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Research Progress and Trend of Ultra-Deep Strike-Slip Fault-Controlled Hydrocarbon Reservoirs in Tarim Basin WANG Qinghua, CAI Zhenzhong, ZHANG Yintao, WU Guanghui, XIE Zhou, WAN Xiaoguo, TANG Hao Xinjiang Petroleum Geology    2024, 45 (4): 379-386.   DOI: 10.7657/XJPG20240401 Abstract （385）   HTML （33）    PDF（pc） （4805KB）（500）       Knowledge map    Save Ultra-deep strike-slip fault-controlled hydrocarbon reservoirs have been discovered as a new frontier for exploration and development in the Tarim basin. However, the complexity of these reservoirs poses a significant challenge for profitable development, necessitating enhanced foundational geological research. The strike-slip fault-controlled hydrocarbon reservoirs are commonly characterized by strong heterogeneity, intricate reservoir and fluid distribution, significant variations in hydrocarbon production, and low recovery. The great differences in faulting, reservoir characteristics, hydrocarbon accumulation, and fluid dynamics of these reservoirs between different areas present a series of exploration and development challenges. A series of models for strike-slip fault zones of different genesis and their controls on reservoirs have been established, and the mechanisms of reservoir formation along strike-slip fault zones including combined reservoir control by microfacies, strike-slip fault and dissolution, and contiguous, differential and extensive development have been revealed. Furthermore, the strike-slip fault-controlled reservoir models with “source-fault-reservoir-caprock coupling” and “small reservoir but large field” are constructed, unveiling the mechanisms of the hydrocarbon accumulation and preservation of ultra-deep strike-slip fault-controlled reservoirs. This research breaks through the limitations in theory that weak strike-slip faults in cratonic basins are difficult to form large-scale strike-slip fault-controlled reservoirs and large oil/gas fields. Finally, the genesis of large-scale strike-slip fault systems, the differential reservoir formation mechanisms within strike-slip fault zones, and the hydrocarbon enrichment patterns in cratonic basins have been clarified. Table and Figures | Reference | Related Articles | Metrics

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Precursor and Mechanism of Hydrocarbon Generation for Shale Oil in Lucaogou Formation, Jimsar Sag WANG Jian, LIU Jin, PAN Xiaohui, ZHANG Baozhen, LI Erting, ZHOU Xinyan Xinjiang Petroleum Geology    2024, 45 (3): 253-261.   DOI: 10.7657/XJPG20240301 Abstract （374）   HTML （30）    PDF（pc） （6824KB）（434）       Knowledge map    Save In order to clarify the differences in hydrocarbon-generating precursor and mechanism of the shale oil between the upper and lower sweet spots of the Lucaogou formation, the source rocks of the Lucaogou formation in the Jimsar sag were characterized ultra-microbiologically using field emission scanning electron microscopy, electron probe, and Fourier transform infrared spectroscopy experiments. The results show that the main hydrocarbon-generating precursor of the shale oil in the upper sweet spot is lamalginite (Microcystis), with straight-chain aliphatic series in dominance, and the main hydrocarbon-generating precursor in the lower sweet spot is telalginite (Tasmanian algae), which is rich in branched-chain aliphatic, aromatic, and sulfoxide functional groups. Due to the significantly higher activation energy required for the cleavage of long straight-chain saturated hydrocarbons than that for branched-chain hydrocarbons, as well as the lower bond energies of carbon-sulfur and carbon-nitrogen bonds, the activation energy of the precursor of the shale oil in the lower sweet spot is lower than that in the upper sweet spot. Consequently, early-stage hydrocarbon generation occurs, leading to the formation of high-density crude oil rich in non-hydrocarbon bitumen at low maturity, which is the primary reason for the relatively heavy and viscous nature of the crude oil in the lower sweet spot. Table and Figures | Reference | Related Articles | Metrics

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Thermal Evolution History of Shale in Da’anzhai Member and Its Petroleum Geological Significance in Central Sichuan Basin JIANG Qijun, LI Yong, XIAO Zhenglu, LU Jungang, QIN Chunyu, ZHANG Shaomin Xinjiang Petroleum Geology    2024, 45 (3): 262-270.   DOI: 10.7657/XJPG20240302 Abstract （298）   HTML （321）    PDF（pc） （821KB）（331）       Knowledge map    Save The Da’anzhai member of the Lower Jurassic Ziliujing formation is the most favorable layer for the development of continental shale oil in the Sichuan basin, and has huge potential in shale oil exploration. However, there is a lack of systematic research on the thermal evolution history of this formation. Using the simulation system for petroliferous basins, the differences in the thermal evolution and hydrocarbon generation of the shales in Da’anzhai member between the northern part and the central part of the central Sichuan basin were comparatively analyzed, and their impacts on shale oil enrichment were discussed. The thermal evolution degree of the shale of Da’anzhai member in the study area gradually increases from southwest to northeast, and the shale can be divided into a highly matured zone and a matured zone on the plane. The highly matured zone is located in the northern part of the study area, with vitrinite reflectance ranging from 1.3% to 1.7%, mainly developing Type Ⅲ organic matter. The early oil generation occured in the early Late Jurassic, and the oil generation peaked at the end of Late Jurassic, experiencing two phases of hydrocarbon generation. The matured zone is located in the central to southern parts of the study area, with vitrinite reflectance ranging from 0.9% to 1.3%, mainly developing Type Ⅱ1-Ⅱ2 organic matter. The sedimentary thickness of the Jurassic is relatively small, the early oil generation occured at the end of the Late Jurassic and reached the peak in the Early Cretaceous, with only one period of hydrocarbon generation. Compared with the northern area, a large set of organic-rich shales deposited in the central area, which provieded a solid material basis for shale oil in the Da’anzhai member. However, the tectonic uplift and stratum erosion since the Paleogene posed a certain destructive effect on the preservation of oil and gas in this area. Table and Figures | Reference | Related Articles | Metrics

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NMR Logging-Based Productivity Analysis and Sweet Spot Evaluation for Shale Oil QIN Jianhua, LI Yingyan, DU Gefeng, ZHOU Yang, DENG Yuan, PENG Shouchang, XIAO Dianshi Xinjiang Petroleum Geology    2024, 45 (3): 317-326.   DOI: 10.7657/XJPG20240308 Abstract （294）   HTML （9）    PDF（pc） （1650KB）（296）       Knowledge map    Save Shale oil horizontal wells in the Lucaogou formation within the Jimsar sag vary greatly in productivity, with notable differences in water production rate. Main factors controlling this phenomenon remain unclear. Moreover, the existing sweet spot classification criteria fail to meet the requirements for fine development of shale oil in this area, and the interpretation of oil saturation and mobility based on the cutoff values from nuclear magnetic resonance (NMR) logging cannot realize precise identification of shale oil sweet spots. In this paper, based on the results of NMR logging and laboratory NMR testing, and through frequency division processing, NMR logging-based pore structure characterization by fluids, and elastic oil displacement simulation, the distribution of different types of fluids in shale oil reservoirs was characterized detailedly. The pore sizes for oil/water occurrence were delineated, and a model for evaluating movable oil amount was established to quantitatively characterize the fluid occurrence, pore size distribution, movable oil quantity, and other parameters. By integrating single-well testing and production data, the factors controlling horizontal well productivity were elucidated. The results show that horizontal well productivity is much more correlated to the large-pore light oil proportion (LOP) and movable oil porosity (MOP) than to porosity, oil saturation, NMR MOP and other parameters. The water influence index reflects the extent of formation water’s impact on shale oil flow, and given the same MOP, a smaller water influence index corresponds to a higher productivity and a lower water cut of a horizontal well. Based on large-pore LOP, water influence index and MOP, the shale oil sweet spots are classified into Class Ⅰ, Class Ⅱ and Class Ⅲ, with rapid decline in daily oil production and significant rise in water cut, which can serve as the basis for finely evaluating shale oil sweet spots in the Lucaogou formation. Table and Figures | Reference | Related Articles | Metrics

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Optimization of Geological Sweet Spots for Shale Oil in Fengcheng Formation in Well Maye-1, Mahu Sag LI Na, LI Hui, LIU Hong, CHEN Fangwen, YANG Sen, ZOU Yang Xinjiang Petroleum Geology    2024, 45 (3): 271-278.   DOI: 10.7657/XJPG20240303 Abstract （281）   HTML （9）    PDF（pc） （940KB）（308）       Knowledge map    Save The Fengcheng formation in the Mahu sag is a typical alkaline lacustrine deposit characterized by mixed provenance, complex lithology, overall oil possibility, and scattered sweet spots. To efficiently explore and develop the shale oil, it is necessary to optimize geological sweet spots for the shale oil. Based on the results of high-pressure mercury injection and rock pyrolysis experiments, the reservoir and shale oil mobility of the Fengcheng formation in Well Maye-1 were evaluated, a model for optimizing geological sweet spots for the shale oil was constructed, and the vertical distribution of geological sweet spots for the shale oil was assessed. The results show that porosity, total organic carbon content, brittle mineral content, and difference between free hydrocarbon content and 100 times of total organic carbon content are parameters for respectively evaluating the reservoir performance, oil-bearing property, brittleness, and shale oil mobility of the Fengcheng formation. A model for optimizing geological sweet spots for the shale oil was constructed by using these four parameters, with sweet spot factors for Class Ⅰ, Ⅱ, and Ⅲ shale oil geological sweet spots in Well Maye-1 being greater than 0.282 3, ranging from 0.011 1 to 0.282 3, and less than 0.011 1, respectively. Class Ⅰ shale oil geological sweet spots in the Fengcheng formation in Well Maye-1 are mainly distributed in the upper part of the second member of Fengcheng formation and in the third member of Fengcheng formation, with lithology dominated by mudstone and dolomitic mudstone. Table and Figures | Reference | Related Articles | Metrics

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Sensitivity Analysis on Injection-Production Parameters for CO2 EOR and Storage in Low-Permeability Reservoirs Considering Storage Mechanism LI Yuanduo, DING Shuaiwei, ZHANG Meng, XU Chuan, FAN Wenyu, QU Chuanchao Xinjiang Petroleum Geology    2024, 45 (6): 711-718.   DOI: 10.7657/XJPG20240610 Abstract （272）   HTML （5）    PDF（pc） （1795KB）（91）       Knowledge map    Save In low-permeability reservoirs, CO2 flooding can enhance oil recovery and achieve CO2 geological storage. Based on the CO2 storage mechanisms, by using a numerical simulation method, a CO2 EOR and storage model considering CO2 structural storage, residual storage, and dissolution storage mechanisms was established. This model was used to analyze the sensitivity of injection-production parameters (e.g. water injection period, CO2 injection rate, injection-production ratio, lower limit of bottomhole flowing pressure in production wells, upper limit of bottomhole flowing pressure in injection wells, number of cycles, and gas-to-water slug ratio) on CO2 EOR and CO2 storage efficiency in low-permeability reservoirs under continuous gas injection and water-alternating-gas (WAG) injection modes. The results demonstrate that CO2 storage mechanisms have significant impacts on both CO2 EOR and CO2 storage. Under the mode of continuous gas injection, CO2 residual storage aids CO2 EOR but has minimal effect on CO2 storage, while dissolution storage hinders CO2 EOR but benefits CO2 storage. Under the mode of WAG injection, the storage mechanisms are less favorable for CO2 EOR but promote CO2 storage. These findings reveal the influences of storage mechanisms on CO2 EOR and storage under different injection modes. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of Rock Mechanical Parameter Profile to Tight Reservoirs in Yongjin Oilfield GAI Shanshan, WANG Zizhen, LIU Haojie, ZHANG Wensheng, YU Wenzheng, YANG Chongxiang, WANG Yuping Xinjiang Petroleum Geology    2024, 45 (3): 362-370.   DOI: 10.7657/XJPG20240314 Abstract （261）   HTML （10）    PDF（pc） （3814KB）（296）       Knowledge map    Save In order to study the fracability evaluation method for low-permeability tight reservoirs, experiments were conducted on six core samples from Well Y301 and Well Y3 in the Yongjin oilfield, Shawan sag, Junggar basin, and the parameters such as rock mineral composition, porosity, stress-strain curves, P-wave velocity, and S-wave velocity were obtained. The experiment results agreed well with logging data, and an empirical rock mechanical model was established for the study area. Meanwhile, based on the equivalent medium model, a new model considering mineral composition and pore structure characteristics was developed for calculating rock brittleness index. Then, a method for constructing the rock mechanical parameter profile of low-permeability tight reservoirs based on logging data was established and applied in Well Y301. The application results show that the Qigu formation in Well Y301 has good fracability, which lays a foundation for the comprehensive evaluation of fracability of tight sandstone reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Dynamic Reserves Calculation Method for Fault-Controlled Carbonate Reservoirs GENG Jie, YUE Ping, YANG Wenming, YANG Bo, ZHAO Bin, ZHANG Rujie Xinjiang Petroleum Geology    2024, 45 (4): 499-504.   DOI: 10.7657/XJPG20240415 Abstract （258）   HTML （11）    PDF（pc） （960KB）（278）       Knowledge map    Save Fault-controlled carbonate reservoirs are highly heterogeneous, with interweaving development of pores, fractures, and vugs of various sizes. For this kind of reservoirs, the dynamic reserves calculated using conventional material balance methods may be larger than the static reserves. By incorporating water-oil ratio and considering rock compressibility coefficients for different pore-fracture-vug media, a comprehensive compressibility coefficient suitable for the fault-controlled reservoirs was derived. On this basis, a new flow material balance equation was established for the fault-karst reservoir, and its accuracy and applicability were verified using numerical simulation. The research results show that the dynamic reserves calculated by the new equation have an error of only 0.1099% with the static reserves obtained from numerical simulation, confirming the new equation’s reliability and accuracy. In the Halahatang area, the relative error between the dynamic reserves calculated using the new equation and the static reserves derived from geological modeling for multiple wells ranged from -4.82% to -0.15%, which is significantly lower than that calculated using the conventional material balance equation. The results obtained from the new equation are closer to actual conditions, making it more suitable for calculating the reserves of the fault-controlled carbonate reservoirs in the Halahatang area. Table and Figures | Reference | Related Articles | Metrics

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Layered Structural Deformation Characteristics of Kuqa Foreland Thrust Belt XU Zhenping, YANG Xianzhang, NENG Yuan, DUAN Yunjiang, ZHANG Wen, HU Jianning, ZHANG Mengyang Xinjiang Petroleum Geology    2024, 45 (5): 505-515.   DOI: 10.7657/XJPG20240501 Abstract （255）   HTML （14）    PDF（pc） （5903KB）（337）       Knowledge map    Save The seismic data acquired from Kuqa foreland thrust belt is characterized by low signal-to-noise ratio and high interpretive ambiguity. By using high-resolution 3D seismic data, drilling and lab hydrocarbon analysis data, the stratigraphic assemblages of Kuqa foreland thrust belt were systematically described, the structural model was detailedly interpreted, and the hydrocarbon accumulation system was deeply analyzed. It is found that the Kuqa foreland thrust belt develops two sets of detachment layers: Paleogene and Neogene gypsum-salt rocks, and Triassic and Jurassic coal measures, all of which feature stratified detachment, vertical stacking, and multiphase deformation. Detachment folds in caprocks are found in the shallow structures, while basement-involved imbricate thrust structures are developed in deep strata. Detachment plastic deformation occured in the gypsum-salt and coal layers. Faulting occured in three phases including Caledonian, late Hercynian-Indosinian, and Yanshanian-Himalayan. The late Hercynian-Indosinian tectonics controlled the Mesozoic sedimentation, showing a north-to-south onlap thinning feature. Layered structural deformation in the Kuqa foreland thrust belt governs the stratified accumulation and migration of hydrocarbons. Hydrocarbons in the strata above the coal seam predominantly originated from the Jurassic source rocks, whereas oil and gas in the strata below the coal seam mainly came from the Triassic source rocks which contributs 60% of the hydrocarbons. A substantial quantity of hydrocarbon remains trapped in the formation below the coal layer. Table and Figures | Reference | Related Articles | Metrics

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OVT-Domain Wide-Azimuth Seismic Forward Modeling of Glutenites in Dongying Sag LOU Fengqin, YU Jingqiang, ZHANG Yunyin, LIU Haining, WU Mingrong, GUO Zhiyang Xinjiang Petroleum Geology    2024, 45 (5): 622-628.   DOI: 10.7657/XJPG20240515 Abstract （253）   HTML （3）    PDF（pc） （7909KB）（123）       Knowledge map    Save Considering the varying lithofacies and lithology of the proximal glutenites in the Dongying sag，a three-dimensional geological model of the glutenites was established for wide-azimuth seismic forward modeling. Using the simulated data cube，and through azimuthal stacking of gathers in OVT-domain，the effects of azimuth variation on parameters such as seismic travel time and amplitude were analyzed，and the relationships between azimuth/amplitude and favorable reservoirs were established. The results show that the variation in the sedimentary direction of the glutenites causes azimuth differences in seismic wave propagation，leading to azimuthal anisotropy in seismic reflections. The data cube obtained from azimuthal stacking at the azimuth perpendicular to the sedimentary boundaries is more sensitive to the responses of the top and internal boundaries of the glutenite，with stronger amplitudes. It more effectively reveals the contacts between glutenites of different periods，thereby facilitating the accurate identification of glutenite and fine prediction of favorable reservoir distribution. Wide-azimuth OVT-domain seismic data are proved effective in glutenite prediction，and have been successfully applied in predicting glutenite reservoirs in the steep slope zone of the northern Dongying sag，with the prediction results in good agreement with actual drilling results. Table and Figures | Reference | Related Articles | Metrics

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Structural Deformation and Hydrocarbon Accumulation Characteristics of Baxigai Formation in Awat Area, Kuqa Depression WANG Yingying, GUI Lili, LU Xuesong, LIU Huichuan, MO Tao, ZHOU Hui, JIANG Lin Xinjiang Petroleum Geology    2024, 45 (6): 631-641.   DOI: 10.7657/XJPG20240601 Abstract （251）   HTML （25）    PDF（pc） （7831KB）（159）       Knowledge map    Save The structural deformation in the foreland thrust belt of the Kuqa depression mainly occurred during the middle-late Himalayan orogeny. Previous studies primarily identified the initiation timing of shallow postsalt fold deformation, but had no absolute dating constraints on the subsalt thrust deformation and the timing of hydrocarbon accumulation. Taking the Awat area in the Kuqa depression as an example, using the data from petrographic observations, calcite U-Pb dating, and fluid inclusion analysis, the diagenesis, formation timing of calcite veins, and hydrocarbon accumulation process of the Lower Cretaceous Baxigai formation reservoirs were investigated, and the timing of structural deformation and hydrocarbon accumulation in the Awat area was determined. The research results show that two periods of calcite were developed in the Baxigai formation in the Awat area. The early calcite cement formed at (98.0±14.0) Ma, while the late calcite veins formed at (3.7±1.0) Ma, reflecting the time of subsalt thrust deformation. Oil inclusions and gas inclusions of different periods were identified in the calcite veins. Based on the homogenization temperatures of the fluid inclusions, burial history and thermal history, it is inferred that the oil charging occurred at 4.0-3.0 Ma, and gas charging at 3.0-1.0 Ma. The early oil reservoir underwent reworking of gas washing in the late Pliocene, forming the current condensate gas reservoir. Table and Figures | Reference | Related Articles | Metrics

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Microscopic Oil Mobility in Tight Conglomerate Reservoirs Under Different Development Modes, Mahu Sag WAN Tao, ZHANG Jing, DONG Yan Xinjiang Petroleum Geology    2024, 45 (3): 327-333.   DOI: 10.7657/XJPG20240309 Abstract （248）   HTML （5）    PDF（pc） （2794KB）（189）       Knowledge map    Save In order to evaluate the oil mobility in the tight sandy conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu sag, the distribution characteristics of movable oil in typical rock samples from Type Ⅰ and Type Ⅱ reservoirs were compared through imbibition, centrifugation, and huff-n-puff tests. For the low-permeability conglomerate reservoirs in the Mahu sag, the imbibition oil recovery is related to the pore structure of the rock. The higher the proportion of small pores, the better the imbibition effect. After 144 hours of oil displacement by imbibition, the recovery rate can reach 30.9%, but the oil displacement process is slow, with low utilization of large pores. Under reservoir pressure of 40 MPa and reservoir temperature, during three cycles of CO2 huff-n-puff process, the recovery percent of each round increase, with the highest increase observed in the first cycle, reaching an oil exchange ratio of 27%. As the huff-n-puff cycle increases, the increment in recovery percent gradually decreases, and the oil exchange ratio of N2 huff-n-puff in the first cycle is 15%. Therefore, CO2 huff-n-puff has the best development effect. Table and Figures | Reference | Related Articles | Metrics

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Fracture Characteristics and Seismic Prediction of Z4 Metamorphic Buried-Hill Reservoir DING Sheng, LIU Jinhua, SHANG Yamin, PENG Pai, FU Jinxiang Xinjiang Petroleum Geology    2024, 45 (5): 516-521.   DOI: 10.7657/XJPG20240502 Abstract （243）   HTML （7）    PDF（pc） （3488KB）（182）       Knowledge map    Save Seismic prediction of fractures is the foundation of fractured reservoir evaluation. Metamorphic buried-hill reservoirs exhibit diverse fracture types, significant variations in fracture development at different reservoir parts, and difficulties in describing fracture heterogeneity. The Z4 metamorphic buried-hill reservoir was investigated for its fracture characteristics and seismic prediction. The development of fractures in the Z4 reservoir has layering characteristics and can be divided into four sections such as weathered-semi-filled fractures at the top, highly developed net-like fractures in the upper part, moderately developed low-angle fractures in the middle part, and poorly developed high-angle fractures at the bottom. A comprehensive fracture prediction technique was proposed, which integrates multi-scale general spectral decomposition, dip-oriented eigenvalue coherent processing, and iterative ant analysis. The fracture orientations and development revealed by cores were compared with the results of seismic prediction, suggesting a high consistency. It is believed that the multi-approach comprehensive fracture seismic prediction technology proposed in this study has high accuracy. Table and Figures | Reference | Related Articles | Metrics

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Development Parameters of Chang 6 Reservoir in Shuanghexi Block of Yanchang Oilfield, Ordos Basin CHEN Junjun, YANG Xingli, XIN Yichao, LIU Zhaoyang, TONG Bowen Xinjiang Petroleum Geology    2024, 45 (5): 552-559.   DOI: 10.7657/XJPG20240506 Abstract （242）   HTML （9）    PDF（pc） （794KB）（140）       Knowledge map    Save The Chang 6 reservoir in the Shuanghexi block of Yanchang oilfield in the Ordos basin is characterized by low permeability. Conventional calculation methods for development indices are not conducive to geological research, policy formulation and cost control for oilfield development. The production decline patterns, producing degree of reserves by water flooding, injection-production ratio, water cut, injected water utilization, and recovery of the Chang 6 reservoir were analyzed. The results show that the production of the Chang 6 reservoir follows a hyperbolic decline pattern. The block has significant potential for water injection development, with the current control degree and producing degree of reserves by water flooding at 74.54% and 36.94%, respectively, and an injection-production connection rate of 27.27%. The optimal injection-production ratio is approximately 2.5. As the recovery efficiency increases, the water cut rises rapidly at the first and then slows down. Based on the water retention rate, water consumption index, and water flooding index, it is evident that in the late stage of development, the water injection effectiveness improves, leading to an increase in ultimate recovery. During the development process, the water cut rise rate should ideally be kept below 6.1%, and the reasonable formation pressure should be maintained above 9.1 MPa. Under these conditions, the final recovery in the study area is approximately 23%. Table and Figures | Reference | Related Articles | Metrics

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Genesis and Identification of Low Resistivity of Oil Layers in Badaowan Formation on Southern Slope of Zhongguai Bulge, Junggar Basin LI Fengling, FANG Xinxin, ZHANG Zhen, MA Sijie, LIU Rongjun Xinjiang Petroleum Geology    2024, 45 (5): 541-551.   DOI: 10.7657/XJPG20240505 Abstract （238）   HTML （15）    PDF（pc） （4996KB）（213）       Knowledge map    Save Compared to other low-resistivity oil layers, the low-resistivity oil layers in the Lower Jurassic Badaowan formation on the southern slope of the Zhongguai bulge in the Junggar basin are characterized by early hydrocarbon accumulation, deep burial, large grain size, and low mud content, showing a unique low-resistivity genesis. Based on a comprehensive analysis on the genetic mechanisms of typical low-resistivity oil layers globally, together with the data of drilling, logging, well testing, and core analysis in the study area, the main controlling factors of the low-resistivity oil layers in the Badaowan formation were investigated from various perspectives including tectonics, sedimentation, diagenesis, reservoir characteristics, and hydrocarbon accumulation conditions. It is found that low resistivity of the oil layers in the study area is jointly controlled by macroscopic and microscopic factors. In a macroscopic setting with low tectonic amplitude and weak hydrodynamic sedimentation, low oil-water differentiation degree, high formation water salinity, and low tuff debris content are the main controlling factors for low resistivity, while low saturation of bound water is a secondary controlling factor. Accordingly, a chart illustrating the relationship between formation resistivity and oil/gas indicator coefficient was established, which matches the formation/production testing data in the study area by 92.9%. The study results provide a basis for identifying low-resistivity oil layers in the Badaowan formation on the southern slope of the Zhongguai bulge. Table and Figures | Reference | Related Articles | Metrics

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Influences of Low-Temperature Oxidation on Oil Recovery During Oxygen-Reduced Air Flooding in Guo-8 Block of Yuguo Oilfield XIAO Zhipeng, ZHANG Yanbin, LI Qihang, LI Yiqiang, HAN Jifan, YAN Qian, WU Yong’en Xinjiang Petroleum Geology    2024, 45 (3): 334-339.   DOI: 10.7657/XJPG20240310 Abstract （237）   HTML （8）    PDF（pc） （964KB）（169）       Knowledge map    Save Oxygen-reduced air injection is an effective technique for developing low-permeability oil reservoirs. Under reservoir conditions, oxygen-reduced air can undergo low-temperature oxidation reaction with crude oil, thereby enhancing oil recovery. Regarding the inadequate understanding of the mechanism underlying the oxygen-reduced air flooding for enhanced oil recovery (EOR) in the Guo-8 block of the Yuguo oilfield, isothermal oxidation experiments and long-core displacement experiments were conducted to investigate the influences of oil oxidation process and generated substances on EOR. The results of the isothermal oxidation experiments indicate that sedimentary substances are generated during the low-temperature oxidation process of light oil. With the increase of temperature, the degree of oxidation significantly increases, with the sedimentation of heavy components reaching 1.25×10-3 g/g at 89°C, 3.43×10-3 g/g at 100°C, and 5.02×10-3 g/g at 120 ℃. The results of the long-core displacement experiments demonstrate that the sedimentation of heavy components at different oxidation temperatures affects EOR. With temperature increasing, the timing of gas channeling delays, the sweeping effect improves, and the final recovery increases to 52.77%, 58.89%, and 65.23% at temperatures of 89°C, 100°C, and 120°C, respectively. Table and Figures | Reference | Related Articles | Metrics

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Enhanced Recovery in Middle and Late Stages of Depletion Development of Condensate Gas Reservoirs With Oil Ring HUANG Zhaoting, LI Chuntao, WANG Bin, QIAO Xia, FU Ying, YAN Bingxu Xinjiang Petroleum Geology    2024, 45 (4): 470-474.   DOI: 10.7657/XJPG20240411 Abstract （236）   HTML （10）    PDF（pc） （549KB）（186）       Knowledge map    Save The depletion development of Y5 condensate gas reservoir in the Tarim basin encounters the challenges such as rapid decline in both reservoir pressure and well productivity, gradual decrease in produced gas-oil ratio, increase in condensate oil density and viscosity, and fast downgrading of development performance. Combining performance analysis and reservoir fluid component evaluation, the Y5 condensate gas reservoir was redefined as a layered condensate gas reservoir with oil ring and edge water and the thickness of the oil ring was determined through numerical simulation. To improve the development performance and enhance the condensate oil/gas recovery, a systematic investigation was conducted on the mechanism of enhanced recovery in the middle and late stages of depletion development of the condensate gas reservoir with oil ring. It is found that optimizing the well pattern and implementing cyclic gas injection can significantly improve oil and gas recovery. Gravity-assisted gas drive is recommended, with CO2 being the optimal injection medium, followed by reservoir gas. Based on reservoir type and enhanced recovery mechanism, a scheme of cyclic gas injection for enhancing the recovery of Y5 condensate gas reservoir was developed, with an expected oil recovery 29.96% higher than that of depletion development alone. Under this scheme, a cumulative gas volume of 0.19×108 m3 was injected, the reservoir pressure restored by 4.31 MPa, and the well productivity increased by 3.09 times compared to that before the scheme was implemented. The research results provide valuable reference for enhancing recovery in the middle and late development stages of similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Pore Throat Structures and Fluid Occurrences of Reservoirs in Fengcheng Formation, Mahu Sag ZHU Yue, WU Shunwei, DENG Yusen, LIU Lin, LEI Xianghui, NIU Youmu Xinjiang Petroleum Geology    2024, 45 (3): 286-295.   DOI: 10.7657/XJPG20240305 Abstract （235）   HTML （13）    PDF（pc） （4537KB）（256）       Knowledge map    Save In order to reveal and compare the microstructures of sandstone and shale reservoirs, and the fluid occurrences within different sizes of pores in the Fengcheng formation of the Mahu sag, the experiments including high-pressure mercury intrusion (HPMI), nuclear magnetic resonance (NMR), and large-view splicing SEM were conducted to quantitatively characterize the pore throat size and fluid occurrence characteristics of the two types of reservoirs. The NMR experimental results and the HPMI experimental results before and after extraction of the original samples and the pressurized oil-saturated sample were compared to reveal the distributions of bound and movable fluids within pores of different sizes. The results indicate that sandstone and shale do not differ significantly in the sizes of pores and throats, which are dominantly 0.01-10.00 μm in pore diameter and <10.00 nm in throat radius, respectively, indicative of mesopores and fine throats. Shale has slightly larger pore diameters but smaller throat radii than sandstone. Shale mainly develops tubular pores such as intercrystalline pores and honeycomb-like dissolution pores. Sandstone has an equal distribution of tubular and spherical pores, with the proportion of spherical pores such as intergranular pores and intergranular dissolution pores increasing as the pore size increases. Fluid occurrence and mobility are controlled by multiple factors such as mineral composition and pore size. The oil-wet properties of organic matter, dolomite and pyrite, and the strong capillary confinement of intergranular pores in clay minerals, reduce the mobility of shale oil, and the movable fluids are mainly distributed in mesopores-macropores with diameters greater than 300 nm. Combining the reservoir physical properties and movable fluid distribution, it is determined that the favorable shale oil block in the study area is the Ma 51X well block, both shale and sandstone in the well block are favorable targets for development. Table and Figures | Reference | Related Articles | Metrics

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Exploration Breakthrough and New Insights of Baijiantan Formation in Mahu Sag and Its Periphery BIAN Baoli, SU Dongxu, JIANG Wenlong, WANG Xueyong, PAN Jin, LIU Longsong, JIANG Zhongfa Xinjiang Petroleum Geology    2024, 45 (3): 296-305.   DOI: 10.7657/XJPG20240306 Abstract （235）   HTML （13）    PDF（pc） （22055KB）（129）       Knowledge map    Save In order to clarify sandbody distribution patterns and hydrocarbon accumulation model of the Baijiantan formation in the Mahu sag, Junggar basin, and evaluate its hydrocarbon exploration prospects, the drilling, logging, seismic and experimental data were comprehensively analyzed to understand the sedimentary patterns and hydrocarbon accumulation characteristics of the second member of the Baijiantan formation (Bai-2 member). It is found that the Bai-2 member represents a braided-river delta-beach bar-turbidite fan sedimentary sequence, with three types of sandbodies of underwater distributary channel, beach bar and turbidite fan. Channel sandbodies are dominant in braided-river delta front; beach bar sandbodies are developed in shore-shallow lake; controlled by slope breaks, multiple turbidite fans are developed in deep lake to semi-deep lake, with turbidite fan sandbodies distributed in a lobate pattern. Thus, a sedimentary pattern of underwater distributary channel-beach bar-turbidite fan was established. Nine major strike-slip fault systems are found in the study area. Among them, three types of fault combinations such as through-type, associated-type, and relay-type strike-slip faults effectively connect the Permian Fengcheng formation source rocks and serve as efficient vertical pathways for hydrocarbon migration. The Bai-2 member follows a hydrocarbon accumulation model characterized by strike-slip faults connecting source rocks, fault-sandbody configuration controlling reservoir, and hydrocarbon enrichment in high-quality reservoirs. Table and Figures | Reference | Related Articles | Metrics

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In-situ Stress Characteristics and Fracture Distribution Prediction of Different Segments in Shunbei No.4 Strike-Slip Fault Zone, Tarim Basin HUANG Chao, GUO Honghui, ZHANG Shenglong, ZHU Lintao, FENG Jianwei, DU He Xinjiang Petroleum Geology    2025, 46 (1): 1-12.   DOI: 10.7657/XJPG20250101 Abstract （233）   HTML （13）    PDF（pc） （4213KB）（237）       Knowledge map    Save Based on the development background of the strike-slip fault zone in the Shunbei area of the Tarim Basin, the in-situ stress states, the fracture systems around faults, and the well productivity characteristics in different segments of the Shunbei No.4 strike-slip fault zone were analyzed by using geomechanical theories. According to the reservoir mechanical properties obtained through P-wave and S-wave logging and rock mechanics experiments, a 3D geomechanical model was constructed. Based on the elastoplastic theory, and by using the finite element numerical simulation method, the fracture development characteristics of the target layer controlled by the strike-slip faults were predicted. The research results show that the in-situ stress patterns vary across segments in the fault zone. The differences in structures of geological units control the in-situ stress distribution, and regions with high fracture density typically exhibit a strip-like distribution on both sides of the fault or between faults. High fracture density combined with Anderson-type Ⅰa and Ⅲ stress states is associated with wells exhibiting high yields. The in-situ stress conditions, fracture development characteristics, and key factors controlling high well productivity in different segments in the Shunbei strike-slip fault zone were clarified. Table and Figures | Reference | Related Articles | Metrics