power exponent of porosity-permeability, indicating stronger anti-compaction, weaker stress sensitivity and dominated fissure-type pores. Fine sandstone with large stress sensitivity coefficient and small power exponent of porosity-permeability, indicating that stress sensitivity is high, and matrix circular/elliptical pores predominate. Oil filling in tight reservoirs displays two pressure gradient points with threshold characteristics (i.e., starting pressure gradient and critical pressure gradient) and two flow characteristics (i.e., low-speed nonlinear seepage and quasi-linear seepage). Only when the actual pressure gradient breaks through the critical pressure gradient into the quasi-linear seepage zone can oil saturation in the tight reservoir reach the lower limit of 30%, attaining higher oil saturation levels gradually during the subsequent filling process. The favorable tight reservoir is characterized by a low stress sensitivity coefficient and a high power exponent of porosity-permeability, and oil exhibits rapid filling characteristics with quasi-linear seepage. Another type of tight reservoir is characterized by a high stress sensitivity coefficient and a low power exponent of porosity-permeability, and oil exhibits slow filling rate with nonlinear seepage. It is therefore difficult in actual geological conditions for such reservoirs to achieve high oil saturation. Increase in oil saturation during the filling process is controlled by a combination of initial permeability, pore geometry, stress sensitivity and the displacement pressure gradient. These factors affect and compensate each other, comprehensively controlling the accumulation of tight oil, and could be used to classify the reservoir types.",57,59,12
ORDOS BASIN,Controlling Factors,"Wang, Xixin; Hou, Jiagen; Li, Shaohua; Dou, Luxing; Song, Suihong; Kang, Qiangqiang; Wang, Dongmei","Insight into the nanoscale pore structure of organic-rich shales in the Bakken Formation, USA",Bakken shale; Pore structure; Controlling factors; Fractal dimension,SILURIAN LONGMAXI SHALES; CANADA SEDIMENTARY BASIN; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; SICHUAN BASIN; CO2 ADSORPTION; SURFACE-AREA; ORDOS BASIN; SIZE; N-2,"The Bakken Shale has attracted much attention because of its huge potential for shale oil. To characterize the nanoscale pore structure of the Bakken shale, ten samples were selected from the upper/lower Bakken Shale for N-2 and CO2 adsorption, which can provide the pore structure parameters, such as pore size, specific surface area (SSA) and pore volume. The controlling factors of the pore structure were studied through the analysis of the mineral composition, total organic carbon (TOC) content, and thermal maturity (VRo-eq). Also, we investigated the fractal characteristics of samples based upon N-2 adsorption. The results exhibited that the composition of the Bakken shale was mainly quartz and clay; the content of clay minerals varies between 24.07% and 53.92%; the content of quartz is between 38.04% and 63.59%. The average value of TOC content of the Bakken shale was 11.49 wt% and the vitrinite equivalent reflectance varied between 0.62 and 1.11%. Micropores (<2 nm) and mesopores (2-50 nm) are the dominant pores in the Bakken shale samples. Quartz, clay and TOC are the key factors controlling the pore structure of Bakken shale. The fractal dimensions D-1 ranged from 2.606 to 2.896 and D-2 ranged from 2.243 to 2.296. D-1 shows a strong positive correlation with D-2, with an R-2 value of 0.8. Higher clay and TOC content lead to more complex pore systems in the Bakken shales. Smaller pore size leads to larger fractal dimensions; hence, the larger the SSA is, the larger fractal dimensions are.",28,29,1
ORDOS BASIN,Controlling Factors,"Yan, Jiwei; Meng, Zhaoping; Zhang, Kun; Yao, Huifang; Hao, Haijin",Pore distribution characteristics of various rank coals matrix and their influences on gas adsorption,Various rank coals; Pore size distribution; Controlling mechanism; Methane adsorption,MERCURY INTRUSION POROSIMETRY; SOUTHERN SICHUAN BASIN; X-RAY-SCATTERING; METHANE ADSORPTION; NANOPORE STRUCTURE; ORDOS BASIN; CO2; POROSITY; SORPTION; RESERVOIRS,"Methane is primarily stored in coal matrix pores and pore size distribution has an important effect on gas adsorption/desorption. Investigation of the relationship between pore size distribution and adsorption performance of coal is of significance for the understanding of the evolution of coalbed methane reservoirs. In this study, a series of laboratory experiments (nitrogen, carbon dioxide and methane adsorption) were carried out to determine the pore size distribution and adsorption capacity of coal samples of various coal ranks. The relationship between pore size distribution, Langmuir volume and the metamorphic degree of coals were established. The factors influencing methane adsorption of coals were also analyzed. The results show that the matrix pores are mainly cylindrical, thin bottleneck-, ink bottleneck- and parallel plate-shaped. With the increase in coal rank, both the total pore volume and the specific surface area initially decrease and then increase. Matrix pores, including micro-, transitional- and mesopores, show a similar asymmetric U-shaped trend in the pore volume and the specific surface area with an increase in coal rank. The percentages by volume and by specific surface area increase for the micropores and declines for the transitional pores and mesopores. In the low-pressure zone, micro- and transitional pores play a dominant role in methane adsorption; however, in the high-pressure zone, the influence of mesopores on methane adsorption is pronounced.",22,24,17
ORDOS BASIN,Controlling Factors,"Liu, Longlong; Li, Yang; Dong, Hongzhi; Sun, Zhongqiang","Diagenesis and reservoir quality of Paleocene tight sandstones, Lishui Sag, East China Sea Shelf Basin",Diagenesis; Tight sandstones; Reservoir quality; Controlling factors; Lishui Sag,ZHENJING AREA; ORDOS BASIN; COMPACTION PROCESSES; RELATIVE IMPORTANCE; BEARING SANDSTONES; OIL SANDSTONES; QUARTZ CEMENT; MASS-TRANSFER; POROSITY; IMPACT,"The Lishui Sag in the East China Sea Shelf Basin (ECSSB) has significant potential hydrocarbon resources, with Paleocene sandstones as its main oil and gas-bearing reservoir. The sandstones in the Paleocene formations are mainly composed of medium-grained, moderately sorted litharenite. In this study, distributions of the porosity and permeability reveal that the Paleocene sandstones have the characteristics of medium porosity and low permeability. The sedimentary microfacies, primary texture, diagenesis, and bioturbation jointly control the reservoir quality. Sandstones with distributary channel and sand bar sedimentary microfacies as well as better sorting tend to exhibit a higher quality. Compaction and carbonate cementation are the major determinants to reductions in porosity and permeability. Grain-coating chlorites within a certain content range may play a positive role in the preservation of porosity in eodiagenesis. Early dissolution has a constructive effect on the reservoir quality. In contrast, the dissolution products such as kaolinite and dawsonite cannot move over a long distance and precipitate nearby to block the intergranular pores when reservoir closure increases. Therefore, dissolution in a relatively closed geochemical reservoir system may contribute little to porosity. Contrastingly, the permeability of the Paleocene reservoir may be reduced by the conversion of the pore network. In the Lishui Sag, the bioturbation plays a role in the deterioration of reservoir quality in a limited scale by decreasing reservoir sorting and increasing compaction.",8,8,7
ORDOS BASIN,Controlling Factors,"Ma, Jian; Liu, Guoheng; Huang, Zhilong; Ou, Guangxi; Li, Tianjun; Guo, Xiaobo","Tight tuff reservoir characteristics and its controlling factors: A comparative study of the Permian Tiaohu Formation and Carboniferous Haerjiawu Formation in the Santanghu Basin, NW China",Tight tuff reservoir; Porosity; Alteration; Haerjiawu Formation; Santanghu Basin,BASALTIC GLASS DISSOLUTION; GRAINED SEDIMENTARY-ROCKS; BOHAI BAY BASIN; LUCAOGOU FORMATION; VOLCANIC-ROCKS; GEOCHEMICAL CHARACTERISTICS; YANCHANG FORMATION; JIMUSAER SAG; ACID ANIONS; ORDOS BASIN,"Tight oil resources have been found in tight tuff reservoirs in many oil and gas bearing basins. The tight tuff reservoir developed in the Santanghu Basin (NW China) has provided an excellent opportunity for further research to enhance our cognition and understanding of tuff reservoir characteristics. This study focuses on the differences in the basic characteristics in petrologic features, reservoir space, and physical properties between the Tiaohu and Haerjiawu formations tuff reservoirs, then determines the formation mechanism causing these differences. (1) The tuff samples of the Tiaohu Formation mainly consist of vitric fragments, and quartz and albite are the major mineralogical components. However, the crystal fragment content is much higher in the Haerjiawu Formation tuff, and albite and anorthite are the major components. (2) Primary pores and the interparticle pores among authigenic minerals formed during alteration are the main pore types for both the Tiaohu Formation and Haerjiawu Formation tuffS. (3) The Tiaohu Formation tuff reservoir is characterized by high porosity (ranging from 10% to 25%) and relatively low permeability (on the order of 0.01-0.50 mD), while that of the Haerjiawu Formation is characterized by lower porosity (<10%) and lower permeability (mainly <0.1 mD). (4) Alteration and compaction processes contributed most to the pore formation in both the Tiaohu and Haerjiawu tuff reservoirs. Hence, the changes in total tuff reservoir porosity can be explained by the evaluation of compaction residual porosity and alteration porosity. The vitric fragments in the Tiaohu Formation originated from acidic or intermediate-acidic volcanic ashes, which are more liable to be altered than the basic volcanic ashes that formed the crystal fragments in the Haerjiawu Formation. Moreover, the Haerjiawu Formation tuff reservoir is buried hundreds of metres deeper than the Tiaohu Formation in general, and thus, experienced stronger diagenetic compaction, which indicates fewer residual pores for Haerjiawu Formation tuff samples. The nature of tuff and the deeper burial depth are the major reasons for the worse physical properties of the Haerjiawu Formation tuff reservoir.",8,8,5
ORDOS BASIN,Stress Sensitivity,"Liu, Bo; Yang, Yuqi; Li, Jiangtao; Chi, Yaao; Li, Junhui; Fu, Xiaofei","Stress sensitivity of tight reservoirs and its effect on oil saturation: A case study of Lower Cretaceous tight clastic reservoirs in the Hailar Basin, Northeast China",Stress sensitivity; Seepage characteristics; Pore structure; Tight oil; Hailar Basin,TRIASSIC YANCHANG FORMATION; SANDSTONE RESERVOIR; ORDOS BASIN; PERMEABILITY; GAS; DIAGENESIS; EVOLUTION; ROCKS; AREA,"To analyze stress sensitivity of tight reservoirs and the boundary conditions for oil filling, core samples of tight clastic reservoirs in the Lower Cretaceous Nantun Formation in the Hailar Basin were selected. The measurements include optical observation of thin sections, changes of porosity and permeability under overburden pressure, together with physical simulation experiments of oil filling. The results show that the stress sensitivity coefficient of permeability is a product of two parameters including the power exponent of porosity-permeability and pore compressibility, which reflect the geometric and mechanical characteristics of pores. The stress sensitivity and pore geometry of tight reservoirs of different lithologies vary greatly. Medium-coarse sandstones-conglomerates have relatively small stress sensitivity coefficient and large power exponent of porosity-permeability, indicating stronger anti-compaction, weaker stress sensitivity and dominated fissure-type pores. Fine sandstone with large stress sensitivity coefficient and small power exponent of porosity-permeability, indicating that stress sensitivity is high, and matrix circular/elliptical pores predominate. Oil filling in tight reservoirs displays two pressure gradient points with threshold characteristics (i.e., starting pressure gradient and critical pressure gradient) and two flow characteristics (i.e., low-speed nonlinear seepage and quasi-linear seepage). Only when the actual pressure gradient breaks through the critical pressure gradient into the quasi-linear seepage zone can oil saturation in the tight reservoir reach the lower limit of 30%, attaining higher oil saturation levels gradually during the subsequent filling process. The favorable tight reservoir is characterized by a low stress sensitivity coefficient and a high power exponent of porosity-permeability, and oil exhibits rapid filling characteristics with quasi-linear seepage. Another type of tight reservoir is characterized by a high stress sensitivity coefficient and a low power exponent of porosity-permeability, and oil exhibits slow filling rate with nonlinear seepage. It is therefore difficult in actual geological conditions for such reservoirs to achieve high oil saturation. Increase in oil saturation during the filling process is controlled by a combination of initial permeability, pore geometry, stress sensitivity and the displacement pressure gradient. These factors affect and compensate each other, comprehensively controlling the accumulation of tight oil, and could be used to classify the reservoir types.",57,59,12
ORDOS BASIN,Stress Sensitivity,"Cheng, Guoxi; Jiang, Bo; Li, Ming; Li, Fengli; Song, Yu",Effects of pore-fracture structure of ductile tectonically deformed coals on their permeability: An experimental study based on raw coal cores,Ductile tectonically deformed coal; Pore-fracture structure; Surface fractal characteristics; Permeability; Suxian mining area,CH4 ADSORPTION CAPACITY; STRESS SENSITIVITY; FINES GENERATION; ORDOS BASIN; RANK COAL; DIMENSION; COMPRESSIBILITY; ROUGHNESS; PARTICLES; RESERVOIR,"The distribution area of ductile tectonically deformed coals (TDCs) usually coincides with the forbidden zones for coalbed methane (CBM) development. Permeability of coal reservoirs, an important indicator to evaluate the energy potential of CBM, is directly affected by the pore-fracture structures. To study the controlling mechanism of pore-fracture structures on permeability, we investigated the micropore - micro-fracture structures of various ductile TDCs by adopting mercury intrusion porosimetry (MIP) and low-pressure gas adsorption. The permeability and the pressure sensitivity of the standard TDC cores were tested by the pressure pulse decay method. The results showed that the total pore volume of ductile TDCs, especially the mesopores and macropores, significantly increased from that of primary structure coals (PSCs), while the volume of transitional pores only slightly increased in strongly crumpled and mylonitized coals, and thus, the dominant pores in coals gradually changed from micro-fractures to mesopores and macropores. The pore-fracture structure of ductile TDCs showed a poorer connectivity and a higher roughness than PSCs. The permeability of typical ductile TDCs obviously decreased, the permeability heterogeneity significantly increased, and the pressure sensitivity of permeability generally showed a pattern of ""weakly crumpled - > PSCs > strongly crumpled - and mylonitized coals"". Correlation analysis showed that the weakly crumpled coals that contain well-developed and well-connected microfractures and fewer <10 mu m coal particles usually display high permeability. In strongly crumpled - and mylonitized coals, the connected pore-fracture structures were damaged and many pore throats and flask-shaped pores formed, which is the main reason for the reduced permeability and the high permeability damage rate.",11,10,4
ORDOS BASIN,Nanoscale Pore Structure,"Wang, Xixin; Hou, Jiagen; Li, Shaohua; Dou, Luxing; Song, Suihong; Kang, Qiangqiang; Wang, Dongmei","Insight into the nanoscale pore structure of organic-rich shales in the Bakken Formation, USA",Bakken shale; Pore structure; Controlling factors; Fractal dimension,SILURIAN LONGMAXI SHALES; CANADA SEDIMENTARY BASIN; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; SICHUAN BASIN; CO2 ADSORPTION; SURFACE-AREA; ORDOS BASIN; SIZE; N-2,"The Bakken Shale has attracted much attention because of its huge potential for shale oil. To characterize the nanoscale pore structure of the Bakken shale, ten samples were selected from the upper/lower Bakken Shale for N-2 and CO2 adsorption, which can provide the pore structure parameters, such as pore size, specific surface area (SSA) and pore volume. The controlling factors of the pore structure were studied through the analysis of the mineral composition, total organic carbon (TOC) content, and thermal maturity (VRo-eq). Also, we investigated the fractal characteristics of samples based upon N-2 adsorption. The results exhibited that the composition of the Bakken shale was mainly quartz and clay; the content of clay minerals varies between 24.07% and 53.92%; the content of quartz is between 38.04% and 63.59%. The average value of TOC content of the Bakken shale was 11.49 wt% and the vitrinite equivalent reflectance varied between 0.62 and 1.11%. Micropores (<2 nm) and mesopores (2-50 nm) are the dominant pores in the Bakken shale samples. Quartz, clay and TOC are the key factors controlling the pore structure of Bakken shale. The fractal dimensions D-1 ranged from 2.606 to 2.896 and D-2 ranged from 2.243 to 2.296. D-1 shows a strong positive correlation with D-2, with an R-2 value of 0.8. Higher clay and TOC content lead to more complex pore systems in the Bakken shales. Smaller pore size leads to larger fractal dimensions; hence, the larger the SSA is, the larger fractal dimensions are.",28,29,1
ORDOS BASIN,Nanoscale Pore Structure,"Shan, Changan; Zhao, Weiwei; Wang, Fengqin; Zhang, Kun; Feng, Zhao; Guo, Liulinbo; Ma, Xueli; Liao, Tian","Nanoscale pore structure heterogeneity and its quantitative characterization in Chang7 lacustrine shale of the southeastern Ordos Basin, China",Nanoscale pore structure heterogeneity; Quantitative characterization; Chang7 lacustrine shale; Fractal characteristic,TRIASSIC YANCHANG FORMATION; SOUTHERN SICHUAN BASIN; CH4 ADSORPTION CAPACITY; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; LONGMAXI SHALE; GEOCHEMICAL CHARACTERISTICS; ELECTRON-MICROSCOPY; MERCURY-INTRUSION; RESERVOIR,"To gain a better understanding of nanoscale pore structure characteristics in Chang7 lacustrine shale, Ordos Basin, China, 33 shale samples from 15 wells are examined and analyzed by total organic carbon (TOC), X-ray diffraction (XRD), mercury porosimetry, helium pycnometry, low-pressure N-2 adsorption experiments and fractal method. The results show that Chang7 lacustrine shale pores diameter is mainly from 1.5 to 5 nm, and mesopores give the largest contribution to the total pore specific surface area (S-BET) and volume (V-BJH), and micropores have the second contribution to S-BET but little contribution to V-BJH, macropores have very little contribution to S-BET but make a good contribution to V-BJH. According to the occurrence and origin of shale pores, micro-pores can be divided into mineral intragranular pore, minera intercrystalline pore and organic pore. Two fractal dimensions (D1 and D2) are obtained from N-2 adsorption isotherms analysis using FHH method. Relationships between fractal dimensions and shale compositions, pore structure parameters are investigated, which show that both D1 and D2 have good positive relationships with S-BET and V-BJH, but obvious negative correlations with the average pore diameter. That is, the smaller the pore diameter, the more complex the pore structure is, resulting in the larger pore surface and volume. D1 and D2 are both positively correlated with total clay, illite, mixed-layer of illite-smectite, whereas no obvious relationships with chlorite, indicating that the layer and flocculent structure increase the complexity of nanoscale pore structure. TOC content has positive correlation with D1 but no obvious relationship with D2, indicating that the pores in organic matter are mostly micropores. Fractal dimensions are negatively correlated with total brittle mineral, quartz and feldspar content, that is because the surface of brittle minerals is smoother and more homogenous than that of clay minerals.",7,7,10
ORDOS BASIN,Spontaneous Imbibition,"Guo, Jianchun; Li, Ming; Chen, Chi; Tao, Liang; Liu, Zhuang; Zhou, Desheng",Experimental investigation of spontaneous imbibition in tight sandstone reservoirs,,OIL-RECOVERY; ORDOS BASIN; COCURRENT; GAS,,19,18,6
ORDOS BASIN,Spontaneous Imbibition,"Mao, Gangtao; Lai, Fengpeng; Li, Zhiping; Wei, Hexin; Zhou, Anqi",Characteristics of pore structure of tight gas reservoir and its influence on fluid distribution during fracturing,,ORDOS BASIN; SPONTANEOUS IMBIBITION; YANCHANG FORMATION; PETROPHYSICAL PROPERTY; SANDSTONE RESERVOIRS; CAPILLARY-PRESSURE; MOVABLE FLUID; OIL-RESERVOIR; SHALE; STORAGE,,9,9,8
ORDOS BASIN,SSA,"Wang, Xixin; Hou, Jiagen; Li, Shaohua; Dou, Luxing; Song, Suihong; Kang, Qiangqiang; Wang, Dongmei","Insight into the nanoscale pore structure of organic-rich shales in the Bakken Formation, USA",Bakken shale; Pore structure; Controlling factors; Fractal dimension,SILURIAN LONGMAXI SHALES; CANADA SEDIMENTARY BASIN; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; SICHUAN BASIN; CO2 ADSORPTION; SURFACE-AREA; ORDOS BASIN; SIZE; N-2,"The Bakken Shale has attracted much attention because of its huge potential for shale oil. To characterize the nanoscale pore structure of the Bakken shale, ten samples were selected from the upper/lower Bakken Shale for N-2 and CO2 adsorption, which can provide the pore structure parameters, such as pore size, specific surface area (SSA) and pore volume. The controlling factors of the pore structure were studied through the analysis of the mineral composition, total organic carbon (TOC) content, and thermal maturity (VRo-eq). Also, we investigated the fractal characteristics of samples based upon N-2 adsorption. The results exhibited that the composition of the Bakken shale was mainly quartz and clay; the content of clay minerals varies between 24.07% and 53.92%; the content of quartz is between 38.04% and 63.59%. The average value of TOC content of the Bakken shale was 11.49 wt% and the vitrinite equivalent reflectance varied between 0.62 and 1.11%. Micropores (<2 nm) and mesopores (2-50 nm) are the dominant pores in the Bakken shale samples. Quartz, clay and TOC are the key factors controlling the pore structure of Bakken shale. The fractal dimensions D-1 ranged from 2.606 to 2.896 and D-2 ranged from 2.243 to 2.296. D-1 shows a strong positive correlation with D-2, with an R-2 value of 0.8. Higher clay and TOC content lead to more complex pore systems in the Bakken shales. Smaller pore size leads to larger fractal dimensions; hence, the larger the SSA is, the larger fractal dimensions are.",28,29,1
ORDOS BASIN,SSA,"Wang, Yang; Liu, Luofu; Cheng, Hongfei","Pore structure of Triassic Yanchang mudstone, Ordos Basin: Insights into the impact of solvent extraction on porosity in lacustrine mudstone within the oil window",Pore structure; Solvent extraction; Nitrogen adsorption; Lacustrine mudstone; Oil window,CONTINENTAL TRANSITIONAL SHALE; ORGANIC-MATTER; SICHUAN BASIN; MARINE SHALE; GEOCHEMICAL CHARACTERISTICS; CHINA IMPLICATIONS; NETWORK EVOLUTION; THERMAL MATURITY; LONGMAXI SHALE; GAS,"Low-pressure nitrogen physisorption was performed on Triassic Yanchang mudstones before and after solvent extraction to characterize the extractable organic matter (EOM) occurrence and ascertain the impact of extracts on the nanoporosity of lacustrine mudstone within the oil window. Organic-rich Yanchang mudstones are currently thermally mature (vitrinite reflectance of 0.48%-0.92%). SEM-observed pore types chiefly comprise interparticle and intraparticle pores related to inorganic minerals, with organic matter pores less developed. Pore volume (PV) of the original mudstones is 0.35-2.15 cm(3)/100 g and the specific surface area (SSA) is 1.22-7.77 m(2)/g. Brittle minerals (quartz + feldspar + carbonates) and I/S mixed layer jointly show the positive effect on the pore space development in the Yanchang mudstone. Four groups of mudstones with obvious differences in pore structure properties were identified, which probably result from the various development degrees of interparticle pores at the edge of brittle minerals, and intraparticle pores associated with I/S aggregates. Generally, solvent extraction will result in a noticeable increase in the volume of N-2 adsorbed due to the reopening of pore space blocked by EOM, which is related to increases in PV an SSA. A declining case, probably caused by the progressive shift of the enlarged open pore space to the larger macropore range (d > 200 nm) which is not detected by N-2 adsorption and counteracts the increased porosity by extraction, however, was also observed in the current study. Overall, the infilling degree of EOM increased with increasing thermal evolution degree of shales within the oil window, which mainly blocks minor pores in lower mature samples but larger pores in higher mature samples.",13,13,6
ORDOS BASIN,Movable Fluid,"Mao, Gangtao; Lai, Fengpeng; Li, Zhiping; Wei, Hexin; Zhou, Anqi",Characteristics of pore structure of tight gas reservoir and its influence on fluid distribution during fracturing,,ORDOS BASIN; SPONTANEOUS IMBIBITION; YANCHANG FORMATION; PETROPHYSICAL PROPERTY; SANDSTONE RESERVOIRS; CAPILLARY-PRESSURE; MOVABLE FLUID; OIL-RESERVOIR; SHALE; STORAGE,,9,9,8
ORDOS BASIN,Movable Fluid,"Qiao, Juncheng; Zeng, Jianhui; Ma, Yong; Jiang, Shu; Feng, Sen; Hu, Huiting",Effects of mineralogy on pore structure and fluid flow capacity of deeply buried sandstone reservoirs with a case study in the Junggar Basin,Deeply buried sandstone; Mineralogy; Pore structure; Fluid flow capacity,ANOMALOUSLY HIGH-POROSITY; TIGHT GAS SANDSTONES; CAPILLARY-PRESSURE; ORDOS BASIN; PETROPHYSICAL PROPERTIES; FRACTAL ANALYSIS; SONGLIAO BASIN; QUALITY PREDICTION; THROAT STRUCTURE; CARBONATE ROCKS,"Integrated experiments including porosity, permeability, casting thin section (CTS), scanning electron microscopy (SEM), pressure-controlled mercury porosimetry (PCP), rate-controlled mercury porosimetry (RCP), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) are conducted to investigate the impacts of mineralogy on the pore structure and fluid flow capacity of the deeply buried sandstone in the Jurassic Sangonghe Formation of the Junggar Basin. The results indicate that the heterogeneous deeply buried sandstone is rich in quartz (54.2%), feldspar (25.1%), and clay (14.2%), with dominant kaolinite and chlorite cementation. The reservoir has a variable overall pore-throat diameter distribution with three peaks in the ranges 0.01-1, 10-80, and 200-1000 mu m. Pores are tri-fractal and can be divided into micropores, mesopores, and macropores. The movable porosity is primarily contributed by intergranular and intragranular pores and widely ranges from 1.75 to 8.24%. Most of the fluids are movable in intergranular pores but are irreducible in intragranular pores. Correlation analyses indicate that quartz benefits the intergranular porosity preservation, increasing pore size and macropores porosity, and reducing heterogeneities of the macropores, micropores, and pore system. Feldspar exhibits poorly opposite influences due to the simultaneous clay precipitation and complex roles of feldspar dissolution in the microporosity. All of the clay minerals act as destructions to intergranular porosity, enhancing the mesopores and micropores porosities, reducing the pore size, and increasing the heterogeneities of the macropores, micropores, and pore system. Quartz is favorable for the fluid flow capacity of deeply buried sandstone, but feldspar and clay play negative roles. The reversed impacts of quartz and feldspar lay in their opposite controls on pore size. Both pore size and hydrophilia should be taken into account when considering the effects of clay. This negative effect is associated with types, contents, hydrophilic degrees of clay minerals, in which I/S and illite exhibit the strongest influences. The fluid flow in the intergranular and intragranular pores is generally enhanced by higher quartz content, and reduced by higher clay content.",7,7,6
ORDOS BASIN,Silurian Longmaxi Formation,"Fan, Cunhui; Li, Hu; Qin, Qirong; He, Shun; Zhong, Cheng","Geological conditions and exploration potential of shale gas reservoir in Wufeng and Longmaxi Formation of southeastern Sichuan Basin, China",Shale gas; Geological conditions; Tectonic uplift; Preservation conditions; Longmaxi Formation; Southeastern Sichuan Basin,TIGHT SANDSTONE RESERVOIRS; PERMIAN LUCAOGOU FORMATION; ORDOS BASIN; UPPER ORDOVICIAN; TECTONIC FRACTURES; DINGSHAN AREA; SOUTH CHINA; OIL-SHALE; GEOCHEMICAL CHARACTERISTICS; PRESERVATION CONDITIONS,"The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R-o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration.",39,40,8
ORDOS BASIN,Silurian Longmaxi Formation,"Wang, Xixin; Hou, Jiagen; Li, Shaohua; Dou, Luxing; Song, Suihong; Kang, Qiangqiang; Wang, Dongmei","Insight into the nanoscale pore structure of organic-rich shales in the Bakken Formation, USA",Bakken shale; Pore structure; Controlling factors; Fractal dimension,SILURIAN LONGMAXI SHALES; CANADA SEDIMENTARY BASIN; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; SICHUAN BASIN; CO2 ADSORPTION; SURFACE-AREA; ORDOS BASIN; SIZE; N-2,"The Bakken Shale has attracted much attention because of its huge potential for shale oil. To characterize the nanoscale pore structure of the Bakken shale, ten samples were selected from the upper/lower Bakken Shale for N-2 and CO2 adsorption, which can provide the pore structure parameters, such as pore size, specific surface area (SSA) and pore volume. The controlling factors of the pore structure were studied through the analysis of the mineral composition, total organic carbon (TOC) content, and thermal maturity (VRo-eq). Also, we investigated the fractal characteristics of samples based upon N-2 adsorption. The results exhibited that the composition of the Bakken shale was mainly quartz and clay; the content of clay minerals varies between 24.07% and 53.92%; the content of quartz is between 38.04% and 63.59%. The average value of TOC content of the Bakken shale was 11.49 wt% and the vitrinite equivalent reflectance varied between 0.62 and 1.11%. Micropores (<2 nm) and mesopores (2-50 nm) are the dominant pores in the Bakken shale samples. Quartz, clay and TOC are the key factors controlling the pore structure of Bakken shale. The fractal dimensions D-1 ranged from 2.606 to 2.896 and D-2 ranged from 2.243 to 2.296. D-1 shows a strong positive correlation with D-2, with an R-2 value of 0.8. Higher clay and TOC content lead to more complex pore systems in the Bakken shales. Smaller pore size leads to larger fractal dimensions; hence, the larger the SSA is, the larger fractal dimensions are.",28,29,1
Source Rocks,Thermal Maturity,"Zhu, Linqi; Zhang, Chong; Zhang, Chaomo; Zhang, Zhansong; Zhou, Xueqing; Liu, Weinan; Zhu, Boyuan",A new and reliable dual model- and data-driven TOC prediction concept: A TOC logging evaluation method using multiple overlapping methods integrated with semi-supervised deep learning,Dual model- and data-driven; Total organic carbon content; Deep learning; Integrated deep semi-supervised ladder network; Novel idea; Multiple overlapping methods,ORGANIC-CARBON CONTENT; THERMAL MATURITY; NEURAL-NETWORKS; WIRELINE LOGS; SHALE; MACHINE; MATTER; COMBINATION; TECHNOLOGY; RESERVOIRS,"The total organic carbon content (TOC) is the most important parameter when determining the source rock quality. At present, there are two main types of TOC well logging calculation methods: model-driven and data-driven methods. However, research on the these two types of methods has slowed over the past ten years, and the ongoing research is very limited; thus, it is difficult to improve the TOC calculation accuracy. This paper analyses the advantages and disadvantages of current methods and proposes a new model- and data-driven TOC prediction concept to improve the TOC prediction accuracy. The proposed concept takes the curve obtained with the overlap method as an input instead of using a conventional log curve; we believe that deep learning is best suited to accomplish this task. We propose a new integrated semi-supervised deep learning network-the integrated deep semi-supervised ladder network (IDLN) algorithm-for small-sample well logging interpretation problems based on the proposed approach. A two-step method consisting of intelligent curve overlapping and automatic TOC prediction is employed to better interpret logging data and core data; this method can predict the TOC without manually overlapping curves. Testing the data from 12 wells in 3 blocks revealed that the proposed concept and IDLN algorithm greatly improve the TOC prediction accuracy, and the mean square error was reduced by more than 50%. The new method is also more reasonable for locating non-reservoir segments. Moreover, this novel approach can further enhance the TOC prediction accuracy and may even constitute a new research direction for improving the existing logging interpretation theory. These novel principles can ultimately help evaluate source rock reservoirs.",27,27,10
Source Rocks,Thermal Maturity,"Zhu, Xinjian; Chen, Jianfa; Li, Wei; Pei, Lixin; Liu, Kaixuan; Chen, Xiaodong; Zhang, Tonglei","Hydrocarbon generation potential of Paleogene coals and organic rich mudstones in Xihu sag, East China Sea Shelf basin, offshore eastern China",Coal and organic rich mudstone; Kerogen type; Thermal maturity; Hydrocarbon generation potential; Xihu sag; Offshore eastern China,OLIGOCENE HUAGANG FORMATION; SOURCE-ROCK EVALUATION; PETROGRAPHIC CHARACTERISTICS; GEOCHEMICAL CHARACTERISTICS; PETROLEUM GENERATION; TECTONIC INVERSION; PINGHU FORMATION; OIL; ENVIRONMENT; PROVENANCE,"Paleogene coals and organic rich mudstones in Xihu sag, East China Sea Shelf basin in offshore eastern China were analysed to evaluate the hydrocarbon generation potential based on organic petrographic and organic geochemical methods. The results reveal that the source rocks are dominated by Type III-II2 kerogens deposited in sub-oxic to oxic environments as coal-bearing source rocks. The total organic carbon (TOC) content values for the samples range from 0.31 wt% to 75.68 wt%, suggesting fair to excellent hydrocarbon generation potential, which is also consistent with the Hydrogen Index (HI) and extractable organic matter (EOM) content results. Thermal maturity of organic matter in Western Depression Group (WDG) area are mainly in early thermal maturity stage (Rr ranges from 0.57% to 0.76%), while Central Uplift Group (CUG) area samples have relatively higher thermal maturity (Rr ranges from 0.72% to 1.41%). The characteristics of Paleogene coal and organic rich mudstones reveal that the potential source rocks in both WDG and CUG area have fair to excellent hydrocarbon generative potential, but vary in hydrocarbon phase. WDG source rocks are expected to generate both commercial liquid hydrocarbons and gaseous hydrocarbons, which is also implied by the presence of significant liptinite and exsudatinite macerals. On the other hand, source rocks for CUG area exhibit a dominant gaseous hydrocarbon generation and some oil hydrocarbon generation potential. The data exhibited in this study illustrate source rock characteristics and provide evidence for hydrocarbon generation potential of Paleogene coal and organic rich mudstones in Xihu sag, in offshore eastern China.",12,13,6
Source Rocks,Thermal Maturity,"Mansour, Ahmed; Gentzis, Thomas; El Nady, Mohamed M.; Mostafa, Fatma; Tahoun, Sameh S.","Hydrocarbon potential of the Albian-early Cenomanian formations (Kharita- Bahariya) in the North Western Desert, Egypt: A review",Abu gharadig basin; Shushan basin; Matruh basin; Thermal maturity; Depositional paleoenvironment; Burial history,ABU-GHARADIG BASIN; SOURCE ROCKS; SHUSHAN BASIN; DEPOSITIONAL-ENVIRONMENTS; PETROLEUM GENERATION; WELLS; OIL; SUCCESSION; EVOLUTION; SYSTEMS,"Rock-Eval pyrolysis/TOC, petrographic, and geochemical data available in the public domain for a total of 296 core and 243 drill cuttings samples from the Albian-early Cenomanian Kharita and Bahariya formations of four main basins, Shushan, Abu Gharadig, Matruh and Dahab-Mireir, were reviewed. This review provides a comprehensive overview to understand the organic richness, type, and thermal maturity of potential source rock intervals within the Kharita and Bahariya formations in northern Egypt by means of burial history modeling and oil -in -place calculations. Geochemical data of both formations confirmed the presence of up to excellent source rocks of varied kerogen types but mainly of Type III (gas -prone) and mixed types II/III. Thermal maturity levels ranged from immature to the early stage of oil window, although some intervals reached the peak oil window in the Abu Gharadig and Shushan basins compared to their counterparts. The depositional paleoenvironment of the Kharita and Bahariya formations is interpreted based on the organic biomarker compounds and palynofacies associations. Generally, both formations in the four basins were inter- preted to accumulate in a fluvio-deltaic to marginal marine setting, although the Kharita rock unit was slightly less marine based on the isoprenoids pristane and phytane to nC 17 and nC 18 ratios. The ratio of 22S/(22S ? 22R) for the homohopanes C 31 and C 32 of Kharita oils from the Shushan Basin ranged from 0.50 to 0.60, indicating marginally mature to the onset of oil generation. However, common amongst much of the previous studies was the notable differences in organic matter contents, thermal maturity levels and hydrocarbon potential. Environmental and ecological processes, including proximity to shoreline, terrestrial/riverine input, oxygenation levels and water column conditions, are consid- ered the primary drivers that triggered variable amounts of organic carbon accumulation. While differences in thermal maturity levels were attributed to tectonic activities and related structural processes.",11,11,2
Source Rocks,Thermal Maturity,"Yu, Kun; Ju, Yiwen; Zhang, Baoxin","Modeling of tectono-thermal evolution of Permo-Carboniferous source rocks in the southern Qinshui Basin, China: Consequences for hydrocarbon generation",,BOHAI BAY BASIN; EASTERN NORTH CHINA; COALBED METHANE RESERVOIRS; TECTONIC THERMAL HISTORY; VITRINITE REFLECTANCE; MATURITY HISTORY; BURIAL HISTORY; ORDOS BASIN; TEMPERATURE; BEARING,,9,9,4
Source Rocks,Crude Oil,"Datta, Poulami; Tiwari, Pankaj; Pandey, Lalit M.",Oil washing proficiency of biosurfactant produced by isolated Bacillus tequilensis MK 729017 from Assam reservoir soil,Biosurfactant production; Optimization; Wetting; Surface tension; Oil washing efficiency; Emulsion,CELL-SURFACE HYDROPHOBICITY; CRUDE-OIL; INTERFACIAL-TENSION; RAPID IDENTIFICATION; RECOVERY; OPTIMIZATION; WETTABILITY; STRAIN; WATER; MEOR,"The present study describes elaborately the isolation of a potential biosurfactant producing and crude oil degrading strains isolated from the reservoir soil of Assam oil reservoir field. The produced biosurfactant was chemically characterized for its applicability for the enhanced oil recovery applications in terms of wetting, interfacial tension (IFT) and oil washing. From the seven isolated strains, Bacillus tequilensis MK 729017 was chosen based on the better surface active properties as it reduced the surface tension to 30 +/- 2 mN/m along with a moderate emulsification index of 66 +/- 2%. The produced biosurfactant was chemically identified to be lipopeptide, surfactin with a lower critical micelle concentration value of 90 mg/L. The carbon source and environmental parameters were optimized for the maximum concentration of the biosurfactant using response surface methodology based on the central composite design (RSM-CCD). The maximum biosurfactant concentration was measured to be 7.46 +/- 0.39 g/L and Y-PS was determined as 0.45. The specific growth rate of the isolate was 0.15 +/- 0.01 h(-1) and Y-XS was estimated as 0.1. The produced biosurfactant was also found to be thermal and colloidal stable. The biosurfactant solutions altered wettability of hydrophobic rock surface from 90 +/- 1 degrees to 26 +/- 1 degrees indicating a better interfacial interaction. The IFT of the produced biosurfactant was found to be 0.32 +/- 0.02 mN/m. The oil washing efficiency (80 +/- 2%) of the produced surfactin was comparable with chemical surfactants and the process involved two-step: initial a faster (surface) washing followed by a slower (internal) washing. The first process was dependent on micelle sizes, while the latter was dependent on water-oil emulsion size. The lower emulsion size of surfactin contributed to a greater internal washing as compared to chemical surfactants.",12,12,2
Source Rocks,Crude Oil,"He, Taohua; Lu, Shuangfang; Li, Wenhao; Wang, Weiming; Sun, Dongquan; Pan, Wenqing; Zhang, Baoshou","Geochemical characteristics and effectiveness of thick, black shales in southwestern depression, Tarim Basin",Southwestern depression; Depositional environment; Red algae; Hydrocarbon potential; Oil-source correlation; Tarim basin,SOURCE ROCKS; CRUDE OILS; NW CHINA; PETROLEUM SYSTEMS; BIYANG DEPRESSION; CRATONIC REGION; ORGANIC-CARBON; TABEI UPLIFT; INDICATORS; MARINE,"An interval of black shales deposited from Precambrian to lower Cambrian from the southwestern depression of the Tarim basin (SDTB) was systematically evaluated in terms of hydrocarbon potential, organic matter, depositional environment and oil-source relationship. The shales have good TOC contents (up to 3.15%) but low S-1+S-2 values (<0.03 mg/g), indicating the source rocks are currently at high thermal maturities. The relationship between pristane/n-C-17 and phytane/n-C-18 indicates the kerogen was oil prone and dominant by algal input. Furthermore, the depositional environment had relatively moderate salinity and stratified water environment indicated by G/C30H ratios (0.15-0.24). The high algal input may have enhanced TOC preservation under reducing conditions reflected by high dibenzothiophene content and low pristane/phytane ratios (mean 0.79). Thus, these source rocks may have generated a significant amount of oil during their geological history. Additionally, in view of the molecular geochemistry indicators, the extracts of black shales hold marked differences with the Cambrian-Ordovician end-member oils, but are quite similar to oils in the northeastern portion of the SDTB. It means that the lightly explored SDTB may contain significant hydrocarbon resources, and coeval source rocks in the ultra-deep portion of the basin may have contributed to the prolific petroleum resources in the Tarim Basin.",8,8,3
Source Rocks,Crude Oil,"Al-Khafaji, Amer Jassim; Hakimi, Mohammed Hail; Ibrahim, El-Khedr; Najaf, Ahmed Askar; Al Faifi, Hussain; Lashin, Aref","Organic geochemistry of oil seeps from the Abu-Jir Fault Zone in the Al-Anbar Governorate, western Iraq: Implications for early-mature sulfur-rich source rock",Oil seeps; Biomarker; Carbon isotope; Source input; Abu-Jir Fault Zone; Western Iraq,SOUTHERN MESOPOTAMIAN BASIN; CRETACEOUS SULAIY FORMATION; CRUDE OILS; DEPOSITIONAL-ENVIRONMENTS; SARGELU FORMATION; PETROLEUM SYSTEM; FOLD BELT; GENERATION; NORTH; KURDISTAN,"Organic geochemical methods were performed on four oil seep samples collected from the Abu-Jir Fault Zone (AJFZ) in the Al-Anbar Governorate, western Iraq. These oil seeps have undergone biodegradation, showing large unresolved complex mixture (UCM) shapes, with degradation of normal alkanes and isoprenoids. The inorganic elements of the Abu-Jir oil seeps, i.e., S, Ni and V, suggest a marine carbonate-rich source rock deposited under reducing environment conditions. The biomarker ratios and parameters of hopane and sterane further suggest that the oil seeps were derived from source rock rich in lipids from phytoplankton and bacteria with less contribution of terrigenous organic debris. The chemical maturity indicators show that the Abu-Jir oil seeps were generated from early mature sulfur -rich source rock, thus in association with a high S content of more than 1.93%. The geochemical characteristics of the analyzed oil seep samples are similar, which is consistent with most of the crude oils in the northern and southern basins in Iraq, and were generated from the Middle Jurassic Sargelu Formation. The overall geochemical correlations and geological information confirm that the Abu-Jir Faultoil seeps in the western Iraq were sourced from the Middle Jurassic Sargelu Formation that reached an early maturity level of oil-generation window and that they migrated into the ground surface through the Abu-Jir major fault during the middle Miocene.",8,8,0
Source Rocks,Crude Oil,"Xu, Huiyuan; George, Simon C.; Hou, Dujie; Cao, Bing; Chen, Xiaodong","Petroleum sources in the Xihu Depression, East China Sea: Evidence from stable carbon isotopic compositions of individual n-alkanes and isoprenoids",Carbon isotope; n-alkane; Isoprenoid; Coal; Mudstone; Xihu depression,CRUDE OILS; ORGANIC-COMPOUNDS; DITERPENOID HYDROCARBONS; RECENT SEDIMENTS; DIVERSE ORIGINS; TARANAKI BASIN; COAL MEASURES; LIAOHE BASIN; SOURCE ROCKS; SOUTH CHINA,"In order to better understand the relative contributions of various source rocks for petroleum in the Xihu Depression, East China Sea Basin, gas chromatography-mass spectrometry analyses of the saturated and aromatic fractions and carbon isotopic analyses of the purified n-alkanes and isoprenoids were performed. The molecular composition and individual n-alkane and isoprenoid carbon isotope compositions were determined for oils and extracts of Paleogene mudstones (TOC: 0.45-2.3%), carbonaceous mudstones (12.7-19.6%), and coals (48-60%) in the Xihu Depression, so as to discriminate the hydrocarbon sources of coals and associated mudstones to the petroleum generated in the basin. Abundant diterpanes (e.g., isopimarane, phyllocladane) are present in all the samples. The differences in the delta C-13 values of pristane and phytane indicate separate origins for the isoprenoids. A general negative sloping profile with increasing n-alkane carbon chain length was observed in coals, mudstones and oils from the Huangyan oilfield, with individual n-alkane delta C-13 values between -25.6 parts per thousand and -34.4 parts per thousand. These values are characteristic of the isotopic compositions of C3 plants, and are also typical of fluvial/lacustrine depositional settings. The isotope compositions of individual n-alkanes from the extracts of coals and mudstones correlate with the relative concentration of terrigenous higher plant-derived diterpenoids, which suggests that plant phyla/classes (for example gymnosperm-derived diterpanes versus angiosperm-derived diterpanes) may be a control on the carbon isotope profiles of n-alkanes. For samples dominated by terrigenous organic matter, long chain n-alkanes with a large proportion of gymnosperm input are approximately 2-3 parts per thousand enriched in C-13 relative to those with angiosperm input, regardless of lithology. The connections between the oils, coals, and mudstones allow determination of the patterns and variations for different hydrocarbon contributions, and provide a way of differentiating specific source contributions to petroleum in the Xihu Depression. Oils generated from the coals have heavier delta C-13 values with increasing chain length within a narrow range (approx. 2-3 parts per thousand) and have more heterotrophic origins, whereas oils from the mudstones are more depleted in C-13 with increasing carbon number (n-C-2(0-)31) and have a greater derivation from land plants. The 825B oils in the Huangyan oilfield have a greater angiosperm-sourced hydrocarbon contribution than those of the 825AD oils, which have a greater gymnosperm-sourced hydrocarbon contribution. The tricyclic and tetracyclic diterpanes and the isotopic compositions of individual n-alkanes and isoprenoids may be useful in differentiating contributions of coals and associated mudstones to petroleum.",7,7,7
Source Rocks,Model,"Mansour, Ahmed; Gentzis, Thomas; El Nady, Mohamed M.; Mostafa, Fatma; Tahoun, Sameh S.","Hydrocarbon potential of the Albian-early Cenomanian formations (Kharita- Bahariya) in the North Western Desert, Egypt: A review",Abu gharadig basin; Shushan basin; Matruh basin; Thermal maturity; Depositional paleoenvironment; Burial history,ABU-GHARADIG BASIN; SOURCE ROCKS; SHUSHAN BASIN; DEPOSITIONAL-ENVIRONMENTS; PETROLEUM GENERATION; WELLS; OIL; SUCCESSION; EVOLUTION; SYSTEMS,"Rock-Eval pyrolysis/TOC, petrographic, and geochemical data available in the public domain for a total of 296 core and 243 drill cuttings samples from the Albian-early Cenomanian Kharita and Bahariya formations of four main basins, Shushan, Abu Gharadig, Matruh and Dahab-Mireir, were reviewed. This review provides a comprehensive overview to understand the organic richness, type, and thermal maturity of potential source rock intervals within the Kharita and Bahariya formations in northern Egypt by means of burial history modeling and oil -in -place calculations. Geochemical data of both formations confirmed the presence of up to excellent source rocks of varied kerogen types but mainly of Type III (gas -prone) and mixed types II/III. Thermal maturity levels ranged from immature to the early stage of oil window, although some intervals reached the peak oil window in the Abu Gharadig and Shushan basins compared to their counterparts. The depositional paleoenvironment of the Kharita and Bahariya formations is interpreted based on the organic biomarker compounds and palynofacies associations. Generally, both formations in the four basins were inter- preted to accumulate in a fluvio-deltaic to marginal marine setting, although the Kharita rock unit was slightly less marine based on the isoprenoids pristane and phytane to nC 17 and nC 18 ratios. The ratio of 22S/(22S ? 22R) for the homohopanes C 31 and C 32 of Kharita oils from the Shushan Basin ranged from 0.50 to 0.60, indicating marginally mature to the onset of oil generation. However, common amongst much of the previous studies was the notable differences in organic matter contents, thermal maturity levels and hydrocarbon potential. Environmental and ecological processes, including proximity to shoreline, terrestrial/riverine input, oxygenation levels and water column conditions, are consid- ered the primary drivers that triggered variable amounts of organic carbon accumulation. While differences in thermal maturity levels were attributed to tectonic activities and related structural processes.",11,11,2
Source Rocks,Model,"Abdelwahhab, Mohammad A.; Raef, Abdelmoneam","Integrated reservoir and basin modeling in understanding the petroleum system and evaluating prospects: The Cenomanian reservoir, Bahariya Formation, at Falak Field, Shushan Basin, Western Desert, Egypt",Static reservoir modeling; Basin modeling; Prospect identification; Volumetric assessment; Bahariya formation; Western desert of Egypt,ABU-GHARADIG BASIN; FAULT-SEAL ANALYSIS; GEOCHEMICAL CHARACTERISTICS; HYDROCARBON GENERATION; KHATATBA FORMATION; SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; MIGRATION PATHWAYS; JURASSIC SYSTEM; NORTHERN EGYPT,"Robust inferences on understanding the reservoir heterogeneity and processes of the respective petroleum system are essential to reduce risks throughout the petroleum exploration and development phases. In this paper we present integrated static reservoir modeling and basin modeling to better characterise the reservoir rock; hydrocarbon-bearing sandstones of the Cenomanian Bahariya Formation. This reservoir is an element of the petroleum system; whose times of hydrocarbon generation-migration-accumulation, and entrapment, are also to be addressed; in Falak Field, Meleiha Area, Shushan Basin, Western Desert, Egypt. We utilized dataset including seismic profiles and well logs of four wells. Stratigraphic and structural modeling was performed to delineate the reservoir framework, then facies and petrophysical modeling, using stochastic simulation algorithms, was performed to delineate the reservoir architecture. 1D basin modeling was performed to retrieve the geohistory and maturation models of the area. Combining both reservoir and basin models was aimed, in this study, at identifying new petroleum prospects and estimating the volume of hydrocarbons within the reservoir intervals of the study area. According to the constructed reservoir and basin models, we identified three new petroleum prospect areas; to the NE, NW, and southern parts of Falak Field; that lead to reliable consistent inferences reasonably have sound impact on the oilfield development phases of the area.",10,10,2
Source Rocks,Model,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Source Rocks,Model,"Tang, Ling; Song, Yan; Pang, Xiongqi; Jiang, Zhenxue; Guo, Yingchun; Zhang, Hongan; Pan, Zhihong; Jiang, Hang","Effects of paleo sedimentary environment in saline lacustrine basin on organic matter accumulation and preservation: A case study from the Dongpu Depression, Bohai Bay Basin, China",Saline lacustrine basin; Organic matter; Enrichment and preservation; Sedimentary environment; Dongpu depression; Shahejie formation,WATER-COLUMN ANOXIA; MARINE BLACK SHALES; QAIDAM BASIN; ISOTOPIC COMPOSITION; CARBON; PRODUCTIVITY; ANCIENT; DEPOSITION; MECHANISMS; INDICATORS,"The Dongpu Depression has abundant oil and gas resources, but the distribution of hydrocarbon resources and enrichment degrees of organic matter (OM) in the northern and southern Dongpu Depression have significant differences due to the diverse sedimentary environment. To gain deep insight into the effects of sedimentary environment on OM accumulation and preservation, a series of experiments including element geochemistry, organic geochemistry and isotope geochemistry were performed on core samples collected from the fresh, brackish and saline regions of the third member of the Eocene Shahejie Formation (Es-3). The lacustrine closure, paleo-salinity, redox conditions, hydrodynamic conditions, paleo-climate and paleo-productivity were quantitatively evaluated. Controlling factors and OM enrichment models were evaluated and established. The results show that the Es-3 Formation was deposited as the lake experienced closed saline to transitional and then fresh lake stages. The lacustrine deposits were accompanied by climate changes from dry to humid and strongly rifting during Es-3 deposition. The weak hydrodynamic conditions (Zr/Rb) and paleo climate indices (delta O-18, climate index, Fe/Mn, Sr/Cu and Al/Mg) imply that moderate humid and dry climate can encourage OM development and preservation. The paleo productivity indices (delta C-13, P/Al, P/Ti and P content) are positively related to TOC indicating that high productivity promotes OM accumulation. All the paleo salinity indices (Z value, Sr/Ba and B/Ga) have positive correlations with TOC content, suggesting that OM enrichment increases with salinity to some extent. The positive relationships between the redox indices (V/Cr, V/Sc, U/Th, and dU) and TOC indicate that redox conditions are the most important for OM preservation. This study not only advances the theory of OM enrichment mechanism in saline basins, but also provides guidance for predicting the distributions of high-quality source rocks in the Dongpu Depression.",9,10,5
Source Rocks,Model,"Yu, Kun; Ju, Yiwen; Zhang, Baoxin","Modeling of tectono-thermal evolution of Permo-Carboniferous source rocks in the southern Qinshui Basin, China: Consequences for hydrocarbon generation",,BOHAI BAY BASIN; EASTERN NORTH CHINA; COALBED METHANE RESERVOIRS; TECTONIC THERMAL HISTORY; VITRINITE REFLECTANCE; MATURITY HISTORY; BURIAL HISTORY; ORDOS BASIN; TEMPERATURE; BEARING,,9,9,4
Source Rocks,Organic Matter Enrichment,"Wang, Qifeng; Jiang, Fujie; Ji, Hancheng; Jiang, Shu; Liu, Xiaohan; Zhao, Zhao; Wu, Yuqi; Xiong, Hang; Li, Yan; Wang, Ze","Effects of paleosedimentary environment on organic matter enrichment in a saline lacustrine rift basin - A case study of Paleogene source rock in the Dongpu Depression, Bohai Bay Basin",Organic matter enrichment; Saline lacustrine shale; Paleosedimentary; Dongpu Depression; Rift basin,PERMIAN LUCAOGOU FORMATION; DEPOSITIONAL ENVIRONMENT; GEOCHEMICAL CHARACTERISTICS; SEDIMENTATION-RATE; BIYANG DEPRESSION; RICH SHALES; OIL CONTENT; ACCUMULATION; ORIGIN; PRODUCTIVITY,"Organic-rich shale, the third member of the PaleogeneShahejie Formation (Es-3), is considered as an excellent lacustrine source rock in the Bohai Bay Basin. However, studies on how paleosedimentary environments affect organic matter enrichment are still lacking. In this study, cores of the Es3 shale in the Dongpu Depression (DD) nearly 200 m in length were collected at well Pu 115 to investigate organic matter enrichment mechanism. Results suggest that the Es3 shale was deposited under reductive conditions based on the redox index (V/(V + Ni)) and the large amount of pyrite. The Mg/Sr and Fe/Mn ratios indicate a generally arid climate with a frequently changing paleowater depth. The paleosalinity analyses indicate the Es3 shale developed under freshbrackish conditions. The Ba content ranges from 75 to 435 ppm (avg. 284 ppm), showing a moderate paleoproductivity. Correlation analyses among the total organic carbon (TOC) and major and trace element ratios show that the TOC rises with the increasing water reduction degree. With increasing water paleosalinity, the TOC increases initially and then decreases, reaching a maximum TOC at a paleosalinity of 11%. In addition, the TOC increases initially and then decreases with increasing detrital input, indicating that a moderate detrital input would be beneficial for organic matter enrichment. The redox conditions, paleosalinity and quantity of detrital input are the key factors controlling the organic matter enrichment. Further analyses show that the redox conditions were controlled by the paleoclimate, and the paleosalinity and terrestrial detrital input quantity were affected by the paleowater depth. The root factors controlling the organic matter enrichment are paleoclimate and paleowater depth in the saline lacustrine rift basin.",9,11,12
Source Rocks,Organic Matter Enrichment,"Tang, Ling; Song, Yan; Pang, Xiongqi; Jiang, Zhenxue; Guo, Yingchun; Zhang, Hongan; Pan, Zhihong; Jiang, Hang","Effects of paleo sedimentary environment in saline lacustrine basin on organic matter accumulation and preservation: A case study from the Dongpu Depression, Bohai Bay Basin, China",Saline lacustrine basin; Organic matter; Enrichment and preservation; Sedimentary environment; Dongpu depression; Shahejie formation,WATER-COLUMN ANOXIA; MARINE BLACK SHALES; QAIDAM BASIN; ISOTOPIC COMPOSITION; CARBON; PRODUCTIVITY; ANCIENT; DEPOSITION; MECHANISMS; INDICATORS,"The Dongpu Depression has abundant oil and gas resources, but the distribution of hydrocarbon resources and enrichment degrees of organic matter (OM) in the northern and southern Dongpu Depression have significant differences due to the diverse sedimentary environment. To gain deep insight into the effects of sedimentary environment on OM accumulation and preservation, a series of experiments including element geochemistry, organic geochemistry and isotope geochemistry were performed on core samples collected from the fresh, brackish and saline regions of the third member of the Eocene Shahejie Formation (Es-3). The lacustrine closure, paleo-salinity, redox conditions, hydrodynamic conditions, paleo-climate and paleo-productivity were quantitatively evaluated. Controlling factors and OM enrichment models were evaluated and established. The results show that the Es-3 Formation was deposited as the lake experienced closed saline to transitional and then fresh lake stages. The lacustrine deposits were accompanied by climate changes from dry to humid and strongly rifting during Es-3 deposition. The weak hydrodynamic conditions (Zr/Rb) and paleo climate indices (delta O-18, climate index, Fe/Mn, Sr/Cu and Al/Mg) imply that moderate humid and dry climate can encourage OM development and preservation. The paleo productivity indices (delta C-13, P/Al, P/Ti and P content) are positively related to TOC indicating that high productivity promotes OM accumulation. All the paleo salinity indices (Z value, Sr/Ba and B/Ga) have positive correlations with TOC content, suggesting that OM enrichment increases with salinity to some extent. The positive relationships between the redox indices (V/Cr, V/Sc, U/Th, and dU) and TOC indicate that redox conditions are the most important for OM preservation. This study not only advances the theory of OM enrichment mechanism in saline basins, but also provides guidance for predicting the distributions of high-quality source rocks in the Dongpu Depression.",9,10,5
Source Rocks,Tight Sandstone,"Cai, Laixing; Guo, Xingwei; Zhang, Xunhua; Zeng, Zhigang; Xiao, Guolin; Pang, Yumao; Wang, Shuping","Pore-throat structures of the Permian Longtan Formation tight sandstones in the South Yellow Sea Basin, China: A case study from borehole CSDP-2",Pore-throat structure; Reservoir quality; Formation mechanism; Tight sandstone; Longtan formation; Borehole CSDP-2; South Yellow Sea Basin,UNCONVENTIONAL HYDROCARBON RESOURCES; RATE-CONTROLLED POROSIMETRY; PRESSURE MERCURY INTRUSION; SICHUAN BASIN; YANCHANG FORMATION; OIL-RESERVOIRS; ORDOS BASIN; CENTRAL UPLIFT; FRACTAL CHARACTERISTICS; LOW PERMEABILITY,"With good exploration prospects and proven source rocks in Permian, reservoir evaluation has become the main bottleneck hindering petroleum exploration in the South Yellow Sea Basin, China, where the pore-throat structures, which are particularly important for the reservoir quality of tight sandstones, have never been characterized. To solve this, tight sandstones taken from borehole CSDP-2 of the Permian Longtan (P(2)l) Formation were systemically investigated with high-precision pore-throat characterization methods. The results show that pore-throat structures of tight sandstones in the Longtan Formation can be classified into three categories with synthesis considerations of pore-throat type, size, and connectivity; these pore-throats are denoted lattice-like, tubular, and isolated, respectively. The lattice-like pore throats with relatively larger radii (>0.1 mu m) and higher connectivity exhibit the best performance for reservoir quality, followed by tubular pore-throat structures, while isolated pore throats have almost no capacity to migrate or store fluids. In the formation mechanism of various pore-throat structures, both the plastic component content and complex diagenesis play a significant role. Strong compaction results in a loss of nearly half of the initial porosity (av. 49.81%) during the initial diagenetic stage. Then, clay mineral cements partially occlude pores and throats, which are the dominant factors in the transition of pore-throat structures from lattice-like to tubular. Silica and carbonate cementation are the key processes that fill the primary pore throats, secondary dissolution pores, and microfractures, leading to the formation of isolated pore-throat structures and low-porosity, ultra-low-permeability reservoirs. Feldspar dissolution cannot take place on a large scale due to the early densification of the sandstone, and it does not significantly improve the reservoir quality; it increases the porosity by less than 4.0%. This research provides constructive insights into the coupled evolution of pore-throat structures and diagenetic processes, which can aid in further understanding the formation mechanism of tight sandstones. In practice, this work also provides a scientific basis for identifying effective reservoirs, and promotes petroleum exploration in the South Yellow Sea Basin, China.",10,11,4
Source Rocks,Tight Sandstone,"Xiao, Meng; Wu, Songtao; Yuan, Xuanjun; Cao, Zhenglin; Xie, Zongrui","Diagenesis effects on the conglomerate reservoir quality of the Baikouquan Formation, Junggar Basin, China",Conglomerate reservoir; Sedimentology; Diagenesis; Favorable reservoir; Junggar basin,ORGANIC-INORGANIC INTERACTIONS; COARSE-GRAINED-DELTAS; BOHAI BAY BASIN; OIL-FIELD; MAHU SAG; TURBIDITE RESERVOIRS; SANDSTONE RESERVOIRS; TRIASSIC RESERVOIRS; GEOCHEMICAL SYSTEMS; DEPOSITIONAL FACIES,"Large accumulations of oil and gas have been found in fan delta conglomerate reservoirs in the upper Triassic Baikouquan Formation in the Mahu Sag at the northwestern margin of the Junggar Basin. To effectively explore strongly heterogeneous, high-quality, conglomerate reservoirs, their deposition, diagenesis, and genetic mechanisms must first be thoroughly studied. Analyses of cores, thin sections, fluid inclusions, oxygen isotopes, logging, physical properties data, X-ray diffraction, scanning electron microscopy, and cathodoluminescence confirm that the conglomerates have high feldspar contents as well as volcanic fragments that comprise a variety of micro-lithofacies. The heterogenous reservoir properties include permeability values of less than 1 mD, 1-10 mD, and higher than 10 mD, which correspond to 44.19%, 37.06%, and 18.75% of the reservoir, respectively. The tight reservoirs, mostly developed in the fan delta plain, have experienced extensive compaction and/or calcite cementation and consist of only a few secondary pores. Reservoirs with high porosity and permeability developed in subaqueous channels and experienced relatively weak compaction. These reservoirs contain large numbers of secondary pores that were mainly formed by the dissolution of K-feldspars and volcanic rock fragments. Comprehensive studies of sedimentation and diagenesis in the Baikouquan Formation indicate that these high porosities originated from the chronological coupling of the following three important geological processes: (1) Conglomerate reservoirs with better sorting and roundness and lower mud content are mainly developed in subaqueous distributary channels and have higher porosity and permeability than reservoirs with poorer sorting and roundness. (2) Strong dissolution of K-feldspar and volcanic debris occurred in reservoirs with good original physical properties, forming large numbers of secondary pores. Acidic fluids from source rocks in the Fengcheng Formation led to dissolution. (3) The byproducts of dissolution, which consist mostly of mixed-layer illite/ smectite and illite, reduced porosity and permeability. In reservoirs with good original physical properties and fault development, dissolution plays an obvious role in improving physical properties in such relatively open diagenetic systems.",10,10,2
Source Rocks,Acoustic Emission,"Zhai, Hongyu; Chang, Xu; Wang, Yibo; Lei, Xinglin; Xue, Ziqiu",Analysis of acoustic emission events induced during stress unloading of a hydraulic fractured Longmaxi shale sample,,MOMENT TENSORS; MECHANICAL-PROPERTIES; SICHUAN BASIN; ROCKS; EVOLUTION; FAILURE; COAL,"In shale-gas exploitation, hydraulic fracturing technology is essential to successfully create complex fracture networks in formations. To investigate the dynamic fracturing process, we performed a hydraulic fracturing experiment on a Longmaxi shale sample in the laboratory. After hydrofracturing, hundreds of induced acoustic emission (AE) events were recorded during the stress unloading procedure. At the same time, the high-pressure water stored in the sample fracture network was also discharged. The fracture network inside the fractured sample was studied using medical X-ray computed tomography (CT) scanning technology. Then, the locations and characteristics of the shale failure were analyzed by localizing and inversing the source mechanism of the AE events. Furthermore, the inversion results were verified by comparing with the scanned internal cracks images. According to the source mechanism inversion result, the induced AE events mainly stemmed from the dilatation or compression of fractures and the shear slip of shale along the fracture plane. Finally, the influence of formation attenuation error (underestimated or overestimated attenuation value) on source mechanism inversion results were quantitatively analyzed. It was confirmed that the shear component of the AE event was more sensitive than the volume component to medium attenuation change, especially when the attenuation value was overestimated.",8,9,10
Source Rocks,Acoustic Emission,"Rossi, Edoardo; Jamali, Shahin; Schwarz, Dennis; Saar, Martin O.; von Rohr, Philipp Rudolf",Field test of a Combined Thermo-Mechanical Drilling technology. Mode II: Flame-assisted rotary drilling,Deep resource; Granite; Thermally assisted drilling; Field demonstration; Drilling performance; Acoustic emission,SIZE REDUCTION RELATIONSHIPS; ACOUSTIC-EMISSION; HIGH-TEMPERATURE; MECHANICAL-BEHAVIOR; PENETRATION RATE; THERMAL-DAMAGE; ROCK; ENERGY; VELOCITY; GRANITE,"To enhance the drilling performance in deep hard rocks and reduce overall drilling efforts, this work proposes a Combined Thermo-Mechanical Drilling (CTMD) technology. This technology employs a heat source (e.g., a flame jet) and includes two main drilling modes: (I) thermal spallation drilling, investigated in the companion paper and (II) flame-assisted rotary drilling, investigated here as a field test. The CTMD technology is expected to reduce drilling efforts, especially in hard rocks, enhancing the rock penetration rate and increasing the bit lifetime, all of which reduces the drilling costs. The present work investigates Mode II (flame-assisted rotary drilling) of the CTMD technology by implementing the concept in an existing drilling rig and testing the technology under relevant process conditions. This contribution studies the underlying rock removal mechanism of CTMD and demonstrates its drilling performance, compared to conventional rotary drilling methods. Acoustic emission monitoring, and analysis of the collected drill cuttings provide multiple evidences for thermal-cracking-enhanced rock removal during the flame-assisted rotary drilling. This removal mechanism appears to represent an optimal compromise to minimize rock fragmentation and cutting transport efforts during drilling, compared to a less efficient mechanical scraping of the hard granite rock, observed during the standalone-mechanical drill test. The drilling performance, in terms of removal and wear rates, are evaluated for the flame-assisted rotary drilling. This shows that the proposed drilling approach is capable of enhancing the removal process in hard granite rock, by a factor of 2.5, compared to standalone-mechanical drilling. The implementation of this drilling approach into a conventional drilling system shows that integration of thermal assistance to conventional rotary drilling requires marginal technical efforts. Additionally, this technology can profit from established knowledge in conventional mechanical drilling, facilitating its implementation to improve drilling performance in hard rocks. Hence, this study demonstrates that the Combined Thermo-Mechanical Drilling method is feasible and concludes that this technology constitutes a promising approach to improve the drilling process, thereby increasing the viability of accessing deep geo-resources in hard rocks.",8,8,3
Source Rocks,Longmaxi Formation,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Source Rocks,Longmaxi Formation,"Zhai, Hongyu; Chang, Xu; Wang, Yibo; Lei, Xinglin; Xue, Ziqiu",Analysis of acoustic emission events induced during stress unloading of a hydraulic fractured Longmaxi shale sample,,MOMENT TENSORS; MECHANICAL-PROPERTIES; SICHUAN BASIN; ROCKS; EVOLUTION; FAILURE; COAL,"In shale-gas exploitation, hydraulic fracturing technology is essential to successfully create complex fracture networks in formations. To investigate the dynamic fracturing process, we performed a hydraulic fracturing experiment on a Longmaxi shale sample in the laboratory. After hydrofracturing, hundreds of induced acoustic emission (AE) events were recorded during the stress unloading procedure. At the same time, the high-pressure water stored in the sample fracture network was also discharged. The fracture network inside the fractured sample was studied using medical X-ray computed tomography (CT) scanning technology. Then, the locations and characteristics of the shale failure were analyzed by localizing and inversing the source mechanism of the AE events. Furthermore, the inversion results were verified by comparing with the scanned internal cracks images. According to the source mechanism inversion result, the induced AE events mainly stemmed from the dilatation or compression of fractures and the shear slip of shale along the fracture plane. Finally, the influence of formation attenuation error (underestimated or overestimated attenuation value) on source mechanism inversion results were quantitatively analyzed. It was confirmed that the shear component of the AE event was more sensitive than the volume component to medium attenuation change, especially when the attenuation value was overestimated.",8,9,10
Source Rocks,Fracture Development,"Zhao, Gang; Ding, Wenlong; Sun, Yaxiong; Wang, Xinghua; Tian, Li; Liu, Jingshou; Shi, Siyu; Jiao, Baocheng; Cui, Long","Fracture development characteristics and controlling factors for reservoirs in the Lower Silurian Longmaxi Formation marine shale of the Sangzhi block, Hunan Province, China",The Longmaxi Formation shale; Fracture development characteristics; Fracture distribution controlling factors; Sangzhi block,NATURAL FRACTURES; SICHUAN BASIN; NIUTITANG FORMATION; NORTHWESTERN HUNAN; QIANGTANG BASIN; NANCHUAN REGION; BARNETT SHALE; SOURCE ROCKS; GAS; PREDICTION,"The Lower Paleozoic Silurian Longmaxi Formation shale in the Sichuan Basin of southern China has achieved commercial exploitation in recent years, and has become a rapid growth point in China's oil and gas reserves. However, the Longmaxi Formation on the peripheral margin of the Sichuan Basin has not made substantial progress. Fractures, that as fluid reservoirs and migration channels, play an important role in shale gas exploration and development. Based on data from field outcrop observations, drilling cores, well logging, geochemical tests, microscopic thin section observations, and focused-ion-beam scanning electron microscope (FIBSEM) combined with energy dispersive spectrometer (EDS) analysis and cathodoluminescence microscope (CLM) technology, the development characteristics of fractures in the Longmaxi Formation SY-5 well in the Sangzhi block of Sangzhi-Shimen synclinorium, NW Hunan Province, are described systematically, and their important roles, primary dominant factors and effectiveness in the shale gas reservoir are discussed. The results showed that tectonic factors are the dominant factors of shale fracture development, followed by nonstructural factors. The fractures were mainly ductile shear fractures, with short extension distances and small apertures, and they had at least two openings in the burial history. The statistical fracture density of drilling cores was no obvious correlated with the contents of total organic carbon (TOC) (0.18%-2.49%) and clay minerals (13.0%-34.0%), and the same with brittle quartz (32%-72%), which indicates that they have controlled the development of fractures together. These results could be used for estimating effective permeability, fracture distribution, numerical simulation, well deployment, hydraulic fracturing and reserves calculation in the processes of exploration and development.",13,15,2
Source Rocks,Fracture Development,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Source Rocks,Type Curves,"Zhu, Linqi; Zhang, Chong; Zhang, Chaomo; Zhang, Zhansong; Zhou, Xueqing; Liu, Weinan; Zhu, Boyuan",A new and reliable dual model- and data-driven TOC prediction concept: A TOC logging evaluation method using multiple overlapping methods integrated with semi-supervised deep learning,Dual model- and data-driven; Total organic carbon content; Deep learning; Integrated deep semi-supervised ladder network; Novel idea; Multiple overlapping methods,ORGANIC-CARBON CONTENT; THERMAL MATURITY; NEURAL-NETWORKS; WIRELINE LOGS; SHALE; MACHINE; MATTER; COMBINATION; TECHNOLOGY; RESERVOIRS,"The total organic carbon content (TOC) is the most important parameter when determining the source rock quality. At present, there are two main types of TOC well logging calculation methods: model-driven and data-driven methods. However, research on the these two types of methods has slowed over the past ten years, and the ongoing research is very limited; thus, it is difficult to improve the TOC calculation accuracy. This paper analyses the advantages and disadvantages of current methods and proposes a new model- and data-driven TOC prediction concept to improve the TOC prediction accuracy. The proposed concept takes the curve obtained with the overlap method as an input instead of using a conventional log curve; we believe that deep learning is best suited to accomplish this task. We propose a new integrated semi-supervised deep learning network-the integrated deep semi-supervised ladder network (IDLN) algorithm-for small-sample well logging interpretation problems based on the proposed approach. A two-step method consisting of intelligent curve overlapping and automatic TOC prediction is employed to better interpret logging data and core data; this method can predict the TOC without manually overlapping curves. Testing the data from 12 wells in 3 blocks revealed that the proposed concept and IDLN algorithm greatly improve the TOC prediction accuracy, and the mean square error was reduced by more than 50%. The new method is also more reasonable for locating non-reservoir segments. Moreover, this novel approach can further enhance the TOC prediction accuracy and may even constitute a new research direction for improving the existing logging interpretation theory. These novel principles can ultimately help evaluate source rock reservoirs.",27,27,10
Source Rocks,Type Curves,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Source Rocks,Pressure,"Cai, Laixing; Guo, Xingwei; Zhang, Xunhua; Zeng, Zhigang; Xiao, Guolin; Pang, Yumao; Wang, Shuping","Pore-throat structures of the Permian Longtan Formation tight sandstones in the South Yellow Sea Basin, China: A case study from borehole CSDP-2",Pore-throat structure; Reservoir quality; Formation mechanism; Tight sandstone; Longtan formation; Borehole CSDP-2; South Yellow Sea Basin,UNCONVENTIONAL HYDROCARBON RESOURCES; RATE-CONTROLLED POROSIMETRY; PRESSURE MERCURY INTRUSION; SICHUAN BASIN; YANCHANG FORMATION; OIL-RESERVOIRS; ORDOS BASIN; CENTRAL UPLIFT; FRACTAL CHARACTERISTICS; LOW PERMEABILITY,"With good exploration prospects and proven source rocks in Permian, reservoir evaluation has become the main bottleneck hindering petroleum exploration in the South Yellow Sea Basin, China, where the pore-throat structures, which are particularly important for the reservoir quality of tight sandstones, have never been characterized. To solve this, tight sandstones taken from borehole CSDP-2 of the Permian Longtan (P(2)l) Formation were systemically investigated with high-precision pore-throat characterization methods. The results show that pore-throat structures of tight sandstones in the Longtan Formation can be classified into three categories with synthesis considerations of pore-throat type, size, and connectivity; these pore-throats are denoted lattice-like, tubular, and isolated, respectively. The lattice-like pore throats with relatively larger radii (>0.1 mu m) and higher connectivity exhibit the best performance for reservoir quality, followed by tubular pore-throat structures, while isolated pore throats have almost no capacity to migrate or store fluids. In the formation mechanism of various pore-throat structures, both the plastic component content and complex diagenesis play a significant role. Strong compaction results in a loss of nearly half of the initial porosity (av. 49.81%) during the initial diagenetic stage. Then, clay mineral cements partially occlude pores and throats, which are the dominant factors in the transition of pore-throat structures from lattice-like to tubular. Silica and carbonate cementation are the key processes that fill the primary pore throats, secondary dissolution pores, and microfractures, leading to the formation of isolated pore-throat structures and low-porosity, ultra-low-permeability reservoirs. Feldspar dissolution cannot take place on a large scale due to the early densification of the sandstone, and it does not significantly improve the reservoir quality; it increases the porosity by less than 4.0%. This research provides constructive insights into the coupled evolution of pore-throat structures and diagenetic processes, which can aid in further understanding the formation mechanism of tight sandstones. In practice, this work also provides a scientific basis for identifying effective reservoirs, and promotes petroleum exploration in the South Yellow Sea Basin, China.",10,11,4
Source Rocks,Pressure,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Source Rocks,Phase,"Zhu, Xinjian; Chen, Jianfa; Li, Wei; Pei, Lixin; Liu, Kaixuan; Chen, Xiaodong; Zhang, Tonglei","Hydrocarbon generation potential of Paleogene coals and organic rich mudstones in Xihu sag, East China Sea Shelf basin, offshore eastern China",Coal and organic rich mudstone; Kerogen type; Thermal maturity; Hydrocarbon generation potential; Xihu sag; Offshore eastern China,OLIGOCENE HUAGANG FORMATION; SOURCE-ROCK EVALUATION; PETROGRAPHIC CHARACTERISTICS; GEOCHEMICAL CHARACTERISTICS; PETROLEUM GENERATION; TECTONIC INVERSION; PINGHU FORMATION; OIL; ENVIRONMENT; PROVENANCE,"Paleogene coals and organic rich mudstones in Xihu sag, East China Sea Shelf basin in offshore eastern China were analysed to evaluate the hydrocarbon generation potential based on organic petrographic and organic geochemical methods. The results reveal that the source rocks are dominated by Type III-II2 kerogens deposited in sub-oxic to oxic environments as coal-bearing source rocks. The total organic carbon (TOC) content values for the samples range from 0.31 wt% to 75.68 wt%, suggesting fair to excellent hydrocarbon generation potential, which is also consistent with the Hydrogen Index (HI) and extractable organic matter (EOM) content results. Thermal maturity of organic matter in Western Depression Group (WDG) area are mainly in early thermal maturity stage (Rr ranges from 0.57% to 0.76%), while Central Uplift Group (CUG) area samples have relatively higher thermal maturity (Rr ranges from 0.72% to 1.41%). The characteristics of Paleogene coal and organic rich mudstones reveal that the potential source rocks in both WDG and CUG area have fair to excellent hydrocarbon generative potential, but vary in hydrocarbon phase. WDG source rocks are expected to generate both commercial liquid hydrocarbons and gaseous hydrocarbons, which is also implied by the presence of significant liptinite and exsudatinite macerals. On the other hand, source rocks for CUG area exhibit a dominant gaseous hydrocarbon generation and some oil hydrocarbon generation potential. The data exhibited in this study illustrate source rock characteristics and provide evidence for hydrocarbon generation potential of Paleogene coal and organic rich mudstones in Xihu sag, in offshore eastern China.",12,13,6
Source Rocks,Phase,"Abdelwahhab, Mohammad A.; Raef, Abdelmoneam","Integrated reservoir and basin modeling in understanding the petroleum system and evaluating prospects: The Cenomanian reservoir, Bahariya Formation, at Falak Field, Shushan Basin, Western Desert, Egypt",Static reservoir modeling; Basin modeling; Prospect identification; Volumetric assessment; Bahariya formation; Western desert of Egypt,ABU-GHARADIG BASIN; FAULT-SEAL ANALYSIS; GEOCHEMICAL CHARACTERISTICS; HYDROCARBON GENERATION; KHATATBA FORMATION; SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; MIGRATION PATHWAYS; JURASSIC SYSTEM; NORTHERN EGYPT,"Robust inferences on understanding the reservoir heterogeneity and processes of the respective petroleum system are essential to reduce risks throughout the petroleum exploration and development phases. In this paper we present integrated static reservoir modeling and basin modeling to better characterise the reservoir rock; hydrocarbon-bearing sandstones of the Cenomanian Bahariya Formation. This reservoir is an element of the petroleum system; whose times of hydrocarbon generation-migration-accumulation, and entrapment, are also to be addressed; in Falak Field, Meleiha Area, Shushan Basin, Western Desert, Egypt. We utilized dataset including seismic profiles and well logs of four wells. Stratigraphic and structural modeling was performed to delineate the reservoir framework, then facies and petrophysical modeling, using stochastic simulation algorithms, was performed to delineate the reservoir architecture. 1D basin modeling was performed to retrieve the geohistory and maturation models of the area. Combining both reservoir and basin models was aimed, in this study, at identifying new petroleum prospects and estimating the volume of hydrocarbons within the reservoir intervals of the study area. According to the constructed reservoir and basin models, we identified three new petroleum prospect areas; to the NE, NW, and southern parts of Falak Field; that lead to reliable consistent inferences reasonably have sound impact on the oilfield development phases of the area.",10,10,2
Source Rocks,Profile,"Abdelwahhab, Mohammad A.; Raef, Abdelmoneam","Integrated reservoir and basin modeling in understanding the petroleum system and evaluating prospects: The Cenomanian reservoir, Bahariya Formation, at Falak Field, Shushan Basin, Western Desert, Egypt",Static reservoir modeling; Basin modeling; Prospect identification; Volumetric assessment; Bahariya formation; Western desert of Egypt,ABU-GHARADIG BASIN; FAULT-SEAL ANALYSIS; GEOCHEMICAL CHARACTERISTICS; HYDROCARBON GENERATION; KHATATBA FORMATION; SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; MIGRATION PATHWAYS; JURASSIC SYSTEM; NORTHERN EGYPT,"Robust inferences on understanding the reservoir heterogeneity and processes of the respective petroleum system are essential to reduce risks throughout the petroleum exploration and development phases. In this paper we present integrated static reservoir modeling and basin modeling to better characterise the reservoir rock; hydrocarbon-bearing sandstones of the Cenomanian Bahariya Formation. This reservoir is an element of the petroleum system; whose times of hydrocarbon generation-migration-accumulation, and entrapment, are also to be addressed; in Falak Field, Meleiha Area, Shushan Basin, Western Desert, Egypt. We utilized dataset including seismic profiles and well logs of four wells. Stratigraphic and structural modeling was performed to delineate the reservoir framework, then facies and petrophysical modeling, using stochastic simulation algorithms, was performed to delineate the reservoir architecture. 1D basin modeling was performed to retrieve the geohistory and maturation models of the area. Combining both reservoir and basin models was aimed, in this study, at identifying new petroleum prospects and estimating the volume of hydrocarbons within the reservoir intervals of the study area. According to the constructed reservoir and basin models, we identified three new petroleum prospect areas; to the NE, NW, and southern parts of Falak Field; that lead to reliable consistent inferences reasonably have sound impact on the oilfield development phases of the area.",10,10,2
Source Rocks,Profile,"Xu, Huiyuan; George, Simon C.; Hou, Dujie; Cao, Bing; Chen, Xiaodong","Petroleum sources in the Xihu Depression, East China Sea: Evidence from stable carbon isotopic compositions of individual n-alkanes and isoprenoids",Carbon isotope; n-alkane; Isoprenoid; Coal; Mudstone; Xihu depression,CRUDE OILS; ORGANIC-COMPOUNDS; DITERPENOID HYDROCARBONS; RECENT SEDIMENTS; DIVERSE ORIGINS; TARANAKI BASIN; COAL MEASURES; LIAOHE BASIN; SOURCE ROCKS; SOUTH CHINA,"In order to better understand the relative contributions of various source rocks for petroleum in the Xihu Depression, East China Sea Basin, gas chromatography-mass spectrometry analyses of the saturated and aromatic fractions and carbon isotopic analyses of the purified n-alkanes and isoprenoids were performed. The molecular composition and individual n-alkane and isoprenoid carbon isotope compositions were determined for oils and extracts of Paleogene mudstones (TOC: 0.45-2.3%), carbonaceous mudstones (12.7-19.6%), and coals (48-60%) in the Xihu Depression, so as to discriminate the hydrocarbon sources of coals and associated mudstones to the petroleum generated in the basin. Abundant diterpanes (e.g., isopimarane, phyllocladane) are present in all the samples. The differences in the delta C-13 values of pristane and phytane indicate separate origins for the isoprenoids. A general negative sloping profile with increasing n-alkane carbon chain length was observed in coals, mudstones and oils from the Huangyan oilfield, with individual n-alkane delta C-13 values between -25.6 parts per thousand and -34.4 parts per thousand. These values are characteristic of the isotopic compositions of C3 plants, and are also typical of fluvial/lacustrine depositional settings. The isotope compositions of individual n-alkanes from the extracts of coals and mudstones correlate with the relative concentration of terrigenous higher plant-derived diterpenoids, which suggests that plant phyla/classes (for example gymnosperm-derived diterpanes versus angiosperm-derived diterpanes) may be a control on the carbon isotope profiles of n-alkanes. For samples dominated by terrigenous organic matter, long chain n-alkanes with a large proportion of gymnosperm input are approximately 2-3 parts per thousand enriched in C-13 relative to those with angiosperm input, regardless of lithology. The connections between the oils, coals, and mudstones allow determination of the patterns and variations for different hydrocarbon contributions, and provide a way of differentiating specific source contributions to petroleum in the Xihu Depression. Oils generated from the coals have heavier delta C-13 values with increasing chain length within a narrow range (approx. 2-3 parts per thousand) and have more heterotrophic origins, whereas oils from the mudstones are more depleted in C-13 with increasing carbon number (n-C-2(0-)31) and have a greater derivation from land plants. The 825B oils in the Huangyan oilfield have a greater angiosperm-sourced hydrocarbon contribution than those of the 825AD oils, which have a greater gymnosperm-sourced hydrocarbon contribution. The tricyclic and tetracyclic diterpanes and the isotopic compositions of individual n-alkanes and isoprenoids may be useful in differentiating contributions of coals and associated mudstones to petroleum.",7,7,7
Fractal Dimension,,"Guo, Ruiliang; Xie, Qichao; Qu, Xuefeng; Chu, Meijuan; Li, Shutong; Ma, Dongxu; Ma, Xiaofeng","Fractal characteristics of pore-throat structure and permeability estimation of tight sandstone reservoirs: A case study of Chang 7 of the Upper Triassic Yanchang Formation in Longdong area, Ordos Basin, China",Fractal dimension; Tight sandstone reservoirs; Yanchang Formation; Permeability estimation; Mercury intrusion capillary pressure,CAPILLARY-PRESSURE; OIL; POROSITY; MICROGEOMETRY; EXPLORATION; PARAMETERS; INSIGHT; IMPACT; SHALES,"Permeability estimation and quantitative evaluation of pore microstructure have always been hotspots and difficulties in tight sandstone reservoirs research. Taking the fractal dimension as the breakthrough, 10 core samples of Chang 7 section in the Upper Triassic Yanchang Formation were collected from different wells in Longdong area of Ordos Basin. The fractal dimension was calculated by mercury intrusion capillary pressure curve which can be obtained from high pressure mercury injection experiment, and samples were divided into four groups as group I, II, III and IV according to the value of fractal dimension estimated. The observation of casting thin sections and field emission scanning electron microscope show that group I mainly has dissolved-intergranular pores and original intergranular pores, group II is mainly dissolved-intergranular pores, group III mainly has dissolved-intragranular pores, and group IV is mainly micropores in clay matrix. Meanwhile, there is a highly correlation between the fractal dimension and the reservoir physical properties. With the fractal dimension of tight sandstone samples approaching 3, the compaction and cementation show a gradual increase, while the pore sorting, physical parameters and percolation capacity display a gradual decrease. Through multiple regression analysis, a set of empirical equations based on the fractal dimension and different pore throat radius were constructed, in which the equation based on maximum permeability contribution radius has the highest correlation. It shows that micropore (0.1-0.2 mu m) contributes most to permeability in tight sandstone reservoir. 10 blind samples were included in regression analysis to improve the prediction accuracy of the new model. A total of 28 samples, including 8 referenced data, were used to verify the predictive accuracy of the new model. The new empirical equation can predict the permeability of tight sandstone relatively accurate. Thus, the fractal dimension can effectively predict the permeability and evaluate the quality of tight sandstone reservoirs.",29,29,7
Fractal Dimension,,"Wang, Xixin; Hou, Jiagen; Li, Shaohua; Dou, Luxing; Song, Suihong; Kang, Qiangqiang; Wang, Dongmei","Insight into the nanoscale pore structure of organic-rich shales in the Bakken Formation, USA",Bakken shale; Pore structure; Controlling factors; Fractal dimension,SILURIAN LONGMAXI SHALES; CANADA SEDIMENTARY BASIN; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; SICHUAN BASIN; CO2 ADSORPTION; SURFACE-AREA; ORDOS BASIN; SIZE; N-2,"The Bakken Shale has attracted much attention because of its huge potential for shale oil. To characterize the nanoscale pore structure of the Bakken shale, ten samples were selected from the upper/lower Bakken Shale for N-2 and CO2 adsorption, which can provide the pore structure parameters, such as pore size, specific surface area (SSA) and pore volume. The controlling factors of the pore structure were studied through the analysis of the mineral composition, total organic carbon (TOC) content, and thermal maturity (VRo-eq). Also, we investigated the fractal characteristics of samples based upon N-2 adsorption. The results exhibited that the composition of the Bakken shale was mainly quartz and clay; the content of clay minerals varies between 24.07% and 53.92%; the content of quartz is between 38.04% and 63.59%. The average value of TOC content of the Bakken shale was 11.49 wt% and the vitrinite equivalent reflectance varied between 0.62 and 1.11%. Micropores (<2 nm) and mesopores (2-50 nm) are the dominant pores in the Bakken shale samples. Quartz, clay and TOC are the key factors controlling the pore structure of Bakken shale. The fractal dimensions D-1 ranged from 2.606 to 2.896 and D-2 ranged from 2.243 to 2.296. D-1 shows a strong positive correlation with D-2, with an R-2 value of 0.8. Higher clay and TOC content lead to more complex pore systems in the Bakken shales. Smaller pore size leads to larger fractal dimensions; hence, the larger the SSA is, the larger fractal dimensions are.",28,29,1
Fractal Dimension,,"Han, Hui; Guo, Chen; Zhong, Ning-ning; Pang, Peng; Gao, Yuan","A study on fractal characteristics of lacustrine shales of Qingshankou Formation in the Songliao Basin, northeast China using nitrogen adsorption and mercury injection methods",Songliao basin; Lacustrine shales; Fractal dimension; Low-pressure N-2 adsorption; Mercury injection; Pore structure,PORE STRUCTURE CHARACTERIZATION; CHANG 7 MEMBER; GAS-ADSORPTION; ORGANIC-MATTER; SICHUAN BASIN; YANCHANG FORMATION; LONGMAXI SHALE; ORDOS BASIN; ACCUMULATION; AREA,"In order to research the fractal characteristics of lacustrine shale, we conducted low-pressure N-2 adsorption and mercury injection measurements on 35 shale samples of Cretaceous Qingshankou Formation in the Songliao Basin, northeast China. The fractal dimensions (D-1, D-2, and D-3) were obtained from N-2 adsorption (P/P-o < 0.5 and P/P-o > 0.5) and mercury injection data, respectively. Accordingly, we analyzed the relationships between fractal dimensions and petmphysical and geochemical parameters. The results show that the fractal dimensions (D-1, D-2, and D-3) are in the ranges of 2.0174-2.5705, 2.5589-2.8425, and 2.1461-2.9728, respectively. There exists a positive relationship between D-1 and D-2, suggesting that micmpores and mesopores have similar surface characteristics. The poor correlations between D-3 and D-1 or D-2 may be related to the different principles of low-pressure N-2 adsorption and mercury injection. The fractal dimensions (D-1 and D-2) correlate positively with pore volumes and surface areas, which indicates that the fractal dimensions can well reflect the pore structure and surface characteristics. The fractal dimensions (D-1 and D-2) decreased with the increasing TOC content, which may be aroused by the low abundance of pores in organic matters. The fractal dimensions (D-1 and D-2) decreased firstly and then increased with the increasing maturity, which is aroused by liquid hydrocarbons generation and cracking. And the fractal dimension D-3 decreased during maturation, which may be induced by compaction. The fractal dimensions (D-1 and D-2) decreased with the increasing Rock-Eval pyrolysis parameters S-1 and S-1/TOC, which suggests that the fractal dimensions can be indicators of oil content of shales.",17,16,7
Fractal Dimension,,"Wang, Fuyong; Cheng, Hui",A fractal permeability model for 2D complex tortuous fractured porous media,Fracture; Permeability; Tortuosity; Porous media; Fractal,CARBONATE ROCK; FLUID-FLOW; NETWORKS,"The complex fracture networks are of significance to petroleum production in unconventional reservoirs, but effectively predicting its permeability is challenging due to the complex distribution and geometry of fracture networks. This paper proposes a new permeability model for 2D complex tortuous fractured porous media based on fractal theory, and two important characteristics of fractures, i.e. branching and tortuosity are considered in the developed permeability model. In this paper, the fractured porous media is assumed to be made up of a bundle of tortuous fractal-like tree fracture networks. First, the modified cubic law for describing flow rate in a fracture with fractal distribution of tortuosity is derived. Secondly, the fractal-like tree fracture network is used to represent the distribution of complex fracture networks, and then flow rate in a tortuous fractal-like tree fracture network is derived. After that, with the assumption of the fractal scaling law between fracture number and fracture apertures, the total flow rate in a bundle of tortuous fractal-like tree fracture networks is given and then the analytical expression for permeability of 2D complex tortuous fractured porous media is derived. Finally, the model reliability is verified with a case study and the key parameters influencing permeability of 2D fracture porous media are investigated with sensitivity study. The research results show that the fractal dimension of aperture distribution D-f, tortuosity fractal dimension D-T, branch level m and fracture length ratio gamma have significant influence on fracture network permeability; the effects of branch angle theta and the straight length of the zero-level fracture l(0) on fracture network permeability are insignificant.",17,18,5
Fractal Dimension,,"Yu, Kun; Ju, Yiwen; Shao, Chunjing",Structure characteristics and evolution mechanism of nanopore in transitional coal-bearing shale,Transitional coal-bearing shale; Pore structure; Pore type; Characteristics; Evolution,PORE-SIZE DISTRIBUTION; DENSITY-FUNCTIONAL THEORY; GAS-ADSORPTION; NITROGEN ADSORPTION; ELECTRON-MICROSCOPY; METHANE ADSORPTION; FRACTAL DIMENSION; HUAINAN COALFIELD; POSIDONIA SHALE; SICHUAN BASIN,"Nanopore plays a crucial role in shale gas adsorption, and its characteristics and evolution are significant for the evaluation of shale reservoirs with strong heterogeneity. In this study, transitional coal-bearing shale samples from the south margin of North China were selected for investigation of pore structure characteristics and evolution mechanism. Results indicated that nanopores of the studied shales are fractal with strong heterogeneity. The higher fractal dimension leads to larger surface area and micropore volume of shale samples. The abundant terrigenous material and limited hydrocarbon generation and expulsion are favorable for the development of intraP pores in clay, so that the Organic matter (OM) pores are poorly developed and are partially filled with clay minerals and pyrite framboids. Shale samples having higher levels of clay content and lower levels of quartz content tend to develop more heterogeneous micropores, producing a more complex pore structure in shale. The evolution of nanopore in studied shales is simultaneously determined by the coupling relationship between clay content and the thermal maturation of OM. In the early oil and low clay content stage, the low degree of the thermal evolution of OM leads to generation of less acidic fluid during the decarboxylation of kerogen, resulting in a weak physical combination and chemical corrosion between OM and clay minerals, with the macropores taking the main place in the pore structure. In the main to late oil and medium clay content stage, hydrocarbon generation of OM leads to the development of pores in kerogen and the gradual generation of more acidic fluids that dissolve clay minerals, so that the mesopores are dominant. In the wet gas and high clay content stage, increases in hydrocarbon generation intensity and clay mineral content cause development of more complexes of OM and clay, with a large number of micropores produced in shale reservoirs.",16,16,3
Fractal Dimension,,"Han, Songcai; Gao, Qi; Cheng, Yuanfang; Yan, Chuanliang; Han, Zhongying; Shi, Xian",Experimental study on brittle response of shale to cryogenic fluid nitrogen treatment,Shale; Cryogenic experiment; Freezing temperature; Mechanical properties; Brittleness evaluation,LIQUID-NITROGEN; FREEZE-THAW; CHINA CHARACTERISTICS; ROCK; GAS; FRACTURE; COAL; TECHNOLOGIES; CHALLENGES; MODEL,"Cryogenic non-aqueous fracturing has attracted extensive attention due to its thermal shock and freezing effects. In this paper, a novel low temperature mechanics experiment (20 similar to -196 degrees C) is conducted for shales under cryogenic fluid nitrogen (CF-N-2) immersion. Experimental results show that the cooling treatment will enhance the mechanical properties of shale and bring about obvious brittleness failure characteristics. A specific manifestation is that the shale stress-strain curves at low temperatures demonstrate higher peak strength, greater Young's modulus, enhanced yield modulus, faster stress drop and lower residual stress. The relationship between the uniaxial compressive strength and Young's modulus of shale and the freezing temperature is established. A more interesting finding is that elastic strengthening phenomenon instead of yield phenomenon occurs with decreasing freezing temperature. To reveal the change of shale brittleness under CF-N-2 cooling, a universal brittleness evaluation model considering the pre- and post-peak deformation characteristics is developed. The evolution of shale brittleness with freezing temperature is obtained. In general, shale brittleness increases with decreasing freezing temperature. The consistency between the brittleness index and the fragmentation fractal dimension at different freezing temperatures verifies the validity of the proposed brittleness evaluation model. Research results indicate that liquid nitrogen, as a new type of cryogenic waterless fracturing fluid, has the potential to improve shale brittleness.",15,15,8
Fractal Dimension,,"Xie, Jing; Gao, Mingzhong; Zhang, Ru; Peng, Gaoyou; Lu, Tong; Wang, Fei",Experimental investigation on the anisotropic fractal characteristics of the rock fracture surface and its application on the fluid flow description,Rock fracture surface; Fractal dimension; Fluid flow; Anisotropic characteristics,ROUGH FRACTURE; HYDRAULIC CONDUCTIVITY; PERMEABILITY MODEL; SINGLE; DIMENSION; RESERVOIR; STRENGTH; APERTURE; LENGTH,"Based on the anisotropic fractal characteristics of natural fracture surfaces, a fractal fluid flow model was developed. Three-dimensional printed fracture models were built using the morphological information of an actual tensile and shear fracture surface of a rock. The impacts of the fractal dimension on the fluid flow characteristics were investigated. The results demonstrated that the concentration distribution of the undulating height of tensile fracture was larger than that of shear fracture. The fractal dimension of fracture lines with different directional sections ranges from 1.01 to 1.03, which results in the fluid flow anisotropy of fracture surfaces. As predicted by the theoretical model, the fluid flows along the tensile fracture surface and the shear fracture surface in different directions are 0.7-1.2 times and 0.9-1.1 times the average flow rates, respectively. With increasing pressure head, the Reynolds number linearly increased, and the Euler number first rapidly decreased and then slowly decreased.",13,13,10
Fractal Dimension,,"Cheng, Guoxi; Jiang, Bo; Li, Ming; Li, Fengli; Song, Yu",Effects of pore-fracture structure of ductile tectonically deformed coals on their permeability: An experimental study based on raw coal cores,Ductile tectonically deformed coal; Pore-fracture structure; Surface fractal characteristics; Permeability; Suxian mining area,CH4 ADSORPTION CAPACITY; STRESS SENSITIVITY; FINES GENERATION; ORDOS BASIN; RANK COAL; DIMENSION; COMPRESSIBILITY; ROUGHNESS; PARTICLES; RESERVOIR,"The distribution area of ductile tectonically deformed coals (TDCs) usually coincides with the forbidden zones for coalbed methane (CBM) development. Permeability of coal reservoirs, an important indicator to evaluate the energy potential of CBM, is directly affected by the pore-fracture structures. To study the controlling mechanism of pore-fracture structures on permeability, we investigated the micropore - micro-fracture structures of various ductile TDCs by adopting mercury intrusion porosimetry (MIP) and low-pressure gas adsorption. The permeability and the pressure sensitivity of the standard TDC cores were tested by the pressure pulse decay method. The results showed that the total pore volume of ductile TDCs, especially the mesopores and macropores, significantly increased from that of primary structure coals (PSCs), while the volume of transitional pores only slightly increased in strongly crumpled and mylonitized coals, and thus, the dominant pores in coals gradually changed from micro-fractures to mesopores and macropores. The pore-fracture structure of ductile TDCs showed a poorer connectivity and a higher roughness than PSCs. The permeability of typical ductile TDCs obviously decreased, the permeability heterogeneity significantly increased, and the pressure sensitivity of permeability generally showed a pattern of ""weakly crumpled - > PSCs > strongly crumpled - and mylonitized coals"". Correlation analysis showed that the weakly crumpled coals that contain well-developed and well-connected microfractures and fewer <10 mu m coal particles usually display high permeability. In strongly crumpled - and mylonitized coals, the connected pore-fracture structures were damaged and many pore throats and flask-shaped pores formed, which is the main reason for the reduced permeability and the high permeability damage rate.",11,10,4
Fractal Dimension,,"Huang, Ting; Du, Pengbin; Peng, Xinkai; Wang, Peng; Zou, Gaofeng",Pressure drop and fractal non-Darcy coefficient model for fluid flow through porous media,Pressure loss; Fractal; Non-Darcy coefficient; Porous media,RESISTANCE MODEL; PERMEABILITY; POROSITY; ERGUN,"Pressure drop loss of fluid flow through porous media is a key issue in many science fields. It has been shown that the non-Darcy coefficient plays a major role in the determination of pressure drop loss. However, the existing prediction models of the non-Darcy coefficient are very divergent, thus requiring to be improved. In this work, a fractal non-Darcy coefficient model for incompressible fluid flow through microporous media materials is established based on the fractal characteristics and fractal capillary bundle model of porous media. The fractal non-Darcy coefficient is expressed as a function of the area ratio between pore and representative elementary volume, pore area fractal dimension, tortuous dimension, porosity, permeability, average tortuosity, maximum pore diameter and mean particle diameter. In this expression, each parameter has a specific physical meaning. The prediction results of our model are compared with the existing experimental data to verify the reliability of the proposed model, and the relationship between the non-Darcy coefficient and each physical parameter has been analyzed thoroughly. The results are helpful to better understand how microstructures of porous media affect the non-Darcy coefficient of fluid flow.",9,9,3
Fractal Dimension,,"Shan, Changan; Zhao, Weiwei; Wang, Fengqin; Zhang, Kun; Feng, Zhao; Guo, Liulinbo; Ma, Xueli; Liao, Tian","Nanoscale pore structure heterogeneity and its quantitative characterization in Chang7 lacustrine shale of the southeastern Ordos Basin, China",Nanoscale pore structure heterogeneity; Quantitative characterization; Chang7 lacustrine shale; Fractal characteristic,TRIASSIC YANCHANG FORMATION; SOUTHERN SICHUAN BASIN; CH4 ADSORPTION CAPACITY; FRACTAL CHARACTERISTICS; GAS-ADSORPTION; LONGMAXI SHALE; GEOCHEMICAL CHARACTERISTICS; ELECTRON-MICROSCOPY; MERCURY-INTRUSION; RESERVOIR,"To gain a better understanding of nanoscale pore structure characteristics in Chang7 lacustrine shale, Ordos Basin, China, 33 shale samples from 15 wells are examined and analyzed by total organic carbon (TOC), X-ray diffraction (XRD), mercury porosimetry, helium pycnometry, low-pressure N-2 adsorption experiments and fractal method. The results show that Chang7 lacustrine shale pores diameter is mainly from 1.5 to 5 nm, and mesopores give the largest contribution to the total pore specific surface area (S-BET) and volume (V-BJH), and micropores have the second contribution to S-BET but little contribution to V-BJH, macropores have very little contribution to S-BET but make a good contribution to V-BJH. According to the occurrence and origin of shale pores, micro-pores can be divided into mineral intragranular pore, minera intercrystalline pore and organic pore. Two fractal dimensions (D1 and D2) are obtained from N-2 adsorption isotherms analysis using FHH method. Relationships between fractal dimensions and shale compositions, pore structure parameters are investigated, which show that both D1 and D2 have good positive relationships with S-BET and V-BJH, but obvious negative correlations with the average pore diameter. That is, the smaller the pore diameter, the more complex the pore structure is, resulting in the larger pore surface and volume. D1 and D2 are both positively correlated with total clay, illite, mixed-layer of illite-smectite, whereas no obvious relationships with chlorite, indicating that the layer and flocculent structure increase the complexity of nanoscale pore structure. TOC content has positive correlation with D1 but no obvious relationship with D2, indicating that the pores in organic matter are mostly micropores. Fractal dimensions are negatively correlated with total brittle mineral, quartz and feldspar content, that is because the surface of brittle minerals is smoother and more homogenous than that of clay minerals.",7,7,10
Well Placement,,"Li, Hu; Wang, Hua; Wang, Lei; Zhou, Xiantian",A modified Boltzmann Annealing Differential Evolution algorithm for inversion of directional resistivity logging-while-drilling measurements,Boltzmann annealing; Differential evolution; Borehole directional resistivity measurements; Distance to boundary; Parallel computation,OPTIMIZATION; MODEL; TOOL,"Being introduced in the last decade for proactive geosteering, directional resistivity logging-while-drilling (DRLWD) measurements have been used to predict and invert formation boundary, which provides more confidence to geosteering engineers in steering a well towards reservoirs' sweet spots. However, the strong non-uniqueness of the inversion problems in the data processing in the DRLWD measurements requires a robust algorithm having a global optimization capability. We propose a modified Boltzmann Annealing Differential Evolution (BADE) algorithm to optimize the inversion problem in the DRLWD measurements. The algorithm combines a multi-population Differential Evolution (DE) algorithm with an annealing strategy. Controlled by the annealing temperature, a bad solution may be accepted probabilistically to avoid the local minima. Moreover, different differential strategies are employed at different stages of annealing to improve the convergence as well as to save computation time. The proposed algorithm is suitable for parallel implementation and it can be accelerated drastically. Synthetic and field examples are presented to showcase the effectiveness and accuracy of the BADE algorithm. Compared to the standard DE algorithm, the modified algorithm converges faster and finds global optimization easier. Combined with a multi-layer model, the BADE algorithm can be used to predict multiple formation boundaries and to evaluate the anisotropic formation resistivities, which will be of great help for proactive geosteering and well placement.",19,19,2
Well Placement,,"Chun, Troy; Li, Yanchao; Wu, Kan",Comprehensive experimental study of proppant transport in an inclined fracture,Proppant transport; Slickwater; Inclined fracture; Hydraulic fracture,SHALE,"The application of slickwater fracturing technology along with horizontal drilling has revolutionized oil and gas energy industry. Solid particles, i.e. proppant, are mixed with slickwater and injected into the formation to keep fractures opened after fracturing. Many researchers have studied the proppant transport and distribution in vertical fractures. However, in unconventional reservoirs with multiple bedding layers and preexisting natural fractures, hydraulically induced fractures with inclined angles are often generated. Thus, proppant transport in various angles of fracture geometry is necessary to study further. In this study, multiple case studies including fracture inclination angle, proppant size, and injection point location were performed to experimentally quantify proppant delivery mechanism in an inclined fracture. Laboratory parameters were scaled down from field conditions to successfully capture proppant transport mechanism without any significant boundary effect. Sand slurry was pumped into a fracture channel and proppant placement was recorded at various conditions. The effect of individual parameter was scientifically analyzed at predetermined condition to quantify the proppant transport trend within an inclined fracture. Friction due to wall roughness and different effective vertical gravitational forces completely change proppant transport behaviors in inclined plane. Frictional force acts stronger, as the fracture plane angle becomes closer to the horizontal plane. Strong wall friction effect creates a thin suspension area rather than settling and forming compact dune. Some proppants are invested for the suspension zone instead of dune area. This leads to greater proppant coverage area, yet smaller dune area. Suspended zone is the most differentiating feature compared to vertical fractures. There is almost no suspended zone observed in the vertical fractures, yet suspended zone is well observed and prevalent in inclined fractures. Fine mesh sized proppants travel farther due to low settling velocity. It therefore forms a well distributed sand pack. Fine particles are heavily influenced by the flow, therefore it follows the streamline of the incoming flow. They also experience strong wall friction. Thus suspension zone and total coverage area increase with smaller proppant size. In addition, the difference between having a single inlet point at various depth compared to having several opened inlet points provides an insight while operating in field environment. The inlet location determines the shape of the sandpack, especially near the wellbore. Lower injection point pushes the sandpack farther, yet this poses a potential wellbore closure or collapse.",17,17,3
Well Placement,,"Chen, Guodong; Zhang, Kai; Xue, Xiaoming; Zhang, Liming; Yao, Jun; Sun, Hai; Fan, Ling; Yang, Yongfei",Surrogate-assisted evolutionary algorithm with dimensionality reduction method for water flooding production optimization,Surrogate model; Production optimization; Dimensionality reduction; Surrogate-assisted evolutionary algorithm; Differential evolution,CONSTRAINED PRODUCTION OPTIMIZATION; CYCLE-PRODUCTION OPTIMIZATION; ALTERNATING-GAS-INJECTION; DIFFERENTIAL EVOLUTION; RESERVOIR MANAGEMENT; GLOBAL OPTIMIZATION; WELL PLACEMENT; MODELS; PROXY; UNCERTAINTIES,"The objective of oil reservoir production optimization is finding optimal scheme of each well to maximize the net present value (NPV) or the hydrocarbon production. Various optimization methods have been proposed to address production optimization problems. Surrogate-assisted evolutionary algorithms have gained increasing attention due to the great performance in reducing the computational resource. However, when dealing with high dimensional optimization problems, surrogate model requires a large number of memories and becomes computationally prohibitive and building a high-quality surrogate model become difficult because of the ""curse of dimensionality"". In this paper, a new framework is proposed based on surrogate-assisted evolutionary algorithm and dimensionality reduction to maximize the expected NPV in life-cycle production optimization. To take advantage of surrogate model in low dimension, Sammon mapping is applied to map high-dimensional decision variables to lower dimensions. Then the search can focus on smaller area guided by surrogate model. The optimization results of two examples show the great performance of the proposed method in comparison with classical evolutionary algorithm and different popular dimensionality reduction methods.",15,16,4
Well Placement,,"Kim, Joonyi; Yang, Hyungjun; Choe, Jonggeun",Robust optimization of the locations and types of multiple wells using CNN based proxy models,,PLACEMENT OPTIMIZATION; PARTICLE SWARM; FIELD DEVELOPMENT; UNCERTAINTY; FLOW; ALGORITHM; ENSEMBLE,,15,15,1
Well Placement,,"Jesmani, Mansoureh; Jafarpour, Behnam; Bellout, Mathias C.; Foss, Bjarne",A reduced random sampling strategy for fast robust well placement optimization,Well placement optimization; Uncertainty; Simultaneous perturbation stochastic approximation (SPSA); Robust algorithm,STOCHASTIC-APPROXIMATION; CONSTRAINED OPTIMIZATION; JOINT OPTIMIZATION; UNCERTAINTY; ALGORITHM; IMPLEMENTATION; LOCATIONS,"Model-based decision-making in oilfield development often involves hundreds of computationally demanding reservoir simulation runs. In particular, well placement optimization under uncertainty in the geologic representation of the reservoir model is an overly time-consuming procedure as the performance of any proposed well configuration needs to be evaluated over multiple realizations, using computationally expensive flow simulations. To reduce computation, we propose an efficient robust optimization procedure in which at each iteration of the optimization procedure, instead of evaluating the well configuration over all available realizations, we approximate the expected performance using a small subset of randomly selected model realizations. Since the samples are selected randomly, all the realizations are expected to eventually be included in the performance evaluation after a certain number of iterations. However, using only a few random realizations to compute the expected cost function introduces noise in the estimated objective function, necessitating the use of a stochastic optimizer. In this paper, we use the Simultaneous Perturbation Stochastic Approximation (SPSA) algorithm, which is known to be robust against noise in the objective function. We first evaluate the performance of different forms of the SPSA algorithm (including discrete, continuous, and adaptive) using several numerical experiments, followed by a discussion of the properties of the proposed reduced random sampling approach and comparison with global optimization techniques. The method is applied to several numerical experiments, including case studies involving vertical, horizontal, and lateral wells, to evaluate its performance. The results from these experiments indicate that the reduced random sampling approach can provide significant computational gain with minimal impact on the attained optimization performance.",15,15,0
Well Placement,,"Chu, Min-gon; Min, Baehyun; Kwon, Seoyoon; Park, Gayoung; Kim, Sungil; Nguyen Xuan Huy",Determination of an infill well placement using a data-driven multi-modal convolutional neural network,Infill well; Convolutional neural network; Multi-modal learning; Productivity,OPTIMIZATION,"This study determines the optimal placement for a vertical infill well using a multi-modal convolutional neural network (CNN). 3D arrays composed of static and dynamic reservoir properties near a candidate infill well are inputted to the convolution stage of CNN. Multi-modal learning is applied to CNN for feature extraction of inputs. The features are compressed via fully connected layers for evaluating the productivity of every candidate infill scenario. The proposed CNN is applied to a channelized oil reservoir, and its performance is compared to that of a feedforward neural network. Dataset for the neural networks is obtained by running full-physics simulations for selected scenarios. CNN outperforms the feedforward neural network for the test scenarios of single- and dualmodal cases. Both neural networks yield comparable predictability for a quad-modal case. Results of the quad-modal CNN are in agreement with reservoir simulation results at cheaper computational costs. The results highlight the potential of data-driven machine learning in expediting the optimal well placement by partially replacing expensive simulation runs.",12,12,1
Well Placement,,"Nasir, Yusuf; Yu, Wei; Sepehrnoori, Kamy",Hybrid derivative-free technique and effective machine learning surrogate for nonlinear constrained well placement and production optimization,Derivative-free optimization; Differential evolution; Machine learning; Well placement; Production optimization,FIELD-DEVELOPMENT OPTIMIZATION; DIFFERENTIAL EVOLUTION; SUBSURFACE FLOW; MODELS; TIME,"It is imperative that wells in an oil field be located and controlled in an optimal fashion to maximize asset value while satisfying the optimization constraints which can be in the form of production limits, water cut, or well spacing. Computational optimization algorithms coupled with a reservoir simulator have become increasingly popular in determining the optimal locations of wells and the optimal controls to be imposed on them. These algorithms should be able to deal with highly non-linear objective functions, the absence of gradient information, and a limited reservoir simulation budget. In this work, we considered derivative-free and non-invasive techniques: Enhanced Success History-Based Adaptive Differential Evolution (ESHADE) strategy with linear population size reduction, which is a variant of L-SHADE (recognized as one of the state-of-the-art global stochastic optimizers for continuous variable), and a Mesh Adaptive Direct Search (MADS) local pattern search method. These two methods are hybridized to develop a hybrid framework (E-MADS) that combines the advantageous aspects of both methods in order to improve optimization efficiency. In order to further improve the efficiency of the framework, gradient boosting machine learning technique is used to generate proxy model, based on regression and classification methods, to predict the objective function and classify optimization solutions into feasibless (satisfies all prescribed constraints) and infeasible groups. This information is then used to screen out solutions that are not expected to improve the objective function. Applications of these algorithms to the joint optimization of well location and time-varying control problem, with bounds and nonlinear constraints, are presented in this work. ESHADE is shown to outperform traditional global optimization algorithms such as Particle Swarm Optimization (PSO) and a real-coded Genetic Algorithm (GA). The E-MADS hybrid is also shown to have a superior performance relative to the standalone ESHADE and MADS methods for the joint optimization problem.",10,10,1
Well Placement,,"Kim, Jaejun; Kim, Sungil; Park, Changhyup; Lee, Kyungbook",Construction of prior models for ES-MDA by a deep neural network with a stacked autoencoder for predicting reservoir production,Deep neural network (DNN); Stacked autoencoder (SAE); Ensemble smoother with multiple data; assimilation (ES-MDA); History matching; Egg model,ITERATIVE ENSEMBLE SMOOTHER; CHANNELIZED RESERVOIRS; UNCERTAINTY QUANTIFICATION; WELL PLACEMENT; KALMAN FILTER; ALGORITHM,"The design of prior models has continued to receive research attention because of their importance for ensemble-based methods. There are two approaches to ensemble design: selection and regeneration. Both strategies try to utilize dynamic data in a qualified prior model. The regeneration approach has a higher degree of freedom than the selection approach because the latter is selected among given initial models. However, previous regeneration methods are still sensitive to prior models because these methods create new models based on the priors' statistics. In this study, a deep neural network (DNN) was implemented to build new prior models. If there is a data pair for a reservoir model and its production, the production data and model parameters become the input and output data, respectively, for training the DNN. The trained DNN can generate new prior models according to the observed production history. For the output layer of the DNN, the main information of the permeability field is extracted by a stacked autoencoder (SAE) to improve the DNN performance. New prior models from DNN with SAE become the qualified prior set for ensemble-based methods because they already reflect observed dynamic data. For validation, an ensemble smoother with multiple data assimilation (ES-MDA) was applied to an Egg model. The proposed method (i.e., prior models designed with DNN-SAE) gave reliable posterior permeability fields and future reservoir performances. Compared with the two control groups (i.e., prior models and prior models with DNN), the proposed method mitigated the overshooting problem and found channel connectivity in the reference field. In a comparison with reliable posterior models, the simulation results of the proposed method not only matched observed production data but also reliably predicted future production. This study is an example of the successful application of a machine learning algorithm to history matching.",9,9,0
Well Placement,,"Naseer, Muhammad Tayyab","Seismic attributes and reservoir simulation' application to image the shallow-marine reservoirs of Middle-Eocene carbonates, SW Pakistan",Gas-bearing shoal limestone reservoir; 45 Hz spectral Magnitude; Seismic-petrophysical shoal model; quantitative seismo-petrophysical simulation (QSPS),SPECTRAL DECOMPOSITION; GAS-FIELD; IDENTIFICATION; FACIES; BASIN,"Carbonates form brilliant stratigraphic traps. The execution of traditional seismic data interpretation using time and depth mapping generates ambiguities in the discrimination of porous and non-porous reservoir beds. In these stratigraphic circumstances, placement of development wells within the unproven prospects is a trial for exploration geophysicist. The 3D post-stack seismic attributes and quantitative seismo-petrophysical simulation (QSPS) are applied on Habib Rahi Limestone (HRL) Member from a gas field, SW Pakistan. 45 Hz spectral magnitude delineates the lithology, fractures, and geomorphology of gas-bearing shoal reservoir facies than full-spectrum seismic tools. 45 Hz predicts a north-east oriented gas-bearing stratigraphic lead, which covers an area of 105 km(2). The QSPS reveals a very low-density (2-2.1 g/c.c.) and low-velocity (similar to 2500-3000 m/s) of shoal reservoir. The high-quality shoal limestone reservoirs of HRL with similar to 30% porosity are deposited during the regression phase of sea-level fall in the east. The low-quality fine-grained seal facies with <9% porosity are deposited during the substantial transgression phase of sea-level rise in the west. The cross plots of seismic-based porosity (%) versus inverted velocity (m/s), inverted density (g/c.c), and reservoir thickness (m) show correlation coefficients of (R)(2)>0.92, (R)(2)>0.97, and (R)(2)>0.89. The coarse-grained gas-bearing reservoirs experience 31.8 m thickness and least density (2-2.1 g/c.c.) are deposited during sea-level fall. The 31.3 m thick and high-density (2.2-2.3 g/c.c.) fine-grained seal facies are deposited during sea-level rise. This workflow can serve as an analogue for the development of carbonate fairways within Asia and similar world basins.",8,8,2
Well Placement,,"Epelle, Emmanuel, I; Gerogiorgis, Dimitrios, I",Adjoint-based well placement optimisation for Enhanced Oil Recovery (EOR) under geological uncertainty: From seismic to production,Well placement; Oil saturation; Well allocation factors; Geological uncertainty; Adjoint formulation; Production optimisation,JOINT OPTIMIZATION; PARAMETERS,"The development of new and existing oil fields is very expensive and technically challenging; this provides an important economic incentive to improve oil recovery via efficient computational optimisation. Decisions related to these activities may be significantly aided by sound and proven mathematical-oriented methods. The use of intuitive engineering judgement alone cannot guarantee sustainable profitability over long periods, especially under geological (reservoir model) uncertainty. To capture the uncertainties in the subsurface geological/reservoir model in this work, geostatistical realisations of the model are obtained using available information (permeabilities and porosities). We also apply specialised algorithms within the MATLAB Reservoir Simulation Toolbox - MRST (interfaced with PETREL (TM)) to optimally vary the well locations and production rates, thus maximising the field's oil recovery. A new modification of an existing pseudowell-based injection well placement algorithm is presented herein with the application of adjoint-computed gradients of an auxiliary objective function (the Lorenz coefficient). The difficulty of this problem is characterised by the presence of discrete variables, a nonlinear and nonconvex objective function and constraints. The developed workflow is applied to a realistic case study, for which robust optimality is demonstrated using the worst case realisation for the determination of optimal well locations and controls. A comparative investigation of optimising injection well location vs. simultaneous optimisation of injection and production well placement is also presented. In our presented case studies, we also discover that increasing the optimisation search space does not necessarily guarantee improved results.",8,8,0
Rock Breaking,,"Liu, Bo; Yang, Yuqi; Li, Jiangtao; Chi, Yaao; Li, Junhui; Fu, Xiaofei","Stress sensitivity of tight reservoirs and its effect on oil saturation: A case study of Lower Cretaceous tight clastic reservoirs in the Hailar Basin, Northeast China",Stress sensitivity; Seepage characteristics; Pore structure; Tight oil; Hailar Basin,TRIASSIC YANCHANG FORMATION; SANDSTONE RESERVOIR; ORDOS BASIN; PERMEABILITY; GAS; DIAGENESIS; EVOLUTION; ROCKS; AREA,"To analyze stress sensitivity of tight reservoirs and the boundary conditions for oil filling, core samples of tight clastic reservoirs in the Lower Cretaceous Nantun Formation in the Hailar Basin were selected. The measurements include optical observation of thin sections, changes of porosity and permeability under overburden pressure, together with physical simulation experiments of oil filling. The results show that the stress sensitivity coefficient of permeability is a product of two parameters including the power exponent of porosity-permeability and pore compressibility, which reflect the geometric and mechanical characteristics of pores. The stress sensitivity and pore geometry of tight reservoirs of different lithologies vary greatly. Medium-coarse sandstones-conglomerates have relatively small stress sensitivity coefficient and large power exponent of porosity-permeability, indicating stronger anti-compaction, weaker stress sensitivity and dominated fissure-type pores. Fine sandstone with large stress sensitivity coefficient and small power exponent of porosity-permeability, indicating that stress sensitivity is high, and matrix circular/elliptical pores predominate. Oil filling in tight reservoirs displays two pressure gradient points with threshold characteristics (i.e., starting pressure gradient and critical pressure gradient) and two flow characteristics (i.e., low-speed nonlinear seepage and quasi-linear seepage). Only when the actual pressure gradient breaks through the critical pressure gradient into the quasi-linear seepage zone can oil saturation in the tight reservoir reach the lower limit of 30%, attaining higher oil saturation levels gradually during the subsequent filling process. The favorable tight reservoir is characterized by a low stress sensitivity coefficient and a high power exponent of porosity-permeability, and oil exhibits rapid filling characteristics with quasi-linear seepage. Another type of tight reservoir is characterized by a high stress sensitivity coefficient and a low power exponent of porosity-permeability, and oil exhibits slow filling rate with nonlinear seepage. It is therefore difficult in actual geological conditions for such reservoirs to achieve high oil saturation. Increase in oil saturation during the filling process is controlled by a combination of initial permeability, pore geometry, stress sensitivity and the displacement pressure gradient. These factors affect and compensate each other, comprehensively controlling the accumulation of tight oil, and could be used to classify the reservoir types.",57,59,12
Rock Breaking,,"Oloruntobi, Olalere; Butt, Stephen",Application of specific energy for lithology identification,Hydromechanical specific energy; Lithology; Rate of penetration; Drilling; Bit,MECHANICAL SPECIFIC ENERGY; PORE-PRESSURE; ROCK,"The previous applications of specific energy to drilling operations have focused mainly on drilling optimization and identification of inefficient drilling conditions. Recent advances in specific energy extend its applications to overpressure detection and pore pressure prediction. In this paper, an attempt is made to further extend the application of specific energy to real-time identification of subsurface lithology. The concept is based on the principle that the total energy required to break and remove a unit volume of rock is a function of lithology. The proposed methodology is tested using a recently drilled exploratory gas well in the tertiary deltaic system of the Niger Delta basin. In general, an excellent agreement is observed in trend between the traditional lithology identifiers (gamma ray and sonic velocity ratio) and the total energy consumed in breaking and removing the penetrated rocks. Unlike the logging while drilling (LWD) technique commonly employed in the industry (including the application of near bit sensors placed few feet behind the bit), the proposed methodology can provide a reliable means of picking formation tops and identifying subsurface lithology at the bit with no extra cost since drilling parameters are routinely recorded at the wellsite during the drilling of a well. The proposed methodology will assist the drilling engineers and geologists in determining the casing setting depths and coring points without having to drill too deep into the formation of interest.",14,15,2
Rock Breaking,,"Zhu, Xiaohua; Luo, Yunxu; Liu, Weiji",On the rock-breaking mechanism of plasma channel drilling technology,Plasma channel drilling; High-voltage electric pulse; Rock-breaking mechanism; Formation pressure; Cracks; DEM,BONDED-PARTICLE MODEL; BREAKDOWN; LIBERATION; FRAGMENTATION; DESTRUCTION; ENERGY; ORES,"Plasma channel drilling (PCD), which is also known as high-voltage electric pulse drilling, is a highly efficient rock-breaking drilling technology with great development potential. This paper presents a method to study the rock-breaking mechanism of PCD technology. Then based on the predecessor's foundation, the factors affecting the development of plasma channels are explored using the dielectric breakdown model (DBM). Finally, a numerical rock-breaking model considering electric-thermal-mechanical three fields is established. This paper reveals the basic rock-breaking process of PCD and how the formation pressure affects the rock-breaking process of PCD technology. The main conclusions are: the formation law of plasma channel is related to the electrode structure and the inputting electrical parameters, the electrical properties of the rock and the type of rock; the plasma channel has an internal dynamic effect on the rock breaking process, and this internal dynamic effect of the plasma channel is sharply weakened after the channel is formed; shear cracks play a lead role in PCD, and the number of shear cracks is larger than that of conventional mechanical-rotary drilling; the formation pressure has little effect on the rock failure, the total volume of the chips, and the total number of cracks in the PCD, and the rock-breaking efficiency is not limited by the drilling depth. Finally, in order to improve the rock breaking-efficiency, it is recommended that the PCD technology be used in conjunction with slim hole drilling technology or jet drilling technology.",13,13,10
Rock Breaking,,"Dai, Xianwei; Huang, Zhongwei; Shi, Huaizhong; Cheng, Zhen; Xiong, Chao; Wu, Xiaoguang; Zhang, Hongyuan",Rock failure analysis based on the cutting force in the single PDC cutter tests,Cutting force; Brittle failure; Compression; Variation rate,MODE TRANSITION DEPTH; PEROXIDE PRESOAKING PRIOR; ENERGY; PRESSURE,"The polycrystalline diamond compact (PDC) bits have gained increasing favor since 1976. In order to further improve the ROP, the single PDC cutter tests were widely used. During these experiments, the cutting force is an important index to identify the efficiency of rock breaking. However, only the average value of cutting force was calculated in the previous researches. The variation trend of cutting force was not emphasized, which could reflect the process of rock failure to a large extent. In this study, a novel method to calculate the cutting force was used. At first, all the peak and valley values in the cutting force were picked out. With these points, the cutting force curves were separated into two parts: 1) rock loading process and 2) rock failure process. Then, the cutting force difference (Delta F), variation time (Delta t) and changing rate of cutting force (Ra) under different conditions were analyzed. Besides, we also calculated the changing rate of Ra with Delta F (Sl(Ra)). The results show that the variation trend of cutting force has a close relationship with the rock failure mode. That is, the above values at different cutting depth show significantly different characteristics in the unloading process of cutting force, which corresponding to the compression or the brittle failure of the rock, respectively. And the loading of cutting force is a stable process all the time. The results of this study are expected to introduce a new research perspective for the investigation of rock failure mode and working pattern of PDC cutters.",11,11,8
Rock Breaking,,"Gao, Mingyang; Zhang, Kai; Zhou, Qin; Zhou, Huifeng; Liu, Baolin; Zheng, Guojing",Numerical investigations on the effect of ultra-high cutting speed on the cutting heat and rock-breaking performance of a single cutter,Ultra-high-speed cutting; Thermal elastoplastic damage model; Rock-breaking mechanism; Cutting heat,DRILLING RESPONSE; BIT; SIMULATION; SURFACE; FORCE; MODEL,"As a new drilling technology, the ultra-high-speed diamond drilling can exhibit great superiority in drilling deep hard rock, which can achieve high rates of penetration (ROP) with substantially lower energy and load. In order to better understand the removal mechanism, the effect of ultra-high cutting speed on the cutting heat and rock-breaking performance of a single cutter was investigated by using ABAQUS software. A thermal elastoplastic damage model has been established by using a finite element analysis system aiming at the linear cutting operations. The changes of stress state, strain accumulation, and heat migration in the tool unit were analyzed. The results show that when the cutting speed exceeds 8 m/s, the heat flux and mechanical specific energy (MSE) decrease as the rotary speed (RPM) increases. That is, when cutting at ultra-high linear speed (>8 m/s), more input energy was used to break rock. In addition, when the cutting speed is in the ultra-high-speed stage and continues to increase, the proportion of brittle failure of the rock will gradually increase, and a new balance will not be reached until the cutting speed reaches 12 m/s, which helps to improve the rock breaking efficiency.",9,9,14
Rock Breaking,,"Li, Lei; Wang, Fangxiang; Li, Tianyang; Dai, Xiaodong; Xing, Xueyang; Yang, Xiancheng",The effects of inclined particle water jet on rock failure mechanism: Experimental and numerical study,Inclined particle water jet; SPH-FEM coupling method; Initial cracks; Confining pressure; Stress wave,SPH; SIMULATION; ALGORITHM; MESHLESS; FLOW; FEM; TECHNOLOGY; DESIGN; DAMAGE; FIELD,"The method of adding particles to water jet can significantly improve the rock breaking efficiency, and it is helpful to increase the rate of penetration for hard and abrasive formation. To compare the vertical and inclined particle jet on the rock failure mechanism and the effect of confining pressure, this paper adopted the SPH-FEM coupling method and the results were verified by experiments. The inclined jet impacting the rock at a certain angle can cause a widespread damage under the comprehensive effect of direct impact and radial stretch. The inclined particle jet is more efficient and easier to form large destruction when the inclined angle is in the appropriate range of 15-20 degrees. The hole profile formed by the vertical impact of the particle jet is conical. The lower edge of the hole profile formed by the inclined impact of the particle jet is parabolic, which is approximately parallel to the incident direction. Confining pressure can reduce the damage range and peak value of stress wave, but the critical rock breaking pressure will increase with increase of confining pressure. Compared with the condition of no confining pressure, the initial damage of rock delays under confining pressure.",8,10,17
Rock Breaking,,"Zhang, Zengzeng; Zhao, Dajun; Zhao, Yan; Zhou, Yu; Tang, Qiongqiong; Han, Junpeng",Simulation and experimental study on temperature and stress field of full-sized PDC bits in rock breaking process,Full-sized PDC bits; Temperature field; Stress field; Finite element simulation,THERMAL RESPONSE; CUTTERS; FORCE; WEAR; REDUCTION; FRACTURE; FATIGUE; SURFACE; STATE; MODEL,"The failure rate of polycrystalline diamond compact (PDC) bits mainly depended on the cutting temperature and the force of the cutting teeth. It was of great value to study the distribution of temperature and stress fields on the PDC cutting teeth during rock breaking for exploring the failure mechanism and improving the service life of the bits. In this paper, the finite element was used to simulate the thermal-structural coupling of rock breaking process of the full-sized PDC bits. The simulation results show that the high temperature region of the cutting teeth was offset from the top of the crown to the outside of the cutting teeth during drilling process, and the high temperature region of the cutting teeth was fan-shaped. The failure reason of PDC cutting teeth was analyzed by simulation. The maximum principal stress of PDC cutting teeth existed in the interface between the polycrystalline diamond (PCD) layer and the cemented carbide (WC-Co) substrate, fracture and delamination were concentrated at the top of the cutting teeth crown. The experimental results show that the temperature of cutting teeth when drilling the granite was about 2 times that of the marble and 3 times that of the sandstone under the same conditions. The simulation results were basically consistent with the experimental results, which verified the accuracy of the finite element model simulation analysis method.",8,9,11
Rock Breaking,,"Xiong, Chao; Huang, Zhongwei; Yang, Ruiyue; Sheng, Mao; Shi, Huaizhong; Dai, Xianwei; Wu, Xiaoguang; Zhang, Shikun",Comparative analysis cutting characteristics of stinger PDC cutter and conventional PDC cutter,Stinger PDC cutter; Cutting characteristics; Single cutter tests; Rock-breaking mechanism,ROCK; TEMPERATURE; BREAKING; GRANITE; SURFACE; FORCE,"The Stinger PDC cutter has a better performance than the conventional PDC cutter drilling for hard, interbedded and highly abrasive rocks. Although researchers have investigated the cutter's characteristic, such as impact resistance, wear resistance and cutter's life, the cutting behaviors of the Stinger PDC cutter still remains unclear. In this study, the single cutter tests were carried out with a Stinger PDC cutter and a conventional PDC cutter as comparisons. The cutting force, cuttings size, surface topography along the cutting trajectory and microscopic morphology of the fracture surface were compared and analyzed. The results show that the average cutting force of a Stinger PDC cutter is 46.14% lower than that of a conventional PDC cutter. The proportion of large cuttings (r > 2.36 mm) generated in the Stinger PDC cutter test is higher than that in the conventional PDC cutter test. In addition, the energy consumption of breaking rocks by a Stinger PDC cutter is 34.09% lower than that by a conventional PDC cutter. The cutting trajectory in the Stinger PDC cutter test has a ""V"" shape and the surface is relatively rough (Sa = 617.08 mu m), while the conventional PDC cutter produces a ""U"" shape cutting trajectory and the surface is relatively smooth (Sa = 462.18 mu m). Furthermore, the SEM analysis shows that the Stinger PDC cutter breaks granite mainly by tensile stress, which is different with the conventional PDC cutter by shear stress. The key findings of this work will help to reveal the rock-breaking process and mechanism with the Stinger PDC cutters.",8,8,7
Rock Breaking,,"Shao, Jiaxin; You, Lijun; Kang, Yili; Gao, Xinping; Chen, Mingjun; Meng, Sen; Zhang, Nan",Experimental study on stress sensitivity of underground gas storage,Underground gas storage; Effective stress; Pressure gradient; Stress sensitivity; Effective stress action time,TRANSPORT BEHAVIOR; PERMEABILITY; MULTISCALE; MECHANISM; BASIN,"The increase in effective stress and effective stress action time reduces the permeability of rock fractures. XG underground gas storage systems are constructed in carbonate formations. Fractures constitute the main seepage channel of pore-fracture carbonate formation. Alternating stress during multi-cycle injection-production of underground gas storage causes the fractures to open and close periodically. This leads to stress sensitivity of the formation and reduces the permeability of rock fractures. In this work, typical rock samples of carbonate formation in XG underground gas storage were selected as the research object, and stress sensitivity experiments, gas speed sensitivity experiments and stress sensitivity experiments considering effective stress action time were carried out. The rock sample permeability during the experiment was measured. The fracture walls of rock samples before and after the stress sensitivity experiments and stress sensitivity experiment considering the effective stress action time were analyzed by SEM. The influence mechanism of effective stress and effective stress action time on permeability of underground gas storage was explored. Stress sensitivity coefficient method was used to evaluate stress sensitivity. The results show that the stress sensitivity of fracture and matrix samples considering effective stress action time was enhanced compared with stress sensitivity experiments. With the increase in effective stress action time, the elastic-plastic deformation of rock increased the breaking of microconvex bodies on the fracture wall. Moreover, micro-fractures were generated to reduce rock strength. The breaking of micro-convex bodies and the generation of micro-fractures strengthened the stress sensitivity of rocks. Moreover, fine migration caused by excessive injection-production pressure gradient also increased the stress sensitivity.",7,7,5
Proxy Model,,"Chen, Guodong; Zhang, Kai; Xue, Xiaoming; Zhang, Liming; Yao, Jun; Sun, Hai; Fan, Ling; Yang, Yongfei",Surrogate-assisted evolutionary algorithm with dimensionality reduction method for water flooding production optimization,Surrogate model; Production optimization; Dimensionality reduction; Surrogate-assisted evolutionary algorithm; Differential evolution,CONSTRAINED PRODUCTION OPTIMIZATION; CYCLE-PRODUCTION OPTIMIZATION; ALTERNATING-GAS-INJECTION; DIFFERENTIAL EVOLUTION; RESERVOIR MANAGEMENT; GLOBAL OPTIMIZATION; WELL PLACEMENT; MODELS; PROXY; UNCERTAINTIES,"The objective of oil reservoir production optimization is finding optimal scheme of each well to maximize the net present value (NPV) or the hydrocarbon production. Various optimization methods have been proposed to address production optimization problems. Surrogate-assisted evolutionary algorithms have gained increasing attention due to the great performance in reducing the computational resource. However, when dealing with high dimensional optimization problems, surrogate model requires a large number of memories and becomes computationally prohibitive and building a high-quality surrogate model become difficult because of the ""curse of dimensionality"". In this paper, a new framework is proposed based on surrogate-assisted evolutionary algorithm and dimensionality reduction to maximize the expected NPV in life-cycle production optimization. To take advantage of surrogate model in low dimension, Sammon mapping is applied to map high-dimensional decision variables to lower dimensions. Then the search can focus on smaller area guided by surrogate model. The optimization results of two examples show the great performance of the proposed method in comparison with classical evolutionary algorithm and different popular dimensionality reduction methods.",15,16,4
Proxy Model,,"Kim, Joonyi; Yang, Hyungjun; Choe, Jonggeun",Robust optimization of the locations and types of multiple wells using CNN based proxy models,,PLACEMENT OPTIMIZATION; PARTICLE SWARM; FIELD DEVELOPMENT; UNCERTAINTY; FLOW; ALGORITHM; ENSEMBLE,,15,15,1
Proxy Model,,"Rao, Xiang; Zhao, Hui; Deng, Qiao",Artificial-neural-network (ANN) based proxy model for performances forecast and inverse project design of water huff-n-puff technology,Water huff-n-puff; Artificial neural network; Improved oil recovery; Tight fractured reservoir,FRACTURE NETWORKS; TIGHT OIL; RESERVOIR,"Water huff-n-puff is an effective improved oil recovery (IOR) technology for tight or low-permeability reservoirs which are developed by fractured horizontal wells. This paper trains a forward-looking and an inverse project design ANN based models by using large amount of sample data generated from embedded discrete fracture model (EDFM). The models fully consider reservoir properties, fracture geometry, capillary pressure, relative permeability and other fluid properties, and engineering design parameters. The forward-looking model can accurately and efficiently predict the oil/water production rates according to input reservoir parameters and schedules, the reverse design model can determine the reasonable water huff-n-puff schedule according to the expected average daily oil production rate. Besides, the models are applied to fast parametric studies of capillary pressure, fracture related parameters to analyze the influencing factors of water huff-n-puff process, and uncertainty analysis of the inverse design ANN model is conducted by Monte Carlo Simulation. In all, the developed ANN models can help petroleum engineers make better use of this important IOR technology of water huff-n-puff for low permeability or tight reservoirs.",14,13,7
Proxy Model,,"Zhong, Zhi; Sun, Alexander Y.; Wang, Yanyong; Ren, Bo",Predicting field production rates for waterflooding using a machine learning-based proxy model,Machine learning; Conditional deep convolutional generative adversarial neural network; Data-driven proxy model; Waterflooding; Field production rate,RESPONSE-SURFACE METHODOLOGY; ALTERNATING-GAS-INJECTION; RELATIVE PERMEABILITY; OIL-FIELD; WORK FLOW; OPTIMIZATION; PRESSURE; DESIGN,"Waterflooding, during which water is injected in the reservoir to increase pressure and therefore boost oil production, is extensively used as a secondary oil recovery technology. Tracking the extent and efficacy of waterflooding (i.e., fluid distributions) is a primary task of reservoir engineers and is traditionally achieved by running full reservoir models. In this work, we design and implement a proxy model using a conditional deep convolutional generative neural network (cDC-GAN), which can be used to quickly calculate the dynamic fluid distribution of a heterogeneous reservoir under waterflooding. Zero-sum game theory is the basis for the cDC-GAN, which includes a pair of generative discriminative models. The generative model tries to learn the relationship between input and output and makes the generated output as close as possible to the training data, while the discriminative model tries to distinguish the fake output and the real data used for training, such that the cDC-GAN learns the real data distribution at the end. In our cDC-GAN formulation, the reservoir properties (permeability distribution in this research) and forecast time information are treated as input, and water saturation is the desired output. The reservoir fluid production rate can be calculated based on the material balance principle. The most significant contribution of this work resides in training a cDC-GAN proxy model to accurately predict fluid saturation. A cDC-GAN has several advantages over the traditional full-model based workflow. First, the model parameters estimated from history matching help to improve reservoir characterization. Second, this proposed proxy model can predict the water and oil saturation distributions simultaneously, which can be used to calculate the water and oil flow rates. Third, this proposed proxy model can be used for waterflooding optimization and uncertainty analysis with far less computational effort than with the traditional method, which uses a reservoir simulator.",13,13,9
Proxy Model,,"Aljuboori, Faisal Awad; Lee, Jang Hyun; Elraies, Khaled A.; Stephen, Karl D.",The effectiveness of low salinity waterflooding in naturally fractured reservoirs,Low salinity (LoSal) waterflooding; Naturally fractured reservoirs (NFR's); Wettability alteration; Residual oil reduction; Qamchuqa reservoir,OIL-RECOVERY; BRINE COMPOSITION; MAUDDUD FORMATION; WATER INJECTION; WETTABILITY; FLOW; SIMULATION; SANDSTONE; FIELD,"Low Salinity (LoSal) waterflooding is a technique which promises to improve and enhance oil recovery. The method has been studied widely in the laboratories using various core plug samples of sandstones and carbonates. Most of the experimental outcomes have demonstrated the possibility of recovery increment in conventional reservoirs. Meanwhile, it is rare to find a discussion in these experiments about the effectiveness of LoSal waterflooding in naturally fractured reservoirs. In this paper, we investigate the potential benefits in fractured reservoirs using simulations. It is often reported from coreflood experiments that LoSal injection has the ability to alter the rock wettability and reduce residual oil saturations through chemical and physical interactions between the rock-oil-water system. Based on the published work, we have calculated relative permeability curves to represent the flow in regions flooded with LoSal water. This includes a qualitative representation of uncertainty. In this sense, the relative permeabilities are a proxy for any physical and chemical mechanisms which are not explicitly represented. The newly generated flow curves were applied to simulate LoSal waterflooding using a fine-scale model and a field scale model based on a fractured reservoir from the Middle East. The simulation results underline the benefits of LoSal whereby the oil recovery from fractured reservoirs can be increased. An additional benefit is the control of water production. The fine-scale modelling has provided an in-depth analysis and accurate estimation of the oil recovery without modelling artefacts or limitations, where an increment of (12-14)% of the Stock Tank Oil Initially In Place (STOIIP) were obtained under secondary and tertiary recovery scheme, respectively. The investigated scenarios demonstrated a sensitivity to the newly generated flow curves and how they affect the ultimate oil recovery. However, for the field scale model, a higher oil production rate has maintained during LoSal waterflooding up to 32 K BPD by the end of year fourteen compared with 25 K BPD in case of high salinity scenario, besides a reduction in the produced water by 35.7%. Therefore, the effectiveness of LoSal brine required a longer time frame to observe the improvements in the oil displacement or sweep efficiency.",13,13,2
Proxy Model,,"Sun, Qian; Ertekin, Turgay",Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies,Artificial neural network; Polymer injection; Optimization; EOR screening; EOR project design,ALGORITHM,"Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.",11,11,2
Proxy Model,,"Nasir, Yusuf; Yu, Wei; Sepehrnoori, Kamy",Hybrid derivative-free technique and effective machine learning surrogate for nonlinear constrained well placement and production optimization,Derivative-free optimization; Differential evolution; Machine learning; Well placement; Production optimization,FIELD-DEVELOPMENT OPTIMIZATION; DIFFERENTIAL EVOLUTION; SUBSURFACE FLOW; MODELS; TIME,"It is imperative that wells in an oil field be located and controlled in an optimal fashion to maximize asset value while satisfying the optimization constraints which can be in the form of production limits, water cut, or well spacing. Computational optimization algorithms coupled with a reservoir simulator have become increasingly popular in determining the optimal locations of wells and the optimal controls to be imposed on them. These algorithms should be able to deal with highly non-linear objective functions, the absence of gradient information, and a limited reservoir simulation budget. In this work, we considered derivative-free and non-invasive techniques: Enhanced Success History-Based Adaptive Differential Evolution (ESHADE) strategy with linear population size reduction, which is a variant of L-SHADE (recognized as one of the state-of-the-art global stochastic optimizers for continuous variable), and a Mesh Adaptive Direct Search (MADS) local pattern search method. These two methods are hybridized to develop a hybrid framework (E-MADS) that combines the advantageous aspects of both methods in order to improve optimization efficiency. In order to further improve the efficiency of the framework, gradient boosting machine learning technique is used to generate proxy model, based on regression and classification methods, to predict the objective function and classify optimization solutions into feasibless (satisfies all prescribed constraints) and infeasible groups. This information is then used to screen out solutions that are not expected to improve the objective function. Applications of these algorithms to the joint optimization of well location and time-varying control problem, with bounds and nonlinear constraints, are presented in this work. ESHADE is shown to outperform traditional global optimization algorithms such as Particle Swarm Optimization (PSO) and a real-coded Genetic Algorithm (GA). The E-MADS hybrid is also shown to have a superior performance relative to the standalone ESHADE and MADS methods for the joint optimization problem.",10,10,1
Proxy Model,,"de Brito, Daniel U.; Durlofsky, Louis J.",Well control optimization using a two-step surrogate treatment,Well control optimization; Surrogate model; Proxy model; Field development optimization; Reservoir simulation,SIMULATION; OIL; NANOTECHNOLOGY; TRANSPORT; RHEOLOGY; PROGRESS,"Large numbers of flow simulations are typically required for the determination of optimal well settings. These simulations are often computationally demanding, which poses challenges for the optimizations. In this paper we present a new two-step surrogate treatment (ST) that reduces the computational expense associated with well control optimization. The method is applicable for oil production via waterflood, with well rates optimized at a single control period. The two-step ST entails two separate optimizations, which can both be performed very efficiently. In the first optimization, optimal well-rate ratios (i.e., the fraction of total injection or production associated with each well) are determined such that a measure of velocity variability over the field is minimized, leading to more uniform sweep. In the second step, overall injection and production rates are determined. The flow physics in the first step is highly simplified, while the actual physical system is simulated in the second step. Near-globally-optimal results can be determined in both cases, as the first optimization is posed as a QP problem, and the second step entails just a single optimization variable. Under full parallelization, the overall elapsed time for the ST corresponds to the runtime for 1-2 full-order simulations. Results are presented for multiple well configurations, for 2D and 3D channelized models, and comparisons with formal optimization procedures (mesh adaptive direct search or MADS, and an adjoint-gradient method) are conducted. Three different fluid mobility ratios (M = 1, 3 and 5) are considered. Optimization results demonstrate that the two-step ST provides results in reasonable agreement with those from MADS and adjoint-gradient methods, with speedups of 5. or more. We also show that the ST is applicable in the inner-loop in field development optimization, where it will be especially useful since many different well configurations must be evaluated.",8,8,0
Sediments,,"Wang, Leizhen; Wang, Guorong; Mao, Liangjie; Fu, Qiang; Zhong, Lin",Experimental research on the breaking effect of natural gas hydrate sediment for water jet and engineering applications,Natural gas hydrates; Solid fluidization; Water jet; Mining; Breaking effect,,"Experimental studies on the influence of traverse speed, jet flow rate, and reciprocating times of jet flushing on natural gas hydrate sediment breaking effect under water jet were carried out. The breaking effect was evaluated from four aspects: shape regularity of broken hole, variation of broken hole diameter, breaking efficiency, and solid phase concentration of slurry formed by the jet. Results show that a uniform arrangement of 18 nozzles in radial direction of the water jet mining head can ensure that broken hole shape is regular and circular. To reach a 0.5 m hole diameter, the reciprocating times of flushing increases with the increase of the traverse speed and decreases with the increase of the jet flow rate. The breaking efficiency which is very low at small borehole diameter increased first and then decreased with the increase of the hole diameter. The increase of the jet flow rate and traverse speed is conducive to improve breaking efficiency. However, that leads to extremely high solid phase concentration of slurry, which will increase the risk of pipeline transportation. In order to achieve well breaking effect of natural gas hydrate sediment by water jet, the recommended technological parameters are jet flow rate of 450 L/min, traverse speed of 5 m/min and 5 reciprocating times of flushing when the initial hole diameter is 0.1 m. This study provides a reference for the formulation of the technological parameters for the first solid fluidization well testing and production operation in the world.",24,26,11
Sediments,,"Dong, Lin; Li, Yanlong; Liao, Hualin; Liu, Changling; Chen, Qiang; Hu, Gaowei; Liu, Lele; Meng, Qingguo",Strength estimation for hydrate-bearing sediments based on triaxial shearing tests,Gas hydrate; Triaxial shearing test; Failure mechanisms; Strength prediction; Strength criterion,MECHANICAL-PROPERTIES; WELLBORE STABILITY; SHENHU AREA; SAND; BEHAVIOR; MODEL,"Evaluating deformation characteristics and predicting strength parameters of hydrate-bearing sediments (HBS) are indispensable for natural gas hydrate exploration and development. A series of triaxial shearing tests were conducted in this paper to analyze the mechanical behaviors and failure mechanisms of hydrate-bearing sediments. The failure strength is discussed comprehensively based on the Mohr-Coulomb criterion, the Drucker-Prager criterion, and the Lade-Duncan criterion. Failure mechanisms of the specimens during shearing are discussed at the micro-level. The results indicate that specimens with relatively high hydrate saturation exhibit strain-softening brittle failure mode, whereas those with relatively low hydrate saturation exhibit obvious strain-hardening ductile failure mode. The cohesion of HBS is enhanced from 0.42 MPa to 1.0 2 MPa, and the friction angle increases from 26.4 degrees to 34.2 degrees with hydrate saturation rising. Additionally, the modified criteria based on the Drucker-Prager criterion can predict the strength with the highest accuracy. The results provide a theoretical and experimental reference for developing the natural gas hydrate reservoirs efficiently.",24,27,6
Sediments,,"Wang, Lei; Li, Yanghui; Wu, Peng; Shen, Shi; Liu, Tao; Leng, Shudong; Chang, Yuan; Zhao, Jiafei",Physical and mechanical properties of the overburden layer on gas hydrate-bearing sediments of the South China sea,Overburden; Gas hydrate-bearing sediments; Physical properties; Mechanical properties; South China sea,SURFACE SEDIMENTS; MARINE-SEDIMENTS; POROUS-MEDIA; WATER-FLOW; GEOCHEMISTRY; SLOPE; PERMEABILITY; STABILITY; RESERVOIR; PRESSURE,"Gas hydrate exploitation may trigger the destruction of the overburden structure and settlement of the overburden layer on the gas hydrate-bearing sediments. It is extremely urgent to explore the basic laws governing the physical and mechanical properties of the overburden layers before performing commercial exploitations of hydrates. However, relatively few studies have focused on the physical and mechanical properties of the overburden layer (uppermost similar to 10 m) on the gas hydrate-bearing sediments of the South China Sea. In this research, we studied the physical and mechanical properties of the overburden sediments from this area, including the particle size distribution, the specific surface area, the pore size distribution, the water content, the liquid/plastic limits, and the mineral and chemical compositions of the particles, as well as the strength and deformation characteristics. According to the results, we found that the overburden sediments of the Shenhu area are characterized as well-graded clayey silts and considered to be internally stable and self-filtering. The isothermal adsorption-desorption curve is a Type H3 hysteretic loop, indicating that the shape of the particles occurs primarily in a plate form, and most of the pores are slit-shaped. The plasticity index in this area is relatively lower than that in other areas, which suggests that there is a risk of overburden collapse during the production process of hydrates. The mineral composition of the overburden sediment particles is primarily quartz, plagioclase, calcite and some accessory clay minerals, which can provide guidance for remolding the overburden sediments in the laboratory. The sediments show strain hardening and shear contraction behavior upon shearing; in addition, the established strength criterion will contribute to the formulation of constitutive equations for the overburden sediments, which can be used as essential input parameters in gas hydrate production simulations.",18,20,15
Sediments,,"Li, Jinlong; Yang, Chunhe; Shi, Xilin; Xu, Wenjie; Li, Yinping; Daemen, Jaak J. K.",Construction modeling and shape prediction of horizontal salt caverns for gas/oil storage in bedded salt,Bedded salt rocks; Natural gas storage; Horizontal cavern; Cavern leaching; Mathematical model; Insoluble sediments,ROCK-SALT; FEASIBILITY ANALYSIS; ENERGY-STORAGE; STABILITY; JINTAN,"Construction modeling and shape prediction are significant for the parameters optimization and capacity prediction of a horizontal salt cavern gas/oil storage. However, most previous studies concentrate on the middle segment of the cavern, and the insoluble substances are ignored. The actual shapes of the horizontal salt caverns in bedded salt remain unknown. Here a coupled model is proposed for the construction of a horizontal cavern. A composite structural mesh is presented to describe the development of three segments of the cavern. The equations of the salt-brine mass transfer rate and boundary movements are introduced. A simplified flow and concentration field model is presented. The accumulation of the insoluble substances is firstly considered in a horizontal cavern. A VC++ program using the finite volume method is developed to obtain the numerical solution of the model and as a construction design tool for the horizontal salt caverns. The reliability of the model and program has been confirmed by comparisons with laboratory experiments. The shape of a field horizontal cavern HA4-5 in Huai'an, China is successfully simulated. The simulation results coincide well with the field data. It is found that the horizontal cavern is actually U-shaped and there is an undetected open cavern in the middle segment. This cavern is suggested to be used as a non-clogging de-brining pool during gas/oil injection and brine discharge. The brine in the pores of the insoluble sediments will be replaced by gas/oil and the storage capacity will be multiplied. The finding promises a broad prospect for the horizontal salt cavern gas storage in bedded salt.",13,13,5
Sediments,,"Yalaoui-Guellal, Drifa; Fella-Temzi, Samira; Djafri-Dib, Salima; Brahmi, Fatiha; Banat, Ibrahim M.; Madani, Khodir",Biodegradation potential of crude petroleum by hydrocarbonoclastic bacteria isolated from Soummam wadi sediment and chemical-biological proprieties of their biosurfactants,Hydrocarbonoclastic bacteria; Biodegradation; Antimicrobial activity; Antioxidant activity; Biosorption capacity of lead,REMEDIATION; OIL; EXOPOLYSACCHARIDE; DIVERSITY; BEJAIA,"This work aims to evaluate the biodegradation potential of petroleum by hydrocarbonoclastic bacteria isolated from Soummam wadi sediments. The chemical-biological properties of their biosurfactants products were also determined. Percentage of petroleum degraded by Rhodococcus ruber, Akaligenes faecalis and Cellulosimicrobium sp. reached the maximum of 56.5 +/- 1.2%, 52.7 +/- 1.1% and 49.7 +/- 1.2% respectively. Chemical profile study of the biosurfactants confirms their lipopeptide nature. The antifungal activity of these biosurfactants has given diameters of the zones of inhibition varying between 11.66 +/- 0.57 mm and 18.33 +/- 0.57 mm. The antioxidant activity showed a low activity for the antiradical power using the DPPH * and the molybdate test. The biosorption capacity of lead showed maximum biosorption of 74.91 +/- 2.1 mu g/g of Rhodococcus ruber biosurfactants. These bacterial isolates may find applications in bioremediation of petroleum spills. Thus their biosurfactants can furnish a choice to the current chemical compounds and they may find applications in biotechnologies.",11,12,0
Sediments,,"Li, Tianjun; Huang, Zhilong; Feng, Yue; Chen, Xuan; Ma, Qiang; Liu, Bo; Guo, Xiaobo","Reservoir characteristics and evaluation of fluid mobility in organic-rich mixed siliciclastic-carbonate sediments: A case study of the lacustrine Qiketai Formation in Shengbei Sag, Turpan-Hami Basin, Northwest China",Lacustrine mixed siliciclastic-carbonate sediments reservoir; Fluid mobility; 2D NMR T-1-T-2 map; Pore distribution; Turpan-Hami basin,PETROPHYSICAL CHARACTERIZATION; ADSORPTION CAPACITY; THERMAL MATURITY; PORE SYSTEM; SHALE; OIL; NUCLEAR; POROSITY; FIELD; RELAXOMETRY,"Organic matter-rich mixed siliciclastic-carbonate sediments is a special type of tight oil reservoir in the Turpan-Hami basin, which is characterized by complex fluid type, mineral composition and pore structure. By using casting thin sections, scanning electron microscopy (SEM) and whole rock X diffraction (XRD), pore types and petrological characterization of reservoirs are analyzed. Combined with the result of the physical property, nuclear magnetic resonance (NMR) experiments, the effects of the porosity, permeability, and pore size distribution on the movable fluid distribution in the tight reservoir were evaluated. The results showed that there are four types of mixed siliciclastic-carbonate sediments reservoir, which have high TOC. The reservoirs are characterized by low porosity range from 2% to 10% and extra low permeability mainly less than 0.1 x 10(-3) mu m(2). Nanometer scale intergranular pores and micro-fractures were the main reservoir pore types, we further divided the pore sizes distribution into two categories based on their water-saturated NMR T-2 spectra: Type I (bimodal pattern) and Type II (left unimodal, micropores with a diameter less than 100 nm). The fluid components in the reservoir including water in nano-pores, movable light oil, non-movable heavy oil and bound water were analyzed using advanced NMR T1-T2 maps. The mobile light oil content in the silt-bearing argillaceous arenaceous limestone and silt-bearing lime micritic dolomite is higher than that of other lithological reservoirs. The movable light oil content exhibited a strong correlation with permeability, and the proportion of large pores, indicating that the large pores, which are mainly supplied by the intergranular pores in dolomite, substantially contributed to mobility of the hydrocarbon fluid. The non-movable heavy oil fluid component is impacted the small pores ratio and solid organic matter, while water the in nano-pores is greatly affected by clay minerals.",10,10,6
Sediments,,"Deng, Xuejing; Feng, Jianwei; Pan, Shaowei; Wang, Zhiyuan; Zhang, Jianbo; Chen, Weiqing",An improved model for the migration of fluids caused by hydrate dissociation in porous media,Methane hydrate; Nature gas hydrate; Dissociation; Multiphase flow in porous,NATURAL-GAS PRODUCTION; METHANE HYDRATE; BEARING SEDIMENTS; RELATIVE PERMEABILITY; WATER PERMEABILITY; DOMINATED SYSTEMS; PREDICTION MODEL; MASS-TRANSFER; SURFACE-AREA; DEPRESSURIZATION,"Natural gas hydrates may be the world's future resources, but extracting from the reservoirs involves accurately understanding the transport mechanism of the fluids caused by hydrate dissociation. In this paper, based on Darcy's unsaturated soil mechanics theory, we establish a coupling model of two-phase flow and heat transfer caused by hydrate dissociation, which considering methane gas compressibility and capillary force naturally. The new model is validated through Masuda's test dataset, and notably, the experimental phenomenon of the small peak in the gas pressure of the far-end boundary (Run 4) is reproduced for the first time. Additionally, an implicit function of pore pressure and time in the initial stage of hydrate dissociation is deduced to interpret the in-situ pore accumulation of the gas generated in dissociation, which leads to a more comprehensive description of the migration mechanism of hydrate reservoir fluids. Furthermore, the initial hydrate saturation of the Run 4 sample in Masuda's test is proved to be closer to 0.501 instead of 0.443 that the author reported, which can help Masuda's test dataset being a benchmark for the hydrate dissociation researching in future. Thus, this work provides further insight into the migration mechanism of the gases caused by hydrate dissociation and services practical support for efficiently and safely extracting methane gas from the hydrate reservoirs.",8,8,6
Sediments,,"Xu, Huiyuan; George, Simon C.; Hou, Dujie; Cao, Bing; Chen, Xiaodong","Petroleum sources in the Xihu Depression, East China Sea: Evidence from stable carbon isotopic compositions of individual n-alkanes and isoprenoids",Carbon isotope; n-alkane; Isoprenoid; Coal; Mudstone; Xihu depression,CRUDE OILS; ORGANIC-COMPOUNDS; DITERPENOID HYDROCARBONS; RECENT SEDIMENTS; DIVERSE ORIGINS; TARANAKI BASIN; COAL MEASURES; LIAOHE BASIN; SOURCE ROCKS; SOUTH CHINA,"In order to better understand the relative contributions of various source rocks for petroleum in the Xihu Depression, East China Sea Basin, gas chromatography-mass spectrometry analyses of the saturated and aromatic fractions and carbon isotopic analyses of the purified n-alkanes and isoprenoids were performed. The molecular composition and individual n-alkane and isoprenoid carbon isotope compositions were determined for oils and extracts of Paleogene mudstones (TOC: 0.45-2.3%), carbonaceous mudstones (12.7-19.6%), and coals (48-60%) in the Xihu Depression, so as to discriminate the hydrocarbon sources of coals and associated mudstones to the petroleum generated in the basin. Abundant diterpanes (e.g., isopimarane, phyllocladane) are present in all the samples. The differences in the delta C-13 values of pristane and phytane indicate separate origins for the isoprenoids. A general negative sloping profile with increasing n-alkane carbon chain length was observed in coals, mudstones and oils from the Huangyan oilfield, with individual n-alkane delta C-13 values between -25.6 parts per thousand and -34.4 parts per thousand. These values are characteristic of the isotopic compositions of C3 plants, and are also typical of fluvial/lacustrine depositional settings. The isotope compositions of individual n-alkanes from the extracts of coals and mudstones correlate with the relative concentration of terrigenous higher plant-derived diterpenoids, which suggests that plant phyla/classes (for example gymnosperm-derived diterpanes versus angiosperm-derived diterpanes) may be a control on the carbon isotope profiles of n-alkanes. For samples dominated by terrigenous organic matter, long chain n-alkanes with a large proportion of gymnosperm input are approximately 2-3 parts per thousand enriched in C-13 relative to those with angiosperm input, regardless of lithology. The connections between the oils, coals, and mudstones allow determination of the patterns and variations for different hydrocarbon contributions, and provide a way of differentiating specific source contributions to petroleum in the Xihu Depression. Oils generated from the coals have heavier delta C-13 values with increasing chain length within a narrow range (approx. 2-3 parts per thousand) and have more heterotrophic origins, whereas oils from the mudstones are more depleted in C-13 with increasing carbon number (n-C-2(0-)31) and have a greater derivation from land plants. The 825B oils in the Huangyan oilfield have a greater angiosperm-sourced hydrocarbon contribution than those of the 825AD oils, which have a greater gymnosperm-sourced hydrocarbon contribution. The tricyclic and tetracyclic diterpanes and the isotopic compositions of individual n-alkanes and isoprenoids may be useful in differentiating contributions of coals and associated mudstones to petroleum.",7,7,7
Objective Function,,"Jesmani, Mansoureh; Jafarpour, Behnam; Bellout, Mathias C.; Foss, Bjarne",A reduced random sampling strategy for fast robust well placement optimization,Well placement optimization; Uncertainty; Simultaneous perturbation stochastic approximation (SPSA); Robust algorithm,STOCHASTIC-APPROXIMATION; CONSTRAINED OPTIMIZATION; JOINT OPTIMIZATION; UNCERTAINTY; ALGORITHM; IMPLEMENTATION; LOCATIONS,"Model-based decision-making in oilfield development often involves hundreds of computationally demanding reservoir simulation runs. In particular, well placement optimization under uncertainty in the geologic representation of the reservoir model is an overly time-consuming procedure as the performance of any proposed well configuration needs to be evaluated over multiple realizations, using computationally expensive flow simulations. To reduce computation, we propose an efficient robust optimization procedure in which at each iteration of the optimization procedure, instead of evaluating the well configuration over all available realizations, we approximate the expected performance using a small subset of randomly selected model realizations. Since the samples are selected randomly, all the realizations are expected to eventually be included in the performance evaluation after a certain number of iterations. However, using only a few random realizations to compute the expected cost function introduces noise in the estimated objective function, necessitating the use of a stochastic optimizer. In this paper, we use the Simultaneous Perturbation Stochastic Approximation (SPSA) algorithm, which is known to be robust against noise in the objective function. We first evaluate the performance of different forms of the SPSA algorithm (including discrete, continuous, and adaptive) using several numerical experiments, followed by a discussion of the properties of the proposed reduced random sampling approach and comparison with global optimization techniques. The method is applied to several numerical experiments, including case studies involving vertical, horizontal, and lateral wells, to evaluate its performance. The results from these experiments indicate that the reduced random sampling approach can provide significant computational gain with minimal impact on the attained optimization performance.",15,15,0
Objective Function,,"Zhang, Hao; Sheng, James",Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume,SRV estimation; Displacement discontinuity method; Stress dependent permeability; Modified-PSO algorithm; Fracturing optimization,TIGHT; PERMEABILITY; MECHANISM; MODEL,"Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.",14,15,3
Objective Function,,"Zhao, Mengjie; Zhang, Kai; Chen, Guodong; Zhao, Xinggang; Yao, Chuanjin; Sun, Hai; Huang, Zhaoqin; Yao, Jun",A surrogate-assisted multi-objective evolutionary algorithm with dimension-reduction for production optimization,Multi-objective production optimization; Gaussian process; Surrogate model; Dimension reduction,LOOP RESERVOIR MANAGEMENT; ENSEMBLE; MODEL; GENERATION; CONSTRAINTS; UNCERTAINTY,"Multi-objective optimization (MOO), which involves more than one conflicting objective to be optimized simultaneously, is expected to provide efficient and comprehensive reservoir management (RM) solutions. The multi-objective production optimization problems are considered to be expensive due to the difficulties and cost of operations. Surrogate-assisted evolutionary algorithms (SAEAs), which has proved to be an effective way to solve expensive problems, design computationally cheap function to approximate each objective function. Meanwhile, the optimization process involves a large number of decision variables. However, building a high-quality surrogate model has become difficult due to the ""curse of dimensionality"". Base on characterization, an efficient multi-objective optimization framework called SA-RVEA-PCA is proposed to effectively deal with large-scale and computationally expensive simulation-based optimization problems, including three parts:1) Given a set of simulation results, a Gaussian process (GP) model based on Principal Component Analysis (PCA) for each objective function is trained so that the surrogate models can guide the optimization more accurately. 2) A reference vector guided evolutionary algorithm (RVEA) recently developed is employed as a multi-objective optimizer. 3) The information of uncertainty given by GP and angle-penalized penalized (APD) proposed in RVEA are used to update the surrogate models. To the best of our knowledge, the proposed algorithm is applied to a benchmark function, and two typical applications of MOO with synthetic reservoir models. Results show that the proposed method can provide more comprehensive and efficient RM with a higher convergence speed.",13,14,6
Objective Function,,"Nasir, Yusuf; Yu, Wei; Sepehrnoori, Kamy",Hybrid derivative-free technique and effective machine learning surrogate for nonlinear constrained well placement and production optimization,Derivative-free optimization; Differential evolution; Machine learning; Well placement; Production optimization,FIELD-DEVELOPMENT OPTIMIZATION; DIFFERENTIAL EVOLUTION; SUBSURFACE FLOW; MODELS; TIME,"It is imperative that wells in an oil field be located and controlled in an optimal fashion to maximize asset value while satisfying the optimization constraints which can be in the form of production limits, water cut, or well spacing. Computational optimization algorithms coupled with a reservoir simulator have become increasingly popular in determining the optimal locations of wells and the optimal controls to be imposed on them. These algorithms should be able to deal with highly non-linear objective functions, the absence of gradient information, and a limited reservoir simulation budget. In this work, we considered derivative-free and non-invasive techniques: Enhanced Success History-Based Adaptive Differential Evolution (ESHADE) strategy with linear population size reduction, which is a variant of L-SHADE (recognized as one of the state-of-the-art global stochastic optimizers for continuous variable), and a Mesh Adaptive Direct Search (MADS) local pattern search method. These two methods are hybridized to develop a hybrid framework (E-MADS) that combines the advantageous aspects of both methods in order to improve optimization efficiency. In order to further improve the efficiency of the framework, gradient boosting machine learning technique is used to generate proxy model, based on regression and classification methods, to predict the objective function and classify optimization solutions into feasibless (satisfies all prescribed constraints) and infeasible groups. This information is then used to screen out solutions that are not expected to improve the objective function. Applications of these algorithms to the joint optimization of well location and time-varying control problem, with bounds and nonlinear constraints, are presented in this work. ESHADE is shown to outperform traditional global optimization algorithms such as Particle Swarm Optimization (PSO) and a real-coded Genetic Algorithm (GA). The E-MADS hybrid is also shown to have a superior performance relative to the standalone ESHADE and MADS methods for the joint optimization problem.",10,10,1
Objective Function,,"Mahjour, Seyed Kourosh; Souza Santos, Antonio Alberto; Correia, Manuel Gomes; Schiozer, Denis Jose",Developing a workflow to select representative reservoir models combining distance-based clustering and data assimilation for decision making process,Representative models; Distance-based clustering; Data assimilation; Uncertainty assessment,PROPER ORTHOGONAL DECOMPOSITION; PETROLEUM FIELD DEVELOPMENT; HYDRAULIC FLOW UNITS; UPSCALING TECHNIQUE; PRODUCTION STRATEGY; RISK ANALYSIS; MONTE-CARLO; UNCERTAINTY; REDUCTION; TIME,"Different types of static and dynamic uncertainties can play critical roles to select an efficient and reliable production strategy in the oil fields, yielding a large number of models to analyze. The definition of such a production strategy requires flow simulation for each model. Since the flow simulation process for this large model ensemble requires a great CPU effort, selecting a subset of representative models (RMs) is often used for accelerating the analysis. However, providing an applicable and efficient method to identify the RMs that statistically reflect the same dynamic and static properties as the full set of models is still challenging. In this study, we develop a new workflow to select RMs based on the integration of distance based clustering and data assimilation aimed at the field development. The workflow begins with the generation of geostatistical models using Latin hypercube (LH) sampling and then reducing them through distance-based clustering according to their static features. Therefore, there is no need to apply numerical simulation for scenario reduction. Next, discrete Latin hypercube with geostatistical realizations (DLHG) method is performed to combine other types of uncertainty with the reduced geostatistical models and build the simulation models. Eventually, data assimilation (DA) is applied to select the subset of models that match the past reservoir performance and production data. In addition, the uncertainty range are evaluated for the defined well and field objective functions using the cumulative distribution function (CDF) and non-parametric Kolmogorov-Smirnov (K-S) test. The methodology is successfully applied to a synthetic benchmark case named UNISIM-II-D considering the flow unit modeling. The results show that the workflow can effectively and suitably identify the RMs considering different uncertainty types, reservoir heterogeneity and many field and well objective functions. The selected RMs are used for making production forecasts and development planning support.",8,8,0
Objective Function,,"Epelle, Emmanuel, I; Gerogiorgis, Dimitrios, I",Adjoint-based well placement optimisation for Enhanced Oil Recovery (EOR) under geological uncertainty: From seismic to production,Well placement; Oil saturation; Well allocation factors; Geological uncertainty; Adjoint formulation; Production optimisation,JOINT OPTIMIZATION; PARAMETERS,"The development of new and existing oil fields is very expensive and technically challenging; this provides an important economic incentive to improve oil recovery via efficient computational optimisation. Decisions related to these activities may be significantly aided by sound and proven mathematical-oriented methods. The use of intuitive engineering judgement alone cannot guarantee sustainable profitability over long periods, especially under geological (reservoir model) uncertainty. To capture the uncertainties in the subsurface geological/reservoir model in this work, geostatistical realisations of the model are obtained using available information (permeabilities and porosities). We also apply specialised algorithms within the MATLAB Reservoir Simulation Toolbox - MRST (interfaced with PETREL (TM)) to optimally vary the well locations and production rates, thus maximising the field's oil recovery. A new modification of an existing pseudowell-based injection well placement algorithm is presented herein with the application of adjoint-computed gradients of an auxiliary objective function (the Lorenz coefficient). The difficulty of this problem is characterised by the presence of discrete variables, a nonlinear and nonconvex objective function and constraints. The developed workflow is applied to a realistic case study, for which robust optimality is demonstrated using the worst case realisation for the determination of optimal well locations and controls. A comparative investigation of optimising injection well location vs. simultaneous optimisation of injection and production well placement is also presented. In our presented case studies, we also discover that increasing the optimisation search space does not necessarily guarantee improved results.",8,8,0
Objective Function,,"Sun, Ruofan; Hu, Jinghong; Zhang, Yuan; Li, Zhiping",A semi-analytical model for investigating the productivity of fractured horizontal wells in tight oil reservoirs with micro-fractures,Micro-fractures; Fractured horizontal wells; Well productivity; Tight oil reservoirs; Sensitivity analysis,PRESSURE-TRANSIENT ANALYSIS; GAS-PRODUCTION; LINEAR FLOW; MICROFRACTURES; SHALE; PERMEABILITY; PERFORMANCE; PREDICTION; BASIN,"Combining horizontal drilling with hydraulic fracturing has become a well-established technique to improve well productivity in tight oil reservoirs. The existence of micro-fractures in these reservoirs affects the fluid flow process as well as the productivity. However, current models for evaluating the well performance of fractured horizontal wells containing micro-fractures lack accuracy. Hence, the objective of this study is to build an efficient model to analyze well productivity, considering the effects of micro-fractures. A novel flow model for multi-fractured horizontal wells was established, considering the effect of micro-fractures on the fluid flow. Subsequently, we built a reservoir model based on the typical fracture and fluid properties of a tight oil block in the Daqing oil field, China. Good agreement between the prediction results and field data was obtained, indicating that the effect of micro-fractures on well productivity cannot be neglected. Further study reveals that micro-fractures essentially function as a joint connecting reservoir matrix and have a persistent impact on well productivity. Micro-fractures can promote well productivity; however, if the value of micro-fracture permeability increases, this promotional effect will slow down. Well productivity can be considerably improved as an increase in micro-fracture percentage. Finally, a series of sensitivity studies were conducted to identify the effects of critical parameters on well productivity. Results show that reservoir permeability significantly influences well productivity, followed by reservoir effective thickness, micro-fracture percentage, fracture number, hydraulic fracture half-length. Pressure sensitivity coefficient, threshold pressure gradient and micro-fracture permeability have the least effect on well productivity. This work provides a sophisticated and efficient tool to evaluate the productivity of multi-fractured horizontal wells in tight oil reservoirs with micro-fractures.",7,7,5
Sand Control,,"Ma, Chengyun; Deng, Jingen; Dong, Xingliang; Sun, Dongzheng; Feng, Zhe; Luo, Chao; Xiao, Qiangzhong; Chen, Jiyu",A new laboratory protocol to study the plugging and sand control performance of sand control screens,Sand control screens; Plugging; Sand-retention test (SRT); Sand production; Sand retaining media,MESH SCREENS; DESIGN; MODEL,"Sand retaining media plugging in sand control wells has become a common and urgent problem in the oil and gas industry. Yet, no unified analysis or industry standards on the evaluation of the sand retaining media has been reported recently. In this paper, a systematic approach was presented to investigate the performance of sand control screens. A series of tasks were performed, including the processing of sand control simulation unit, the analysis of formation parameters such as the size of formation sand and reservoir fluid viscosity, the determining of pressure drop through the sand retaining medium, the calculation of oil-production index and so on. The importance of using the sand control unit was clearly demonstrated. The pressure drop along block sand media was determined in three different positions simultaneously with the high precision pressure sensor. The process of forming the sand bridge was recorded for all tests using a Digital Camera. The oil-production index and permeability of the sand control screen were calculated based on the flow rate and pressure drop. An electron microscope was conducted to observe the plugging of the sand control screens. This process is conducive to analyze the clogging process of sand control screens and optimize the design of sand control parameters. The amount and particle size distribution of sand produced and sand arch also were determined. These parameters are very important to the sand control properties of sand control screens. A set of novel sand control physical simulation experiment device was introduced to measure the above parameters. The measurement techniques and procedures presented in this paper provide a standard measurement protocol for the characterization of different sand control screens. The result of a case test shows that the new test method presented in this paper can effectively improve the drawbacks of existing methods.",13,13,6
Sand Control,,"Shi, Xian; Zhang, Weidong; Xu, Hongxing; Xiao, Caiyun; Jiang, Shu",Experimental study of hydraulic fracture initiation and propagation in unconsolidated sand with the injection of temporary plugging agent,Unconsolidated sand; Plugging agent; Hydraulic fracturing; Acoustic emission; Fracture initiation,VERTICAL WELL; GAS,"High fluid leak-off rate and low pressurization rate are great challenges for hydraulic fracturing in unconsolidated sands. In this paper, the design of an injection plugging agent as a pad for fracture initiation aid in unconsolidated sands is presented. We have carried out tri-axial hydraulic fracturing tests, focusing on super-high- and high-permeability unconsolidated sands with AE (acoustic emission) monitoring. Powdered oil-soluble materials are used as temporary plugging agents. The laboratory tests demonstrated that three types of fracture geometry, multiple fracture, bi-wing fracture and single-wing fracture, are created. Furthermore, there are continuous AE energy signals with the increase of plugging agent injection, which is a good match with the fluctuated pressure. Moreover, multiple peak fracture points can be observed due to intense grains interaction. In addition, the breakdown pressure has positive relationships with the pump rate and concentration of injection of plugging agents. Multiple fractures only exist for super-high-permeability unconsolidated sands with high pumping rate and low plugging agent concentration, which is primarily due to the plugging agent seal for both hydraulic fracture and the rock matrix. A low injection rate with low plugging agent concentration led to single-wing fracture for high-permeability unconsolidated sands, whereas a high injection rate with high plugging agent concentration led to single-wing fracture for low-permeability unconsolidated sands. Low plugging agent concentration is beneficial for aiding hydraulic fracture propagation along the maximum horizontal stress direction. In addition, the high-pump-rate and low-plugging-agent-concentration scenario and low-pump-rate and highplugging-agent-concentration scenario have a greater chance of creating bi-wing fracture for super-high-permeability unconsolidated sands, whereas low pump rate and high plugging agent concentration are beneficial for bi-wing fracture for high-permeability unconsolidated sands. Local tortuous fracture path indicate tensile and fracture both exist during unconsolidated sands fracturing. With respect to sand control and large contact area, these treatments should be the better fracturing scenario for unconsolidated sand fracturing design with injection of a plugging agent. The findings of this study can help for better understanding of the fracturing mechanism and optimizing treatment parameters in unconsolidated sands fracturing.",12,11,4
Sand Control,,"Ali, Muhammad; Ma, Huolin; Pan, Heping; Ashraf, Umar; Jiang, Ren",Building a rock physics model for the formation evaluation of the Lower Goru sand reservoir of the Southern Indus Basin in Pakistan,Lower goru sand reservoir; Rock physics model; Rock physics template; Well logs; Petrophysical analysis,ACOUSTIC VELOCITIES; GAS-FIELD; POROSITY; LOGS; FUNDAMENTALS; SANDSTONES,"The geological factors of any reservoir, such as porosity, lithology, and fluid characteristics, control the rock physics models. Several retrospective studies have discussed the methods of discriminating and calculating these geological factors in the Lower Goru sand reservoir. Therefore, it is imperative to build the best-modified suitable rock physics model and template to diagnose an inadequately consolidated reservoir that has been previously overlooked. For the purpose, the research evaluates a dataset of five wells to develop a modified rock physics model and template for a Lower Goru sand reservoir in Pakistan. The study compares and evaluates different rock physic models such as Stiff sand, Friable-sand, Greenberg and Castagna, and Raymer's model to calibrate the best model, which would comprehensively assist the future researchers. According to the results, Stiff sand is quite a suitable rock physics model. Furthermore, the rock physics template (RPT) is utilized to test the reliability of the predicted model that is helpful for the formation evaluation, reservoir characterization, and prospect evaluation across different fields of the Lower Goru sand reservoir. The predicted model can be further used to estimate porosity from the seismically derived impedance in the entire Lower Goru sand reservoir, Pakistan, and worldwide which has the same geological trends and reservoir distribution.",12,12,1
Sand Control,,"Voltolini, Marco; Ajo-Franklin, Jonathan",Evolution of propped fractures in shales: The microscale controlling factors as revealed by in situ X-Ray microtomography,Proppant; Fractures; Tight oil and gas shales; X-ray microtomography; Permeability,GAS; CONDUCTIVITY; CHALLENGES,"The behavior of proppant at the microscale during fracture closure in oil and gas shales is not yet well understood. In this context, we used a combination of dynamic synchrotron X-ray micro computed tomography with morphometric analysis and flow modeling to provide new insight into the dominant physical processes acting at the microscale during fracture closure, and understand their impact on hydraulic properties of the fracture. The roles of three variables have been investigated in proppant monolayers: i) Shale mineralogy and microstructure; ii) Shale bedding orientation with respect to the fracture plane; iii) Proppant characteristics. Unsurprisingly, all three variables have an impact on the permeability evolution during closure and their extent has been quantified via Stokes flow simulations. For the fracture geometry considered, proppant rearrangement during loading is the leading cause of permeability loss. The mechanical strength of proppant and shale becomes important at the later stages of the fracture closure. Bedding orientation has an impact on the mechanical response of the proppantshale contact areas. The more regular morphology and higher mechanical strength of ceramic proppant allows to maintain a better permeability throughout the whole fracture evolution cycle when compared to quartz sand. This combined analysis approach allowed us to understand and quantify the processes involved during the closure of a propped fracture and to directly link them to the evolution of morphology and hydraulic properties. A better understanding of the contributions of these processes could ultimately help in the design and optimization of proppants, enabling more efficient extraction of hydrocarbons from unconventional systems.",10,10,2
Sand Control,,"Liu, Longlong; Li, Yang; Dong, Hongzhi; Sun, Zhongqiang","Diagenesis and reservoir quality of Paleocene tight sandstones, Lishui Sag, East China Sea Shelf Basin",Diagenesis; Tight sandstones; Reservoir quality; Controlling factors; Lishui Sag,ZHENJING AREA; ORDOS BASIN; COMPACTION PROCESSES; RELATIVE IMPORTANCE; BEARING SANDSTONES; OIL SANDSTONES; QUARTZ CEMENT; MASS-TRANSFER; POROSITY; IMPACT,"The Lishui Sag in the East China Sea Shelf Basin (ECSSB) has significant potential hydrocarbon resources, with Paleocene sandstones as its main oil and gas-bearing reservoir. The sandstones in the Paleocene formations are mainly composed of medium-grained, moderately sorted litharenite. In this study, distributions of the porosity and permeability reveal that the Paleocene sandstones have the characteristics of medium porosity and low permeability. The sedimentary microfacies, primary texture, diagenesis, and bioturbation jointly control the reservoir quality. Sandstones with distributary channel and sand bar sedimentary microfacies as well as better sorting tend to exhibit a higher quality. Compaction and carbonate cementation are the major determinants to reductions in porosity and permeability. Grain-coating chlorites within a certain content range may play a positive role in the preservation of porosity in eodiagenesis. Early dissolution has a constructive effect on the reservoir quality. In contrast, the dissolution products such as kaolinite and dawsonite cannot move over a long distance and precipitate nearby to block the intergranular pores when reservoir closure increases. Therefore, dissolution in a relatively closed geochemical reservoir system may contribute little to porosity. Contrastingly, the permeability of the Paleocene reservoir may be reduced by the conversion of the pore network. In the Lishui Sag, the bioturbation plays a role in the deterioration of reservoir quality in a limited scale by decreasing reservoir sorting and increasing compaction.",8,8,7
Sand Control,,"Wang, Chenxi; Pallares, Jesus D. Montero; Haftani, Mohammad; Nouri, Alireza",Developing a methodology to characterize formation damage (pore plugging) due to fines migration in sand control tests,Stand-alone screens; Flow performance; Formation damage; Fines migration,SCREENS; SAGD; TEMPERATURE; PERFORMANCE; SALT,"Stand-alone screens (SAS) have been widely used in steam assisted gravity drainage (SAGD) operations. Although many researchers investigated the flow performance of SAS through sand control tests, the formation damage (pore plugging) due to fines migration has not been characterized under multi-phase flow conditions. In this study, a methodology is developed to quantify and characterize the fines migration under multi-phase flow sand control testing conditions. A large-scale sand retention test (SRT) facility is used to investigate the flow performance of SAS. Duplicated sand samples with similar particle size distribution (PSD), shape, and mineralogy properties to the McMurray Formation oil sands are obtained by mixing different types of commercial sands, silts, and clays. Oil and brine are simultaneously injected into the sand-pack at different water-cut levels and liquid rates to emulate the changing inflow conditions in SAGD operations. The saturation levels in each flow stage are measured to determine the relative permeability values. Next, the relative permeability curves of the duplicated sand-pack sample are measured following the steady-state method. Finally, the pressure data obtained from the SRT in each flow stage are coupled with the relative permeability values to calculate the retained permeability as the indicator of flow performance of SAS'. Generally, testing results show that single-phase oil flow generates minor and negligible permeability impairments in the near-screen zone of the sand-pack. An evident permeability reduction is observed once the water breakthrough happens, indicating that the wetting-phase fluid significantly mobilizes fine particles and causes pore plugging. Also, with the increase of flow rate and water cut, a further reduction in permeability is found as a result of the higher drag force and greater exposure area of fines to brine. The proposed methodology presented in this study allows quantitative characterization of the formation damage under multi-phase flow condition and provides a practical and straightforward method for the evaluation of the SAS's flow performance.",8,8,1
Asphaltene Precipitation,,"Campen, Sophie; Moorhouse, Saul J.; Wong, Janet S. S.",Mechanism of an asphaltene inhibitor in different depositing environments: Influence of colloid stability,Asphaltenes; Fouling; Inhibitor; Remediation; Colloid; QCM-D,QUARTZ-CRYSTAL MICROBALANCE; BENZENE-DERIVED AMPHIPHILES; SELF-ASSEMBLED MONOLAYERS; REFRACTIVE-INDEX; QCM-D; CRUDE-OIL; ADSORPTION; RESINS; PRECIPITATION; AGGREGATION,"Additives are used to reduce unwanted carbonaceous deposits of asphaltenes on surfaces during petroleum production from natural oil and gas reservoirs. The working mechanism of formulated additive packages can be multifaceted. Additives may be effective in the bulk fluid by preventing asphaltenes aggregation, as well as at the surface by preventing asphaltenes adhesion. In this paper, we investigate the numerous different mechanisms by which an asphaltene inhibitor can interfere with the formation of carbonaceous deposits using a combination of techniques including dynamic light scattering to determine particle size distribution, quartz crystal microbalance with dissipation monitoring to examine deposition behaviour and atomic force microscopy to probe deposit morphology. The tested inhibitor prevents deposition of asphaltenes in toluene, where asphaltenes exist as a stable colloidal dispersion of nanoaggregates, by forming barrier-type films that inhibit asphaltenes adhesion and displacing adsorbed thin films of asphaltenes. However, inhibitor performance in heptane-toluene, where asphaltenes are destabilised, depends on the degree of destabilisation. At low heptane volume fraction, inhibitor slows the rate of deposition and deposition rate decreases with increasing inhibitor concentration. However, at high heptane volume fraction, inhibitor can increase the deposition rate, particularly when used in high concentration. At high heptane volume fraction, inhibitor addition alters the morphology of the deposit from that consisting of large flocculent aggregates to that consisting of smaller, submicrometer aggregates. This is consistent with the finding that inhibitor acts as an anti-agglomerant and prevents the formation of large aggregates in the bulk liquid. This paper shows that the impact of inhibitor addition depends on the environmental conditions encountered and the degree of destabilisation of the asphaltenes. Where inhibitor addition alters the nature of depositing species from large flocculent aggregates to smaller submicrometer aggregates, an increase in deposition rate may be observed.",18,18,3
Asphaltene Precipitation,,"Abdulredha, Murtada Mohammed; Hussain, Siti Aslina; Abdullah, Luqman Chuah",Optimization of the demulsification of water in oil emulsion via non-ionic surfactant by the response surface methods,Central Composite Design; Demulsification emulsion; Response surface method; Surfactant,CRUDE-OIL; ASPHALTENE PRECIPITATION; FACTORIAL DESIGN; IONIC LIQUIDS; TOLUENE; RSM; STABILITY; DEGRADATION; SEPARATION; BEHAVIOR,"The most challenging issue faced by the petroleum industry in recent years was the water production during crude oil and gas extraction. This challenge has caused aggravated damages to treatment facilities by increasing the cost of production as water production increased over time. However, most of the water produced from oil and gas platforms is produced as water in oil emulsion. Treating emulsion has been experienced using techniques involve specific chemical methods. This study used the bottle test technique to investigate the performance of non-ionic demulsifiers, Propargyl Alcohol (PA) and Triethylene Glycol (TG), in breaking water in oil emulsion. Subsequently, a factorial design was applied for the characterisation of five variables, namely demulsifier dose, toluene concentration, pressure drop, temperature, and sitting time. Then, the significant factors were further analysed using Central Composite Design (CCD) based on the Response Surface Method (RSM). In particular, CCD was used to study the influence of demulsifier dose, toluene concentration, pressure drop, temperature, and sitting time on the response and to find the optimal condition to achieve maximum dehydration. Additionally, Analysis of Variance (ANOVA) was used to test the accuracy of the mathematical models established using CCD. The results show that demulsifier dose, temperature, and sitting time were the most significant parameters for breaking the emulsion, and that the optimal values for the input variables were successfully obtained using RSM.",18,18,2
Asphaltene Precipitation,,"Deka, Barasha; Sharma, Rohit; Mahto, Vikas",Synthesis and performance evaluation of poly (fatty esters-co-succinic anhydride) as pour point depressants for waxy crude oils,Waxy crude oil; Polymeric additive; Flow assurance; pour point; Gelation point; pour point depressant,FLOW IMPROVERS; RHEOLOGICAL BEHAVIOR; PRECIPITATION; ASPHALTENES; DEPOSITION; ACID; TEMPERATURE; PIPELINE; GELATION,"This research work focuses on the development of two polymeric compounds poly (n-dodecyl linoleate -co- succinic anhydride) and poly (n-dodecyl ricinoleate -co- succinic anhydride) from the naturally obtained vegetable oils fatty acids, which were subsequently evaluated as pour point depressants (PPDs) for a waxy crude oil. The developed chemical additives were characterized by FTIR and NMR spectroscopies. Significant reduction in pour point and apparent viscosities were obtained for the PPD treated crude oils compared to virgin crude oil, which indicated improvement in low temperature flow properties of the crude oil. Moreover, reduction in gelation point, storage and loss modulus of PPD treated crude oils exhibit improvement in the restart flowability of crude oil in case of pipeline shut down. Microscopic studies revealed the changes in the wax crystal structures after addition of chemical additives. One of the important studies, cold finger test showed that, wax deposition from the crude oil was considerably reduced by the addition of the two synthesized PPDs during flow through tubing, resembling the pipeline flow condition.",12,12,5
Asphaltene Precipitation,,"Taheri-Shakib, Jaber; Zojaji, Iman; Saadati, Nastaran; Kazemzadeh, Ezzatallah; Esfandiarian, Ali; Rajabi-Kochi, Mahyar",Investigating molecular interaction between wax and asphaltene: Accounting for wax appearance temperature and crystallization,Wax appearance temperature; Asphaltene; Crystal; FTIR spectra; NMR,NUCLEAR-MAGNETIC-RESONANCE; MATHEMATICAL-MODEL EVALUATION; HEAVY CRUDE-OIL; HEATING TIME; PART 1.; AGGREGATION; DEPOSITION; ADSORPTION; PRECIPITATION; SPECTROSCOPY,"Three modes will improve the interaction of the wax-asphaltene molecules that eventually increase wax appearance temperature (WAT) within crude oil. The first mode takes place when the wax is composed of long-chain alkanes, and its aromatic compounds are low, and adjacent hydrogens in its constituent aromatic rings are substituted with long-chain paraffin. The second condition is when the wax is formed from low carbon number alkanes. In this case, the lower the asphaltene aromaticity and the carbon number of side alkyl chain, the higher its interaction with wax would be. The third approach occurs if naphthenic or aromatic structures exist in wax, and asphaltene aromatic rings are arranged as peri-condenses. Higher interaction of wax and asphaltene reduces wax crystals' size. The presence of polar compounds in the molecular structure of the wax and asphaltene does not affect WAT, but the size and morphology of crystals alter in microscopic images.",11,11,4
Asphaltene Precipitation,,"Azizkhani, Ashkan; Gandomkar, Asghar",A novel method for application of nanoparticles as direct asphaltene inhibitors during miscible CO2 injection,Asphaltene precipitation; Direct asphaltene inhibitors; Cloud point pressure; MMP; Nanoparticles; Miscible CO2 injection,PRECIPITATION; OIL; DEPOSITION; BEHAVIOR; FE3O4; GAS; PREDICTION; TOLUENE; IMPACT; TIO2,"Asphaltene precipitation is one of the main technical challenges during the miscible gas injection. The asphaltene may deposit on the rock surface and it may change the reservoir wettability and reduces permeability. This paper focused on the asphaltene precipitation by liquid-free asphaltene inhibitors at reservoir conditions. The Fe3O4 and Al2O3 nanoparticles were used as direct asphaltene inhibitors (DAI) during CO2 injection. The cloud point pressures were measured to ensure that the CO2/nanoparticles mixtures are in single-phase conditions. After that, the vanishing interfacial tension technique was considered to evaluate the effect of DAI on minimum miscibility pressure. Moreover, the asphaltene precipitation during CO2/nanoparticles injection was studied for both volatile and intermediate live oils at reservoir conditions for DAI concentration varied from 500 to 3000 ppm. The results showed that the DAI can reduce the amounts of asphaltene precipitation during miscible CO2/nanoparticles injection at reservoir conditions. In addition, the CO2/nanoparticles injection reduced the asphaltene precipitation in comparison to pure CO2 injection. Also, the mixtures containing Fe3O4 can provide more performance than Al2O3 solutions, so the effect of solubility is more dominant than the aggregation impact during DAI injection.",11,11,2
Asphaltene Precipitation,,"Sulaimon, Aliyu Adebayo; De Castro, John Kevin Mendoza; Vatsa, Suyash",New correlations and deposition envelopes for predicting asphaltene stability in crude oils,Asphaltene stability; SARA analysis; Colloidal instability index; Asphaltene/resin ratio,PRECIPITATION; FLOCCULATION; SOLUBILITY; SEPARATION; DYNAMICS; POLARITY,"The precipitation and deposition of asphaltene are among the most pressing issues in the petroleum industry. This flow assurance issue may cause formation damage in porous media, the plugging and coking of wellbore and production pipelines and difficulties in the refining process. Such events lead to additional operating costs for the company. Therefore, knowing the conditions at which asphaltene may precipitate and can be stable may enable its management. Existing models of asphaltene stability are dependent on saturate, aromatic, resin and asphaltene (SARA) analysis which can be very expensive and time-consuming. Therefore, using regression analysis as well as MATLAB curve fitting and optimization procedures, a new set of correlations and asphaltene stability envelops (ASEs) based on the newly developed Density-Based Asphaltene/Resin ratio (DBAR), Density-Based Saturate/Aromatic ratio (DBSAr) and the Density-Based Colloidal Instability Index (DBCII) all as functions of oil density have been developed to consistently predict asphaltene stability. The new criteria were developed for the correlations by considering the boundary between stable and unstable regions in their respective plots. The new envelopes showed 83% reliability by accurately predicting asphaltene stability in 24 (eight stable and 16 unstable samples) out of 29 (13 stable and 16 unstable) crude oil samples. The correlation coefficient (R-2), average absolute relative error (AARE) and the root-mean-square error (RMSE) for the new DBAR correlation are 0.9456, 0.8357 and 0.1219 respectively. The DBSAr correlation resulted in R-2 of 0.9437, AARE of 0.1860 and RMSE of 0.2450. For the DBCII, the statistical indicator results were 0.9639 for the R-2, 0.1376 for the RMSE and 0.1038 for the AARE.",10,10,2
Asphaltene Precipitation,,"Ahooei, Arman; Norouzi-Apourvari, Saeid; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin","Experimental study and modeling of asphaltene deposition on metal surfaces via electrodeposition process: The role of ultrasonic radiation, asphaltene concentration and structure",Electrodeposition; DC electric field; Asphaltene deposition; Ultrasonic radiation; Kinetic modelling; Structural analysis,ELECTRICAL-CONDUCTIVITY; ADSORPTION; CRUDE; PRECIPITATION; KINETICS; REMOVAL; RESINS; OIL; MECHANISMS; PARTICLES,"Asphaltene deposition in the wellbore is considered as a major operational challenge while producing some crude oils. It has been claimed that, external fields, such as electric field and ultrasonic radiation, could help tackling this issue. Although the effect of electric field on the aggregation size and the aggregation rate of asphaltene particles has been investigated before, its correlation with asphaltene deposition in the presence and absence of ultrasonic radiation is not known. In this study, the asphaltene deposition on metal surfaces was first mimicked using an electrodeposition process, and then the effect of ultrasonic radiation on electrodeposition of asphaltene were measured and analysed. Our observations showed that the electric filed itself does not unstable the dissolved asphaltene, and the asphaltene deposition on electrodes, under the effect of DC electric filed, first requires the formation of asphaltene aggregates. The maximum deposition was generated at 2 kV/cm, the exposure time of 300 s to the electric field, and the weight ratio of toluene to heptane 4.2%. It was also found that the structure and composition of asphaltenes, especially their polarity and aromaticity, affect asphaltenes deposition. Among different adsorption kinetic models, the nth-order kinetics model was selected to estimate the amount of deposited asphaltene. Finally, simultaneous ultrasound radiation during the process of electrodeposition, reduced the deposition rate on the metal blades from an average of 65 wt % of the total asphaltene content to 10 wt%. The findings of this study highlight the role of composition and structural properties of asphaltene on its surface deposition in the wellbore. More importantly, simultaneous radiation of ultrasonic waves during electrodeposition process confirms the effectiveness of ultrasonic radiation, as a quite new asphatene remediation technique.",8,8,3
Centrifugal Pump,,"Liu, Ming; Tan, Lei; Xu, Yun; Cao, Shuliang",Optimization design method of multi-stage multiphase pump based on Oseen vortex,Multi-stage pump; Multiphase pump; Optimization design method; Oseen vortex,MIXED-FLOW PUMP; CENTRIFUGAL PUMP; OFFSHORE OIL; PERFORMANCE; IMPELLER; SYSTEMS; TURBINE; CFD,"The multiphase pump is a vital equipment for exploitation of oil-gas resources on offshore platform. Multi-stage structure is essential for multiphase pump to obtain required head. In present study, a novel method is proposed to optimize performance of multi-stage multiphase pump by theoretical prediction based on Oseen vortex. The velocity moment of flow field downstream diffuser can be predicted according to established theoretical model, and it is applied to optimize inlet blade angle of next impeller. In order to validate the proposed optimization method, case study has been done on a three-stage multiphase pump. The velocity moment is accurately predicted by theoretical model based on Oseen vortex, with average deviation of 6.45%. Applying proposed optimization method, the pump head and efficiency can be improved by 0.29% and 0.19% in average, respectively.",24,25,5
Centrifugal Pump,,"Cubas, Jhoan M. C.; Stel, Henrique; Ofuchi, Edgar M.; Marcelino Neto, Moises A.; Morales, Rigoberto E. M.",Visualization of two-phase gas-liquid flow in a radial centrifugal pump with a vaned diffuser,Centrifugal pumps; Two-phase flow; High-speed visualization,ENTRAINED AIR; PERFORMANCE; PATTERNS,"The operation of centrifugal pumps with gas-liquid mixtures is a common problem in the oil and gas industry. The main problem is related to the accumulation of gas inside the Electric Submersible Pump (ESP) impellers, which causes degradation of the pump pressure-rise. Literature about global performance parameters of centrifugal pumps operating with gas-liquid flows is limited, and studies focused on understanding the complex flow patterns occurring inside impellers are even scarcer. In this scenario, this work presents an experimental work developed to carry out, simultaneously, head evaluation and high-speed flow visualization in a two-stage centrifugal pump with radial-type impellers and a vaned diffuser. The pump casing and the first stage impeller were replaced by equivalent pieces reproduced with great fidelity using a transparent material in order to allow flow visualization while minimizing the effect of non-original pump parts on performance. Results show flow pattern transitions in the impeller channels when the rotating speed, the inlet gas flow rate and the liquid flow rate are changed, whereas only a single flow pattern was observed in the diffuser for the whole range of tested operating conditions. In addition, increasing the rotating speed causes, in general, a decrease of the bubble diameters inside the impeller, improving the pump's ability to handle higher gas flow rates and ultimately extending the operational window of the pump. This analysis can provide a source of data that can be useful to support theoretical models or to validate numerical simulations.",12,12,3
Centrifugal Pump,,"Ge, Zhenguo; He, Denghui; Huang, Rui; Zuo, Juanli; Luo, Xingqi",Application of CFD-PBM coupling model for analysis of gas-liquid distribution characteristics in centrifugal pump,Two-phase flow; Centrifugal pump; PBM model; Eulerian-eulerian model; Void fraction; Bubble size,FLOW PATTERNS; ENTRAINED AIR; ESP; PERFORMANCE; IMPELLER,"The gas and liquid distributions in the pump are significant for understanding the pump performance under bubble flow inlet. An accurate numerical simulation method will contribute to obtain the gas and liquid distribution characteristics in the pump. In this study, the simulation method based on the CFD-PBM (CFD-Population Balance Model) coupling model was developed and validated by experiments. The simulation results predicted by the new numerical method agreed better with the experimental results than calculations based on Eulerian-Eulerian model. The coalescence and breakup of bubbles in the centrifugal pump should be considered, which is well handled by the CFD-PBM coupling model. The influences of inlet gas volume fraction and liquid phase flow rate on the void fraction and bubble size distribution in the centrifugal pump were investigated. The results show that more bubbles accumulated in the impeller than in the volute as inlet gas volume fraction increased to a certain value. Small gas pockets accumulated in the impeller and formed large gas masses around the impeller inlet leading to ""Surging"" of the pump. The percentages of bubbles with large diameter increased with the inlet gas volume fraction increasing, rather, the bubbles with small diameter decreased. In addition, the bubbles were more likely to break up into smaller bubbles and difficult to aggregate into bigger bubbles when the liquid flow rate increased. Several void fraction and bubble size prediction models were also compared for the present cases. This study provides an effective method to simulate the pump characteristics under gas and liquid conditions, which is helpful to investigate the gas-liquid performance of the pump.",9,10,5
Centrifugal Pump,,"Castellanos, Mauricio Barrios; Serpa, Alberto Luiz; Biazussi, Jorge Luiz; Verde, William Monte; Dias Arrifano Sassim, Natache do Socorro",Fault identification using a chain of decision trees in an electrical submersible pump operating in a liquid-gas flow,Decision tree classifier; Fault detection; Electrical submersible pump; Machine learning,DIAGNOSIS,"The monitoring of centrifugal pumps is essential for the suitable operation of several industrial applications. The reliability of petroleum artificial lifting systems that use Electrical Submersible Pumps (ESP) depends substantially on the performance of these pumps. ESP can operate subjected to severe operating conditions such as viscous and two-phase flow. In recent years, real-time technologies based on machine learning algorithms have gained importance due to the capability to take advantage of historical data for future predictions. The present work proposes a particular assembly of Classification and Regression Trees (CART) for the detection and classification of incipient faults in a pumping system. Experiments were carried out on a ten-stage ESP to simulate, monitor and label the faults. The pump worked at 1800, 2400, 3000 and 3500 rpm, with a two-phase liquid-gas mixture. The gas-phase was nitrogen, and the liquid-phase was a heavy oil with a viscosity between 200 and 1000 cP. The proposed methodology, named here as Chain of Decision Trees, observe the system behavior based on the monitoring of the pressure, flow, torque, and temperature only. The algorithm has two steps. The first determines whether the system is in a fault state; if it is, the second determines the type of fault. The failures considered were the unexpected closure of the choke valve, the input pressure decreasing, the fluid viscosity increasing and the gas flow rate increasing. The proposed approach intends to improve the balance in classification and the interpretation of the cause of failure. The Chain of Decision Trees and the Decision Tree were compared regarding the overall accuracy and the individual fault misclassification getting a reduction in individual misclassification and better comprehensibility for the Chain of Decision Tree.",8,8,4
Centrifugal Pump,,"Pablo Valdes, Juan; Becerra, Deisy; Rozo, Daniel; Cediel, Alexandra; Torres, Felipe; Asuaje, Miguel; Ratkovich, Nicolas",Comparative analysis of an electrical submersible pump's performance handling viscous Newtonian and non-Newtonian fluids through experimental and CFD approaches,Turbomachinery; Non-Newtonian liquid; CFD; Electrical Submersible Pumps (ESP); Shear-thinning,CENTRIFUGAL PUMPS; FLOW; VISCOSITY; IMPELLER; RHEOLOGY; PHASE,"Electrical Submersible Pumps (ESPs) are among the most common artificial lifting methods employed nowadays in the O&G industry. This work aims to carry out an exhaustive analysis of the performance and flow features of a multistage ESP when handling Shear-Thinning non-Newtonian fluids, which are commonly found in mature, heavy oil wells. Currently, no studies have been conducted for multistage centrifugal pumps operating under such conditions. In this study, water, two Newtonian oils of different viscosities, and two non-Newtonian fluids, consisting of two CMC solutions in water (0.5% and 1% w/w), were tested. The testing facility consisted of a four-stage ESP located in a closed-loop arrangement in which the flowrate could be freely manipulated. Experimental measurements were taken to determine the pressure rise and power consumption by the ESP's motor. The CFD model was validated against experimental data collected in this study. The CFD head rise was in excellent agreement against the experimental data for water, with MSE of 4.91%. Good agreement was also observed, with a slight overprediction, for the pump's efficiency, with an MSE of 10.6%. The non-Newtonian fluids best fitted the Cross viscosity model. CMC 0.5% obtained a 12% higher average head rise than that of CMC 1%, despite the latter exhibiting a more pronounced Shear-Thinning trend (higher Cross time constant). It was found that the non-Newtonian fluids tested out-performed, in terms of head rise, the Newtonian oils by an average of 23.5%, and 11.4% against the heavier and the lighter oil, respectively. This improved performance was observed despite the non-Newtonian range of effective viscosities being over one or more orders of magnitude higher than the oils' dynamic viscosities. Furthermore, it was noted that the pump's performance with both non-Newtonian fluids did not deteriorate as rapidly as it did for the viscous oils. This lead to a shift in the BEP towards higher flowrates for the non-Newtonian fluids. This observation was supported by the CFD effective viscosity profiles, which showed a decline in the viscosity as the flowrate increased. CFD proved to be a valuable tool to analyze and understand in depth the viscosity variations and flow features throughout the pump's domain and their connection with the global performance observed for the ESP.",8,8,2
Diffusion Coefficient,,"Amar, Menad Nait; Ghahfarokhi, Ashkan Jahanbani",Prediction of CO2 diffusivity in brine using white-box machine learning,CO2-Brine; Diffusivity coefficient; Empirical correlations; GEP; GMDH,ENHANCED OIL-RECOVERY; CARBON-DIOXIDE; NEURAL-NETWORK; GAS/VAPOR VISCOSITY; TRAPPING PROCESSES; GAS-DIFFUSION; NITROUS-OXIDE; MASS-TRANSFER; COEFFICIENTS; STORAGE,"Accurate knowledge of the diffusivity coefficient of CO2 in brine has a significant effect on the design success and monitoring of CO2 storage in saline aquifers, which is a part of carbon capture and sequestration (CCS). Frequently applied experimental approaches for determining this parameter are expensive and time-consuming, and empirical models cannot ensure accurate predictions. Therefore, there is a need to establish cutting-edge correlations for prediction of the diffusivity coefficient of CO2 in brine under various operating conditions. In this work, two white-box machine learning techniques, namely group method of data handling (GMDH) and gene expression programming (GEP) were implemented for correlating the diffusivity coefficient of CO2 in brine with pressure, temperature and the viscosity of the solvent. The obtained results demonstrated the accuracy of the proposed correlations. In addition, statistical and graphical analysis of the performances revealed that GEP correlation outperforms the GMDH correlation, decision trees (DTs), random forest (RF) and all the previous predictive models. GEP correlation exhibited an overall average absolute relative deviation (AARD) of 4.3014% and coefficient of determination (R-2) of 0.9979. Finally, by performing the outliers detection, the validity of the GEP correlation was confirmed and only two experimental data points were identified as outliers.",15,15,2
Diffusion Coefficient,,"Yang, Yun; Liu, Shimin",Laboratory study of cryogenic treatment induced pore-scale structural alterations of Illinois coal and their implications on gas sorption and diffusion behaviors,Cryogenic fracturing; CBM stimulation; Diffusion coefficient; Sorption isotherm,WAALS ADSORPTION-ISOTHERMS; NITROGEN FREEZE-THAW; LIQUID-NITROGEN; SURFACE-DIFFUSION; SIZE DISTRIBUTION; STRUCTURE DAMAGE; CARBON-DIOXIDE; METHANE; HYSTERESIS; DESORPTION,"Cryogenic fracturing using liquid nitrogen is a choice for CBM reservoir stimulation. However, the development of cryogenic fracturing is still at its infancy. This work focused on induced pore structural alterations due to cryogenic treatment and their effects on gas sorption and diffusion behaviors. The changes in the pore structure of coal induced by cyclic nitrogen injections were studied by physical adsorption at low temperatures. A micromechanical model is proposed to simulate the microscopic process and predict the degree of deterioration due to low temperature treatments. As a common characteristic of modeled results and experimental results, the total volume of mesopore and macropore increased with cryogenic treatment, but the growth rate of pore volume became much smaller as freezing-thawing were repeated. Pores of different sizes experienced different degrees of deterioration. In the range of micropores, no significant alteration of pore volume occurred with the repetition of freezing and thawing. In the range of mesopores, pore volume increased with the repetition of freezing and thawing. In the range of macropores, pore volume increased after the first cycle of freezing and thawing but decreased after three cycles of freezing and thawing. Because of pore structural alteration, cryogenic treatment enhanced gas transport process as the diffusion coefficients of the freeze-thawed coal samples were increased by 18.76% and 30.18% in the adsorption and desorption process. The effect of cyclic cryogenic treatment on the pore structure of tested coal varied depending on coal properties. For the studied Illinois coal sample, repetitive applications of cryogenic treatment reduced macropore volume and increase mesopore volume. For the tested sample, the diffusion coefficient of the coal sample that underwent three cycles of freezing-thawing was lower than that of the coal sample that underwent a single cycle of freezing and thawing. The outcome of this study provides justification for a post-cryogenic fracturing effect on diffusion improvement and gas production enhancement, especially for high ""sorption time"" CBM reservoirs.",14,14,17
Diffusion Coefficient,,"Janiga, Damian; Czarnota, Robert; Kuk, Edyta; Stopa, Jerzy; Wojnarowski, Pawel",Measurement of Oil-CO2 diffusion coefficient using pulse-echo method for pressure-volume decay approach under reservoir conditions,CO2 diffusion coefficient; Mass transfer; Pressure-volume decay; Acoustically monitored separator (AMS); CO2-EOR,SATURATED POROUS-MEDIA; HEAVY-OIL; GAS DIFFUSIVITY; LIQUID HYDROCARBONS; CO2 DIFFUSION; MASS-TRANSFER; PUFF PROCESS; HUFF; RECOVERY; BITUMEN,In order to achieve synergic environmental effect CO2-EOR can be applied to improve oil production and reduce carbon dioxide emission. Greater results can be obtained by the CO2 huff-n-puff process which in the case of oil reservoirs is based mainly on the oil swelling effect. During the soaking period the primary mechanism distributing CO2 in the reservoir is molecular diffusion. To calculate mass transferred to oil phase molecular diffusion coefficient is used. Its determination can be based on direct or indirect techniques but no standard method is normed. This paper presents a pulse-echo pressure-volume decay technique to determine oil-CO2 diffusion coefficient under reservoir conditions with the use of acoustically monitored separator. In the proposed method measurements of difference between signal routing are recalculated to volume change in order to compute diffusion coefficient. Experimental procedure was conducted for three different temperatures. The obtained results are consistent with previous studies on diffusion coefficient determination. The proposed technique is more reliable and yields straightforward solution due to simultaneous binary measurements of pressure and volume system.,14,13,6
Diffusion Coefficient,,"Cui, Guanglei; Xia-Ting, Feng; Pan, Zhejun; Chen, Tianyu; Liu, Jishan; Elsworth, Derek; Tan, Yuling; Wang, Chunguang",Impact of shale matrix mechanical interactions on gas transport during production,Effective diffusion; Surface diffusion; Organic matter; Inorganic minerals; Effective stress,ORGANIC-RICH SHALE; COAL PERMEABILITY; SURFACE-DIFFUSION; FLOW BEHAVIOR; ADSORBED GAS; SLIP-FLOW; MODEL; EVOLUTION; RESERVOIR; ADSORPTION,"Shale gas has played an increasingly important role in world energy supply in recent years. The gas transport process in the shale matrix is particularly important as it affects the long-term production behavior of shale gas. The shale matrix consists of inorganic minerals and embedded organic matter with mass transfer influenced by mechanical interactions. We develop a micro-scale discrete coupled model to explicitly account for mass transfer and mechanical interactions, and how these interactions affect the gas transport characteristics of both components. Specifically, the model comprises organic matter embedded within inorganic minerals. The proposed model is implemented and solved within the framework of COMSOL Multiphysics (Version 5.4). The model is first verified against the results of a desorption-diffusion-seepage coupled experiment and then extended to field scale. It is found that the impacts of gas pressure and effective strain are different for the gas seepage in inorganic minerals and gas diffusion in organic matter. Gas pressure may enhance the permeability of the inorganic phase due to the gas slippage effect while compactive effective strain decreases permeability during the gas depletion process. For gas diffusion in the organic matter, surface diffusion decreases and effective diffusion coefficient increases with declining gas pressure. While the impacts of effective strain on the effective diffusion are dependent on the external boundary conditions, the effective diffusion coefficient is lower than the initial value under constant stress conditions and larger than the initial value under constant volume conditions. The proposed model provides a complementary method to conventional continuum dual-media approaches and provides a clear understanding of the interactions between the two components. Field-observed oscillatory gas production data is readily history-matched and key mechanisms explained with the proposed approach presented in this work.",13,13,11
Diffusion Coefficient,,"Dong, Jun; Cheng, Yuanping; Pan, Zhejun",Comparison of transient and pseudo-steady diffusion of methane in coal and implications for coalbed methane control,Coalbed methane; Transient diffusion; Pseudo-steady diffusion; Diffusivity; Matrix shape factor,GAS; TIME; COEFFICIENT; DESORPTION; PRESSURE; BEHAVIOR,"Diffusion coefficient is a key parameter characterizing the methane diffusion capacity. Because of the differences between transient diffusion and pseudo-steady diffusion in methane diffusion rate, the diffusion processes and diffusion coefficients are different. In this study, the transient diffusion and pseudo-steady diffusion properties were measured via particle method and counter diffusion method, respectively. The results indicated that the pseudo-steady diffusion coefficient is higher than the transient diffusion coefficient, and the difference may be attributed to the influence of surface diffusion of adsorbed methane. The matrix shape factor is also a key parameter influencing the methane diffusivity, and it has a higher influence on diffusion amount of methane than the diffusion coefficient. It is suggested that for methane extraction project, the pseudo-steady diffusion coefficient and coal matrix shape factor should be considered, while transient diffusion coefficient should be used to calculate the indices for evaluating the risk of coal and gas outburst.",7,7,10
Cement Sheath,,"Xi, Yan; Li, Jun; Tao, Qian; Guo, Boyun; Liu, Gonghui",Experimental and numerical investigations of accumulated plastic deformation in cement sheath during multistage fracturing in shale gas wells,Multistage fracturing; Accumulated plastic deformation; Cyclic loading; Cement sheath integrity,CASING DEFORMATION; INTEGRITY; PRESSURE; INTERFACE,"Sustained Casing Pressure (SCP) has become a serious problem in the development of shale gas fields, which is believed to relate to the multistage fracturing. However, few researches were on this, especially the study of micro-annulus at the interface between the cement sheath and casing, which was one of the mechanisms of the cement sheath integrity failure, and always caused by accumulated plastic deformation. This paper presented experimental and numerical investigations of the emergence and development of plastic deformation occurred at the interface between the cement sheath and casing during multistage fracturing. Mechanical tests and physical simulation experiments were carried out so as to analyze the plastic deformation variation characteristic of the cement sheath under cyclical loading and unloading. 3-D numerical models were established to analyze the emergence and development of the accumulated plastic deformation based on the test results, considering the actual engineering and geological conditions during multistage fracturing in shale gas wells, which presented a new method to calculate the width of the micro-annulus between the cement sheath and casing. The research showed that the numerical results were in accordance with the experimental results. With the increase of cycle times, the accumulated plastic deformation increased, which was the greatest for the first time, and then increased linearly. Decreasing elastic modulus and increasing Poisson's ratio, cohesive force and internal friction angle could facilitate the protection of the cement sheath integrity. Finally, a new cement slurry system was proposed based on the results of study and applied in 5 wells with good effects acquired, none of them showed SCP after fracturing.",12,13,2
Cement Sheath,,"Wise, Jarrett; Cedola, Alexandra; Nygaard, Runar; Hareland, Geir; Arild, Oystein; Lohne, Hans Petter; Ford, Eric Patrick",Wellbore Characteristics that Control Debonding Initiation and Microannuli Width in Finite Element Simulations,Wellbore; Microannuli; Debonding; Finite Element; Plug and Abandoned,CEMENT; INTEGRITY; MODEL,"Environmental protection is an increasing concern for plugged and abandoned wells within the Gulf of Mexico. Leakage, however, has been shown to occur before the plug and abandonment (P&A) process takes place. The cement used when completing a well may develop leakage paths in the form of microannuli gaps between the casing and cement due to decreases in pressure and/or temperature. The goal of this paper is to use Finite Element Models (FEM) to determine the decrease in pressure or temperature required to initiate debonding of the cement sheath and the corresponding microannuli widths. Results of this paper show that there is a reduction threshold in which microannuli gaps start to initiate and increase in magnitude. A parametric analysis of the parameters within a wellbore has been performed and determined that the dimensions of the wellbore play a critical factor in microannuli gap width. With this knowledge, microannuli gap prediction graphs can be developed for different wellbore dimensions with pressure and temperature variations to determine whether a wellbore is at risk for leakage prior to P&A.",9,9,2
Cement Sheath,,Deng Kuanhai; Yuan Yue; Hao Yi; Li Zhonghui; Lin Yuanhua,Experimental study on the integrity of casing-cement sheath in shale gas wells under pressure and temperature cycle loading,Casing-cement sheath; Full-scale integrity test; Temperature cycle loading; Pressure cycle loading; Interface mechanical properties; Multistage hydraulic fracturing,ZONAL ISOLATION; FAILURE; MODEL,"During large-scale multistage hydraulic fracturing in shale-gas wells, the cement sheath loses its integrity easily because of repeated temperature and pressure variations in the wellbore. This is likely to form a potential leak path, subsequently leading to the loss of zonal isolation and sustained casing pressure. To prevent such barrier failures, it is crucial to investigate and understand the failure mechanism of cement sheath. In this study, an experimental apparatus and evaluation method of the sealing integrity and mechanical integrity for casing-cement sheath under temperatures and pressures cycle loading have been presented in this paper by which sixteen groups of full-scale integrity tests of general and high-strength cement sheath have been conducted under temperature ranging from 30 to 150 degrees C and pressure ranging from 0 to 70 MPa cycling loading. The anti-channeling/sealing performance and interface mechanical behavior of casing-cement sheath are measured and characterized respectively under different loading-unloading methods. The cycle numbers required for sealing integrity failure of cement sheath under different cyclic temperatures and pressures have been obtained. The interface mechanical properties (cementing force, friction force, shearing strength and lateral bonding strength) of cement sheath have been obtained, and effects of alternating temperatures and pressures on those mechanical properties and late integrity have been analyzed. Research results can provide a very important reference for the fracturing design of shale-gas wells.",8,8,6
Cement Sheath,,"Wu, Yuxing; Patel, Harshkumar; Salehi, Saeed; Mokhtari, Mehdi",Experimental and finite element modelling evaluation of cement integrity under diametric compression,Finite element modelling; Well integrity; Cement failure; Digital image correlation; Diametric compression,FAILURE MECHANISMS; WELL INTEGRITY; STORAGE,"With the increased exploration activity in unconventional and extreme operational environment, well integrity is becoming a challenging problem. Cement sheath, being an important barrier element, should be designed properly for adaptation of complicated loads surrounding the wellbores. This experimental and modelling study evaluates casing-cement-formation system under diametrically compressive load. Digital image correlation (DIC) technique was employed to examine the strain distribution and failure in experimental setup. A 3D numerical model was developed and the comparison between simulation and experimental results indicated a reasonable match. Using validated model, the effect of cement elastic properties on stresses in cement was studied. The stress distribution in the cement-formation system shows that casing-cement interface is the weakest point in the system, thus it has the highest risk of failure. The failure initiates at orientation parallel (theta = 0 degrees) to the applied load followed by in perpendicular (theta= 90 degrees) direction. Hoop stress is more sensitive to Young's modulus and Poisson's ratio than radial stress, so it is more critical for the failure assessment. In general, flexible cement with low Young's modulus and high Poisson's ratio has low risk of failure.",8,9,2
Data Assimilation,,"Luo, Xiaodong; Bhakta, Tuhin",Automatic and adaptive localization for ensemble-based history matching,Ensemble data assimilation; Iterative ensemble smoother; Correlation-based adaptive localization; Seismic history matching; Big data assimilation,KALMAN FILTER; DATA ASSIMILATION; SAMPLING ERROR,"Ensemble-based history matching methods are among the state-of-the-art approaches to reservoir characterization. In practice, however, they often suffer from ensemble collapse, a phenomenon that deteriorates history matching performance. To prevent ensemble collapse, it is customary to equip an ensemble history matching algorithm with a certain localization scheme. In a previous study, the authors propose an adaptive localization scheme that exploits the correlations between model variables and simulated observations. Correlation-based adaptive localization not only overcomes some longstanding issues (e.g., the challenges in handling non-local or time-lapse observations) arising in the conventional distance-based localization, but also is more convenient and flexible to use in real field case studies. In applications, however, correlation-based localization is also found to be subject to two problems. One is that, it requires to run a relatively large ensemble in order to achieve decent performance in an automatic manner, which becomes computationally expensive in large-scale problems. As a result, certain empirical tuning factors are introduced to reduce the computational costs. The other problem is that, the way used to compute the tapering coefficients in the previous study may induce discontinuities, and neglect the information of certain still-influential observations for model updates. The main objective of this work is to improve the efficiency and accuracy of correlation-based adaptive localization, making it run in an automatic manner but without incurring substantial extra computational costs. To this end, we introduce two enhancements that aim to avoid the aforementioned two problems, namely, empirical tuning and discontinuities. We apply the resulting automatic and adaptive correlation-based localization with these two enhancements to a 2D and a 3D cases investigated in the previous study, and show that it leads to better history matching performance (in terms of efficiency and/or estimation accuracy) than that is achieved in the previous work.",11,11,0
Data Assimilation,,"Kim, Jaejun; Kim, Sungil; Park, Changhyup; Lee, Kyungbook",Construction of prior models for ES-MDA by a deep neural network with a stacked autoencoder for predicting reservoir production,Deep neural network (DNN); Stacked autoencoder (SAE); Ensemble smoother with multiple data; assimilation (ES-MDA); History matching; Egg model,ITERATIVE ENSEMBLE SMOOTHER; CHANNELIZED RESERVOIRS; UNCERTAINTY QUANTIFICATION; WELL PLACEMENT; KALMAN FILTER; ALGORITHM,"The design of prior models has continued to receive research attention because of their importance for ensemble-based methods. There are two approaches to ensemble design: selection and regeneration. Both strategies try to utilize dynamic data in a qualified prior model. The regeneration approach has a higher degree of freedom than the selection approach because the latter is selected among given initial models. However, previous regeneration methods are still sensitive to prior models because these methods create new models based on the priors' statistics. In this study, a deep neural network (DNN) was implemented to build new prior models. If there is a data pair for a reservoir model and its production, the production data and model parameters become the input and output data, respectively, for training the DNN. The trained DNN can generate new prior models according to the observed production history. For the output layer of the DNN, the main information of the permeability field is extracted by a stacked autoencoder (SAE) to improve the DNN performance. New prior models from DNN with SAE become the qualified prior set for ensemble-based methods because they already reflect observed dynamic data. For validation, an ensemble smoother with multiple data assimilation (ES-MDA) was applied to an Egg model. The proposed method (i.e., prior models designed with DNN-SAE) gave reliable posterior permeability fields and future reservoir performances. Compared with the two control groups (i.e., prior models and prior models with DNN), the proposed method mitigated the overshooting problem and found channel connectivity in the reference field. In a comparison with reliable posterior models, the simulation results of the proposed method not only matched observed production data but also reliably predicted future production. This study is an example of the successful application of a machine learning algorithm to history matching.",9,9,0
Data Assimilation,,"Soares, R., V; Luo, X.; Evensen, G.; Bhakta, T.",4D seismic history matching: Assessing the use of a dictionary learning based sparse representation method,Ensemble data assimilation; Iterative ensemble smoother; 4D seismic history matching; Big data assimilation; Dictionary learning,ITERATIVE ENSEMBLE SMOOTHER; DATA ASSIMILATION; FIELD MODEL; PARAMETERIZATION; LOCALIZATION,"It is possible to improve oil-reservoir simulation models by conditioning them on 4D seismic data. Computational issues may arise related to both storage and CPU time due to the size of the 4D seismic dataset. An approach to reducing the computational requirements is to use a sparse representation method, e.g., Dictionary Learning, to select only the main features of the 4D seismic data. However, the introduction of a sparse representation method incurs an additional computational cost. Alternatively, if one uses ensemble-based methods, it is possible to reduce storage and CPU time by projecting the full seismic dataset on a smaller subspace. This paper evaluates the potential of sparsely representing the seismic data. We compare two experiments, one where we condition on the full dataset projected on a smaller subspace, and one where we use Dictionary Learning to represent the data sparsely. We use Dictionary Learning both on the complete 4D seismic dataset and also on a denoised version of the data. We perform the data assimilation in a slightly different formulation of the Iterative Ensemble Smoother Regularized LevenbergMarquardt together with correlation-based adaptive localization. We apply these methods to the Brugge benchmark case. Experiment results show that sparse representation methods lead to a final ensemble that is closer to the reference solution, and denoising the seismic data before applying the sparse representation allows us to capture the 4D effect better. Thus, using a sparse representation method in 4D-seismic history matching leads to improved results compared to what we obtain when conditioning the models on the projected 4D seismic dataset.",9,9,0
Data Assimilation,,"Mahjour, Seyed Kourosh; Souza Santos, Antonio Alberto; Correia, Manuel Gomes; Schiozer, Denis Jose",Developing a workflow to select representative reservoir models combining distance-based clustering and data assimilation for decision making process,Representative models; Distance-based clustering; Data assimilation; Uncertainty assessment,PROPER ORTHOGONAL DECOMPOSITION; PETROLEUM FIELD DEVELOPMENT; HYDRAULIC FLOW UNITS; UPSCALING TECHNIQUE; PRODUCTION STRATEGY; RISK ANALYSIS; MONTE-CARLO; UNCERTAINTY; REDUCTION; TIME,"Different types of static and dynamic uncertainties can play critical roles to select an efficient and reliable production strategy in the oil fields, yielding a large number of models to analyze. The definition of such a production strategy requires flow simulation for each model. Since the flow simulation process for this large model ensemble requires a great CPU effort, selecting a subset of representative models (RMs) is often used for accelerating the analysis. However, providing an applicable and efficient method to identify the RMs that statistically reflect the same dynamic and static properties as the full set of models is still challenging. In this study, we develop a new workflow to select RMs based on the integration of distance based clustering and data assimilation aimed at the field development. The workflow begins with the generation of geostatistical models using Latin hypercube (LH) sampling and then reducing them through distance-based clustering according to their static features. Therefore, there is no need to apply numerical simulation for scenario reduction. Next, discrete Latin hypercube with geostatistical realizations (DLHG) method is performed to combine other types of uncertainty with the reduced geostatistical models and build the simulation models. Eventually, data assimilation (DA) is applied to select the subset of models that match the past reservoir performance and production data. In addition, the uncertainty range are evaluated for the defined well and field objective functions using the cumulative distribution function (CDF) and non-parametric Kolmogorov-Smirnov (K-S) test. The methodology is successfully applied to a synthetic benchmark case named UNISIM-II-D considering the flow unit modeling. The results show that the workflow can effectively and suitably identify the RMs considering different uncertainty types, reservoir heterogeneity and many field and well objective functions. The selected RMs are used for making production forecasts and development planning support.",8,8,0
Gas Condensate Reservoirs,,"Haji-Savameri, Mohammad; Menad, Nait Amar; Norouzi-Apourvari, Saeid; Hemmati-Sarapardeh, Abdolhossein","Modeling dew point pressure of gas condensate reservoirs: Comparison of hybrid soft computing approaches, correlations, and thermodynamic models",Gas condensate reservoir; Pd; EOS; Soft computing; CMIS,NEURAL-NETWORK; GENERALIZED MODELS; WELL PRODUCTIVITY; DEWPOINT PRESSURE; PHASE-BEHAVIOR; CRUDE-OIL; PREDICTION; EQUATIONS; OPTIMIZATION; REGRESSION,"Optimal future management of gas condensate reservoirs requires reliable estimation of the dew point pressure (Pd). Due to the limitations of the available Pd determination methods, such as cost and the prohibitive time for experimental approaches, and inaccuracies and lack of generalization for predictive approaches, it is still necessary to establish more accurate and user friendly Pd paradigms. In this study, various methodologies based on soft computing (SC) techniques, optimization algorithms, and generalized reduced gradient (GRG) method were implemented to develop Pd models based on a widespread databank. Two types of artificial neural networks, namely radial basis function (RBF) neural networks and Multilayer perceptron (MLP) are the employed SC methods. To improve the prediction capability of the latter, Levenberg-Marquardt (LM), Bayesian Regularization (BR), and Scaled Conjugate Gradient (SCG) algorithms were used in the training phase of MLP, while three nature-inspired algorithms, namely Genetic Algorithm (GA), Bat Algorithm (BA), and Salp Swarm Algorithm (SSA) were first considered in the RBF learning phase. Then, the four best-found models were assembled beneath a unified paradigm utilizing a committee machine intelligent system (CMIS). Also, a correlation was developed using GRG. The developed CMIS and GRG correlation were compared with four empirical correlations as well as seven equations of state (EOSs). Based on the results obtained, CMIS model exhibits very satisfactory Pd predictions with an overall average absolute percent relative error (AAPRE) of 5.28%, and outperforms largely the other existing predictive approaches. Furthermore, the developed correlation provided more accurate results compared to existing correlations and EOSs.",14,14,1
Gas Condensate Reservoirs,,"Mahdaviara, Mehdi; Menad, Nait Amar; Ghazanfari, Mohammad Hossein; Hemmati-Sarapardeh, Abdolhossein",Modeling relative permeability of gas condensate reservoirs: Advanced computational frameworks,Relative permeability; Gas condensate; Empirical correlation; Artificial intelligence; Comprehensive modeling,EXTREME LEARNING-MACHINE; NEURAL-NETWORK; INTERFACIAL-TENSION; GAS/VAPOR VISCOSITY; LINEAR-REGRESSION; PREDICTION; ALGORITHM; SATURATION; EQUATION; POROSITY,"In the last years, an appreciable effort has been directed toward developing empirical models to link the relative permeability of gas condensate reservoirs to the interfacial tension and velocity as well as saturation. However, these models suffer from non-universality and uncertainties in setting the tuning parameters. In order to alleviate the aforesaid infirmities in this study, comprehensive modeling was carried out by employing numerous smart computer-aided algorithms including Support Vector Regression (SVR), Least Square Support Vector Machine (LSSVM), Extreme Learning Machine (ELM), Multilayer Perceptron (MLP), Group Method of Data Handling (GMDH), and Gene Expression Programming (GEP) as predictors and Genetic Algorithm (GA), Particle Swarm Optimization (PSO), Levenberg-Marquardt Algorithm (LMA), Bayesian Regularization (BR), Scaled Conjugate Gradient (SCG) and Randomized Polynomial Time (RP) as optimizers. To this end, a wide variety of reliable databanks encompasses more than 1000 data points from eights sets of experimental data was utilized in the training and testing steps of the modeling process. The predictors were integrated with optimization algorithms to assign the optimum tuning parameters of each model. The modeling was implemented in two different manners from the standpoint of models inputs: (1) 2-input (saturation and capillary number); (2) 3-input (saturation, interfacial tension, and capillary number). The results of the comparison between these strategies demonstrate more accuracy of the models when employing three independent parameters as the input (3-input). Among the developed models, the MLP-LMA modeling algorithm outperformed all other models with root mean square errors (RMSEs) of 0.035 and 0.019 for gas and condensate phases, respectively. At the end, in a comparison between both 2-input and 3-input MLP-LMA models and five traditional literature models, both smart modeling approaches were established themselves as the most accurate techniques for estimation of relative permeability in gas condensate reservoirs.",11,11,1
Gas Condensate Reservoirs,,"Karami, Saeed; Dehaghani, Amir Hossein Saeedi; Mousavi, Seyed Amir Hossein Seyed",Condensate blockage removal using microwave and ultrasonic waves: Discussion on rock mechanical and electrical properties,,HUFF-N-PUFF; ENHANCED OIL-RECOVERY; HEAVY CRUDE-OIL; WELL PRODUCTIVITY; GAS INJECTION; TECHNOLOGY; NANOPARTICLES; STIMULATION; RESERVOIRS; DEPOSITION,,10,10,1
Gas Condensate Reservoirs,,"Dahim, Sadegh; Taghavinejad, Amin; Razghandi, Milad; Rigi, Hamed Rahimi; Moeini, Kianoosh; Jamshidi, Saeid; Sharifi, Mohammad",Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs,Pseudo triple-porosity; Pressure transient analysis; Multi-stage hydraulically fractured well; Shale gas condensate; Rate transient analysis,RATE-DECLINE ANALYSIS; PERFORMANCE; SINGLE; VISCOSITY; BEHAVIOR; FLOW,"Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. The strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.",9,9,6
Pipeline,,"Moayedi, Hossein; Aghel, Babak; Vaferi, Behzad; Foong, Loke Kok; Dieu Tien Bui",The feasibility of Levenberg-Marquardt algorithm combined with imperialist competitive computational method predicting drag reduction in crude oil pipelines,Drag reduction; Artificial intelligence; Levenberg-Marquardt; Imperialist competition algorithm; Comparative study,ARTIFICIAL NEURAL-NETWORKS; REDUCING POLYMERS; FLOW; MODEL; PERFORMANCE,"Adding small amounts of drag-reducing agents (DRA) to the crude oil can effectively reduce energy losses and its associated pressure drop in transportation pipelines. They do their roles by reducing the turbulent friction factor of the flowing liquids in the pipeline. In this study, the artificial neural networks (ANN) are utilized for estimation of drag reduction (DR) in crude oil pipelines as a function of Reynolds number, concentration, and type of drag-reducing agents, temperature, and type of pipe. Two different training algorithms, i.e. Levenberg-Marquardt (LM) and imperialist competition algorithm (ICA) are used for adjustment of parameters of multilayer perceptron (MLP) networks. Predictive accuracies of trained MLP by Levenberg-Marquardt (LM-MLP) and imperialist competition algorithm (ICA-MLP) for estimating drag reduction in crude oil pipelines were compared. The comparisons were done by three statistical criteria, i.e. root mean square error (RMSE), the coefficient of determination (R-2), and mean absolute error (MAE). The obtained results show that replacing LM by ICA evolutionary algorithm for adjustment of parameters of MLP leads to increasing R-2 from 0.9585 to 0.9791 in the training phase, and from 0.9310 to 0.9698 in the testing phase. Furthermore, ICA has reduced the RMSE and MAE of testing group from 3.0396 to 2.2616 to the 2.0080 and 1.5579, respectively. Finally, a simple ANN-based formulation is provided for using our developed ICA-MLP model to estimate DR in the crude oil pipelines.",25,26,5
Pipeline,,"Wang, Leizhen; Wang, Guorong; Mao, Liangjie; Fu, Qiang; Zhong, Lin",Experimental research on the breaking effect of natural gas hydrate sediment for water jet and engineering applications,Natural gas hydrates; Solid fluidization; Water jet; Mining; Breaking effect,,"Experimental studies on the influence of traverse speed, jet flow rate, and reciprocating times of jet flushing on natural gas hydrate sediment breaking effect under water jet were carried out. The breaking effect was evaluated from four aspects: shape regularity of broken hole, variation of broken hole diameter, breaking efficiency, and solid phase concentration of slurry formed by the jet. Results show that a uniform arrangement of 18 nozzles in radial direction of the water jet mining head can ensure that broken hole shape is regular and circular. To reach a 0.5 m hole diameter, the reciprocating times of flushing increases with the increase of the traverse speed and decreases with the increase of the jet flow rate. The breaking efficiency which is very low at small borehole diameter increased first and then decreased with the increase of the hole diameter. The increase of the jet flow rate and traverse speed is conducive to improve breaking efficiency. However, that leads to extremely high solid phase concentration of slurry, which will increase the risk of pipeline transportation. In order to achieve well breaking effect of natural gas hydrate sediment by water jet, the recommended technological parameters are jet flow rate of 450 L/min, traverse speed of 5 m/min and 5 reciprocating times of flushing when the initial hole diameter is 0.1 m. This study provides a reference for the formulation of the technological parameters for the first solid fluidization well testing and production operation in the world.",24,26,11
Pipeline,,"Deka, Barasha; Sharma, Rohit; Mahto, Vikas",Synthesis and performance evaluation of poly (fatty esters-co-succinic anhydride) as pour point depressants for waxy crude oils,Waxy crude oil; Polymeric additive; Flow assurance; pour point; Gelation point; pour point depressant,FLOW IMPROVERS; RHEOLOGICAL BEHAVIOR; PRECIPITATION; ASPHALTENES; DEPOSITION; ACID; TEMPERATURE; PIPELINE; GELATION,"This research work focuses on the development of two polymeric compounds poly (n-dodecyl linoleate -co- succinic anhydride) and poly (n-dodecyl ricinoleate -co- succinic anhydride) from the naturally obtained vegetable oils fatty acids, which were subsequently evaluated as pour point depressants (PPDs) for a waxy crude oil. The developed chemical additives were characterized by FTIR and NMR spectroscopies. Significant reduction in pour point and apparent viscosities were obtained for the PPD treated crude oils compared to virgin crude oil, which indicated improvement in low temperature flow properties of the crude oil. Moreover, reduction in gelation point, storage and loss modulus of PPD treated crude oils exhibit improvement in the restart flowability of crude oil in case of pipeline shut down. Microscopic studies revealed the changes in the wax crystal structures after addition of chemical additives. One of the important studies, cold finger test showed that, wax deposition from the crude oil was considerably reduced by the addition of the two synthesized PPDs during flow through tubing, resembling the pipeline flow condition.",12,12,5
Pipeline,,"Doshmanziari, Roya; Khaloozadeh, Hamid; Nikoofard, Amirhossein",Gas pipeline leakage detection based on sensor fusion under model-based fault detection framework,Pipeline; Leakage detection; Leakage location; State estimation; Extended Kalman Filter; Fisher method; OLGA,LOCATION; FLOW,"A model-based approach to detect and locate leakage along a finite length pipeline is proposed. Developing a generalized state space representation of the pipeline system is one of the achievements of this study. The approach relies on nonlinear modeling derived from momentum, continuity equations. Leaks are defined as system states thus, Extended Kalman Filter as a state observer is implemented to start leak detection. Hydraulic pressure measurements in spatial discretization points are required as output parameters in the estimation process. In order to increase system redundancy and leak estimation accuracy, displacement of sensor arrays instead of a single sensor is suggested. Fisher fusion method is implemented to combine noisy measurements and results in noticeable estimation accuracy improvement. Simulation of a realistic high-pressure operational pipeline is done by OLGA multiphase flow simulation software. The convergence of system states and leak estimation precision confirm the proposed method effectiveness.",10,10,6
Inhibitor,,"Solomon, Moses M.; Umoren, Saviour A.; Quraishi, Mumtaz A.; Tripathy, Divya B.; Abai, Ekaette J.","Effect of akyl chain length, flow, and temperature on the corrosion inhibition of carbon steel in a simulated acidizing environment by an imidazoline-based inhibitor",Corrosion; Inhibition; Imidazoline; Synergism; Pendant group chain,MILD-STEEL; BETA-CYCLODEXTRIN; N80 STEEL; ACID; BENZIMIDAZOLE; DERIVATIVES,"An imidazoline, 2-heptadecyl-1-[2-(octadecanoylamino)ethyl]-2- imidazoline (QSI) with -C17H35 as the tail chain length was synthesized, characterized, and studied as corrosion inhibitor for low carbon steel in 15% HCl solution under static and hydrodynamic conditions. Influence of addition of KI, temperature, and chain length of pendant hydrocarbon on inhibition efficiency (eta) was also examined. It is found that, QSI exhibits a mixed type behavior but fairly inhibited the corrosion of low carbon steel in the studied medium. The maximum concentration studied (400 mg/L) afforded eta of <50%. Addition of KI to QSI synergistically enhanced the corrosion inhibition performance of QSI, upgrading the. to approximately 90%. Increase in the system temperature increases the eta of both QSI and QSI + KI. From the variation of eta with temperature and the calculated corrosion kinetic parameters, chemical adsorption is proposed as the adsorption mechanism of the additives. QSI performs better under hydrodynamic condition than static condition eta However, the corrosion resistance of the metal decreases at rotation speed higher than 1000 rpm. Inhibition efficiency of imidazoline decreases as the length of the hydrocarbon pendant chain increases. Imidazoline compounds with -C13H27 and -C15H31 as the length of the pendant group hydrocarbon perform better than QSI with -C17H35.",28,31,2
Inhibitor,,"Campen, Sophie; Moorhouse, Saul J.; Wong, Janet S. S.",Mechanism of an asphaltene inhibitor in different depositing environments: Influence of colloid stability,Asphaltenes; Fouling; Inhibitor; Remediation; Colloid; QCM-D,QUARTZ-CRYSTAL MICROBALANCE; BENZENE-DERIVED AMPHIPHILES; SELF-ASSEMBLED MONOLAYERS; REFRACTIVE-INDEX; QCM-D; CRUDE-OIL; ADSORPTION; RESINS; PRECIPITATION; AGGREGATION,"Additives are used to reduce unwanted carbonaceous deposits of asphaltenes on surfaces during petroleum production from natural oil and gas reservoirs. The working mechanism of formulated additive packages can be multifaceted. Additives may be effective in the bulk fluid by preventing asphaltenes aggregation, as well as at the surface by preventing asphaltenes adhesion. In this paper, we investigate the numerous different mechanisms by which an asphaltene inhibitor can interfere with the formation of carbonaceous deposits using a combination of techniques including dynamic light scattering to determine particle size distribution, quartz crystal microbalance with dissipation monitoring to examine deposition behaviour and atomic force microscopy to probe deposit morphology. The tested inhibitor prevents deposition of asphaltenes in toluene, where asphaltenes exist as a stable colloidal dispersion of nanoaggregates, by forming barrier-type films that inhibit asphaltenes adhesion and displacing adsorbed thin films of asphaltenes. However, inhibitor performance in heptane-toluene, where asphaltenes are destabilised, depends on the degree of destabilisation. At low heptane volume fraction, inhibitor slows the rate of deposition and deposition rate decreases with increasing inhibitor concentration. However, at high heptane volume fraction, inhibitor can increase the deposition rate, particularly when used in high concentration. At high heptane volume fraction, inhibitor addition alters the morphology of the deposit from that consisting of large flocculent aggregates to that consisting of smaller, submicrometer aggregates. This is consistent with the finding that inhibitor acts as an anti-agglomerant and prevents the formation of large aggregates in the bulk liquid. This paper shows that the impact of inhibitor addition depends on the environmental conditions encountered and the degree of destabilisation of the asphaltenes. Where inhibitor addition alters the nature of depositing species from large flocculent aggregates to smaller submicrometer aggregates, an increase in deposition rate may be observed.",18,18,3
Inhibitor,,"Hegde, Chiranth; Pyrcz, Michael; Millwater, Harry; Daigle, Hugh; Gray, Ken",Fully coupled end-to-end drilling optimization model using machine learning,ROP; Data-driven; Machine learning; Drilling; Optimization; Vibration,PREDICTION; EFFICIENCY,"Drilling optimization has been studied extensively given its impact on an oil and gas project - especially in a low-price environment. This is generally approached by optimizing the rate of penetration (ROP) of the well, which may not always be the best strategy. Additionally, optimization strategies rarely include the effect of torsional drilling vibrations (stick-slip) - the biggest ROP inhibitor. As such, most optimization studies have attempted to optimize only one drilling metric - ROP, mechanical specific energy (MSE) or vibrations - independent of the other, despite their interaction downhole. This does not represent bottom hole conditions accurately. This paper introduces a method of coupling several downhole parameters using machine learning algorithms. Individual models for ROP, torque on bit (TOB), MSE, and stick-slip are built using a data-driven modeling approach using the random forests algorithm. The random forest algorithm is used given its lower error rate in modeling ROP (11%), TOB (13%), and classifying drilling vibrations (F-1 score of 0.94) as compared to other machine learning algorithms evaluated in this paper (linear regression, k nearest neighbors, bagging, and neural networks). The models are coupled by building them conjointly during training. The model uses weight-on-bit (WOB), rotary speed, flowrate, and rock strength as inputs to provide an optimal set of these input parameters to use ahead of the bit for optimal drilling. The coupled model was evaluated to optimize ROP and MSE on validation data. ROP increased by 31% and MSE decreased by 49% on average with the use of this optimization model. A case study from the Williston Basin is discussed to illustrate the practical application of this model.",9,9,6
Exposure Time,,"Ahooei, Arman; Norouzi-Apourvari, Saeid; Hemmati-Sarapardeh, Abdolhossein; Schaffie, Mahin","Experimental study and modeling of asphaltene deposition on metal surfaces via electrodeposition process: The role of ultrasonic radiation, asphaltene concentration and structure",Electrodeposition; DC electric field; Asphaltene deposition; Ultrasonic radiation; Kinetic modelling; Structural analysis,ELECTRICAL-CONDUCTIVITY; ADSORPTION; CRUDE; PRECIPITATION; KINETICS; REMOVAL; RESINS; OIL; MECHANISMS; PARTICLES,"Asphaltene deposition in the wellbore is considered as a major operational challenge while producing some crude oils. It has been claimed that, external fields, such as electric field and ultrasonic radiation, could help tackling this issue. Although the effect of electric field on the aggregation size and the aggregation rate of asphaltene particles has been investigated before, its correlation with asphaltene deposition in the presence and absence of ultrasonic radiation is not known. In this study, the asphaltene deposition on metal surfaces was first mimicked using an electrodeposition process, and then the effect of ultrasonic radiation on electrodeposition of asphaltene were measured and analysed. Our observations showed that the electric filed itself does not unstable the dissolved asphaltene, and the asphaltene deposition on electrodes, under the effect of DC electric filed, first requires the formation of asphaltene aggregates. The maximum deposition was generated at 2 kV/cm, the exposure time of 300 s to the electric field, and the weight ratio of toluene to heptane 4.2%. It was also found that the structure and composition of asphaltenes, especially their polarity and aromaticity, affect asphaltenes deposition. Among different adsorption kinetic models, the nth-order kinetics model was selected to estimate the amount of deposited asphaltene. Finally, simultaneous ultrasound radiation during the process of electrodeposition, reduced the deposition rate on the metal blades from an average of 65 wt % of the total asphaltene content to 10 wt%. The findings of this study highlight the role of composition and structural properties of asphaltene on its surface deposition in the wellbore. More importantly, simultaneous radiation of ultrasonic waves during electrodeposition process confirms the effectiveness of ultrasonic radiation, as a quite new asphatene remediation technique.",8,8,3
Exposure Time,,"Gamal, Hany; Elkatatny, Salaheldin; Adebayo, Abdulrauf; Bageri, Badr",Effect of exposure time on the compressive strength and formation damage of sandstone while drilling horizontal wells,Compressive strength; Formation damage; Barite-water-based drilling fluid; Exposure time; Sandstone formation; Horizontal drilling,WATER; FLUID; FIELD; MODEL; MUD,"Worldwide increase demand for oil and gas led to an evolution in drilling techniques that maximize oil and gas production such as inclined, multilateral, and long horizontal drilling. The interaction of the drilling fluid and mud filtration with the penetrated formation is very critical and very important to be evaluated especially in the case of horizontal drilling where the drilling operation may take more than 20 days. This study aims to assess the effect of exposure time on the changes of the unconfined compressive strength (UCS) while drilling horizontal sandstone formation using water-based drilling fluid. Modified high-pressure high-temperature (HPHT) filter press cell was used to soak Buff Berea sandstone cores with barite-weighted mud under 300 psi differential pressure and 200 degrees F temperature for different periods. Nuclear magnetic resonance (NMR) was used to assess the change of the porosity while the scratch test was conducted to evaluate the changes in the UCS. The obtained results showed that UCS decreased significantly with increasing exposure time. For instance, the UCS was reduced by 18% after 5 days. NMR results confirmed that there was a corresponding increase in formation damage as shown by a progressive decrease in the rock porosity and permeability with time. The exposure time was found to be a controlling factor for both reducing the rock UCS and porosity. The statistical analysis showed that there is an inverse linear relationship (with 0.92 coefficient of determination R-2) between the UCS values vs the extended exposure time. Meanwhile, an approximate logarithmic relationship (with R-2 of 0.98) for estimating the reduction in rock porosity with the exposure time was investigated.",8,8,0
Corrosion Inhibition,,"Solomon, Moses M.; Umoren, Saviour A.; Quraishi, Mumtaz A.; Tripathy, Divya B.; Abai, Ekaette J.","Effect of akyl chain length, flow, and temperature on the corrosion inhibition of carbon steel in a simulated acidizing environment by an imidazoline-based inhibitor",Corrosion; Inhibition; Imidazoline; Synergism; Pendant group chain,MILD-STEEL; BETA-CYCLODEXTRIN; N80 STEEL; ACID; BENZIMIDAZOLE; DERIVATIVES,"An imidazoline, 2-heptadecyl-1-[2-(octadecanoylamino)ethyl]-2- imidazoline (QSI) with -C17H35 as the tail chain length was synthesized, characterized, and studied as corrosion inhibitor for low carbon steel in 15% HCl solution under static and hydrodynamic conditions. Influence of addition of KI, temperature, and chain length of pendant hydrocarbon on inhibition efficiency (eta) was also examined. It is found that, QSI exhibits a mixed type behavior but fairly inhibited the corrosion of low carbon steel in the studied medium. The maximum concentration studied (400 mg/L) afforded eta of <50%. Addition of KI to QSI synergistically enhanced the corrosion inhibition performance of QSI, upgrading the. to approximately 90%. Increase in the system temperature increases the eta of both QSI and QSI + KI. From the variation of eta with temperature and the calculated corrosion kinetic parameters, chemical adsorption is proposed as the adsorption mechanism of the additives. QSI performs better under hydrodynamic condition than static condition eta However, the corrosion resistance of the metal decreases at rotation speed higher than 1000 rpm. Inhibition efficiency of imidazoline decreases as the length of the hydrocarbon pendant chain increases. Imidazoline compounds with -C13H27 and -C15H31 as the length of the pendant group hydrocarbon perform better than QSI with -C17H35.",28,31,2
Corrosion Inhibition,,"Mpelwa, Musa; Tang, Shanfa; Jin, Lijun; Hu, Ruizhi; Wang, Changquan; Hu, Yang",The study on the properties of the newly extended Gemini surfactants and their application potentials in the petroleum industry,Chemical EOR; Gemini surfactant; Interfacial tension; Rheological behavior; Corrosion inhibition,ENHANCED OIL-RECOVERY; ULTRALOW INTERFACIAL-TENSION; CORROSION-INHIBITORS; PERFORMANCE; BEHAVIOR; SPACER; TEMPERATURE; ADSORPTION; STEEL,"In this study, the newly extended Gemini surfactants (EGSs) were studied as potential candidates in the petroleum industry applications. The performances of EGSs with respect to variant spacer lengths were studied through surface tension, conductivity, dynamic light scattering (DLS), interfacial tension, rheological behavior, field emission electron microscopy (FESEM), core flooding, and corrosion inhibition measurements. The surface pressure (pi(CMC)), surface efficiency (pC(20)), critical micelle concentration (CMC), maximum surface excess concentration (Gamma(max)), minimum area per molecule of surfactant at the air-water interface (A(min)), average the degree of counterion binding to micelle (beta), Gibb's free energy of micellization (Delta G(mic)), and Gibb's free energy of adsorption (Delta G(ads)) of the EGSs were determined from surface tension and conductivity data. The results showed that the EGSs exhibited more surface activity properties, low CMCs, and spontaneously adsorbed at the air-water interface and micellized in the bulk aqueous phase. The surfactants reduced the oil-water interfacial tension (IFT) to ultralow values (10(-3) mN/m) at low concentration, and it decreased substantively to very ultralow values (10(-4) mN/m) due to the addition of inorganic salts. Also, they exhibited fascinating viscosifying effect and viscoelastic behavior at the experimental temperatures (30 degrees C-60 degrees C). The rheological behaviors were influenced by the formation of entangled micelles in aqueous solutions. Furthermore, through core flooding, EGS1 increased oil recovery by 12.30% which is an interesting incremental recovery. Besides, the EGSs surfactants showed high anticorrosion efficacy on A3 carbon steel in 1 M HCl aqueous solution and the inhibitive action mechanism was revealed to be by creating a protective film on the carbon steel surface through physisorption. Overall, the surface activity, interfacial activity, rheological behaviors, and anticorrosion property were dependent on the length of the spacer group. The surfactants, particularly EGS1 demonstrated a more promising interfacial activity and rheological behavior for enhanced oil recovery (EOR) in heterogeneity reservoirs as well as a remarkable anticorrosion property.",13,13,1
Other topics ,,"Yang, Erlong; Fang, Yujia; Liu, Yongsheng; Li, Zhengquan; Wu, Jun",Research and application of microfoam selective water plugging agent in shallow low -temperature reservoirs,,ENHANCED OIL-RECOVERY; POROUS-MEDIA; FOAM; PERFORMANCE; FLUID; GEL,,43,42,5
Other topics ,,"Asemani, Morteza; Rabbani, Ahmad Reza",Detailed FTIR spectroscopy characterization of crude oil extracted asphaltenes: Curve resolve of overlapping bands,Petroleum asphaltenes; FTIR spectra; Curve fitting technique; Functional groups; Elemental analysis,DERIVATIVE IR-SPECTRA; CH STRETCHING REGION; CHEMICAL-STRUCTURE; MASS-SPECTROMETRY; STRUCTURAL-CHARACTERIZATION; INFRARED-SPECTROSCOPY; PETROLEUM ASPHALTENES; ATHABASCA ASPHALTENE; MOLECULAR-STRUCTURE; FRACTIONS,"In recent years, characterization of asphaltenes as an appropriate way to deal with their related problems in the oil industry has been received considerable attention. The Fourier-transform infrared (FTIR) analysis, since its appearance in the 1880s, become one of the most applicable techniques to gain the valuable information about characteristics and functional groups of different samples especially petroleum related materials (e.g. asphaltenes). Despite these advantages, this technique suffers from a severe drawback especially in analyzing complex compounds such as asphaltenes. This problem is defined as overlapping related to the functional groups with the near occurrence bands which can hinder thorough qualitative and quantitative analyzing. A considerable number of studies were dedicated to FTIR analysis of asphaltenes, but the curve resolving of petroleum asphaltenes spectra has not yet been extensively studied. In this paper, four asphaltenes extracted from crude oils were analyzed by FTIR and then these spectra were completely resolved. The results, for the first time, provide a deep insight into the functional groups present in asphaltenes and their attaching substitutions. The comprehensive investigation of bands shifting and the relationship of their band area with elemental results reveal that carboxylic acids are linked to both saturate (band at about 1743 cm(-1)) and aromatic compounds (band at about 1698 cm(-1)); however, esters and alcohols (e.g., secondary and tertiary alcohols) are attached to saturated compounds in the studied asphaltenes (band at 1743 cm(-1) for saturated esters and bands at 1347, 1160 and 1110 cm(-1) for saturated alcohols). Ketones occur as diaryl and mixed (1616 and 1685 cm(-1) bands), but ethers appear as alkyl/aryl (1018 cm(-1)). The sulfoxide (1033 cm(-1)), secondary amides (bands at 3239, 1649, 1575 and 1310 cm(-1)), polyaromatic (with different substitutions at region below 900 cm(-1)), phenols (3430 and 1229 cm(-1)) and aliphatic compounds (such as methyl, methylene, and methine in the 1460 and 1375 cm(-1) bands and in the 3850-3000 cm(-1) region) are also present in the studied asphaltenes.",42,42,4
Other topics ,,"Miao, Yanan; Zhao, Chaojie; Zhou, Gang",New rate-decline forecast approach for low-permeability gas reservoirs with hydraulic fracturing treatments,Low-permeability gas reservoirs; Fractured-dominated; Production prediction; Decline model,SHALE GAS; MODEL,"Estimating production in low-permeability gas reservoirs accurately has been of more concern to oil and gas industries in recent years. Until now, various techniques to estimate well production have been developed. Among them, decline curve analysis models have been recognized as the most efficient and easiest approach to be applied. Unfortunately, each decline curve model has its own limitation and will not allow us to forecast production in low-permeability gas reservoirs with confidence. In this paper, firstly, the review of Arps, stretched exponential production decline (SEPD), and Duong methods is conducted explicitly to illustrate the reasons resulted in their limitations. Subsequently, a new empirical decline model with two fitting parameters is developed based on the proposed linear relation of logarithmic production versus the product of square root of time and logarithmic time, which takes the change of decline exponent with production time into account. In addition, a detailed procedure applying this novel decline model for low-permeability gas wells is presented, which is reliable and easy to be utilized. Furthermore, this new model is validated by numerically simulated cases and field observations, which appears good match between forecast rates calculated by this proposed method and numerically simulated rates/field rates. The comparison between this novel method and several traditional methods are further conducted, which indicates that this new approach leads to more reliable forecast than commonly utilized approaches. This work should provide a theoretical guidance to assist analysts in estimating hydrocarbon production rapidly and efficiently in low-permeability reservoirs.",24,26,4
Other topics ,,"Norouzi, Nima; Fani, Maryam; Ziarani, Zahra Karami",The fall of oil Age:A scenario planning approach over the last peak oil of human history by 2040,Peak oil; Oil production; Hybrid foresight model; Oil,ENERGY EFFICIENCY; IRAN,"In the late 50s a debate on the Oil depletion has been started which is continuing to the present day. Campbell largely updated Hubert's model with new reserve resources forecast and estimated that the world's oil production would peak around the 2004-2006 and then would decline over the years. Then was Campbell who proposed the term which was later widely used as the ""The peak Oil"" to define the global maximum of the Oil production Time series. In this paper a scenario planning based on the expert-choices (participated by the OPEC experts and policy makers) combined with the Hubert's forecast method (based on the Monte-Carlo non-linear forecast Regression) is done for the peak-oil forecasting and three high score scenarios have been derived. The ""True me"", the ""feigned sleep"" and the death of the unity in which these scenarios are highly affected by the political environments of each. However, in one of the scenarios because of the tensions in the political environment the peak oil will not occur by 2040 but the other scenarios show that peak oil maybe is sooner than the world expects (the mid-2020s) and energy supply and demand markets must be ready for this phenomena.",23,23,4
Other topics ,,"Pan, Bin; Li, Yajun; Zhang, Mingshan; Wang, Xiaopu; Iglauer, Stefan",Effect of total organic carbon (TOC) content on shale wettability at high pressure and high temperature conditions,,CLAY BOUND WATER; CONTACT ANGLES; SUPERCRITICAL CO2; SPONTANEOUS IMBIBITION; INTERFACIAL-TENSIONS; GAS-STORAGE; PORE-SCALE; OIL-WET; QUARTZ; RESERVOIR,,23,23,3
Other topics ,,"Bemani, Amin; Baghban, Alireza; Mohammadi, Amir H.",An insight into the modeling of sulfur content of sour gases in supercritical region,Sulfur solubility; LSSVM-PSO; ANFIS-PSO; Sour gas; Modeling,HYDROGEN-SULFIDE; ELEMENTAL SULFUR; CARBON-DIOXIDE; PHASE-EQUILIBRIUM; AQUEOUS-SOLUTIONS; PREDICTION MODEL; IONIC LIQUIDS; SOLUBILITY; VISCOSITY; EQUATION,"Sour gas reservoirs are one of the well-known energy re-sources in the world so investigation of their problems especially deposition of sulfur is of interest for chemical and petroleum engineers. Due to this fact, prediction of sulfur solubility in supercritical sour gases, which is known as the most important factor in the deposition of sulfur, is considered as the main aim of the current investigation. In this work, least-squares support vector machine (LSSVM) and adaptive neuro-fuzzy inference system (ANFIS) were coupled with particle swarm optimization (PSO) to estimate sulfur solubility in terms of reservoir pressure, temperature, and composition of sour gas. The ability and potential of proposed algorithms were investigated through 170 experimental data, which are available in literature. Also, the proposed algorithms results were compared with four published methods results to show the great capability of LSSVM-PSO and ANFIS-PSO in the estimation of sulfur solubility. On the other hand, the effectiveness of input parameters was evaluated and it was acclaimed that pressure has the most impact on sulfur solubility in supercritical sour gases.",23,22,3
Other topics ,,"Sadeghinezhad, Emad; Siddiqui, Mohammed Abdul Qadeer; Roshan, Hamid; Regenauer-Lieb, Klaus",On the interpretation of contact angle for geomaterial wettability: Contact area versus three-phase contact line,Wettability; Three-phase contact line; Contact area; Patterned surface; Surface roughness; Contact angle,WETTING BEHAVIOR; SPONTANEOUS IMBIBITION; RESERVOIR ROCKS; YOUNGS EQUATION; NANO-SILICA; OIL-WET; WATER; SANDSTONE; CARBONATE; SURFACES,"Several techniques are available to characterise the wettability of porous rocks wherein the contact angle measurement technique has gained popularity, especially in tight rocks. Recent studies in surface science however raise an important issue on contact angle measurement and its theoretical analysis - whether the contact angle is controlled by the properties of the substrate area underneath the droplet or by the properties of the substrate at the circumference forming the three-phase contact line. This important issue has not been discussed in geomaterial contact angle characterisation despite its significant importance. We, therefore, conducted a series of experiments to study the role of contact area and three-phase contact line on dictating the contact angle. The experiments considered the material heterogeneity (i.e. clay, organic matter, and acrylic), surface roughness and geometry, and its patterns. We also used a new approach using interferometry to investigate the contact angle localisation. The results of this study revealed that the formation of the contact angle is only dictated by the three-phase contact line and not the contact area. No change in contact angle was observed when different materials or surface geometries were introduced under the droplet. The results also suggested that an increase in roughness can lead to erroneous contact angle measurements due to localisation of the contact angle and changes in the three-phase contact line point. The results further showed that the surface pattern plays a major role in contact angle measurement and must be considered if present. Finally, the combined understanding of the results indicated that the current contact angle measurements of geomaterials might carry significant error and that additional methodologies for determining their surface wettability should be used.",16,16,11
Other topics ,,"Suleimanov, Baghir A.; Veliyev, Elchin F.; Azizagha, Aliyev A.",Colloidal dispersion nanogels for in -situ fluid diversion,,PARTIALLY HYDROLYZED POLYACRYLAMIDE; NANOCOMPOSITE HYDROGELS; SWELLING BEHAVIOR; POLYMER; GELATION; GELS,,15,15,2
Other topics ,,"Song, Shuai-Bing; Liu, Jiang-Feng; Ni, Hong-Yang; Cao, Xu-Lou; Pu, Hai; Huang, Bing-Xiang",A new automatic thresholding algorithm for unimodal gray -level distribution images by using the gray gradient information,Automatic thresholding; Gray-level distribution; Image segmentation; Gray gradient; Porosity,PORE STRUCTURE; PREDICTION; ENTROPY,"Automatic thresholding is an important image-processing technique that extracts target regions of interest from background based on the gray-level information. There are many methods that have been proposed to provide an appropriate threshold value for an image with an evident bimodal gray-level histogram. Nevertheless, most of these methods can not accurately and efficiently segment an image with a unimodal gray-level distribution. In this study, a new approach of determining the optimal threshold is proposed to address the above issues by introducing the gray gradient of pixels. The gray gradient value of each pixel is calculated by performing an element multiplication with the image patch and the Sobel operator masks. Then, the gray gradient distribution is obtained on the basis of the results of statistical averaging the gray gradient values of the pixels with different gray-levels. By analysing the morphology of the gray gradient distribution histogram, the optimal threshold for image segmentation is obtained. Furthermore, several test images with unimodal gray-level distributions are segmented by other algorithms, such as the Otsu algorithm, MaxEntropy algorithm and Valley-Emphasis algorithm, to assess the performance of our proposed algorithm. In addition, conventional physical mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) are used to test the porosity of the imaged samples, to further verify the accuracy of the new algorithm. The comparison results indicate that the proposed algorithm demonstrates a better segmentation performance over those of the other methods for an image with a unimodal gray-level distribution and results in a porosity that is in accordance with that of the MIP and NMR test.",14,14,6
Other topics ,,"Safaei, Ali; Esmaeilzadeh, Feridun; Sardarian, Alireza; Mousavi, Seyedeh Maryam; Wang, Xiaopo","Experimental investigation of wettability alteration of carbonate gas-condensate reservoirs from oil-wetting to gas-wetting using Fe3O4 nanoparticles coated with Poly (vinyl alcohol), (PVA) or Hydroxyapatite (HAp)",Carbonate gas-condensate reservoirs; Fe3O4 NPs; HAp; PVA; Wettability alteration; Imbibition and fluid flow test; Tight rock,RECOVERY; SILICA; WATER; NANOFLUID; ROCKS,"Wettability alteration near-wellbore region in a gas-condensate reservoir is an effective way to reduce liquid blockage. To this end, Fe3O4 NPs (nanoparticles) first synthesized by the co-precipitation method and then coated with Poly (vinyl alcohol) (PVA) and or Hydroxyapatite (HAp). Besides, the synthesized NPs and two core-shell nanostructures were characterized by the Field Emission Scanning Electron Microscopy (FE-SEM), X-ray diffraction (XRD) analysis and the Fourier-Transform Infrared spectroscopy (FTIR). The synthesized NPs coated with PVA and or HAp were then exploited to coat on the surface of carbonate rocks by the dip-coating method in the course of 48 h. Next, the contact angle on the surface of carbonate rocks in condensate/air and water/air systems was measured in a wide range of pressure from 1 to 40 bar. In contact angle measurements, the effect of different parameters including the NPs concentration, temperature and pressure was examined. Also, the spontaneous imbibition and fluid flow tests were fulfilled in the artificial core-plugs before and after the wettability alteration. The results show that the imbibition rate of water and condensate noticeably reduced after the wettability alteration by both core-shell nanostructures. Additionally, the pressure drop and breakthrough time significantly diminished after the wettability alteration by both core-shell nanostructures. Moreover, coating of the two core-shell nanostructures on the surface of carbonate rocks was confirmed by the Scanning Electron Microscope (SEM) analyses. Furthermore, based on contact angle measurements between gas-condensate and the carbonate artificial core-plug surface after the treatment with the Fe3O4-PVA and or Fe3O4-HAp nanostructures, the optimum concentrations of Fe3O4/PVA and Fe3O4-HAp nanostructures in distilled water were 0.5 wt % and 0.4 wt %, respectively, to attain the greatest wettability alteration from oil-wetting to preferentially gas-wetting. In this condition, the contact angle between gas-condensate and the treated carbonate artificial core-plug surface by the Fe3O4/PVA and or Fe3O4-HAp nanostructures shifted from 10 degrees to 66 degrees and or 90 degrees, respectively. Also, the contact angle between water and the treated carbonate artificial core-plug surface using the Fe3O4/PVA and or Fe3O4-HAp NPs altered from 62 degrees to 107 degrees and or 116 degrees, respectively. Generally, the iron oxide NPs coated with HAp significantly improved the wettability of the rock samples from oil-wetting to gas-wetting as compared to those coated with PVA. Finally, the spontaneous imbibition experiments were carried out in the tight rock before and after the wettability alteration. Results demonstrated that the imbibition rate of gas-condensate decreased about 63 and 64% after the wettability alteration by the Fe3O4-PVA/DW and Fe3O4-HAp/DW nanofluids with the optimum concentration of 0.5 and 0.4 wt %, in sequence. Additionally, experimental results of the fluid flow tests at high pressures showed that the pressure drop reduced 34 and 32% after the wettability alteration for both Fe3O4-PVA/DW and Fe3O4-HAp/DW nanofluids, respectively.",14,15,4
Other topics ,,"Majeed, Talha; Solling, Theis, I; Kamal, Muhammad Shahzad","Foamstability: The interplay between salt-, surfactant- and critical micelle concentration",Foam; CMC; AOS; EOR; Salinity,ALPHA-OLEFIN SULFONATE; FOAM FILMS; AQUEOUS-SOLUTIONS; GAS DISPERSION; OIL; ADSORPTION; STABILITY; FLOW; ELECTROLYTES; PERMEABILITY,"It is central to understand the underlying factors that affect the generation and stabilization of foam. Nevertheless, reports on how foam stability is impacted by surfactant concentration, electrolyte concentration, and electrolyte nature are ambiguous. This paper summarizes the foaming properties below and above the critical micelle concentration (CMC) at various electrolyte concentrations. The commonly used surfactant, alpha olefin sulfonate (AOS), was used along with NaCl in a range of concentrations. The foam height, foam volume stability, bubble count, and foam structure were studied to determine the foam behavior at given conditions. The optimum surfactant concentration for the formation of a stable micellar film was found to be just above the CMC value and the foam stability on the addition of salts is related to the surfactant concentration. There exists another critical concentration (not CMC) that is important to determine the impact of salts on the stability of the foam. The addition of NaCl does not have the same impact below and above this critical concentration. If the concentration of surfactant is below the critical concentration, addition of NaCl reduces the half-life and foam stability. However, at higher surfactant concentrations, the presence of NaCl improves the half-life and foam stability. This study clarifies the ambiguities that are present in the literature pertaining to the effect of salt on foam stability and foaming properties.",13,13,7
Other topics ,,"Alvi, Muhammad Awais Ashfaq; Khalifeh, Mahmoud; Agonafir, Mesfin Belayneh",Effect of nanoparticles on properties of geopolymers designed for well cementing applications,Well cementing; Geopolymer; Rock-based; Nanoparticles,INTEGRITY; PERMEABILITY; DURABILITY; STRENGTH; GAS; OIL,"Recently the focus of the oil and gas industry is to find the alternative material for well barrier applications. Geopolymers are among the suggested materials, which could be used in the future to solve the well integrity issues rooted by the properties of Portland cement. Previous study with rock-based geopolymer indicates the potential of geopolymer to be used as a barrier material. However, there are still some shortcomings of geopolymer material, which need to be improved to make it a possible option for well cementing applications. This study aims to improve the properties of the geopolymer. Al2O3 and multi walled carbon nanotubes functionalized with hydroxyl group (MWCNT-OH) nanomaterials were used to study their effect on rheological, filtration loss, and mechanical properties of the geopolymer. Moreover, the effect of nanomaterials on the setting time and microstructure of the geopolymer has been studied. Results obtained from this work indicate that, nanomaterials-based geopolymers have better mechanical properties and setting time compared to the neat geopolymer. Addition of nanomaterials produced a more ductile structure with higher compressive and tensile strengths. Microstructure and element analysis confirmed the formation of a more compact and dense structure with the presence of MWCNT-OH and Al2O3 throughout the structure of the geopolymer.",13,13,6
Other topics ,,"Li, Zerui; Kang, Yu; Feng, Deyong; Wang, Xing-Mou; Lv, Wenjun; Chang, Ji; Zheng, Wei Xing",Semi-supervised learning for lithology identification using Laplacian support vector machine,Lithology identification; Semi-supervised learning; Laplacian support vector machine; Depth similarity,SEISMIC ATTRIBUTES; CLASSIFICATION; LITHOFACIES; PREDICTION; LOGS,"Lithology identification is a fundamental task in well log interpretation. Considering the presence of substantial unlabeled data in the field of petroleum exploration, this paper investigates the semi-supervised learning method for lithology identification, and proposes a semi-supervised lithology identification workflow. In the workflow, the Laplacian support vector machine is employed to achieve semi-supervised learning. The feature similarity and depth similarity are introduced to reveal the data distribution characteristic, thus enabling us to elevate the classification performance of the Laplacian support vector machine dealing with the issue of lacking labels. Considering the well logging dataset without label, K-means clustering is used to select the k well logging samples that should be labeled by experts, based on which Laplacian support vector machine algorithm can be then conducted. The proposed method is compared with the supervised method (e.g., support vector machine) that excludes the unlabeled data and the semi-supervised method without considering the depth similarity. The comparison experiments are conducted on four datasets that are collected from the Jiyang Depression, Bohai Bay Basin, China. The experimental results show that the utilization of unlabeled data can improve identification performance, especially that of minority lithology classes. It is also verified that the information provided by feature similarity and depth similarity are helpful for lithology identification.",12,12,7
Other topics ,,"Tugan, Murat Fatih; Weijermars, Ruud",Improved EUR prediction for multi-fractured hydrocarbon wells based on 3-segment DCA: Implications for production forecasting of parent and child wells,Production forecasts; 3-Segment DCA; Parent wells; Child wells; EUR prediction; Eagle Ford,RATE-DECLINE ANALYSIS; SHALE GAS PROJECTS,"A substantial number of methods has been proposed as part of the quest for better production forecasting and hence more accurate reserves estimations, especially for multi-fractured shale wells producing either gas or liquids (or both). However, none of the current methods stand out to be robust and practical enough to give reliable results for all field cases. The current study proposes a novel 3-segment decline curve analysis (DCA) method that uses the unique flow regime sequence of shale wells to delineate the periods for each of the three segments used in the DCA. The production data of 6 Eagle Ford wells (4 parents and 2 infills) was modeled with over 95% history matching quality. The proposed method, validated using hind-casting, proved to be extremely successful in predicting the production of the child wells, when production data is available from either parent wells or first generation child wells. The proposed method is based on the widely-used Arps' equation and honors the principal flow regimes recognized in recent studies. The improved history matching capability of the proposed method leads to a much reliable production forecast. Hence, the uncertainty in the reserves estimations significantly reduces, which is why this study argues for conclusive categorization of the estimated reserves based on type curves of later generation parent wells as P90 (proved reserves) rather than P50 (proved plus probable reserves).",12,12,1
Other topics ,,"Essa, Khalid S.; Geraud, Yves",Parameters estimation from the gravity anomaly caused by the two-dimensional horizontal thin sheet applying the global particle swarm algorithm,,SIMPLE GEOMETRIC-STRUCTURES; OPTIMIZATION METHOD; NORTHERN CAMEROON; STRUCTURAL STYLES; BASIN; INVERSION; CHAD,,12,12,0
Other topics ,,"Li, Cunbao; Wang, Jun; Xie, Heping",Anisotropic creep characteristics and mechanism of shale under elevated deviatoric stress,Anisotropic creep; Shale; Bedding layer orientation; Empirical creep law; Basic creep patterns,BEHAVIOR; DEFORMATION; DAMAGE; STATE,"The time-dependent characteristics of anisotropic shale are important for accurately predicting a reservoir's behavior over a long period of time. To study the transverse isotropic creep characteristics of shale, a series of shale creep tests using specimens with 4 different bedding layer orientations (0 degrees, 45 degrees, 75 degrees and 90 degrees) under multiple levels of deviatoric stress were conducted. The experimental results indicate that shale presents creep behavior even when the deviatoric stress is relatively low. Anisotropy has significant influences on the creep deformation and steady creep rate. When the bedding plane inclined angle is 45 degrees and under the same deviatoric stress, the creep deformation and steady creep rate are the highest, while the smallest creep deformation and steady creep rate are generated when the bedding plane orientation is 90 degrees. Time-dependent deformation appears the tertiary creep stage when the deviatoric stress is crack damage threshold, which implies that crack damage stress can be regarded as the shale's long term strength. The steady creep rate increases exponentially with increasing deviatoric stress as the stress is larger than the crack initiation threshold. The rationality of the empirical creep law is evaluated. It is concluded that the empirical creep model can only fit the existing creep data, but it is almost impossible to predict the creep deformation. The mechanism for generating anisotropic creep behavior of shale is analyzed in detail, and three basic creep patterns for shale are proposed based on the action mechanism of the stress tensor components. A general methodology for proposing the anisotropic creep model is finally suggested.",10,10,10
Other topics ,,"Wang, Jie; Zhou, Fujian; Bai, Hao; Li, Yafei; Yang, Hong",A Comprehensive method to evaluate the viscous slickwater as fracturing fluids for hydraulic fracturing applications,,FRICTION REDUCER; WATER-USE; GAS,,10,10,7
Other topics ,,"Luo, Cong; Ba, Jing; Carcione, Jose M.; Huang, Guangtan; Guo, Qiang",Joint PP and PS pre-stack AVA inversion for VTI medium based on the exact Graebner equation,Pre-stack AVA inversion; Shale reservoir; VTI medium; Anisotropy parameters; Exact reflection coefficient; Multi-parameter,WAVE-FORM INVERSION; TRANSMISSION COEFFICIENTS; REFLECTION COEFFICIENTS; PROPERTY ESTIMATION; SCATTERING MATRIX; SEISMIC-WAVES; APPROXIMATION; PARAMETERS; AMPLITUDE; RESERVOIR,"Unconventional hydrocarbon reservoirs, such as shale rocks, are generally transversely isotropic with a vertical axis of symmetry (VTI). The identification of sweet spots in these reservoirs, which must take into account this anisotropic character, can be performed with amplitude variations with offset/angle (AVO/AVA) inversion. However, most approaches use the Ruger reflection approximate equation as forward modeling, which has low accuracy at moderate to large angles, where the seismic gathers contain most of useful information on anisotropy parameters. In this paper, we propose an exact-equation-based seismic pre-stack AVA inversion for stable estimations of anisotropy parameters in VTI media. A linear inversion scheme is adopted to save computational time and the Frechet derivatives, the key factors of the scheme, are derived here. To improve the stability and accuracy, the PP data inversion is extended to joint PP and PS inversion, termed joint exact-Graebner-based prestack inversion (JEGI). It is applied to both synthetic and field multi-component seismic data, showing its feasibility and effectiveness.",10,10,2
Other topics ,,"Baouche, Rafik; Sen, Souvik; Debiane, Kahina; Ganguli, Shib Sankar","Integrated reservoir characterization of the Paleozoic and Mesozoic sandstones of the El Ouar field, Algeria",Depositional environment; Petrophysics; Triassic; Paleozoic; El Ouar; Berkine basin,MARGINAL GONDWANA BASIN; TRACE FOSSILS; BERKINE BASIN; PERMEABILITY DETERMINATION; BARAKAR FORMATION; GHADAMES BASIN; OURHOUD FIELD; LOG DATA; FACIES; RESISTIVITY,"This study presents the interpretation of depositional environment and petrophysical properties of Mesozoic and Paleozoic reservoirs from the south-eastern Berkine Basin, Algeria by integrating core analyses and geophysical logs. Sedimentary structures and ichnofossils identified from 100 m of recovered cores have been interpreted to characterize the depositional settings of the studied reservoirs. During the mid-late Triassic, fluvial to marginal marine processes deposited the TAGS and TAGI reservoirs, while the Palaeozoic megasequences are characterized by shallow marine reservoirs (tidal bars and foreshore deposits) interbedded with thin marine shales. Porosity and water saturation have been estimated from geophysical logs and calibrated with core-based laboratory measurements. An empirical relationship between core porosity and permeability has been established for the El Ouar area and the same has been employed to generate a continuous and confident permeability profile against the target reservoir formations. Petrophysical characterization indicates a higher porosity and permeability in Triassic and Carboniferous sandstones than the Devonian F6 members. Triassic TAGS and TAGI sandstones possess the highest reservoir qualities in the El Ouar field. The Thorium and Potassium content available from spectral gamma-ray data have been utilized to identify the clay types associated with various sandstone reservoirs (Illite in Triassic sandstone, Kaolinite in Carboniferous units, mixed clay and Th bearing heavy mineral dominance in Devonian units). The study will be helpful for understanding of hydrocarbon resource potential and subsequent production planning in the study area.",10,10,0
Other topics ,,"Tian, Haiyang; Quan, Hongping; Huang, Zhiyu",Investigation on rheological properties and thickening mechanism of a novel thickener based on hydrophobically associating water-soluble polymer during the acid rock reaction,Thickener; Hydrophobically associating polymer; Acid rock reaction; Thickening mechanism,SITU-GELLED ACIDS; VISCOELASTIC SURFACTANT; COPOLYMERS,"A novel betaine-type hydmphobically associating polyacrylamides (CPAM) consisting of acrylamide (AM), 1-carboxy-N, N'-dimethyl N (3-methyl-acrylamidopropyl) ethanaminium (CBMAA-1), Methacrylatoethyl trimethyl ammonium chloride (DMC) and N, N'-dimethyl octadecyl allyl ammonium chloride (DOAC) was synthesized, which was characterized by FT-IR and 1 H NMR spectra. Rheological properties of CPAM acid solutions were studied via six-speed rotational viscometer and HAAK MARSIII Rheometer. Moreover, the thickening mechanism of CPAM acid solutions during the acid rock reaction was investigated by simulating the acid rock reaction process. Results showed that CPAM acid solutions demonstrated good thickening ability from low apparent viscosity to high apparent viscosity during the acid rock reaction. Meanwhile, CPAM spent acid solutions showed good shear resistance, viscoelasticity and high temperature resistance, showing great potential as a self-diverting acid solution for carbonate formation. Besides, it was found that the main factor of affecting the thickening of the CPAM acid solutions was the concentration of CaCl2.",9,9,17
Other topics ,,"Morozov, Anton D.; Popkov, Dmitry O.; Duplyakov, Victor M.; Mutalova, Renata F.; Osiptsov, Andrei A.; Vainshtein, Albert L.; Burnaev, Evgeny, V; Shel, Egor, V; Paderin, Grigory, V",Data-driven model for hydraulic fracturing design optimization: focus on building digital database and production forecast,Fracture; Machine learning; Predictive modeling; Data collection; Design optimization; Hydraulic fracturing; Production forecast; Gradient boosting; Decision tree; Data analytics; Data preprocessing; Feature analysis,REGRESSION; MECHANICS; TIME,"Growing amount of hydraulic fracturing (HF) jobs in the recent two decades resulted in a significant amount of measured data available for development of predictive models via machine learning (ML). In multistage fractured completions, post-fracturing production analysis (e.g., from production logging tools) reveals evidence that different stages produce very non-uniformly, and up to 30% may not be producing at all due to a combination of geomechanics and fracturing design factors. Hence, there is a significant room for improvement of current design practices. We propose a data-driven model for fracturing design optimization, where the workflow is essentially split into two stages. As a result of the first stage, the present paper summarizes the efforts in the creation of a digital database of field data from several thousands of multistage HF jobs on vertical, inclined and near-horizontal wells from circa 20 different oilfields in Western Siberia, Russia. In terms of the number of points (fracturing jobs), the present database is a rare case of a representative dataset of about 5000 data points, compared to typical databases available in the literature, comprising tens or hundreds of points at best. Each point in the data base contains the vector of 92 input variables (the reservoir, well and the frac design parameters) and the vector of production data, which is characterized by 16 parameters, including the target, cumulative oil production. The focus is made on data gathering from various sources, data preprocessing and development of the architecture of the database as well as solving the production forecast problem via ML. Data preparation has been done using various ML techniques: the problem of missing values in the database is solved with collaborative filtering for data imputation; outliers are removed using visualization of cluster data structure by t-SNE algorithm. The production forecast problem is solved via CatBoost algorithm. Prediction capability of the model is measured with the coefficient of determination (R-2) and reached 0.815. The inverse problem (selecting an optimum set of fracturing design parameters to maximize production) will be considered in the second part of the study to be published in another paper, along with a recommendation system for advising MSC and production stimulation engineers on an optimized fracturing design.",9,9,3
Other topics ,,"Meira, Luis A. A.; Coelho, Guilherme P.; da Silva, Celmar G.; Abreu, Joao L. A.; Santos, Antonio A. S.; Schiozer, Denis J.",Improving representativeness in a scenario reduction process to aid decision making in petroleum fields,Representative model selection; Decision analysis under uncertainty; Uncertain geological models; Optimization,PRODUCTION STRATEGY; UNCERTAINTY; MODELS; INTEGRATION,"This paper presents an extension of the RMFinder technique, previously proposed for scenario reduction within the decision-making process in oil fields. As there are several uncertainties associated with this process, a large number of scenarios should be analyzed so that high-quality production strategies can be defined. Such broad analysis is very time-consuming so techniques to automatically identify representative models (RMs) are particularly relevant. In this context, traditional approaches are often based on the selection of three representative models: pessimistic, optimistic and most likely, according only to the most relevant variable of the problem. Here, the RMs are selected to (i) guarantee representativeness in tens of variables of the problem simultaneously; (ii) maintain the original distribution of the uncertain variables; (iii) preserve a good distribution in the scatterplots (cross-plots) of the main output variables of the problem; and (iv) allow a specialist to adjust the relative importance among the considered variables. Therefore, we modeled such a scenario reduction problem as a multi-criteria optimization problem assisted by an expert. We applied the proposed methodology to the OLYMPUS benchmark model and to two reservoir models based on real-world Brazilian fields: (i) UNISIM-I-D, a benchmark case based on the sandstone Namorado field; and (ii) UNISIM-II-D, a benchmark case based on a highly fractured pre-salt carbonate reservoir. In each experiment, the number of RMs varied from 1 to 25. We verified that, the larger the number of RMs, the smaller the bias will be with respect to the risk curves. The obtained sets of RMs were analyzed by petroleum engineers and considered appropriate for the problems studied, and they were adopted as the standard models in the following steps of the decision-making process to define the production strategies under uncertainties.",9,9,1
Other topics ,,"Li, Kewen; Zhou, Guangyue; Yang, Yaozhong; Li, Fulai; Jiao, Zonghao",A novel prediction method for favorable reservoir of oil field based on grey wolf optimizer and twin support vector machine,Prediction for favorable reservoir; Multi-classification twin support vector machine; Hybrid parameter; Grey wolf optimizer,CLASSIFIER,"Most of the domestic oil fields are in the middle or late stage of exploration and development, and there are fewer and fewer oil fields that can be easily discovered. Proved reserves are dominated by concealed reservoirs, but concealed reservoirs are difficult to find. The prediction for favorable reservoir is a key in the process of exploration and development, but the traditional prediction methods of favorable reservoir rely on analysis of geological prospectors according to commonly used seismic attributes, which leads to low exploration efficiency. To improve effectiveness of the prediction for favorable reservoir, this paper introduces a multi-classification Twin Support Vector Machine (MTWSVM) method suitable for the case of insufficient reservoir label samples caused by fewer drilling data, which is used to identify favorable reservoirs. Since each sub-classifier of existing MTWSVM uses the same penalty parameters and kernel parameters, ignoring the differences between different classes, it cannot play the best role of each sub-classifier. We propose a multi-classification Twin Support Vector Machine based on hybrid parameters (HP-MTWSVM). This algorithm selects appropriate parameters for different sub-classifiers, maintaining the diversity of classifiers. Twin Support Vector Machine (TWSVM) is facing the problem that its parameters are difficult to be appointed. Additionally, HP-MTWSVM algorithm introduces a large number of parameters. This paper further proposes a hybrid parameter multi-classification Twin Support Vector Machine based on Grey Wolf Optimizer (GWO-HP-MTWSVM). This method uses GWO to optimize the parameters of HP-MTWSVM. Experiments show that the prediction accuracy of GWO-HP-MTWSVM is more than 64%, better than that of manual prediction in complex concealed reservoirs. The model can help geological exploration personnel quickly delineate favorable areas, provide basis for accurately drilling wells and avoid waste of resources caused by empty reservoirs.",9,9,1
Other topics ,,"Zhao, Shuai; Sun, Youhong; Lu, Xiaoshu; Li, Qiang",Energy consumption and product release characteristics evaluation of oil shale non-isothermal pyrolysis based on TG-DSC,Oil shale; TG-DSC; Pyrolysis characteristics; Product release characteristic index; Heating rate and atmosphere,CO2 GASIFICATION EXPERIMENTS; BIOMASS CHAR PARTICLES; THERMOGRAVIMETRIC ANALYSIS; COAL; COMBUSTION; KINETICS; MODEL,"Thermogravimetric-Differential Scanning Calorimetry Analysis (TG-DSC) was applied to study non-isothermal pyrolysis characteristics of oil shales, such as the starting point, stability, pyrolysis interval and product release using Fuyu and Huadian oil shale samples. Results show that with the increase of heating rate, oil shale pyrolysis moves to higher temperature zone. This trend is more noticeable at higher oil content. The pyrolysis stability of the oil shale is related to oil content and pyrolysis atmosphere. The higher the oil content, the more stable the pyrolysis of the oil shale. Under nitrogen atmosphere, the pyrolysis interval of oil shale is more concentrated, air prolongs the pyrolysis interval, and the pyrolysis stability index decreases. In addition, the increase of heating rate favours the release characteristic index of the product, which is not practically affected by oil content. The release characteristic indices of pyrolysis products from oil shale under nitrogen atmosphere are higher than those under air atmosphere. The optimum heating rate that produces the highest oil product yield for pyrolysis progress of Huadian oil shale is 20 degrees C/min, and Fuyu oil shale is 40 degrees C/min.",8,8,17
Other topics ,,"Mardalizad, Aria; Saksala, Timo; Manes, Andrea; Giglio, Marco",Numerical modeling of the tool-rock penetration process using FEM coupled with SPH technique,Drilling; Punch penetration test (PPT); Coupled FEM-SPH; KCC,PARTICLE HYDRODYNAMICS; FINITE-ELEMENTS; STRENGTH; INDENTATION; PERFORMANCE; BRITTLE; INDEXES; FIESOLE; SOLIDS; DAMAGE,"The numerical simulation of penetration into rock is an important tool to gain insights into rock drilling mechanisms, since it can be exploited as an alternative to the expensive field testing. This research aims to present an innovative computer simulation of rock penetration process on the basis of the finite element method (FEM) coupled with smoothed particle hydrodynamics (SPH). An advanced material model, namely the Karagozian and Case Concrete (KCC) model, was employed for this purpose. The Punch Penetration test (PPT) was carried out on a medium strength sandstone for validating the numerical method. The comparison of the numerical and experimental results obtained concluded that the FEM coupled with SPH method in conjunction with the fully calibrated KCC material model is a reliable method for the study of rock penetration due to its ability to deal with large deformations and its realistic constitutive modeling. The modeling approach was finally applied to estimate the required force to penetrate an offshore reservoir rock block under the in-situ confining pressure with a double conical tool up to 5 mm depth. The effective stresses in sedimentary basins of Agosta and Dosso Campus at a depth of 3000 m below the seabed are considered as the confining pressures of this study.",8,8,7
Other topics ,,"Ni, Xiaoming; Zhao, Zheng; Wang, Yanbin; Wang, Li","Optimisation and application of well types for ground development of coalbed methane from no. 3 coal seam in shizhuang south block in Qinshui basin, Shanxi province, China",Optimisation of well types; Productivity; Gas content; Permeability,PRODUCTIVITY,"Determining the optimal well types for ground development of coalbed methane (CBM) is a significant premise from which to reduce construction risk during a project and improve CBM production efficiency. Based on Langmuir isotherm adsorption theory and Darcy's law, the research established mathematical models for productivity of vertical wells and stage-fractured horizontal wells, respectively. In combination with the economic evaluation model, the research proposed an optimisation method for CBM wells through productivity prediction, evaluation of comprehensive economic benefit, and well-type determination. Then, the method was verified based on practical reservoir conditions and CBM production of the developed wells in middle and south of Qinshui Basin (Shanxi Province, China). Meanwhile, charts of CBM production under influences of gas content and post-fracturing permeability using vertical wells and stage-fractured horizontal wells, respectively. The results indicate that, in the Shizhuang south block, when the gas content is less than 10 m(3)/t, CBM wells are not recommended; If the gas content is between 10 and 12 m(3)/t, stage-fractured horizontal wells can be constructed in areas where post-fracturing permeability can exceed 1.27 x 10(-3)mu m(2), faults and collapse columns were not developed, and hydrogeological conditions were not complicated; If the gas content is between 12 and 15 m(3)/t, stage-fractured horizontal wells can be constructed except in areas of mylonite coal; For reservoirs with gas contents between 15 and 18 m(3)/t, stage-fractured horizontal wells are preferred, and vertical wells can be considered in areas where post-fracturing permeability can exceed 0.91. 10 3 mu m(2), faults and collapse columns were not developed; In the case that the gas content exceeds 18 m(3)/t, both types of wells can be constructed, except in areas of mylonite coal. The results allow us to select a suitable method for selecting CBM well types under different reservoir conditions.",8,8,6
Other topics ,,"Male, Frank; Duncan, Ian J.",Lessons for machine learning from the analysis of porosity-permeability transforms for carbonate reservoirs,Data analysis; Reservoir characterization; Permeability prediction,CLASSIFICATION; ROCK,"Prediction of permeability is one of the most difficult aspects of reservoir characterization because permeability cannot be directly measured by current well logging technology. This is particularly challenging for carbonate rocks. Machine learning (ML) and robust multivariate methods have been developed that have been used in many fields of study to make accurate estimators for variables of interest from both large and small datasets. ML has been criticized for utilizing approaches that are typically not interpretable. That is, it is not clear how the answers are arrived at and what aspects of input data may be resulting in inaccurate results. The current study uses a number of the mathematical algorithms that operate inside ML modules. It applies them to developing porosity-permeability transforms, with or without rock types, to two well-characterized data sets for carbonate reservoirs. One data set is from Jerry Lucia's 1995 study of carbonate rock types, and the other is from a study of the Seminole, West Texas, San Andres Unit. This study of statistical analysis of porosity-permeability transforms includes: transforming the data to normal distributions; performing cross-validation blind testing; and detecting heteroscedasticity by creating plots of residuals. Heteroscedastic data (populations with variable variance) may have an adverse impact on ML algorithms such as Random Forests (RF). We find that including lithofacies information does not greatly improve porosity-permeability transforms. We also propose a number of strategies to make ML analyses of reservoir (and other geosciences) data sets more robust and accurate.",8,8,2
Other topics ,,"Kim, Min; Shin, Hyundon",Machine learning -based prediction of the shale barrier size and spatial location using key features of SAGD production curves,,ASSISTED-GRAVITY-DRAINAGE; STEAM-CHAMBER; RESERVOIR PARAMETERS; NEURAL-NETWORKS; INTEGRATION; SIMULATION; INSIGHTS; DESIGN; GROWTH; MODEL,,8,8,2
Other topics ,,"Liu, Zhida; Sun, Yonghe","Characteristics and formation process of contractional deformation bands in oil-bearing sandstones in the hinge of a fold: A case study of the Youshashan anticline, western Qaidam Basin, China",Deformation bands; Compactional shear bands; Qaidam basin; Oil-bearing sandstones; Fluid flow,CENOZOIC TECTONIC EVOLUTION; ENHANCED COMPACTION BANDS; FLUID-FLOW; POROUS SANDSTONES; NAVAJO SANDSTONE; DAMAGE ZONES; SHEAR BANDS; ALTYN-TAGH; FAULT; PERMEABILITY,"The deformation bands in oil-bearing sandstones in a thrust fault-related fold were studied. The outcrop is exposed in the hinge of the Youshashan anticline. The deformation bands are compactional shear bands (CSBs), which are characterized by low net shear displacement (S) and compaction (C) ratios and by conjugate networks. The kinematics of the deformation bands are the result of the combined effects of shear and compaction, in which shear played a dominant role and was accompanied by additional compaction. CSBs are identified in two sets, including Dl CSBs that were cut by D2 CSBs. The CSBs formed under a contractional regime due to regional shortening and are oriented approximately in the NE-SW direction. The time of formation of the Dl CSBs (NNE-SSW-striking and E-W-striking) is consistent with or slightly later than the formation of the Youshashan anticline. At the beginning of the anticline formation, the Dl CSBs formed under a strike-slip regime due to the deeper burial depths (approximately 2.5 km). With the evolution of the anticline, the burial depths gradually become shallower. The D2 CSBs formed a NW-SE-striking direction under a thrust-fault regime. The porosities of the contractional Dl and D2 CSBs that developed in oil-bearing sandstones are 14-19.7% and 11-18% lower than those of the host rock, respectively. The permeability reduction for the Dl and D2 CSBs are between 1 and 2 orders of magnitude. Our findings suggest that the stress state changed during the formation uplift in the contractional regime, from a strike-slip stress state to a thrust-fault stress state, forming CSBs with low S/C ratios. The CSBs have low porosity and small pore space for hydrocarbon storage, and thus, the oil-bearing properties of the CSBs are less favorable than those of the host rock. Nevertheless, the oil saturations in the CSBs are 15.7-47.9% higher than those in the unformed oil-bearing sandstones.",8,8,1
Other topics ,,"Wanderley Neto, Alcides Oliveira; da Silva, Valdic Luiz; Rodrigues, Daniela Venancio; Ribeiro, Lais Sibaldo; Nunes da Silva, Daniel Nobre; de Oliveira Freitas, Julio Cesar",A novel oil-in-water microemulsion as a cementation flushing fluid for removing non-aqueous filter cake,Cleanup fluid; Filter cake; Cement slurry; Surfactants; Microemulsions,PHASE-BEHAVIOR; SYSTEMS; WETTABILITY; SURFACTANTS; CMC,"Drilling fluid removal is an important step for attaining successful cementing operations, however mud removal composition have not kept up with the increasing complexity of drilling fluid chemistry. For this reason, this work developed a novel cementation flushing fluid with high efficiency, capacity of wettability inversion and chemical properties compatible with the cement slurry. The novel preflush is an oil-in-water microemulsion system formulated with cationic surfactant (DAC) and different aqueous phases. The systems were characterized by rheology, surface tension, droplet diameter, filter cake removal efficiency, wettability, fluid compatibility test and by the influence of pre-flush on the performance of cement slurries. The system with 11.6% of C/S, 2.4% of oil phase and 86% of aqueous phase presented 100% removal efficiency, changed the rock wettability and was compatible with the cement, showing that the system developed presents an excellent and environmentalfriendly alternative flushing fluid.",8,8,1
Other topics ,,"Gao, Tao; Zhao, Dong; Wang, Chen; Feng, Zengchao",Energy variation in coal samples with different particle sizes in the process of adsorption and desorption,Adsorption; Desorption; Particle size; Temperature; Energy variation,CARBON-DIOXIDE ADSORPTION; GAS DESORPTION; METHANE; DEFORMATION; PRESSURE; CH4; CO2,"The study of energy variation rules in the process of gas adsorption and desorption in coal is important to predict mine outburst disasters. In this study, an adsorption-desorption experimental device was developed and used to evaluate six coal samples of various particle sizes under different pressure conditions. Temperature was measured in real-time throughout the process. The rate of temperature change, maximum temperature variation, and adsorption quantity increased with particle size and an increase in equilibrium pressure. There is a positive linear relationship between adsorption quantity and temperature variation. This study focused on energy variation during adsorption and desorption. The results showed that the smaller the coal particle size, the larger the reduction in surface free energy and the change in heat. With an increase in equilibrium pressure, the rate of reduction in the surface free energy slows gradually, indicating that there is a non-uniform adsorption potential field on the surface of coal. By comparing the difference of temperature and heat data between a columnar coal sample and a granular coal sample in the process of adsorption and desorption, it can be concluded that the surface free energy is converted into heat and deformation energy in the adsorption process, and the deformation energy is converted into heat energy in the desorption process.",7,7,15
Other topics ,,"Li, Huan; Yang, Chunhe; Ma, Hongling; Shi, Xilin; Zhang, Haina; Dong, Zhikai",A 3D grain-based creep model (3D-GBCM) for simulating long-term mechanical characteristic of rock salt,Rock salt; Creep damage; Particle Flow Code; Exponential function model,BONDED-PARTICLE MODEL; ENERGY-STORAGE; LOADING RATE; GAS-STORAGE; BEHAVIOR; DAMAGE; DEFORMATION; RHEOLOGY; CAVERNS; CALIBRATION,"A 3D micro-creep model based on the grain-based structure and the framework of the Particle Flow Code (PFC) approach is proposed. Simultaneously, a Voronoi polyhedral technique is employed to approximatively construct the grain structure of the real rock salt. Based on literature research, an exponential attenuation mode controlled by the temperature and stress-level is assumed to characterize variation behavior of the parallel bond diameter (PBD) with time. This model is then configured to simulate the time-dependent deformation responses associated with the damage features of rock salt. The validity and applicability of this 3D micro-creep model are verified through comparing the steady-state creep rate, multi-steps creep responses, and microcracking modes obtained in lab tests. This work could provide a promising alternative to study the micro-creep damage mechanism of rock salt.",7,7,11
Other topics ,,"Yang, Wei; Zhang, Dongxiao; Lei, Gang",Experimental study on multiphase flow in fracture-vug medium using 3D printing technology and visualization techniques,,PORE-SCALE; GAS INJECTION; SINGLE-PHASE; OIL-RECOVERY; SIMULATION; MODEL; ROCK,,7,7,5
