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01 February 2026, Volume 47 Issue 1 Previous Issue   

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OIL AND GAS EXPLORATION

Hydrocarbon Accumulation Mechanism and Exploration Potential of Permian Whole Petroleum System in the Jimsar Sag CHEN Xuan, LIN Lin, LIU Juntian, GONG Deyu, YANG Runze, WANG Bo, XIE An 2026, 47 (1):  1-10.  doi: 10.7657/XJPG20260101 Abstract ( 14 )   HTML ( 4 )   PDF (6979KB) ( 5 )   Save In the Jimsar sag, petroleum exploration mainly focuses on unconventional oil reservoirs. In recent years, breakthroughs have been made in multiple strata above and below the source rocks of the Lucaogou formation and across the sag, revealing its good exploration potential and the characteristics of a whole petroleum system. Based on seismic, drilling, logging, and organic geochemistry data, the formation conditions of the whole petroleum system, and the hydrocarbon accumulation model are investigated by thoroughly dissecting known oil reservoirs. The results show that there is an orderly symbiosis between conventional and unconventional reservoirs in the Jimsar sag. Horizontally, shale oil, tight oil, and conventional sandy conglomerate oil reservoirs are developed successively from the sag area through the slope area to the structural high. Vertically, tight oil, shale oil, and conventional oil reservoirs are found successively in the Jingjingzigou formation-Lucaogou formation-Wutonggou formation sequence. The source rocks of Lucaogou formation undergone mass hydrocarbon generation and expulsion in low maturity stage, laying a material foundation for the whole petroleum system. The Lucaogou formation contains sandstone/conglomerate, mixed-rock, and shale reservoirs successively from basin margin to basin interior horizontally, and full grain sequence reservoirs of overlying Wutonggou formation and underlying Jingjingzigou formation are found vertically. A three-dimensional hydrocarbon accumulation model consisting of three horizontal zones and three vertical floors is established. Controlled by the hydrocarbon generation evolution of source rocks of the Lucaogou formation and the presence of multi-type reservoirs, the Permian strata in the Jimsar sag show characteristics of a whole petroleum system with orderly symbiosis between unconventional and conventional reservoirs. Based on the theory of the whole petroleum system and the exploration practice in the Jimsar sag, the Permian petroleum exploration in eastern Junggar Basin should focus on the sags such as Shishugou and Jinan, especially for finding tight oil and gas reservoirs in the slope or sub-source areas, structural-lithologic oil and gas reservoirs in the above-source fault-step belts and high structural positions, and shale oil reservoirs in the inner-source zones. Figures and Tables | References | Related Articles | Metrics

Characteristics and Development Model of Associated Alkaline Ore in the Shale Oil Reservoirs of the Second Member of Fengcheng Formation, Mahu Sag, Junggar Basin HUANG Liliang, ZOU Yang, YANG Yongqiang, LI Guangxing, WU Junjun, JIANG Zhenxue, LIU Xinlong 2026, 47 (1):  11-19.  doi: 10.7657/XJPG20260102 Abstract ( 6 )   HTML ( 1 )   PDF (10657KB) ( 1 )   Save The Lower Permian Fengcheng formation in the Mahu sag of the Junggar Basin hosts alkaline ore which represents an important type of solid mineral resources. The alkaline ore has been insufficiently studied with respect to genetic mechanism and sedimentary evolution process. This paper restores the spatial distribution of alkaline ore in the Fengcheng formation in the Mahu sag through detailed core description, whole-rock X-ray diffraction(XRD) analysis, rock thin section identification, scanning electron microscopy(SEM) analysis, and geochemical analysis, and considering the geophysical characteristics, and then establishes the development model of the alkaline ore. It is found that the alkaline ore in the Fengcheng formation is predominantly composed of carbonate minerals, including trona, nahcolite, northupite, eitelite, and shortite, and it was formed with the source supply by deep volcanic hydrothermal activities. The symbiotic combination of Na-carbonate minerals are constrained by formation water salinity, and the logging responses to the minerals are characterized by high CAL, high AC, high CNL, low RT, low DEN, and low GR values, with obviously opposite trends for RLLD and RLLS. The alkaline ore is distributed in both slope and depression zones, with significant differences in macroscopic occurrence states. Based on the analysis of sedimentary facies and sequence of core samples, a model of multi-source alkaline-ore development under the alternating effects of climate fluctuation and episodic volcanic activity was established. The study results provide valuable reference for the exploration and comprehensive utilization of alkaline ore in similar lake basins. Figures and Tables | References | Related Articles | Metrics

Genesis of Pyroclastic-Rich Sandy Conglomerate Reservoirs in the Lower-Middle Permian of Mahu-Shawan Sags LYU Houkuan, ZHANG Lei, AN Zhiyuan, KUANG Hao, DOU Fangpeng, LI Cun, PAN Lang 2026, 47 (1):  20-30.  doi: 10.7657/XJPG20260103 Abstract ( 8 )   HTML ( 1 )   PDF (25850KB) ( 4 )   Save The genetic differences of zeolite cements lead to diverse pore space types, complex composition, and strong heterogeneity of reservoirs. To investigate their impacts on reservoir space, this study systematically compares and analyzes the types and formation mechanisms of zeolite cements, and reservoir space in the Lower-Middle Permian strata of the Mahu and Shawan sags by integrating macroscopic and microscopic approaches such as core observation, thin-section analysis, scanning electron microscopy (SEM), whole-rock X-ray diffraction (XRD), and energy-dispersive spectroscopy (EDS). The results indicate that variations in detrital composition control the types and genesis of zeolite cements: the zeolite cements in the Fengcheng and Xiazijie formations of the Mahu and Shawan sags were originated from the hydration of volcanic glass in tuff, while the zeolite cements in the Jiamuhe formation of the Zhongguai and Chepaizi bulges from the albitization of plagioclase. These genetic differences resulted in distinct reservoir space: in the Fengcheng and Xiazijie formations of the Mahu and Shawan sags, the evolution of zeolite cements involved changes in cement density and release of crystalline water, facilitating the creation of grain-edge fractures; while in the Jiamuhe formation of the Zhongguai and Chepaizi bulges, the dissolution of laumontite and calcite resulted in reservoir space dominated by dissolution pores. Figures and Tables | References | Related Articles | Metrics

Sedimentary Evolution of the Lower-Middle Jurassic Shuixigou Group in the Turpan-Hami Basin CHEN Kairui, ZHAO Junfeng, WANG Jiangbo, WANG Gang, ZHANG Peng 2026, 47 (1):  31-45.  doi: 10.7657/XJPG20260104 Abstract ( 14 )   HTML ( 2 )   PDF (24575KB) ( 1 )   Save The Lower-Middle Jurassic Shuixigou group in the Turpan-Hami Basin develops a fluvial-deltaic-lacustrine sedimentary system as a whole. However, the basin has undergone multiple tectonic movements, and the paleogeomorphological framework during the deposition of the Shuixigou group is believed to be the main factor controlling the evolution of this sedimentary system. Based on drilling, seismic, core and outcrop data, and combined with previous research, the sedimentary evolution of the Shuixigou group was comprehensively analyzed. The study shows that the Shuixigou group is generally thick in the north and thin in the south, and many small separated depocenters from the early stage of Early Jurassic to the Middle Jurassic migrated to the Taibei sag, forming a large and unified depocenter. The paleogeomorphology and sedimentation-provenance pattern of the Shuixigou group were shaped by the tectonic uplifting of the basin-margin mountains and the main bulges in the basin. The deposition of the Shuixigou group was mainly governed by both northern and southern provenances, as well as the sediment supply from the intra-basinal bulges. The early-formed paleo-bulges in the southern part of the basin served as the primary provenance, mainly owing to the distal deltaic system. The Bogda uplift and Buerga bulge, which rose continuously during the deposition of the Shuixigou group, were secondary provenances. The frequent fluctuation of lake level is another contributor to the distribution of the Shuixigou group sedimentary system. The early stage of lake transgression (the depositional period of the Badaowan formation) and the late stage of lake regression (the early depositional period of the Xishanyao formation), when delta plain subfacies was widely distributed within the basin, are critical coal-accumulation stages. The Sangonghe formation records the maximum lake transgression during the Early-Middle Jurassic, giving rise to the high-quality lacustrine source rocks of the Lower-Middle Jurassic Shuixigou group. Figures and Tables | References | Related Articles | Metrics

Influences of Paleo-Sedimentary Environment on Shale Oil Sweet Spots in the Fengcheng Formation, Mahu Sag, Junggar Basin CHEN Shaorong, ZHAO Yi, ZOU Yang, REN Haijiao, CHEN Fangwen, WU Junjun 2026, 47 (1):  46-56.  doi: 10.7657/XJPG20260105 Abstract ( 12 )   HTML ( 1 )   PDF (5511KB) ( 6 )   Save The paleo-sedimentary environment of the Permian Fengcheng formation in the Mahu sag of the Junggar Basin controlled the development of shale oil sweet spots. However, such controlling mechanism in alkaline lake environment is unclear, which restricts the efficient exploration and development for shale oil. Based on the core, geochemical and logging data of the Fengcheng formation in Well MY1, the paleo-sedimentary environment parameters (e.g. paleo-water depth, paleo-climate, paleo-salinity, and paleo-redox conditions) of different qualities of source rocks, reservoirs, and source-reservoir assemblages were analyzed, and the influences of paleo-sedimentary environment on the development of shale oil sweet spots were dissected. The results show that the Class Ⅰ high quality source-reservoir assemblages of the Fengcheng formation in Well MY1 were formed in the saltwater environment with a relatively small range of paleo-water depth, relatively warm and humid paleo-climate, relatively high contents of carbonate and terrigenous clastic sediments, and relatively low paleo-salinity, and also in the environment with stronger paleo-reduction condition. An appropriate sedimentary environment provides a possibility for the flocculation and enrichment of algae organic matters featuring a high hydrocarbon yield, promotes the formation of primary productivity, and contributes organic matter preservation conditions, allowing for extensive hydrocarbon generation from organic matters with relatively low maturity. The interlayered, laminar, and pure shale-type source-reservoir assemblages respectively correspond to the Class Ⅰ, Class Ⅱ and Class Ⅲ source-reservoir assemblages in a descending order of oil expulsion efficiency. It is determined that the paleo-sedimentary environment controls the development of shale oil sweet spots in the Fengcheng formation through a three-factor (source-storage-preservation) mechanism. This research insight provides a theoretical support for shale oil exploration. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

Synergistic Mechanism and Displacement Efficiency of Nanomaterial-Assisted Polymer/Surfactant Flooding in High-Salinity Oil Reservoirs LIU Zheyu, FENG Yaoguo, WANG Kuibin, WANG Wenxu, GAO Wenbin, LI Yiqiang 2026, 47 (1):  57-63.  doi: 10.7657/XJPG20260106 Abstract ( 9 )   HTML ( 1 )   PDF (10434KB) ( 4 )   Save Chemical flooding is a potential technique for enhancing oil recovery in high-salinity reservoirs. However, the high salinity impacts the viscosity of chemical system, thereby impeding the system’s effectiveness in mobility control and oil recovery improvement. This paper proposes the synergy of nanomaterials with polymer/surfactant for enhancing oil recovery in high-salinity reservoirs. The zero-dimensional nano-particle F80 and two-dimensional nano-sheet GO were compared for their effects on the viscosity and interfacial tension (IFT) of the polymer/surfactant composite system under high salinity conditions. The oil displacement mechanism of the polymer/surfactant composite system before and after the addition of nanomaterials was analyzed depending on the changes in microscopic residual oil and through core displacement experiments. It is found that F80 exhibits stronger ion-dipole interactions with cations in the formation water than GO, and it increases the viscosity of the chemical system by 1.4 times and maintains a lower oil-water IFT. In both microscopic visualization displacement and core displacement experiments, the polymer/surfactant/F80 composite system, with a high viscosity, significantly increases the flow resistance and reduces the dispersed residual oil, and enhances the oil recovery after water flooding by 20.1%, which is 5.4% higher than that of the polymer/surfactant composite system with the same mass fraction. Figures and Tables | References | Related Articles | Metrics

Design of Reasonable Injection and Production Parameters for the Yu-37 Gas Storage Considering Sand Production WANG Ping, WEI Yongsheng, GUO Yanni, TANG Shiqi, HUANG Hai, QU Zhan, WANG Liang, HE Yawen 2026, 47 (1):  64-73.  doi: 10.7657/XJPG20260107 Abstract ( 6 )   HTML ( 0 )   PDF (956KB) ( 2 )   Save Repeated high-intensity injection and production in wells of a gas-storage lead to frequent stress changes in the reservoirs, which may trigger sand production to threaten the stable operation of the gas storage. Taking the Yu-37 gas storage in the Ordos Basin as an example, the nodal analysis method was used, together with the critical flow velocity model for proppant migration, as well as the critical sand production pressure difference model for sand production prediction and the critical erosion flow model, to define the reasonable injection and production rates of wells for ensuring the operation safety of the Yu-37 gas storage under the extreme production state. According to the calculation using the critical flow velocity model for initiation of proppant migration in the fractures, which was established through the stress analysis of the proppant in the reservoir fractures, the proppant reaches its critical flow velocity for initiation of migration when the injection and production rates are 10.89 m/s and 8.19 m/s, respectively. Three restrictive models are used to modify the nodal analysis method, the reasonable injection and production rates of Well Yu 43-1 are determined to be (1.79-6.53)×104 m3/d and (2.82-6.35)×104 m3/d, respectively. Given the safety limits, the reasonable injection and production rates of 10 wells at the Yu-37 gas storage are defined. Figures and Tables | References | Related Articles | Metrics

Pseudo Threshold Pressure Gradient Model for Shallow Heavy Oil Reservoirs in Xinjiang Oilfield Under the Heat-Hydrocarbon Synergy LI Qihang, YAN Yonghe, Muhetar , WANG Zhizhang, LI Yiqiang, CHEN Wenhao, YUAN Chaoye 2026, 47 (1):  74-80.  doi: 10.7657/XJPG20260108 Abstract ( 10 )   HTML ( 1 )   PDF (734KB) ( 8 )   Save The high-temperature steam huff-and-puff in the J230 block of Xinjiang oilfield has led to an increased viscosity in residual heavy oil in the formation, significant differences in threshold pressure, and severe fluid channeling. Adding light hydrocarbon solvent can effectively reduce heavy oil threshold pressure gradient. In this paper, viscosity-temperature and rheological tests were conducted to compare the viscosity-temperature curves and rheological properties of heavy oil before and after the addition of light hydrocarbon solvent, and flow experiments were performed to clarify the relationship between the mobility of heavy oil and the pseudo threshold pressure gradient. Finally, a pseudo threshold pressure gradient model for solvent-assisted steam flooding was established. The study shows that the synergy between viscosity reduction by heat and viscosity reduction by light hydrocarbon solvent （or heat-hydrocarbon synergy in brief） allows for an improved performance. Light hydrocarbon solvent can modify the flow capacity of heavy oil. Adding 5%（mass fraction） light hydrocarbon solvent at 40℃ yields a pseudo threshold pressure gradient of heavy oil comparable to that at 70℃. Addition of light hydrocarbon solvent can reduce the quantity of immovable heavy oil. As shown in the pseudo threshold pressure gradient diagram, when the mass fraction of light hydrocarbon solvent added is 0.5%, 2.0%, and 5.0%, the quantity of immovable heavy oil is reduced by 39.13%, 70.56%, and 87.14%, respectively. Addition of the light hydrocarbon solvent can reduce steam consumption, thereby effectively lowering the pseudo threshold pressure of heavy oil, and thus suppressing fluid channeling. Figures and Tables | References | Related Articles | Metrics

PROMISING ENERGY

Theory and Practice of Full-Domain CO2 Flooding WEI Zhaosheng, WANG Yanjie, LI Qing, DING Chao, LUO Gang, ZHENG Sheng, CHEN Chao, LUO Qiang, ZHANG Xuyang, TAN Long, REN Xu 2026, 47 (1):  81-91.  doi: 10.7657/XJPG20260109 Abstract ( 5 )   HTML ( 1 )   PDF (996KB) ( 0 )   Save The Xinjiang oilfield faces the challenges such as complex reservoir type, strong reservoir heterogeneity, and low recovery efficiency. Considering the requirements for petroleum industry to meet China’s “dual carbon” goals, and through literature review, laboratory experiments, integration of key technologies, and field application in typical reservoirs, this paper proposes a theory of full-domain CO2 flooding to effectively guide the significant enhancement of oil recovery through CO2 flooding in highly heterogeneous reservoirs. A coupling mechanism between displacing medium (CO2) and reservoir characteristics across three dimensions (space domain, time domain, and fluid domain) is established to maximize the mobilization of crude oil in pores and throats of varying scales. Consequently, a series of key CO2 flooding technologies featuring full-reservoir coverage, full-scale adaptation, full-cycle optimization, and full-process integration have been formed. Field applications of the full-domain CO2 flooding theory and associated technologies in the Xinjiang oilfield have demonstrated remarkable results, with the estimated recovery enhancement by over 20%. This theory provides a new idea/approach for the efficient development of various complex reservoirs in the Xinjiang oilfield, but also lays a theoretical foundation for the significant EOR in complex reservoirs across China. It is promising, industrially and economically, for application in other oilfields. Figures and Tables | References | Related Articles | Metrics

Distribution of Present Geothermal Field and Evaluation of Geothermal Resources in the Western Uplift of the Junggar Basin LU Hui, WANG Fei, ZHANG Yidan, WANG Junwei, ZHANG Jinlong, CHEN Lei, XIAO Bei, YANG Huang, LI Chen 2026, 47 (1):  92-102.  doi: 10.7657/XJPG20260110 Abstract ( 9 )   HTML ( 0 )   PDF (5134KB) ( 0 )   Save Geothermal resources, as clean and stable non-carbon-based energy sources, are of great significance for China to achieve its “Dual Carbon” goals. The geothermal resources in the Junggar Basin have been insufficiently studied. This paper discusses the distribution of present geothermal field and performs the evaluation of geothermal resources in the western uplift of the Junggar Basin. Based on the high-quality, continuous temperature measurement data from 11 wells, the distribution characteristics of geothermal gradient and terrestrial heat flow were analyzed. Using the one-dimensional steady-state heat conduction equation, the planar distribution of temperature in the strata shallower than 5 000 m was revealed. On this basis, the geothermal resources of 7 sets of geothermal reservoirs (including the Carboniferous and above systems) were evaluated. The results show that, in the western uplift of the Junggar Basin, the average geothermal gradient is (21.3±3.0) ℃/km, and the average terrestrial heat flow is (43.9±6.9) mW/m2. In the Zhongguai bulge, a relatively high-temperature anomaly area, the average geothermal gradient is (23.3±2.8) ℃/km, and the average terrestrial heat flow is (47.9±5.8) mW/m2. The formation temperature at a depth of 4 000 m ranges from 78.0 ℃ to 122.9 ℃ in the western uplift, with an average of 100.7 ℃ in the Zhongguai bulge, indicating a good geothermal potential. The geothermal resources are estimated to be 411.24 EJ in the study area, with the largest quantity (132.61 EJ) endowed in the Permian, followed by the Carboniferous (121.52 EJ). The largest fluid resources are registered by the Cretaceous, reaching 19.58 EJ. This study provides key parameters for the development and utilization of geothermal resources in the western uplift and also offers a methodological reference for geothermal evaluation in other areas of the Junggar Basin. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

NMR-Based Investigation on Microscopic Retention and Plugging During Microsphere Flooding HAN Bo, GAO Hui, LIU Yunlong, YI Ping, WANG Chen, CHENG Zhilin, LI Teng 2026, 47 (1):  103-110.  doi: 10.7657/XJPG20260111 Abstract ( 7 )   HTML ( 1 )   PDF (1287KB) ( 0 )   Save Microsphere flooding technology can effectively address the issues of severe water channeling in high-permeability layers and difficult oil mobilizing in low-permeability layers in low-permeability reservoirs. This paper investigates the microscopic retention and plugging characteristics of microspheres by combining a parallel dual-core microsphere flooding physical simulation experiment with low-field nuclear magnetic resonance (NMR) testing, and quantitatively evaluates the microscopic plugging capacity of microspheres by defining the degree of core plugging and the plugging contributions of large and small pores. The results show that microsphere flooding can further enhance oil recovery. Microsphere injection at varying rates after water flooding enables the oil recovery of low-permeability and high-permeability cores to increase by an average of 9.47% and 5.80%, respectively. The permeabilities of the cores reduce to a varying extent after microsphere flooding, with a higher reduction in low-permeability cores than in high-permeability cores. The NMR test results indicate that the plugging degree of microspheres in low-permeability cores is greater than that in high-permeability cores. The average plugging degrees of low-permeability and high-permeability cores at different injection rates are 5.44% and 1.02%, respectively, suggesting that microspheres with a diameter of 50 nm used in the test are compatible with low-permeability cores. Additionally, the calculation results show that the plugging contribution rate of large pores is higher than that of small pores, with the latter being negative, indicating that microspheres preferentially deposit in large pores and displace the water in large pores into small pores, thereby mobilizing the fluocarbon oil in small pores. Figures and Tables | References | Related Articles | Metrics

Calculation Method of Critical Edge-Water Distance During Steam Huff and Puff for Preventing Water Invasion ZHENG Wenqian, GENG Zhigang, GE Taotao, SONG Jianfang 2026, 47 (1):  111-115.  doi: 10.7657/XJPG20260112 Abstract ( 7 )   HTML ( 1 )   PDF (719KB) ( 0 )   Save For edge-water heavy oil reservoirs, the critical edge-water distance during steam huff and puff is vital for the placement of new wells and the development adjustment of existing wells. When a well for steam huff and puff is placed at a distance less than the critical edge-water distance, edge-water invasion may easily occur, resulting in poor development effect of heavy oil reservoirs. In this paper, the formation after steam huff and puff is divided into a thermally swept zone and a cold zone, and a characterization method of flow field parameters after steam huff and puff is determined. The comprehensive mobility of the thermally swept zone is equivalent to the comprehensive mobility of the cold zone by transforming the length of the thermally swept zone. On this basis, the calculation method of critical edge-water distance during steam huff and puff in heavy oil reservoirs is established considering the start-up pressure gradient of heavy oil, together with the mirror reflection and the potential superposition theory. The results show that the relationship curve between the critical edge-water distance and the permeability is plotted to guide the placement of new wells, effectively preventing edge-water invasion, and the relationship curve between the cumulative liquid production and the cumulative steam injection volume under different edge-water distances is provided to support the optimization of the cyclic steam injection volume in existing wells. Field application in Well A demonstrated that the critical edge-water distance was reduced from 180 m in the first cycle to 150 m in the second cycle, effectively preventing edge-water invasion. By optimizing the cyclic steam injection volume, the steam huff and puff recovery has been increased by 3.1%. Figures and Tables | References | Related Articles | Metrics

Modeling Method for Fault-Controlled Reservoirs Based on Internal Filling Model and Its Application TIAN Yuan, WANG Jiale, YUE Ping, ZHAO Liming, ZHANG Ying, FAN Qingzhen, GENG Jie, MOU Yu 2026, 47 (1):  116-125.  doi: 10.7657/XJPG20260113 Abstract ( 7 )   HTML ( 1 )   PDF (8866KB) ( 2 )   Save The complex and highly heterogeneous reservoir space in the Ordovician carbonate reservoirs in Tahe oilfield poses significant challenges to reservoir characterization and modeling. This paper proposes a modeling method for fault-controlled reservoirs based on internal filling model, enabling the construction of a high-precision model with the methodology of lithology-structure dual constraints, hierarchical modeling, and categorical integration. First, depending on the genesis of fault-controlled reservoirs and the characteristics of reservoir architectures, the reservoirs are divided into three types of structural units: vugs, pores, and fractures. Vugs and pores are delineated by using deterministic modelling with cutoff value and corrected manually to define their boundaries; combined with log-derived lithofacies, the reservoirs are identified, and the internal architecture is finely characterized by integrating deep neural network with seismic inversion data. Faults and fractures are characterized at different scales: large faults are identified through ant-tracking and coherence attributes; small-medium faults are defined by diffraction tensor ant-tracking with volume constraints; and fractures are finely described via discrete fracture network (DFN) modeling. Next, based on the coupling of genetic mechanism, storage-permeability function, and engineering application, multi-scale model integration is performed. Finally, a matrix-fracture dual-medium geological model is established. Application in a unit of the Tahe oilfield has demonstrated that the high-precision filling model yields the validated results of static reserves and production performance in good agreement with the actual production data. The proposed model can effectively support the simulations of remaining oil recovery and development adjustment, and significantly enhance the reliability of numerical simulation for such reservoirs. Figures and Tables | References | Related Articles | Metrics