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Development Status of Logging-Based Lithology Identification Technology for Shale Formations CHEN Xiujuan, FENG Zhentao, ZENG Furong, HU Jianbo, XU Song Xinjiang Petroleum Geology    2024, 45 (6): 742-752.   DOI: 10.7657/XJPG20240614 Abstract （797）   HTML （10）    PDF（pc） （1009KB）（677）       Knowledge map    Save Shale reservoirs contribute the most promising unconventional oil and gas resources in China and have become a hotspot in unconventional oil and gas exploration and development. Shale formations in China are mostly continental, with varying lithologies, diverse minerals, poor physical properties, strong heterogeneity, and poor continuity. These characteristics make it difficult to accurately identify lithology only using conventional logging interpretation methods, which in turn hinders the effective characterization of shale reservoirs and severely constrains reserves estimation and oil/gas development activities. In order to effectively identify the lithology of shale formations, the logging-based lithology identification technologies at home and abroad were systematically reviewed, and the lithology identification technologies based on logging interpretation and logging techniques were introduced. The logging lithology identification technologies based on machine learning were dissected in respect to their principles, advantages, disadvantages, and applicability. Finally, the prospects of logging-based lithology identification technologies for shale formations were proposed. Table and Figures | Reference | Related Articles | Metrics

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Optimization of Perforation in CBM Horizontal Wells in Southern Qinshui Basin LI Kexin, ZHANG Cong, LI Jun, LIU Chunchun, YANG Ruiqiang, ZHANG Wuchang, LI Shaonan, REN Zhijian Xinjiang Petroleum Geology    2024, 45 (5): 581-589.   DOI: 10.7657/XJPG20240510 Abstract （903）   HTML （14）    PDF（pc） （766KB）（632）       Knowledge map    Save To enhance the fracturing performance of coalbed methane (CBM) horizontal wells in the Qinshui basin, by analyzing the data of distributed optical fiber monitoring of water and gas production profiles, mud log, and well logging, the key factors influencing the fracturing performance were identified. These factors include coal quality, coal structure, drilling position, and perforation method. The middle to upper part of coal seam No. 3 in the Qinshui basin, characterized by low GR values, high coal quality, and intact coal structure, is identified as the optimal interval for fracturing stimulation. Based on the double GR curves, the drilling position of horizontal wellbore trajectory in the coal seam can be accurately determined, aiding in the selection of optimal fracturing interval and perforation method. When the drilling position is located in the middle part of the coal seam, conventional perforation method can be efficient. When the drilling position approaches the roof or is beyond the seam, downward directional perforation is preferred to effectively stimulate the high-quality upper part of the coal seam. When the drilling position is near the lower dirt band, upward directional perforation is advisable to target the high-quality middle part of the coal seam. Field application to 46 horizontal wells demonstrated that the single well production exceeded 2.5×104 m3/d and was stabilized at 2×104 m3/d, and the reservoir fracturing efficiency increased by 10% to 50%, recording a satisfactory development effect of the horizontal wells. Table and Figures | Reference | Related Articles | Metrics

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Identification and Productivity Prediction of High-Quality Reservoirs in the Metamorphic Buried Hills of the Bozhong 19-6 Structure TAN Zhongjian, GUO Kangliang, WU Liwei, ZHANG Guoqiang, LI Hongru, DENG Jinhui, BI Hongri Xinjiang Petroleum Geology    2025, 46 (1): 57-63.   DOI: 10.7657/XJPG20250107 Abstract （691）   HTML （10）    PDF（pc） （3783KB）（605）       Knowledge map    Save In the Bozhong 19-6 structure, fractures serve as the primary flow channels and storage spaces in the metamorphic buried-hill reservoirs, significantly controlling the formation of high-quality reservoirs and well productivity. To accurately identify high-quality reservoirs in the Bozhong 19-6 structure and predict their productivity, fractures were quantitatively characterized using thin sections, imaging logs, and other data. Based on the division of vertical structural units within the buried-hill reservoirs, high-quality reservoirs in the target intervals were identified using conventional mud log, wireline and imaging logging data. The reservoirs were finely evaluated by introducing fracture development index and comprehensive index methods and then a comprehensive method for identifying high-quality reservoirs was established. By substituting the effective thickness and fracture parameters of the high-quality reservoir into productivity evaluation equation, the gas layer productivity of the target intervals was calculated and compared with the test results. It is found that the relative error between the predicted productivity index per meter and the actual productivity values is less than 15%, which indicates a high feasibility of this comprehensive evaluation method in identifying high-quality reservoirs in metamorphic buried hills. This study offers a guidance for oil and gas development in the metamorphic buried hills in the Bozhong 19-6 structure. 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 （668）   HTML （25）    PDF（pc） （4213KB）（567）       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

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Exploration History and New Frontiers of Oil and Gas in Deep to Ultra-Deep Carbonate Reservoirs in Tarim Basin CAO Zicheng, GENG Feng, REN Lidan, JIANG Huashan, SHANG Kai, LIU Yongli Xinjiang Petroleum Geology    2025, 46 (4): 395-402.   DOI: 10.7657/XJPG20250401 Abstract （581）   HTML （37）    PDF（pc） （1595KB）（505）       Knowledge map    Save Deep to ultra-deep carbonate reservoirs have become a critical component for increasing hydrocarbon reserves and production in the Tarim Basin, and represent a pivotal direction for future exploration. This paper systematically reviews the geological theories of hydrocarbon accumulation and summarizes the exploration achievements in the Tarim Basin. The exploration of deep to ultra-deep marine carbonate reservoirs in the Tarim Basin can be primarily divided into four stages: the buried-hill reservoir exploration stage (1984-1996), the karst fractured-vuggy reservoir exploration stage (1997-2015), the fault-controlled fractured-vuggy reservoir exploration stage (2016-2020), and the new frontier and new type reservoir exploration stage (2021-present). Through an integrated analysis on geological conditions, exploration trends, and potential reserves-enhancing areas, several key prospects were identified, including fault-controlled fracture-cavity zones in the Shunbei area, multi-type fracture-cavity zones in the Tabei area, composite fracture-cavity zones in the Tazhong area, composite fracture-cavity zones in the Maigaiti slope, and deep Sinian-Cambrian dolomites in the western margin of the Manjiaer depression. Table and Figures | Reference | Related Articles | Metrics

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Fracture Evolution and Mechanical Properties of Deep Shales Under Spontaneous Imbibition FANG Zheng, CHEN Mian, LI Ji, WEI Shiming, KAO Jiawei, MAO Yu Xinjiang Petroleum Geology    2025, 46 (2): 208-216.   DOI: 10.7657/XJPG20250210 Abstract （571）   HTML （8）    PDF（pc） （1539KB）（497）       Knowledge map    Save The mechanism of fracture propagation and changes in mechanical properties of deep shale reservoirs caused by the imbibition of fracturing fluid after hydraulic fracturing remain unclear. By CT scanning, continuous scratch testing, and overburden pressure porosity-permeability testing, as well as spontaneous imbibition experiments, the fracture propagation patterns, changes in rock mechanics, and variations in physical properties before and after imbibition were comprehensively evaluated. The results show that imbibition promotes the activation, propagation, and interconnection of shale beddings and pre-existing microcracks, forming a more complex fracture network to enhance reservoir porosity and permeability. The development of fracture and bedding plane reduce the overall strength and stability of rock, demonstrating a dual effect of improving fluid transport capacity while weakening mechanical performance. Under limited crack propagation conditions, the increase in porosity and permeability is modest. When a complex fracture network is developed, reservoir porosity and permeability significantly improve, and mechanical weakening becomes more pronounced. In the evaluation and stimulation design of unconventional reservoirs, it is essential to balance the fracture network induced by spontaneous imbibition to account for its impact on reservoir flow conditions and formation stability. Table and Figures | Reference | Related Articles | Metrics

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Characterization Method for Full-Size Pore Radius Distribution in Lianggaoshan Formation, Sichuan Basin ZHAO Ji’er, RAN Qi, XIE Bing, LAI Qiang, BAI Li, ZHU Xun Xinjiang Petroleum Geology    2025, 46 (2): 181-191.   DOI: 10.7657/XJPG20250207 Abstract （397）   HTML （8）    PDF（pc） （3296KB）（470）       Knowledge map    Save The shale reservoirs of Lower Jurassic Lianggaoshan formation in the Sichuan Basin are well-developed, with nanoscale pores. These reservoirs are characterized by low porosity, low permeability, diverse pore types, complex pore structures, and a wide range of pore radius distribution. Therefore, accurately evaluating pore structure of shale reservoirs is of great significance for reservoir evaluation and sweet spot prediction. Using the data from scanning electron microscopy (SEM), gas adsorption experiments, and nuclear magnetic resonance (NMR) experiments, the pore structures of different lithofacies in the Lianggaoshan formation were characterized. The calculation models for pore radius distribution based on N2 and CO2 adsorption were defined，and the surface relaxation rate, a conversion parameter between pore radius and transverse relaxation time, was determined to enable the characterization of full-size pore radius across lithofacies. And the relationship between surface relaxation rate and mineral contents was investigated. The results show that the surface relaxation rate is inversely proportional to the contents of quartz, plagioclase, and calcite, and directly proportional to the contents of potassium feldspar, siderite, and clay minerals. Chlorite, pyrite, and siderite are paramagnetic materials; as the concentration of paramagnetic ions increases, the magnetic susceptibility of these minerals increases, thereby enhancing the surface relaxation rate. 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 （573）   HTML （20）    PDF（pc） （5903KB）（446）       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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Shale Lithology Identification Based on Improved Random Forest Algorithm：A Case of Lucaogou Formation in Junggar Basin QIN Zhijun, CAO Yingchang, FENG Cheng Xinjiang Petroleum Geology    2024, 45 (5): 595-603.   DOI: 10.7657/XJPG20240512 Abstract （633）   HTML （7）    PDF（pc） （6023KB）（398）       Knowledge map    Save In the application of reservoir lithology identification, the efficiency, accuracy and effective information integration ability of machine learning algorithm have been fully verified, especially in unconventional reservoirs with strong heterogeneity such as shale. Based on the optimal selection of parameters such as natural gamma, T2 geometric mean, structural index, skeleton density index, density, and deep lateral resistivity, and using a random forest algorithm combined with recursive feature elimination (RF-RFE), major lithologies of the shale reservoirs in the Middle Permian Lucaogou formation in the Junggar basin were identified. Lithology prediction was conducted on the same dataset using conventional RF and support vector machine (SVM) algorithms, and the results were compared with those obtained from thin-section identifications. It is found that RF-RFE yields better results with only half of the logging parameters, and the parameters defined by optimal selection help reduce the algorithm’s running time. Thus, the use of RF-RFE algorithm can realize optimal selection of characteristic logging parameters, more accurate identification of shale lithology, and reduction of running time. The algorithm provides a new approach for complex lithology identification and multi-parameter selection. Table and Figures | Reference | Related Articles | Metrics

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CO2 Solubility Experiments and Prediction Model YANG Hongnan, YUE Ping, FAN Wei, ZHANG Wei, WANG Zhouhua, LI Danchen Xinjiang Petroleum Geology    2025, 46 (3): 360-366.   DOI: 10.7657/XJPG20250313 Abstract （473）   HTML （12）    PDF（pc） （936KB）（394）       Knowledge map    Save CO2 solubility is a critical parameter impacting the effects of CO2 injection for enhanced oil recovery (EOR) in low-permeability/tight reservoirs and CO2 storage in deep saline aquifers. By using a high-temperature, high-pressure visualized phase reactor, CO2 dissolution experiments were conducted to investigate the influences of formation temperature/pressure, formation water salinity, and multiphase fluid saturation on solubility of CO2 in crude oil-formation water systems. A prediction model for CO2 solubility in crude oil-formation water systems under formation temperature and formation pressure was developed by fitting experimental data. The results show that in crude oil-formation water systems, CO2 solubility is strongly influenced by pressure and fluid type, and higher pressure and oil saturation can promote CO2 dissolution. Both formation water salinity and temperature have minor impacts on solubility of CO2 in formation water. CO2 dissolution in crude oil exhibits multistage behaviors, and the CO2 solubility increases significantly with the increase of oil saturation. Moreover, CO2 solubility declines rapidly with increasing water saturation in oil-water systems and decreases slightly with increasing temperature. The solubility prediction model, derived from the fitting of experimental data, calculates CO2 solubility in two-phase systems via saturation-weighted contributions of the solubility in oil and water phases and the results show high consistency with the experimental results. Table and Figures | Reference | Related Articles | Metrics

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Classification of Sweet Spots in Shale Oil Reservoir of Lucaogou Formation in Jimsar Sag，Jurggar Basin QI Hongyan, WANG Zhenlin, ZHANG Yanning, LIN Jingqi, HU Xuan, SU Jing, XU Rui, CAO Zhifeng Xinjiang Petroleum Geology    2025, 46 (2): 127-135.   DOI: 10.7657/XJPG20250201 Abstract （812）   HTML （37）    PDF（pc） （3916KB）（374）       Knowledge map    Save The shale oil reservoir of Permian Lucaogou formation in the Jimsar sag of the Junggar Basin can be divided into two sweet spots from top to bottom. These sweet spots vary significantly in productivity and remain unclear for controlling factors, making sweet spot prediction challenging. By using geological, petrophysical experiment, logging, and formation testing data, the enrichment mechanisms of shale oil were identified, the main factors controlling sweet spots in the shale oil reservoir were investigated, sweet spot index was constructed, and a classification standard for sweet spots was established. The research results show that the dominant reservoir rocks in the sweet spots in the study area are silty-fine sandstone and psammitic dolomite, with good pore structure, relatively abundant free oil, and moderate brittleness. The development, distribution, and effectiveness of micro-fractures in the shale oil reservoir are influenced by formation overpressure. The sweet spots in the shale oil reservoir are mainly controlled by free oil saturation, formation overpressure, and brittleness index. The sweet spot index is greater than 45 for Class Ⅰ sweet spots, 25-45 for Class Ⅱ sweet spots, and less than 25 for Class Ⅲ sweet spots. Class Ⅰ and Class Ⅱ sweet spots are considered as prime targets for horizontal wells, while Class Ⅲ sweet spots are reserved for future development. Table and Figures | Reference | Related Articles | Metrics

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Interphase Mass Transfer in the Petroleum System During CCUS-EOR Process SU Jinchang, LIU Bin, LI Ruguang Xinjiang Petroleum Geology    2024, 45 (5): 590-594.   DOI: 10.7657/XJPG20240511 Abstract （629）   HTML （3）    PDF（pc） （524KB）（365）       Knowledge map    Save CO2 flooding is a technique that utilizes CO2 to enhance oil recovery (CCUS-EOR), and an effective means to reduce carbon emissions. To understand the interphase mass transfer in the petroleum system during CCUS-EOR, CO2/dry gas contact experiments were conducted to elucidate the changes in components of the petroleum system during the initial contact conditions at different pressures. The results indicate that during the initial contact between CO2 and oil, the interphase mass transfer for volatile and non-volatile components occurs through evaporative extraction, while the interphase mass transfer for intermediate components occurs through dissolution diffusion, which is stronger than evaporative extraction. As pressure increases, the volatile components show enhanced evaporative extraction, the non-volatile components reflect diminished evaporative extraction, and the intermediate components exhibit augmented dissolution diffusion. At relatively low pressure in the initial stage of gas injection, the interphase mass transfer of the petroleum system is dominated by evaporative extraction. As pressure increases, the mechanism of interphase mass transfer for volatile components shifts to dissolution diffusion. During the initial contact process between dry gas and oil, the interphase mass transfer for intermediate and non-volatile components is dominantly evaporative extraction. CO2 is more capable of evaporative extraction than dry gas. Table and Figures | Reference | Related Articles | Metrics

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Configuration Pattern of Combined Conventional Mercury Intrusion-Constant Rate Mercury Intrusion Curves and Its Indicative Significance DAI Jinyou, LEI Xizhen, PI Sha, SHEN Xiaoshu, CHEN Daixin Xinjiang Petroleum Geology    2024, 45 (6): 735-741.   DOI: 10.7657/XJPG20240613 Abstract （639）   HTML （10）    PDF（pc） （597KB）（363）       Knowledge map    Save Based on the configuration theory and the analytic hierarchy process (AHP), the configuration shapes of the combined conventional mercury intrusion-constant rate mercury intrusion (CMI-CRMI) curves were classified, and a universal three-segment configuration pattern for the curves was established. The indicative significance of this pattern to the pore-throat systems and their wetting hysteresis was clarified. The results show that the combined CMI-CRMI curves consist of three configuration segments: a, b, and c, which are interconnected but exhibit distinct shapes. The segment a displays an overlapping shape, indicative of a macro-pore-throat system, where the combined CMI-CRMI curve shows no wetting hysteresis. The segment b demonstrates a separated shape and can be subdivided into subsegments b1 and b2. Subsegment b1 indicates a meso-pore-throat system, where the CRMI intrusion curve shows no wetting hysteresis, but the CMI curve does. Subsegment b2 also indicates a meso-pore-throat system, where the combined CMI-CRMI curve shows wetting hysteresis. The segment c exhibits an overlapping shape, representing a micro-pore-throat system, where both the CMI and CRMI curves exhibit equal wetting hysteresis. The deformation of the mercury meniscus during CMI is concentrated in the segments b and c, while the deformation of the mercury meniscus during CRMI is concentrated in the segments b2 and c. Subsegment b1 in both the CMI and CRMI curves can be used for contact angle correction. This three-segment configuration pattern of the combined CMI-CRMI curves provides a significant guidance for segmental contact angle correction and pore-throat distribution characterization. Table and Figures | Reference | Related Articles | Metrics

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Research on Expansion Patterns of SAGD Steam Chambers Based on Time-Lapse Microgravity Monitoring Technology ZHENG Aiping, LIU Huan, HUANG Houchuan, ZHAO Jinghan, YANG Dengjie, MA Jianqiang, LI Xuan Xinjiang Petroleum Geology    2024, 45 (6): 680-686.   DOI: 10.7657/XJPG20240606 Abstract （611）   HTML （9）    PDF（pc） （1960KB）（334）       Knowledge map    Save To reveal expansion pattern of steam chambers in heavy oil reservoirs during steam-assisted gravity drainage (SAGD), the time-lapse microgravity monitoring technology was employed to investigate the expansion pattern of SAGD steam chambers in the heavy oil reservoirs of the Jurassic Qigu formation in the H well block of the Xinjiang oilfield. This technology provided residual gravity anomaly data reflecting the remaining density of the reservoir. Using these data, a 3D least-squares inversion was performed to accurately depict the vertical distribution of the steam chambers. Furthermore, a method for interpreting the relationship between the steam chamber expansion pattern and residual gravity anomalies was proposed. The results indicate that the evolution of the steam chambers can be divided into three stages: rising, lateral expansion, and downward expansion. The proposed method can effectively explain the expansion patterns of the steam chambers in five well groups in the H well block, and its accuracy and reliability were validated with well temperature data. The method reveals the expansion patterns of the SAGD steam chambers in the reservoirs, providing a technical support for the efficient development of heavy oil reservoirs and aiding in the optimization of production control measures. It also offers a theoretical and practical foundation for similar reservoir development. Table and Figures | Reference | Related Articles | Metrics

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Architecture Characterization of Sandy Braided River Reservoirs: A Case Study of Guantao Formation in Western Block 7 of Gudong Oilfield DU Juan, YIN Yanshu, WEN Bin, REN Li, WU Wei Xinjiang Petroleum Geology    2025, 46 (1): 39-47.   DOI: 10.7657/XJPG20250105 Abstract （557）   HTML （10）    PDF（pc） （1124KB）（328）       Knowledge map    Save The sublayers from N1g45 to N1g16 of the Guantao formation in western Block 7 of the Gudong oilfield are typical of braided river deposits, with complex internal sandbody architectures. A detailed analysis of the reservoir architecture is necessary to understand its impact on oil and gas development. By using the Miall’s architectural element analysis method, and constrained by modern braided river scale, the sandbody architecture was characterized. Combining dynamic and static methods, the reservoir architectures were validated, and their influences on waterflood performance and residual oil distribution were identified. The research results show that the study area exhibits sandy braided river deposits, mainly with four sedimentary architecture units: braided river channels, mid-channel bars, overbanks, and floodplains. The braided flow zone is 150-750 m wide, with a width-to-thickness ratio ranging from 47 to 74. Within the braided flow zone, there are four types of architectural patterns: braided river channel-braided river channel, mid-channel bar-mid-channel bar, braided river channel-mid-channel bar-braided river channel, and mid-channel bar-braided river channel-mid-channel bar. The mid-channel bars have average length of 250-350 m and average width of 110-140 m, with a length-to-width ratio of 2.20-2.50. The ratio of mid-channel bar area to channel area ranges from 0.36 to 0.51. The mid-channel bars typically develop 2-4 fall-silt seams with their extension ranging from 70 to 150 m, which are nearly horizontal, with interlayer dip angles between 0.9° and 2.3°. Production performance reveals that due to poor petrophysical properties at the edges of architecture units, oil and gas flows are impeded at the architectural junctions where residual oil will be enriched locally. In contrast, the main parts of the architecture units show good reservoir connectivity and development effects. 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 （658）   HTML （16）    PDF（pc） （4996KB）（317）       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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Causes Behind Low Recovery in Tight Sandstone Gas Reservoirs DAI Jinyou, LEI Xizhen, SHI Yangyang, PAN Zhiyang, SHEN Xiaoshu, ZHANG Lijuan, ZHOU Xiaofeng Xinjiang Petroleum Geology    2025, 46 (2): 224-230.   DOI: 10.7657/XJPG20250212 Abstract （509）   HTML （6）    PDF（pc） （1762KB）（309）       Knowledge map    Save To identify the causes behind low recovery in tight sandstone gas reservoirs, taking the Shan 2 gas reservoir in the Zizhou gas field as an example, and based on the definition of recovery for gas reservoirs, a zonal reserves producing model and an analytical theoretical model for recovery were established. With the 2 models, the recovery of the gas reservoir was calculated, and the causes behind the low recovery in the tight sandstone gas reservoir were systematically analyzed. The results show that the low recovery in the Shan 2 gas reservoir is primarily attributed to the low vertical sweep coefficient, low plane sweep coefficient, and low gas displacement efficiency. The vertical sweep coefficient is mainly influenced by the vertical heterogeneity of the reservoir, the gas displacement efficiency is closely related to the abandonment pressure of the gas reservoir, while the plane sweep efficiency is primarily constrained by the horizontal heterogeneity of the reservoir and the controlling extent of well pattern. Rationalizing well pattern deployment and enhancing plane sweep coefficient are effective methods for increasing the recovery of tight sandstone gas reservoirs. However, even when the plane sweep coefficient is 100%, the ultimate recovery remains relatively low. Therefore, strengthening research on increasing vertical sweep coefficient and improving gas displacement efficiency is crucial for enhancing recovery in tight sandstone gas reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Shale Reservoir Brittleness and Its Evaluation Method ZHAI Yong, GUO Yaning, DING Yi, LI Yishan, CUI Yinuo, LI Bin, LIU Xiangjun Xinjiang Petroleum Geology    2025, 46 (1): 22-28.   DOI: 10.7657/XJPG20250103 Abstract （456）   HTML （14）    PDF（pc） （1823KB）（296）       Knowledge map    Save Shale oil and gas resources are abundant in China, and hydraulic fracturing to stimulate reservoir is a significant way to efficiently develop these resources. Brittleness is a key parameter for reservoir stimulation and a core indicator for identifying engineering sweet spots. Taking the shale reservoir in the Dongying sag as an example, the rock mechanical properties and brittleness characteristics of the shale reservoir were analyzed through uniaxial, triaxial, and high-temperature, high-pressure (HTHP) compressive tests. Based on the rock energy balance theory and brittleness characteristics, as well as the energy evolution behaviors before and after rock failure, a new method for evaluating shale brittleness was proposed. The research results show that under uniaxial conditions, the shale exhibits significant brittle failure with multiple cracks, which is beneficial for reservoir stimulation. In HTHP conditions, the synergistic effect of temperature and confining pressure suppresses rock brittle fracture but strengthens rock ductility, leading to a significant reduction in brittleness. Based on the proposed brittleness evaluation method, the primary factors controlling shale brittleness were identified. It is found that the rock physical parameters (porosity, density, and acoustic travel time) is weakly correlated with brittleness, while mineral composition and elastic parameters are more effective in assessing brittleness. The effects of temperature and pressure cannot be ignored. The research results are conductive to identifying engineering sweet spots in shale reservoirs and provide a theoretical foundation for efficient reservoir stimulation. 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 （668）   HTML （10）    PDF（pc） （3488KB）（283）       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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Microscopic Characteristics of and Gas Occurrence in Coal Rock in Benxi Formation, Ordos Basin HUANG Yougen, ZHENG Xiaopeng, ZHANG Daofeng, HU Weiwei, HE Mengqing, WANG Bing Xinjiang Petroleum Geology    2025, 46 (3): 253-262.   DOI: 10.7657/XJPG20250301 Abstract （633）   HTML （18）    PDF（pc） （6207KB）（275）       Knowledge map    Save Coal rock gas (CRG) in the Upper Carboniferous Benxi formation in the Ordos Basin is currently in the early stage of exploration and development, and knowledge regarding the coal rock’s microscopic composition, pore structure, and their controls on gas occurrence remains limited. By using techniques including petrographic microscopy, X-ray diffraction (XRD), micro-CT scanning, low-temperature CO2 adsorption, low-temperature N2 adsorption, high-pressure mercury intrusion, and high-pressure autoclave-gold tube pyrolysis simulation, etc., the maceral composition, industrial component, pore structure, and gas occurrence states in the No. 8 coal seam of the Benxi formation in the study area were investigated. The results show that the No. 8 coal seam is dominated by bright and semi-bright coals, with average vitrinite, inertinite, and exinite contents of 78.8%, 18.2%, and 1.0%, respectively. The coal rock exhibits an average fixed carbon content of 70.00% and an ash content of 13.90%, indicative of low-ash coal. The micropores, mesopores, and macropores contribute 75.7%, 14.4%, and 9.9% to the total pore volume, respectively, while their specific surface area proportions are 98.3%, 1.0%, and 0.7%, respectively. The micropores contribute the most to both total pore volume and specific surface area. The adsorbed gas and free gas account for 74.7% and 25.3% of the total gas content, respectively. The adsorbed gas content is positively correlated with micropore volume and micropore specific surface area, while the free gas content shows an approximately positive correlation with macropore volume. Table and Figures | Reference | Related Articles | Metrics

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Grading Evaluation of Jurassic Ultra-Deep Tight Sandstone Reservoirs in Yongjin-Zhengshacun Area, Junggar Basin WANG Chunwei, YANG Jun, ZHAO Dongrui, DU Huanfu, SUN Xin, WANG Yelei, MENG Fanghua Xinjiang Petroleum Geology    2025, 46 (1): 48-56.   DOI: 10.7657/XJPG20250106 Abstract （708）   HTML （10）    PDF（pc） （5722KB）（274）       Knowledge map    Save The Jurassic ultra-deep sandstone reservoirs in the Yongjin-Zhengshacun area of the Junggar Basin are tight and heterogeneous, and the standards for evaluating these reservoirs and the favorable reservoir distribution are unclear, restricting oil and gas exploration and development. Based on well logging, coring, and testing data, and by using mineral analysis, nuclear magnetic resonance (NMR), capillary pressure experiments, and core displacement tests, a study was conducted on the pore structure of the Jurassic reservoirs. The lower limit of movable pore radius was determined, and a grading evaluation standard was established with movable fluid porosity as the key indicator. The results show that the reservoir space in the medium- to fine-grained lithic and feldspathic sandstones is composed of intergranular pores, secondary dissolution pores, and microfractures, with small pore radii ranging from 0.005 to 5.000 μm. After calibrating the experimental capillary pressure curves, the lower limit of movable pore radius was determined as 0.100 μm through the NMR T2 spectrum at different displacement states, and then the movable fluid porosity of oil-bearing rocks was clarified. By comprehensively considering the lithoelectric characteristics, pore type and structure, and oil-bearing property, and combining the productivity characteristics of typical wells, a grading reservoir evaluation standard for the study area was established. Based on the standard the reservoirs were classified into Class Ⅰ, Class Ⅱ, and Class Ⅲ. The evaluation provides a basis for subsequent oil and gas field development and well deployment, and offers valuable insights for the exploration and development of ultra-deep tight oil reservoirs in the study area and for reservoir evaluation in neighboring areas. Table and Figures | Reference | Related Articles | Metrics

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Water Production Characteristics and Water Control Practices in T3X2 Fractured and Watered Gas Reservoir in Xinchang Structural Belt, Sichuan Basin ZENG Hui, YI Ting, LI Xingwen, YUAN Yue, YANG Ai, XIANG Lei Xinjiang Petroleum Geology    2025, 46 (2): 246-252.   DOI: 10.7657/XJPG20250215 Abstract （435）   HTML （10）    PDF（pc） （1183KB）（271）       Knowledge map    Save The T3X2 gas reservoir in the Xinchang structural belt, Sichuan Basin, suffers a lot of challenges such as widespread water production, complex water production characteristics, unclear water invasion patterns, and a lack of effective water control strategies, affecting the stable production. Based on geological data and production performance from the gas reservoir, and using the theories/techniques of gas reservoir engineering, orthogonal experiments and development practices, the water production characteristics of the gas reservoir were analyzed, typical water invasion patterns were clarified, and water control strategies for gas wells were proposed. The results show that the T3X2 gas reservoir has 5 types of water production which can be identified by plotting charts. The water invasion patterns are classified into: rapid water channeling along fractures and slow water advancing. The degree of fracture development and the scale of fracturing treatments are the key factors influencing water invasion pattern. For the pattern of rapid water channeling along fractures, controlling pressure difference and balancing water drainage are critical, while for the pattern of slow water advancing, rationalizing production system and localized water blocking are recommended. Table and Figures | Reference | Related Articles | Metrics

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Application of Logging Data Wavelet Transform and Pseudo-Imaging to Fine Division of Deep Barrier/Interlayer SHAO Cairui, WANG Meng, CHANG Lunjie, WANG Kaiyu, ZHANG Fuming, WANG Chao Xinjiang Petroleum Geology    2024, 45 (5): 611-621.   DOI: 10.7657/XJPG20240514 Abstract （499）   HTML （10）    PDF（pc） （1474KB）（269）       Knowledge map    Save Barrier/interlayer is a key factor that significantly affects fluid flow and controls the distribution of oil and water, and it serves as a crucial evidence for understanding the distribution of remaining oil. Barrier/interlayer in deep strata is difficult to identify due to the high coring cost, large depth error in logging data, low resolution of conventional logging curves, and ambiguous signals from thin interbeds. Through core analysis of key wells, the logging curves sensitive to barrier/interlayer and their response characteristics were identified. By employing wavelet decomposition and reconstruction, the conventional sensitive logging curves were processed with high resolution, which reduced the smoothing effect of adjacent layers and highlighted the logging response characteristics of thin layer interfaces, making thin layer identification resolution enhanced by nearly 100%. By integrating the vector pattern of formation dip and pseudo-imaging characteristics of barrier/interlayer, a method for identifying and dividing deep barrier/interlayer was established. Actual applications demonstrate that this method allows for precise identification of barrier/interlayer, with a much higher capability than conventional methods. This method yields an accuracy of layer correlation between wells increased by 38%, elucidating the issue of inclined oil-water contact and providing remaining oil distribution. Table and Figures | Reference | Related Articles | Metrics

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Geological Characteristics and Petroleum Exploration of Shiqiantan Formation in Shiqiantan Sag, Junggar Basin HE Changsong, WANG Bingqian, WEI Shuangbao, PU Zhenshan, WANG Lilong, MA Qiang, ZHANG Wei Xinjiang Petroleum Geology    2024, 45 (6): 642-649.   DOI: 10.7657/XJPG20240602 Abstract （571）   HTML （16）    PDF（pc） （3399KB）（268）       Knowledge map    Save Well S3 drilled in the gentle slope zone of the eastern Shiqiantan sag in the east uplift of the Junggar basin, has produced a high-yield industrial gas flow from the Carboniferous Shiqiantan formation. This significant breakthrough in natural gas exploration in the Shiqiantan formation further confirms the presence of a marine clastic-rock sag rich in natural gas in the eastern Junggar basin. To better understand the geological characteristics and petroleum exploration potential of the Shiqiantan formation in the Shiqiantan sag, a comprehensive study of source rocks, reservoirs, and hydrocarbon accumulation was conducted using seismic, drilling, logging, core, and testing data. The Shiqiantan formation in the study area contains two sets of source rocks, which are generally thick and of high quality, providing a solid material basis for large-scale gas reservoir development. The reservoirs in the Shiqiantan formation are typically composed of tight sandy conglomerate in which a fan delta system with bidirectional provenances in the south and north is found. Large scale delta-front sand bodies are mainly distributed in the slope zone around the sag. The Shiqiantan formation hosts near-source tight lithological sandstone gas reservoirs, making it the key target for gas exploration in the Carboniferous of the Shiqiantan sag. It has favorable source-reservoir assemblages jointly controlled by proximity to the source and sand body size. Table and Figures | Reference | Related Articles | Metrics

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Occurrence State of Water in Ultra-Low Permeability Gas Reservoirs and Its Impact on Development of A Gas Field LIAO Hengjie, LOU Min, HE Xianke, DUAN Dongping, WANG Wenji, LI Yuansheng, LIU Binbin Xinjiang Petroleum Geology    2025, 46 (1): 88-96.   DOI: 10.7657/XJPG20250111 Abstract （539）   HTML （6）    PDF（pc） （895KB）（259）       Knowledge map    Save Ultra-low permeability gas reservoirs are complex in gas-water contact, and differ significantly in formation water occurrence state from conventional gas reservoirs. The occurrence state of formation water and the water saturation in such reservoirs were determined through mercury intrusion experiments and relative permeability tests, and the gas-water segregation was analyzed using the trap closure height method. Logging curves were used to predict the distribution of formation water saturation in different states for a single well, and the impact of formation water on productivity was assessed. The results show that the formation water in the study area mainly consists of strongly bound water and weakly bound water, with a small amount of movable water. No distinct gas-water segregation was observed. The clay water film is a key component of strongly bound water. In fine sandstone and the sandstone with high content of carbonate cements, the saturation of weakly bound water is higher. The movable water saturation in the study area is generally less than 6%, and the initial water production is low, exerting slight impact on productivity. Table and Figures | Reference | Related Articles | Metrics

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Identification and Modeling of Micro-Minor Fractures in Thin Biolimestones in Wangxuzhuang Oilfield LI Yunpeng, LIN Xuechun, YU Xingchen, KANG Zhihong, LI Peijing, WANG Yajing, QI Aiping Xinjiang Petroleum Geology    2024, 45 (6): 671-679.   DOI: 10.7657/XJPG20240605 Abstract （496）   HTML （9）    PDF（pc） （5000KB）（258）       Knowledge map    Save Micro-minor fractures represent a key type of reservoir space in the thin biolimestones of the Shahejie formation in the Wangxuzhuang oilfield. Due to the lack of effective measurement methods and characterization techniques, it is challenging to understand these fractures, thereby hindering accurate prediction of fluid flow capacity during oil and gas development. By integrating the data of core samples, thin sections, CT scanning, formation micro-resistivity imaging (FMI) logging, and conventional logging, the development of micro-minor fractures was investigated. With a PSO-BP neural network, the fracture development and distribution in the fractured reservoirs of the study area were predicted. Then a discrete fracture network modeling approach was proposed to simulate the spatial distribution of these fractures. The results show that the biolimestone with developed micro-minor fractures exhibits significant amplitude differences between shallow and deep lateral resistivity readings. Micro-minor fractures are well developed in the biolimestones in the study area, which play a crucial role in improving reservoir physical properties and waterflood response directions. These fractures are controlled by fault zones and sedimentary microfacies of the biolimestone. Numerical simulation confirms that the dual-porosity dual-permeability model incorporating micro-minor fractures can provide a better fit for the dynamic behavior of oil-water relations. Table and Figures | Reference | Related Articles | Metrics

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Experimental Study on Oil Displacement Efficiency by Different Fluids in Low-Permeability Sandstone Reservoirs CHEN Chao, YAN Xiaolong, LUO Xiaojing, ZHEN Yanming Xinjiang Petroleum Geology    2025, 46 (1): 105-113.   DOI: 10.7657/XJPG20250113 Abstract （511）   HTML （4）    PDF（pc） （1769KB）（258）       Knowledge map    Save In the middle-late stage of waterflood development in low-permeability sandstone reservoirs in the eastern margin of the Junggar Basin, the development performance deteriorates, and the water cut increases, necessitating new effective development techniques. Different fluids were selected for oil displacement efficiency experiments. Using long cores and under simulated formation conditions, oil displacement experiments were performed for waterflooding and gas flooding with N?, CH?, and CO? after waterflooding till achieving the current recovery efficiency of the reservoir. Nuclear magnetic resonance scanning and oil-containing pore size inversion were conducted on cores before and after injection of different fluids. The results show that CO? flooding can increase the recovery factor by 21.58%. The fluids rank as CO?, CH?, H?O, and N? in a descending order of oil displacement efficiency and producing degree. N? flooding primarily recovers oil from larger pores, with the lower limit of pore size being 170.9 nm. CH? flooding primarily mobilizes oil from medium to large pores, with the lower limit of pore size being 48.7 nm. CO? flooding can extract oil from pores of all sizes, with the lower limit of pore size being 27.8 nm, the lowest level among the processes tested. A CO? flooding pilot test zone was established in the oilfield. After CO? injection, the liquid production increased, the water cut decreased, and the oil production improved, suggesting good field application. Table and Figures | Reference | Related Articles | Metrics

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Efficient Development Strategy for Ultra-Deep Fault-Controlled Volatile Reservoirs in Shunbei Oilfield REN Wenbo, LIU Diren, LI Xiaobo, CAO Fei, LIU Xueli, DAI Jincheng Xinjiang Petroleum Geology    2025, 46 (4): 448-456.   DOI: 10.7657/XJPG20250407 Abstract （347）   HTML （13）    PDF（pc） （2606KB）（253）       Knowledge map    Save The ultra-deep fault-controlled volatile reservoirs in Shunbei oilfield are characterized by great burial depth, significant thickness, and tabular distribution, with weak natural energy and rapid decline in both pressure and production during development. Early practice revealed that rapid water injection and high-rate gas injection tend to induce channeling through high-conductivity pathways between wells, compromising displacement efficiency and sweep volume. This paper presents a 3D composite gas-water injection-production strategy. To be specific, water injection is supplemented with gas injection for energy replenishment, so that injector-producer patterns are established with injecting water at lower position and producing oil from higher position, and injecting gas into higher position and producing oil from lower position, forming a 3D well pattern for composite gas-water injection and production. Water injection targets the unswept oil between wells and in middle-lower zones around wellbores, while gas injection displaces the oil at the top, thereby enhancing displacement efficiency and expanding sweep volume to ensure a long-term energy stability of the reservoir. Guided by this strategy, a typical composite gas-water drive unit is projected to enhance oil recovery by 26.0%, restore reservoir pressure by 9.0 MPa, reduce the gas-oil ratio to 820 m3/t, and increase flowing pressure to 45 MPa. Table and Figures | Reference | Related Articles | Metrics

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Lower Limits of Physical and Electrical Properties of Low to Ultra-Low Permeability Gas Reservoirs HU Xiangyang, WU Jian, YANG Dong, ZHANG Heng, TAN Wei, YUAN Wei Xinjiang Petroleum Geology    2025, 46 (1): 29-38.   DOI: 10.7657/XJPG20250104 Abstract （487）   HTML （7）    PDF（pc） （3825KB）（250）       Knowledge map    Save The low to ultra-low permeability reservoirs in the DF A and WC X/Y blocks, western South China Sea, are characterized by complex microscopic structures, making it difficult to understand the lower limits of reservoir physical and electrical properties. Through core single-phase displacement experiments under various pressure differences, and core capillary pressure-lithoelectric experiments at high temperature and high pressure, the lower limits of porosity, permeability, saturation, and resistivity of these low to ultra-low permeability gas reservoirs were examined. On this basis, the variations of the lower limits of these reservoir properties were discussed. The results show that the cores obtained from the gas reservoirs in the DF A block have the physical properties which are positively correlated with gas flow rate, and the cores from the ultra-low permeability gas reservoirs in the WC X/Y block exhibit very low gas flow rate, which couldn’t be improved significantly as the pressure difference was increased. In the presence of irreducible water, as the differential pressure for production increased, the lower limits of porosity and permeability of cores from both blocks declined gradually. As the physical properties of the reservoirs improved, the upper limit of water saturation became lower. As the reservoir physical properties improve, the cores from the DF A block demonstrated an increasing lower limit of resistivity, while the cores from the WC X/Y block reflected a decreasing lower limit. It is supposed that the reason should be attributed to different pore structures and fluid occurrence states of the reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Microscale Salt Tolerance and Profile Control of CO2 Foam in High-Salinity, Low-Permeability Reservoirs WEI Hongkun, WANG Jian, WANG Danling, LU Yuhao, ZHOU Yaqin, ZHAO Peng Xinjiang Petroleum Geology    2024, 45 (6): 703-710.   DOI: 10.7657/XJPG20240609 Abstract （683）   HTML （6）    PDF（pc） （1786KB）（248）       Knowledge map    Save Regarding gas channeling during CO2 flooding in high-salinity, low-permeability reservoirs, taking the H3 block of Changqing oilfield as an example, an enhanced CO2 foam system with SiO2 nano-particales was constructed to evaluate its salt tolerance with respect to foam rheology, gas-liquid interfacial tension, liquid film thickness and permeability, and foam microstructure. A parallel core displacement experiment was conducted for the foam system to assess its profile control performance. Based on the experimental results, a foam system of 0.20%(OW-1)+0.30%(OW-4)+0.05%(SiO2) was developed under reservoir conditions, achieving a comprehensive index of 36,834 mL·min. The microscale salt tolerance evaluation indicates that, as compared with the foaming agents prepared at salinity of 46,357 mg/L and 500 mg/L, the developed foam system exhibits better rheological properties. The gas-liquid interfacial tension increased by only 1 mN/m at 10 MPa, and the liquid film permeability was improved by 0.14 cm/s. However, the foam system still maintains a robust skeletal structure. Thus, it is demonstrated with excellent salt tolerance at the microscale. Furthermore, for parallel cores with the permeability ratio of 15.55, the developed SiO2 nanoparticle-enhanced CO2 foam system improves the core profile by 97.28%, suggesting a remarkable enhancement in oil recovery, and demonstrating a good profile control performance. Table and Figures | Reference | Related Articles | Metrics

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Geological Characteristics and Development Technologies of Shale Gas Field in Anchang Area, Guizhou Province LIU Honglin, LU Dan, LIANG Feng, HE Xinbing, LI Gangquan, ZHAO Qun, BAI Wenhua Xinjiang Petroleum Geology    2025, 46 (1): 78-87.   DOI: 10.7657/XJPG20250110 Abstract （813）   HTML （3）    PDF（pc） （3888KB）（247）       Knowledge map    Save The shale gas field in Anchang area in the northern part of Guizhou province is primarily producing from the shales in the Wufeng formation to Longmaxi formation. This gas field is characterized by a source-reservoir integrated system in stable distribution and self-generation and self-storage pattern, and it is classified as a shallow mountainous shale gas field under normal pressure. From top to bottom, the gas-bearing layers show an increasing content of siliceous minerals and a decreasing content of clay minerals. The shale reservoir space primarily consists of nanometer-scale organic pores, followed by residual intergranular pores, intercrystalline pores, secondary dissolution pores, and clay mineral interlamellar pores. The gas wells generally exhibit low flowback rates upon gas breakthrough, slow production decline, and long stable production period. Considering the geological and developmental characteristics of this type of gas reservoir, it is important to enhance detailed geological modeling and fracturing design optimization, as well as to moderately expand well spacing. Given the presence of faults and strong heterogeneity, integrated geological and engineering design should be strengthened, and the 3D reservoir geological model should be iteratively optimized to establish an accurate shale gas reservoir model. In view of the large differential horizontal stress ratios and the difficulty in forming complex fracture networks, fracturing stage length and cluster spacing should be optimized, and multi-cluster fracturing and fracture diversion techniques can be implemented. For low reservoir pressure, fast decline in wellhead pressure, and low gas production, the flowback management system in the gas testing stage should be further optimized. Table and Figures | Reference | Related Articles | Metrics

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Identification and Analysis of Inter-Well Frac-Hit in the Tight Oil Reservoir of Jinlong 2 Well Block, Junggar Basin HUANG Houchuan, CAO Xiaolu, LI Ning, JIA Yufeng, WU Guolong, JU Shichang Xinjiang Petroleum Geology    2025, 46 (2): 201-207.   DOI: 10.7657/XJPG20250209 Abstract （527）   HTML （11）    PDF（pc） （741KB）（246）       Knowledge map    Save The tight oil reservoir in the Jinlong 2 well block in the Zhongguai bulge, western uplift of the Junggar Basin, is developed by horizontal well hydraulic fracturing. Frequent inter-well frac-hit caused by the large-scale well infilling and the presence of fault zones in the reservoir impedes production efficiency greatly. By investigating the applicability of monitoring and identification methods for inter-well frac-hit in multi-stage fractured horizontal wells, and combining field fracturing monitoring and production data from the Jinlong 2 well block, a comprehensive identification workflow for inter-well frac-hit was established. This workflow which integrates production performance, fracturing operation, and microseismic characteristics was used to identify and analyze inter-well frac-hit in the study area. The results show that severe inter-well frac-hit exists in the Jinlong 2 well block, not only within but also across individual horizons and fault blocks. The relatively small horizontal well spacing and developed fault system in the reservoir in the Jinlong 2 well block may induce inter-well frac-hit. It is recommended to avoid well infilling in large-scale fault zones and reduce fracturing scale for infill wells. 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 （869）   HTML （14）    PDF（pc） （794KB）（246）       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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Research and Application of a New Method for Dynamic Diagnosis of Gas-Cap Reservoirs WU Ruidong, WANG Rui, MA Lian, ZHANG Chunguang, SONG Gangxiang, SHI Meixue, LU Ying Xinjiang Petroleum Geology    2024, 45 (5): 574-580.   DOI: 10.7657/XJPG20240509 Abstract （757）   HTML （4）    PDF（pc） （1046KB）（239）       Knowledge map    Save During the development of gas-cap reservoirs, crude oil, dissolved gas, gas-cap gas, condensate oil, and formation water may be produced simultaneously. Accurately calculating formation pressure and recovery percent of each phase is crucial for dynamic diagnosis and potential tapping of remaining oil and gas in such reservoirs. Current methods for calculating formation pressure fail to take water invasion into consideration, leading to uncertainty in production splitting, which increases the risks in subsequent adjustment and potential tapping. Through water influx fitting and Newton iteration methods, a new method for dynamic diagnosis of gas-cap reservoirs based on water invasion characteristic analysis and average formation pressure prediction was established. The application of this method in the Y3 gas-cap reservoir in the M oilfield indicates that crude oil and condensate oil account for 89.7% and 10.3% in the produced oil, respectively, and the produced gas contains 97.9% gas-cap gas and only 2.1% dissolved gas. The recovery efficiency of gas-cap gas and condensate oil is as high as 46.6% and 31.2%, respectively, while the recovery efficiency of crude oil and dissolved gas is merely 12.1% and 1.7%, respectively. These results are consistent with production test results. Table and Figures | Reference | Related Articles | Metrics

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Analysis on Water Invasion Patterns and Sensitivity of Drainage Parameters in Fractured Gas Reservoirs With Edge/Bottom Water HU Shuyong, LIU Han Xinjiang Petroleum Geology    2025, 46 (4): 478-484.   DOI: 10.7657/XJPG20250411 Abstract （479）   HTML （7）    PDF（pc） （2297KB）（226）       Knowledge map    Save Fractured gas reservoirs with edge/bottom water usually suffer a series of problems, such as sharp decline in production upon water breakthrough, complex water production patterns, and difficult water-drainage gas recovery. Based on the geological parameters of the Dina gas field, the drainage indicators after water breakthrough were clarified through numerical simulation. Three water invasion patterns were identified: strong invasion along fractures, weak invasion along fractures, and weak water tonguing along fractures. On this basis, a multi-factor sensitivity analysis was conducted, the concept of dimensionless well spacing was introduced, and the impacts of factors such as drainage well output, drainage-production well spacing, gas production rate and water volume ratio on predicted cumulative gas production at the end of the forecast period were investigated. The research results show that for the pattern of strong invasion along fractures, the main factors affecting cumulative gas production are drainage volume, gas production rate, dimensionless well spacing, and water volume ratio in sequence, while for the pattern of weak invasion along fractures, gas production rate and drainage volume are key factors, with the influence sequence being gas production rate, drainage volume, dimensionless well spacing, and water volume ratio. Based on the results of the sensitivity analysis, the concept of the drainage-production ratio was further proposed, and the optimal drainage-production ratio for the gas reservoir were determined. 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 （603）   HTML （35）    PDF（pc） （7831KB）（224）       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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New Insights into Eruption Model of Huoshiling Formation Volcanic Rocks in Chaganhua Subsag of Changling Fault Depression XU Fangzhe, ZHU Jianfeng, LIU Yuhu, LENG Qinglei Xinjiang Petroleum Geology    2024, 45 (5): 533-540.   DOI: 10.7657/XJPG20240504 Abstract （564）   HTML （10）    PDF（pc） （7496KB）（215）       Knowledge map    Save The exploration and development practice has suggested that the volcanic rocks of the Huoshiling formation in the Chaganhua subsag of the Changling fault depression are distinct in rock types and lithologic assemblages from typical volcanoclastic rocks. Core samples and thin sections from the Huoshiling formation volcanic rocks reveal unique structures such as volcanic ash balls and quench-fractured breccia, with generally poor reservoir physical properties. Typical hummocky envelopes of volcanic edifice cannot be identified. All these phenomena indicate a potential unique eruption environment in this area. By analyzing seismic reflection characteristics, core descriptions, thin section features, and laboratory test results, typical indicators of the eruption environments were identified. Combining lithologic assemblages from existing wells and the regional tectonic setting, a volcanic eruption and deposition model for this area was established. The study reveals that the volcanic rocks in this area experienced three periods of eruption in onshore, land-water and underwater environments, respectively. Underwater volcanic rocks exhibit low aspect ratio, and is often in wide and gentle shield shape, with poorly developed primary pores, but developed dissolution and devitrification pores. The overall reservoir space is dominated by medium to small pores. The onshore volcanic rock strata are selected as exploration targets due to developed pores and good rock physical properties. Table and Figures | Reference | Related Articles | Metrics

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Factors Influencing Productivity of Edge Waterflood in Elongated Anticlinal Reservoirs XIE Qichao, TIAN Yafei, YUE Ping, SONG Peng, LIU Xinju, LIU Jian, LIU Wantao Xinjiang Petroleum Geology    2024, 45 (5): 560-566.   DOI: 10.7657/XJPG20240507 Abstract （590）   HTML （5）    PDF（pc） （2616KB）（215）       Knowledge map    Save The Y reservoir in the JY oilfield is a typical elongated anticlinal structure, where the injected water readily advances along channel centerline, resulting in rapid water-flooding and rapid production decline in producers. Development of such reservoirs is challenging due to unclear factors influencing productivity, such as water body size, structural amplitude, and reservoir physical property. To address these issues, a fine numerical model was established for the elongated anticlinal reservoir, and an “edge waterflood + progressive producer-injector conversion” process was proposed. On this basis, the influences of water body size, structural amplitude, and reservoir physical property on productivity were analyzed. The results indicate that the “edge waterflood + progressive producer-injector conversion” process enhances the edge water energy to allow for bidirectional responses of well patterns, and also delays water breakthrough in producers at the structural high to significantly reduce the water cut of oil well. Furthermore, considering the structural characteristics of the reservoir, the production performance under different factors were quantified, reasonable limits for the parameters such as water body size, structural amplitude, and the ratio of vertical permeability to horizontal permeability were defined, and the adaptability of reservoir area under different reservoir physical properties was demonstrated. The study results provide valuable insights for improving waterflood effects in similar reservoirs. 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 （929）   HTML （12）    PDF（pc） （1795KB）（214）       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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Fault/Fracture Characteristics and Production Strategies for Ultra-Deep Fractured Tight Sandstone Gas Reservoirs WANG Yanli, ZHU Songbai, WU Weimin, NIE Yanbo, LIN Na, ZHAO Ji, HUANG Rui Xinjiang Petroleum Geology    2025, 46 (2): 217-223.   DOI: 10.7657/XJPG20250211 Abstract （625）   HTML （11）    PDF（pc） （1142KB）（211）       Knowledge map    Save The Keshen gas field in the northern Kuqa depression of the Tarim Basin is a typical representative of ultra-deep fractured tight sandstone gas reservoirs. The intensifying water invasion has significantly affected the steady gas field development in recent years. Taking the Cretaceous Bashijiqike formation in the Keshen X gas reservoir as an example, the fault/fracture characteristics of the reservoir were analyzed using the drilling fluid loss and imaging logging data, and their controls over production performance were identified. Depending on production behaviors of various gas wells and water invasion patterns in the reservoir, a production performance model of the reservoir under fault/fracture control was established, and corresponding production strategies were proposed. The results show that microfractures are well developed in the Keshen X gas reservoir, and the reservoirs can be divided into three types by fault/fracture presence: multi-fracture, single-fracture and micro-fracture. Two wells targeting multi-fracture reservoirs are deployed in the middle-upper part of the Keshen X gas reservoir, four wells targeting single-fracture reservoirs in the middle and edge parts of the gas reservoir, and one well targeting micro-fracture reservoirs in the upper part of the gas reservoir. Based on production behaviors, gas wells can be classified into highly water-flooded wells, long-term water production wells, and long-term stable production wells without water breakthrough, corresponding to single-fracture reservoir, multi-fracture reservoir, and micro-fracture reservoir, respectively. It is recommended to maintain a moderate productivity for wells targeting multi-fracture reservoir, inject gas to replenish energy in the initial stage of water invasion for wells targeting single-fracture reservoir, and keep a proper production pressure differential for wells targeting micro-fracture reservoir. Table and Figures | Reference | Related Articles | Metrics

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Controls of Fractures and In-Situ Stress on Productivity in Strike-Slip Fault Zones in Shunbei Area, Tarim Basin HE Xinming, ZHANG Huitao, GUO Honghui Xinjiang Petroleum Geology    2025, 46 (4): 410-418.   DOI: 10.7657/XJPG20250403 Abstract （386）   HTML （14）    PDF（pc） （3008KB）（203）       Knowledge map    Save According to development background of the strike-slip fault zones in the Shunbei area of Tarim Basin, combined with the Riedel shear model, the development characteristics of dominant fractures of different strike-slip structural styles and the reworking of the effectiveness of fracture systems in different structural segments are analyzed by using the theory of geomechanics, and the controls of fracture and in-situ stress on productivity are clarified. The research shows that the combination of strike-slip faults controls the local stress state and fracture development pattern. The oil and gas productivity of the strike-slip fault-controlled reservoirs is controlled by the characteristics of stress field, and the occurrences of new fractures and pre-existing dominant fractures. The combination of small-scale faults and fractures derived from the strike-slip structural segments increases the effectiveness of the fault zones, and the well productivity in this area is generally high. Table and Figures | Reference | Related Articles | Metrics

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Mechanisms of Imbibition and Displacement in Horizontal Well Volume Fracturing for Shale Oil Recovery in Chang 7 Member, Qingcheng Oilfield QU Xuefeng, CHANG Rui, HE You’an, LEI Qihong, HUANG Tianjing, WANG Gaoqiang, GUAN Yun, LI Zhen Xinjiang Petroleum Geology    2025, 46 (3): 344-352.   DOI: 10.7657/XJPG20250311 Abstract （459）   HTML （9）    PDF（pc） （691KB）（201）       Knowledge map    Save Shale oil is primarily developed through horizontal well volume fracturing, where substantial fluid is injected into and produced from the matrix. However, the contributions of imbibition and displacement remain controversial. To clarify their mechanisms and contributions in shale oil reservoirs, the shale core samples from the Chang 7 member of the Qingcheng oilfield were used for analysis. The imbibition + displacement and displacement experiments under formation pressure, as well as imbibition experiments under varying pressures, were performed to obtain the nuclear magnetic resonance (NMR) T2 spectra at different stages, and the impact of well soaking on production were analyzed. Furthermore, by integrating fractal theory and oil-water two-phase flow theory, a mathematical model of flow mechanics which considered displacement pressure and capillary pressure was established, and a chart illustrating imbibition and displacement under different pressure differences was plotted. The results show that displacement primarily mobilizes oil in medium-to-large pores, while imbibition recovers oil from pores and throats of all sizes. Compared to pure water flooding, post-imbibition water flooding demonstrates superior oil displacement efficiency, because imbibition can not only mobilizes oil directly but also facilitates subsequent water flooding performance. Table and Figures | Reference | Related Articles | Metrics

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Multi-Scale and Multi-Constraint Geological Modeling of Fault-Controlled Karst Reservoirs LI Jikang, ZENG Qingyong, GUO Chen, LI Qing, ZHU Lele Xinjiang Petroleum Geology    2024, 45 (6): 719-724.   DOI: 10.7657/XJPG20240611 Abstract （581）   HTML （6）    PDF（pc） （4324KB）（201）       Knowledge map    Save Fault-controlled karst fractured-vuggy reservoirs that are characterized by well-developed fault systems exhibit complex reservoir spaces with significant discreteness and heterogeneity, posing great challenges to fault system modeling and description. Guided by the developmental and genetic patterns of fault-controlled karst reservoirs, a multi-scale and multi-constraint geological model of fault-controlled karst reservoir was established. Depending on the genesis of fault-controlled karst, the development of these reservoirs was divided into four stages (Ⅰ-Ⅳ). Based on the reservoir model of Stage Ⅳ, the fault-controlled karst reservoirs were divided into karst cave facies, dissolution pore facies, and dissolution fracture facies. A fracture development probability cube was constructed with multiple constraints which include ant weight sampling, fault displacement model, and fracture parameter characterization, and two groups of small-scale fractures of NW-SE and NE-SW trending were generated by applying a goal-oriented simulation algorithm. A fracture model of fault-controlled karst was established to reflect the development characteristics of the fractures in fault-controlled karst to the greatest extent, for reducing the uncertainty in fracture prediction. Thus, a new method for predicting fractures in fault-controlled karst reservoirs was formed. The reliability of the proposed model has been validated by the application in two wells, which may support subsequent development research. Table and Figures | Reference | Related Articles | Metrics

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Producing Patterns and Improvement of Polymer Flooding Profile in Class ⅡB Reservoir, Daqing Oilfield ZHOU Congcong, CAO Ruibo, SUN Hongguo, FAN Yu, GUO Songlin, LIANG Guoliang Xinjiang Petroleum Geology    2024, 45 (5): 567-573.   DOI: 10.7657/XJPG20240508 Abstract （588）   HTML （3）    PDF（pc） （611KB）（190）       Knowledge map    Save The application of polymer flooding is expanding in Daqing oilfield, with the target transferring to poor-quality Class ⅡB reservoir. The existing polymers exhibit poor compatibility with the reservoir, the producing patterns of the profile remain unclear, and the effects of polymer flooding development vary greatly in different areas. To address these issues, through the analysis of field profile data statistics and laboratory experiments, the producing patterns and improvement methods for the profiles in Class ⅡB reservoir were investigated. In view of the producing status from water-injected layers, Lamadian area which is characterized by thick channel sandbodies and good reservoir properties exhibits the highest proportion of net pay producing, with the reservoir exploited frequently, multiple polymer breakthrough layers, and relatively high liquid absorption. The Sazhong and Sanan areas, with limited channel sandbodies and multiple thin sand layers with poor properties, show a low net pay producing proportion in the water flooding stage, after polymer flooding which is 12.5% and 15.4% higher than those in the water flooding stage, respectively. Additionally, the reservoirs with permeability ranging from 100 to 300 mD show a significant profile improvement. In view of the producing status of water-unswept layers, the strong vertical heterogeneity of Class ⅡB reservoir results in a high net pay unproducing proportion between layers. In this case, the profile should be improved by achieving balanced interlayer production. The alternating injection of salt-resistant polymer of high and low concentrations can delay the rise of water cut, enhance the liquid absorption in low-permeability layers, and significantly improve the recovery efficiency of polymer flooding. A pilot test on alternating injection of DS1200 salt-resistant polymer of high and low concentrations was conducted in A area of Beibei block in Lamadian, achieving satisfactory water-cut reduction and oil increment. This technology provides a guidance for improving the polymer flooding profiles of Class ⅡB reservoir in Daqing oilfield. Table and Figures | Reference | Related Articles | Metrics

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Impacts of Rock Mineral Composition and Structure of Conglomerate Reservoirs on Enhanced Oil Recovery of Polymer-Surfactant Binary Flooding ZHANG Chaoliang, LI Jun, YAN Xiaolong, LYU Jianrong, ZHANG Defu, DOU Ping Xinjiang Petroleum Geology    2025, 46 (2): 231-239.   DOI: 10.7657/XJPG20250213 Abstract （531）   HTML （8）    PDF（pc） （739KB）（189）       Knowledge map    Save The complex mineral components of conglomerate reservoirs have active surface physical and chemical properties, making them liable to interact with polymers and surfactants. These interactions may result in loss and alteration of binary flooding formulations underground. By using core samples from different types of conglomerate reservoirs, the microscopic structure and mineral composition/content were investigated, specific surface area and Zeta potential were measured, and the adsorption charts of chemical agents on the cores were established. Through oil displacement experiments, the impacts of rock mineral composition and structure of conglomerate reservoirs on the recovery of polymer-surfactant binary flooding was validated. The results show that in conglomerate reservoirs, clay and zeolite minerals have large specific surface areas and high Zeta potentials, and their active physical and chemical properties affect oil displacement efficiency. The cores from Class I reservoirs with the best petrophysical properties exhibited the highest ultimate recovery factor, the cores from Class II reservoirs with the lowest content of active minerals achieved the highest chemical flooding efficiency, while the cores from Class III reservoirs showed the lowest oil displacement efficiency. Table and Figures | Reference | Related Articles | Metrics

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Effectiveness Evaluation of Tight Sandstone Reservoirs Based on NMR Logging MU Qian, LI Gaoren, ZHANG Wenjing, CHI Ruiqiang Xinjiang Petroleum Geology    2025, 46 (1): 121-126.   DOI: 10.7657/XJPG20250115 Abstract （566）   HTML （9）    PDF（pc） （786KB）（188）       Knowledge map    Save In the Zhijing-Ansai area of the Ordos Basin, the reservoirs in the 8th and 9th members of the Upper Triassic Yanchang formation (Chang 8 and Chang 9 members) are tight, with complex pore structure and unclear vertical distribution of effective reservoirs. A method for evaluating the effectiveness of the tight sandstone reservoirs was proposed based on nuclear magnetic resonance (NMR) logging data and mercury injection data of rock samples. For wells with NMR logging data, the proportions of macropores, mesopores, and micropores can be directly obtained from the NMR data, and an NMR logging-based three-pore component index can be constructed. For wells without NMR logging data, the pore throat radius index can be established by using the relationship between NMR transverse relaxation time and pore throat radius. Both the NMR logging-based three-pore component index and the pore throat radius index can quantitatively characterize the pore structure of tight sandstone reservoirs. Integrating with analysis of formation test data, it is found that single-well liquid production index per meter is positively correlated with pore structure. Thus, an effectiveness evaluation standard for tight sandstone reservoirs was established. The application of this standard to the Chang 8 and Chang 9 members in the Zhijing-Ansai area demonstrates excellent results, with significantly improved accuracy of well logging interpretation. Table and Figures | Reference | Related Articles | Metrics

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Formation Heat Variation Pattern During Cyclic Steam Stimulation YAO Changjiang, JIA Xinfeng, SHANG Ce, LI Kehan, JIAO Binhai, GAO Fei, LIN Zhiqiang Xinjiang Petroleum Geology    2025, 46 (1): 64-70.   DOI: 10.7657/XJPG20250108 Abstract （647）   HTML （12）    PDF（pc） （639KB）（186）       Knowledge map    Save Heating formation to reduce crude oil viscosity is one of the main mechanisms of cyclic steam stimulation (CSS). A dynamic heat transfer model considering both thermal convection and thermal conduction was established. Coupling temperature and pressure fields, this model was used to determine formation pressure, formation temperature, and fluid convection velocity, so that the dynamic variation of formation heat was analyzed. The research results show that, in the steam injection stage, given the same cyclic steam injection volume, higher heating rates and net heat are achieved when the injection duration is 6.0-10.0 days. In the soaking stage, when the pressure stops rising, thermal convection weakens rapidly, and formation heating rate significantly decreases, with an 88.3% drop in heating rate after 4.0 days of soaking, allowing for well production. In the production stage, thermal conduction becomes the dominant mechanism, and the formation heat increases slowly and steadily. After one cycle of CSS, 57.7% of the incremental heat is recovered with the produced fluid, while 42.3% remains in the formation. This study provides a deeper understanding of the formation heat variation during CSS, which supports the optimization of injection-production parameters and the analysis of steam heat flow. Table and Figures | Reference | Related Articles | Metrics

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Determination of Limit Water Cut of Technically Recoverable Reserves Calibrated by Water Drive Curve LIAN Jianwen, WANG Yaozong, YANG Jiguang Xinjiang Petroleum Geology    2024, 45 (6): 687-695.   DOI: 10.7657/XJPG20240607 Abstract （460）   HTML （5）    PDF（pc） （883KB）（184）       Knowledge map    Save Water drive curve method is one of the important methods in dynamically calibrating recoverable reserves. This is a forward estimation method for water flooding reservoir without major adjustment measures and changing development modes, and with basically steady water flooding status. Setting the limit water cut at 0.98 lacks a solid scientific basis. Since the water drive characteristics vary significantly among different reservoirs, it is essential to select a water drive curve that best aligns with the reservoir’s actual behavior from the four water drive characteristic curves, rather than choosing the one with the lowest technically recoverable reserves, which will lead to weak reliability of calibration. Therefore, the four water drive characteristic curves and the production decline method were inverted and optimized for joint elimination, and a new relationship between water/liquid-oil ratio and production decline was established. This can determine the limit water cut and also ensure the uniqueness of the recoverable reserves calibrated by dynamic methods. 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 （586）   HTML （9）    PDF（pc） （7909KB）（180）       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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Characteristics and Controlling Factors of Pore Structure in Coal-Measure Shale Reservoirs: Taking Longtan Formation in Western Guizhou as an Example LI Juhao, HE Jinxian, YANG Zhaobiao, ZHANG Xiaoli, WU Meng, MA Li, YUAN Yuan, WEN Mingzhong Xinjiang Petroleum Geology    2025, 46 (5): 521-530.   DOI: 10.7657/XJPG20250501 Abstract （429）   HTML （26）    PDF（pc） （4043KB）（179）       Knowledge map    Save Pore structure affects gas storage performance of shale and is an important parameter for evaluating shale gas resource potential. Taking the coal-measure shale of Upper Permian Longtan formation in western Guizhou as an example, micro-pores and micro-fractures were qualitatively observed using scanning electron microscopy (SEM) and classified, and the microscopic pore structure and pore size distribution were quantitatively characterized through high-pressure mercury injection and low-temperature nitrogen adsorption experiments. Combining with organic geochemical parameters and mineral composition distribution characteristics, the factors controlling the pore structures of coal-measure shale reservoirs were identified. The results show that the matrix pores in coal-measure shale of the Longtan formation can be divided into six occurrence types: residual primary intergranular pores, mineral moldic pores, clay mineral intergranular pores, intergranular pores, intragranular dissolution pores, and organic pores, and the micro-fractures are mainly extensional, shear, bedding, and diagenetic shrinkage micro-fractures. Micro-pores (especially those with diameter <5 nm) and transitional pores provide the main pore space. The pore space types are dominated by ink bottle holes and V-shaped holes, with a certain amount of parallel slits, and the connectivity between pores is relatively good. Total organic carbon content (TOC), maturity of organic matter, and mineral composition are the main factors controlling the pore structure of the coal-measure shale reservoirs of Longtan formation in western Guizhou. The single-point pore volume and specific surface area of the shale increase with the increase of TOC. The degree of thermal evolution contributes positively to the increase of micro-pore and transitional pore volume. Clay minerals have complex impacts on the pore structure. High brittleness index has a positive effect on the development of meso-pores, macro-pores and micro-fractures, being conducive to shale gas flow. Table and Figures | Reference | Related Articles | Metrics

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Genetic Mechanisms of Deep Ordovician Dolomite Reservoirs in Jizhong Depression XIANG Pengfei, JI Hancheng, WANG Xinwei, SHI Yanqing, HUANG Yun, SUN Yushu Xinjiang Petroleum Geology    2024, 45 (6): 659-670.   DOI: 10.7657/XJPG20240604 Abstract （523）   HTML （15）    PDF（pc） （25597KB）（175）       Knowledge map    Save The deep buried-hill interior reservoirs in the Jizhong depression are key successive zones for oil and gas exploration, and clarifying their genetic mechanisms is particularly important for effective exploration and development. Based on the data of drilling, logging, outcrops, cores, and thin sections, the deep Ordovician dolomite reservoirs were characterized, their controlling factors were analyzed, and the evolution models of high-quality reservoirs were established. The research results show that three sets of high-quality reservoirs are developed in the Ordovician of the Jizhong depression. These reservoirs which are primarily composed of crystalline dolomite and limy dolomite exhibit strong heterogeneity and poor porosity-permeability correlation. Four types of reservoir spaces including intercrystalline pores, dissolved pores, karst caves, and fractures are found in the reservoirs. Dolomitization, dissolution, and tectonic fracturing are identified as constructive diagenetic processes, whereas compaction, cementation, dedolomitization, pyritization, and silicification are classified as destructive diagenetic processes. Sedimentation controlled by periodic sea-level changes and dolomitization provided material basis for the reservoir formation. The diagenetic sequence determined the three stages of pore evolution. Tectonic activities played a dominant role in reservoir reformation. Ultimately, the deep buried-hill type and slope type high-quality dolomite reservoirs were formed after four evolutionary stages. Table and Figures | Reference | Related Articles | Metrics

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Identification and Distribution of Silurian Interlayers in YM 35 Well Block, Tarim Basin WANG Wei, DAI Mengying, CHEN Junkai, ZOU Yunlong, WU Qiong, JIANG Qiong, FENG Cheng Xinjiang Petroleum Geology    2025, 46 (2): 154-162.   DOI: 10.7657/XJPG20250204 Abstract （644）   HTML （8）    PDF（pc） （1061KB）（174）       Knowledge map    Save The distribution patterns of interlayers in the YM 35 well block of the Tarim Basin are unclear, which poses challenges for subsequent oil and gas exploration and development. To identify the interlayer types in the study area and analyze their spatial distribution characteristics, by integrating the data of cores, conventional logging, laboratory analysis, and imaging logging, the primary interlayer types in the study area were clarified. By using the three-end-member classification method, charts for identifying interlayers were established for sublayers, and identification criteria were proposed. The distribution of interlayers was analyzed laterally and vertically, and the controls of interlayers on remaining oil distribution were investigated. The results show that the study area primarily develops argillaceous interlayers and physical interlayers. Laterally, argillaceous interlayers are mainly concentrated in the lower part of the target layer, with good continuity, while physical interlayers are mainly distributed in the middle-upper part, with smaller thickness but good continuity. On plane, interlayers are mainly concentrated in the central part of the study area, forming a distinct thickness aggregation zone. The interlayer becomes thinner toward its margin as its distance from the central area increases. Controlled by the spatial distribution of interlayers, remaining oil is mainly distributed in the K3 sublayer. Table and Figures | Reference | Related Articles | Metrics

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Study on CO2 Storage and CH4 Recovery Enhancement in Tight Sandstone Gas Reservoirs JIANG Yi, YANG Shenglai, BAI Haoyan, CHEN Yingli, MEI Qingyan, WANG Beidong Xinjiang Petroleum Geology    2025, 46 (5): 591-599.   DOI: 10.7657/XJPG20250509 Abstract （324）   HTML （4）    PDF（pc） （1471KB）（170）       Knowledge map    Save The CO2 storage and enhanced gas recovery (CS-EGR) technology represents a promising option for boosting production in the context of “dual carbon” goals. However, its application in tight sandstone gas reservoirs has been scarcely studied, and its field performance remains unclear. This study establishes a reservoir-scale numerical model based on a comprehensive analysis of gas-water two-phase flow mechanisms and stress sensitivity across three reservoir types. Using this model, the adaptability of CO2 injection to reservoirs, CO2 migration behaviors, CO2 trapping mechanisms, impacts of movable water on the CS-EGR process, and optimization of engineering parameters for CS-EGR are analyzed. It is indicated that CS-EGR is viable only for Class Ⅰ reservoirs, but less performed in Class Ⅱ and Class Ⅲ reservoirs. In terms of CO2 trapping mechanism, both structural trapping and residual trapping account for 95.8%, while CO2 mineralization and storage contributes 0.15%. For Class Ⅰ reservoirs, the optimal CO2 injection rate is 10,000 m3/d, the cumulative production of CH4 is 0.146×108 m3 when CO2 breaking through, and the cumulative storage of CO2 is 0.794×108 m3. Movable water significantly hinders CO2 migration and increases the risk of gas well flooding. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of a New Mathematical Model of Oil/Water Relative Permeability: A Case Study of Low-Viscosity Reservoirs in Tuha Basin GE Qibing, LIU Qian, MA Jianhong, GAO Wenjun Xinjiang Petroleum Geology    2024, 45 (6): 725-734.   DOI: 10.7657/XJPG20240612 Abstract （595）   HTML （7）    PDF（pc） （850KB）（168）       Knowledge map    Save The low-viscosity reservoirs in the Tuha basin exhibit rapid decline of oil relatively permeability in the initial development stage and slower decline in the late development stage with high water-cut. This paper presents a new mathematical model of oil/water relative permeability. The new model simplifies the determination of parameters and offers a high fitting accuracy. It can describe the oil relative permeability curve and the convex water relative permeability curve, and also the common X-shaped oil/water two-phase relative permeability curve. For convenient application, the new model was configured with a corresponding water flooding analytical method, and then compared with the Gao’s simplified model of oil/water relative permeability. In this way, the linear relationship between the average water saturation of oil layer and the water saturation at the outlet end was further validated. By directly substituting this relationship into the fractional flow equation, a new generalized water cut variation pattern was derived. The actual application of this model shows good results, making it a valuable reference for similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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A Method of Anisotropic Velocity Modeling for HTI Medium in the Surface of Piedmont Gravel Zone KONG Fanyong, XIE An, XIA Jianjun, ZHANG Lulu, WANG Liye, WANG Wei, YU Jinlin, WEI Jianbo Xinjiang Petroleum Geology    2024, 45 (5): 604-610.   DOI: 10.7657/XJPG20240513 Abstract （480）   HTML （6）    PDF（pc） （17953KB）（167）       Knowledge map    Save There are widespread alluvial fans with extremely thick gravel deposits in the surface of the piedmont zones in western China. These fans exhibit strong azimuth anisotropy. The tomographic inversion velocity differs greatly from the vertical velocity, severely impacting the accuracy of static correction value of 3D seismic data and the imaging of shallow-to-medium layer in pre-stack depth migration. Based on the HTI medium theory, a method for determining the symmetry axis and constructing an anisotropic model through azimuthal tomography fitting using first-arrival forward modeling was proposed. First, based on anisotropy, the first-arrival time from both micro-logging forward modeling and actual data is examined and compared to identify the symmetry axis characteristics. Then, elliptical fitting is performed on the azimuthal first-arrival tomography inversion model to derive the initial fast and slow velocities and the symmetry axis orientation. Next, by using 2D VTI anisotropic forward modeling and tomography inversion, the correction coefficients of the velocity in the direction of the symmetry axis are obtained. Finally, an anisotropic velocity model is established for the piedmont gravel zone. Table and Figures | Reference | Related Articles | Metrics

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Mechanism and Performance of Flue Gas-Assisted Steam Flooding in Heavy Oil Reservoirs SONG Tao, LI Yiqiang, LYU Xiaolong, YAN Zhiqian, TANG Xuechen, ZI Jianqiang, LIU Zheyu Xinjiang Petroleum Geology    2025, 46 (5): 606-613.   DOI: 10.7657/XJPG20250511 Abstract （366）   HTML （4）    PDF（pc） （5201KB）（166）       Knowledge map    Save Flue gas-assisted steam flooding is an economically viable enhanced oil recovery (EOR) technology for heavy oil reservoirs. To address the complex mechanisms of synergy between flue gas injection and steam injection, and the unclear impacts of injection process and reservoir properties on development performance, experiments and numerical simulations were performed on flue gas-assisted steam flooding following conventional steam flooding. Taking a heavy oil reservoir as an example, core flooding experiments were conducted to compare oil displacement efficiencies under different injection media. A mechanistic model of flue gas-assisted steam flooding for heavy oil reservoirs was established to systematically investigate its underlying mechanism and performance. The research results show that flue gas-assisted steam flooding improves oil recovery efficiency by 5.84% compared to pure steam flooding, attributed to multiple mechanisms such as thermal viscosity reduction by steam, pressurization effect of flue gas, enhanced thermal sweep efficiency via gis-liquid Jamin effect, and oil mobilization by flue gas flow. The injected flue gas forms a gas zone at the steam chamber front, prolonging steam-oil interaction time while mitigating steam override, thereby expanding thermal sweep area. An optimal steam-to-flue gas molar ratio of 7∶3 during injection can achieve a favorable balance between enhanced oil recovery and reduced steam consumption. Slug injection generates periodic pressure differentials in the reservoir, further improving displacement efficiency over co-injection. These findings provide theoretical and practical guidance for designing flue gas-assisted steam flooding schemes in heavy oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Seismic Prediction of Small- to Medium-Sized Fault-Controlled Fracture-Cave Bodies in Shunbei Area, Tarim Basin LI Hongyan, LIU Jun, GONG Wei, ZHANG Rong Xinjiang Petroleum Geology    2025, 46 (2): 240-245.   DOI: 10.7657/XJPG20250214 Abstract （517）   HTML （12）    PDF（pc） （6759KB）（161）       Knowledge map    Save The Shunbei area in Tarim Basin develops fault-controlled fracture-cave reservoirs, and good results have been achieved in exploration and development of the main fault zones. In addition to the main fault zones, there are numerous small- to medium-sized faults in the area, which are more abundant, widely distributed, and smaller in scale. Due to the target depth (>8 000 m) and scale, it is difficult for small- to medium-sized faults and their controlled fracture-cave bodies to get clear seismic responses, so to identify and describe them is hard. Based on seismic data interpretation, spectral extension and strong reflection separation techniques were applied to enhance the kinetic information in the seismic data, effectively highlighting the seismic reflection characteristics of the small- to medium-sized fault-controlled fracture-cave bodies. Sensitive attributes were selected depending on the characteristics of different types of reservoirs. The multi-scale coherence of curvelet is found to be sensitive to small- to medium-sized faults, and the attributes such as disorderliness and frequency-division energy can be used to effectively identify fault zones and fracture-cave bodies. Small- to medium-sized fault-controlled fracture-cave bodies were successfully predicted and described by integrating the attributes reflecting different information. This technique was applied in the Shunbei area, which effectively guided well deployment, facilitating the oil and gas development. Table and Figures | Reference | Related Articles | Metrics

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Movable Fluid Differences in Permian Shan-1 Member Reservoirs in Northern and Southwestern Parts of Ordos Basin WANG Wenqing, PENG Lei, SHI Huaqiang, HOU Rui, GAO Hui, WANG Chen, LI Teng Xinjiang Petroleum Geology    2025, 46 (2): 172-180.   DOI: 10.7657/XJPG20250206 Abstract （476）   HTML （3）    PDF（pc） （5850KB）（161）       Knowledge map    Save Physical properties, petrological properties, and microscopic pore structure are key factors controlling movable fluids in tight sandstone reservoirs. To reveal the differences of the movable fluids in the reservoirs of the Shan-1 member in the Sulige gas field, northern Ordos Basin and in the Qingyang gas field, southwestern Ordos Basin, by employing multiple techniques such as X-ray diffraction, scanning electron microscopy, cast thin section analysis, high-pressure mercury intrusion, and nuclear magnetic resonance (NMR), the differences in microscopic pore structure of reservoirs were clarified, and then the differences of movable fluids from the Shan-1 member reservoirs in the two areas were identified. The results show that the pore structures in the two parts can be classified into three types based on pore-throat radius distribution and reservoir physical properties. Type I pore structures are relatively well-developed, with movable fluids present across a wide range of pore radii, and the movable fluid content significantly sensitive to the sorting coefficient. Type II pore structures exhibit uneven pore-throat distribution, with the movable fluid content notably affected by the median pore-throat radius. Type III pore structures have a smaller range of pore radius distribution, with movable fluids mainly concentrated in small pores, and the movable fluid content primarily influenced by clay mineral content. In the Sulige gas field, the Shan-1 member is dominated by Type II pore structures, with a movable fluid content of 24.11%, which is influenced by permeability, median pore-throat radius, and illite content. In the Qingyang gas field, the Shan-1 member is dominated by Type III pore structures, with the movable fluid content mainly influenced by porosity, permeabilty, and clay mineral content. Table and Figures | Reference | Related Articles | Metrics

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Pore Structure and Reservoir Properties of Deep Coals: A Case Study of No.5 Coal Rock of Shanxi Formation in Southwestern Ordos Basin LUO Jing, ZHANG Lei, ZHANG Jianwu, PAN Xing, CAO Qian, LI Lei, YAN Ting, LI Teng Xinjiang Petroleum Geology    2025, 46 (5): 531-543.   DOI: 10.7657/XJPG20250502 Abstract （433）   HTML （13）    PDF（pc） （9852KB）（159）       Knowledge map    Save In order to clarify the deep coal-forming environment and its controls on the microsopic pore structure and reservoir properties of coal rocks, the deep No.5 coal rock of Shanxi formation in southwestern Ordos Basin was selected for investigating the facies, pore structure and reservoir properties of deep coal rocks through macroscopic observations, coal quality measurements, scanning electron microscope (SEM), and gas adsorption tests. The results show that the No.5 coal rock features extra-low water yield, moderate ash yield, extra-low volatile yield, and moderate-high fixed carbon content, with the average vitrinite reflectance up to 2.38%. The content of vitrinite ranges from 42.09% to 72.49%, with an average of 60.60%, and the content of inertinite reaches 27.34% averagely, while exinite is rare in the coal. Desmocollinite, telocollinite and semifusinite are the dominant sub-macerals of the coal samples. The coal-forming environment was dominated by moist forest-swamp facies, with large overlying water depth and weak hydrodynamic force. The bedding fractures, gas pores and plant tissue pores serve as the dominant reservoir space types, and a small amount of intergranular pores and clay mineral intercrystalline pores are also observed. Micropores and mesopores with pore sizes less than 22 nm are the reservoir space, and the heterogeneity of pore structure containing larger mesopores is more significant. The coal-forming environment with strong water overburden and weak flow is conducive to the development of vitrinite, which also determines that micropores are the main reservoir space of the deep coal. Under the action of gelation, the adsorption and adhesion of terrigenous detritus by coal organic matters led to strong heterogeneity of pore structure containing larger mesopores. Table and Figures | Reference | Related Articles | Metrics

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Laboratory Experiments and Field Tests of CO2 Near-Miscible Flooding for Medium-Viscosity Oil in NJH Block, Santanghu Oilfield ZHANG Qi, ZHU Yongxian, HAN Tianhui Xinjiang Petroleum Geology    2025, 46 (1): 114-120.   DOI: 10.7657/XJPG20250114 Abstract （1345）   HTML （5）    PDF（pc） （655KB）（156）       Knowledge map    Save The NJH block of the Santanghu oilfield features sandstone reservoirs containing medium-viscosity oil, with crude oil viscosity of 20.8 mPa·s. The reservoir is at medium water cut stage, with a predicted waterflood recovery factor of 22.70%, leaving a limited potential for further enhanced oil recovery. To figure out an applicable enhanced oil recovery (EOR) technique, laboratory experiments and field test were conducted on CO2 near-miscible flooding for medium-viscosity oil to understand the mass transfer patterns and EOR mechanisms of this technique, thereby determining its feasibility. The research results show that the front of the CO2 flooding mainly plays a swelling effect, and the rear exerts a stronger extraction effect than the front. Reducing the viscosity and improving the remaining oil displacement efficiency are the main stimulation mechanisms. The viscosity of surface crude oil reduced by 55%, the content of C2-C15 components increased by 18.3%, and the displacement efficiency improved by 4.6 times. Permeability ratio is found to be the primary factor influencing swept volume, with a permeability ratio of 6, leading to a recovery factor of only 13.84% in low-permeability layers. During the field test, the cumulative injected gas volume is 2.66×104 t, cumulative oil production is 0.78×104 t, and oil exchange ratio is 0.29, confirming a promising application of CO2 near-miscible flooding for medium-viscosity oil. Table and Figures | Reference | Related Articles | Metrics

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Subsalt Structural Deformation Models in the Kuqa Foreland Thrust Belt MEI Yongxu, ZHANG Jinning, PAN Yangyong, LIU Peiye, XIANG Honghan, NENG Yuan Xinjiang Petroleum Geology    2025, 46 (4): 429-437.   DOI: 10.7657/XJPG20250405 Abstract （494）   HTML （15）    PDF（pc） （3481KB）（155）       Knowledge map    Save The structural modeling of the Kuqa foreland thrust belt has undergone three periods of theoretical transformations. The subsalt Mesozoic Triassic-Jurassic detachment structures have not been profoundly studied, and there are still considerable controversies regarding the structural deformation models and mechanisms of multi-detachment layers. Considering the presence of multi-detachment layers in the ultra-deep complex structural belts in the Kuqa foreland thrust belt, the structural deformation system of layered detachment in the Kuqa foreland thrust belt was investigated from the perspectives of geometry, kinematics and dynamics. Combined with the high-precision 3D seismic data, the subsalt structural deformation patterns were analyzed, and the structural models of the deep subsalt multi-detachment layers were depicted. The influences of geological factors such as paleo-uplifts, pre-existing faults, and evaporite rocks on the deep subsalt structures were discussed. The results show that the subsalt structural deformation in the Kuqa foreland thrust belt is mainly associated with five sets of regional detachment layers, exhibiting the features of multi-detachment layers in stacked distribution, vertically stratified detachment deformation, and spatially differentiated superposition deformation. Spatially, from the southwest to the northeast, the structures transform from the basement-involved thrust to the cap rock sliding, together with a ramp-flat multi-detachment-layer superimposed transition zone, generally presenting a trend of three-segment progressive deformation. Orderly and large-scale pop-up structures are developed at the ramp-flat fault transition joints. The subsalt Mesozoic has the possibility of developing secondary anticline traps in rows and bands, making it promising for oil and gas exploration. Table and Figures | Reference | Related Articles | Metrics

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Dominant Geomechanical Factors Controlling the Volumetric Stimulation Effectiveness in the Shale Oil Reservoirs of the Lucaogou Formation, Jimsar Sag LIU Xiangjun, GAN Renzhong, XIONG Jian, TANG Shiqi, WAN Youwei, ZHOU Xin, LIANG Lixi, ZHANG Miao Xinjiang Petroleum Geology    2025, 46 (6): 723-733.   DOI: 10.7657/XJPG20250608 Abstract （202）   HTML （2）    PDF（pc） （2520KB）（154）       Knowledge map    Save In response to the challenges in enhancing volumetric stimulation effectiveness in the shale oil reservoirs of the Lucaogou formation in the Jimsar sag of the Junggar Basin, a systematic study was conducted. Based on the lithological assemblage characteristics and geomechanical parameters of the study area, numerical simulation was employed to analyze the propagation patterns of hydraulic fractures under different lithological assemblages. The research focused on the controlling effects of interlayer strength, in-situ stress, interface strength coefficient, displacement, and horizontal well placement on fracture propagation, and explored a differentiated optimization method for fracturing stages. The results indicate that an increase in the elastic modulus of the reservoir/barrier layers and a decrease in tensile strength both facilitate vertical fracture propagation, whereas a high horizontal stress difference significantly inhibits vertical fracture extension. A critical threshold exists for the interlayer interface strength coefficient, which directly governs fracture propagation behavior. Under this critical condition, high displacement promotes fracture penetration through barriers, while low displacement lead to fracture diversion along interfaces. Well placement exhibits a limited impact on fracture geometry, as effective vertical propagation can be achieved regardless of whether the horizontal well is placed within the reservoir or barrier layers. A nonuniform staging scheme based on geological-engineering sweet spot evaluation effectively enhances stimulation efficiency and reduces ineffective operations. This research results provide theoretical support and practical guidance for optimizing horizontal well trajectory, fracturing stage design, and treatment parameters in the shale oil development of the study area. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Deep Geothermal Field in Shuntuoguole Area of Tarim Basin LIAO Keyan, QIU Nansheng, CHANG Jian, LI Dan, LI Huili, MA Anlai, LI Jingying Xinjiang Petroleum Geology    2025, 46 (2): 163-171.   DOI: 10.7657/XJPG20250205 Abstract （618）   HTML （13）    PDF（pc） （2818KB）（154）       Knowledge map    Save The Tarim Basin is characterized by low surface heat flow and significant variation in formation temperature. To clarify the characteristics and controlling factors of deep geothermal field in the Shuntuoguole area of central Tarim Basin, by using the systematic steady-state temperature measurement data from 33 wells in the Shuntuoguole and surrounding areas, the geothermal gradients and deep temperature distribution characteristics were investigated. On this basis, the geothermal properties of sedimentary rocks and their impacts on heat flow and temperature were analyzed. Coupling with geophysical data, a layering model for the earth’s crust was constructed, and the heat flow density of the crust was calculated. The research results show that in the Shunnan, Shuntuo, and Shunbei areas, the average geothermal gradients at a depth ranging from 0 to 5 km are 22.5°C/km, 20.0°C/km, and 18.6°C/km, respectively, and the average formation temperatures at the depth of 8 km in the 3 areas are approximately 200°C, 175°C, and 135°C, respectively, indicating significant differences in the geothermal fields. The differences in the crustal structure account for variations in the crustal heat flow, and the crustal structure is the primary controlling factor for the geothermal field differences in the study area. The geothermal properties of sedimentary rocks have a negligible impact on the geothermal field. The rapid sedimentation in the Shunbei area since the Pliocene and the deep hydrothermal activity in the Shunnan area have no influence on the present-day geothermal field. Table and Figures | Reference | Related Articles | Metrics

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Mineral Features of Chlorite and Laumontite and Their Impacts on Reservoir Physical Properties: A Case Study of Lower Wuerhe Formation in Western Luliang Uplift, Junggar Basin NIU Jun, WANG Cong, LIANG Fei Xinjiang Petroleum Geology    2025, 46 (1): 13-21.   DOI: 10.7657/XJPG20250102 Abstract （932）   HTML （17）    PDF（pc） （19298KB）（153）       Knowledge map    Save In order to enhance the understanding of mineral features of chlorite and laumontite in the lower Wuerhe formation of Permian in the western Luliang uplift, Junggar Basin, the chemical composition, occurrence states, and impacts on reservoir physical properties were studied by means of thin section, electron probe and X-ray diffraction. It is found that the chlorite has an trioctahedral crystal structure and occurs in three states: pore lining, particle coating, and pore filling. It is classified as an iron-magnesium transitional type, richer in magnesium. Fe replacing Mg mainly occurs in the octahedrons, with the Al/(Al+Mg+Fe) ratio ranging from 0.25 to 0.37. The forming of chlorite is attributed to the alteration of argillaceous rocks and the transformation of mafic rocks, with substantial material input from the hydrolytic dissolution of tuffaceous volcanic materials and the interconversion of clay minerals. Laumontite occurs in three states: crystal aggregate, filling, and replacement. The laumontite in crystal aggregate state is surrounded by numerous debris, which promotes the formation of laumontite. The laumontite in filling state coexists with chlorite, calcite and other minerals, which compete with them for material sources, partially inhibiting the formation of laumontite. The laumontite in replacement state is mainly formed by the replacement of feldspar and debris, resulting in high Si/Al ratio and good acid resistance, which allow the laumontite to be not easily dissolved. Chlorite and laumontite have dual effects on reservoir physical properties. Chlorite can significantly improve reservoir physical properties, resulting in the formation of high-quality reservoirs. In contrast, the effect of laumontite on reservoir properties is limited. With the increase of burial depth, the lower Wuerhe formation presents a variation in diagenetic environment from alkaline to weakly acidic and then to alkaline, with a relatively closed diagenetic system. Table and Figures | Reference | Related Articles | Metrics

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Experimental Study on Oil/Water Relative Permeability in Fractured Reservoirs in Shunbei Oilfield, Tarim Basin YUN Lu, WANG Yang, CAO Fei, PAN Lin, WANG Xiao Xinjiang Petroleum Geology    2025, 46 (4): 485-491.   DOI: 10.7657/XJPG20250412 Abstract （367）   HTML （8）    PDF（pc） （1682KB）（153）       Knowledge map    Save The fault-controlled fractured reservoirs in the Shunbei oilfield are characterized by strong heterogeneity and complex oil-water movement patterns, making traditional homogeneous models fail to accurately characterize relative permeability. This study proposes a physical simulation method based on modular fracture networks. Regarding the characteristics of natural fractures in carbonate reservoirs, corresponding modular fracture network physical models with varying fracture complexity are designed, and the oil-water displacement experiments are conducted to obtain displacement parameters for different fracture models. On this basis, oil/water relative permeabilities are calculated, and the relative permeability charts are plotted. The obtained oil/water relative permeability curves are analyzed and validated using actual production data of wells in the fractured reservoirs to understand the variations of reservoir performance in the Shunbei oilfield. Table and Figures | Reference | Related Articles | Metrics

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Performance Evaluation of Water Injection for Energy Replenishment in Fault-Controlled Fractured-Vuggy Reservoirs in Shunbei No.1 Fault Zone, Tarim Basin LIU Yaoyu, HE Yunfeng, ZHANG Wenxue, MEI Shengwen, CHI Linxian, WANG Ligang Xinjiang Petroleum Geology    2025, 46 (4): 470-477.   DOI: 10.7657/XJPG20250410 Abstract （364）   HTML （10）    PDF（pc） （1434KB）（151）       Knowledge map    Save In the Shunbei oilfield, the fault-controlled fractured-vuggy reservoirs are difficult to develop, and particularly in the Shunbei Zone 1, the severely depleted formation energy has induced a sharp rise of the natural decline rate of production, necessitating water injection for energy replenishment. The water flow pathways are predominantly constrained by fault surfaces, leading to severe water channeling and flooding during waterflooding process. Currently, there is a lack of theoretical frameworks for analyzing waterflooding failures. Based on the performance data of production by water injection in the Shunbei oilfield, and by using the K-means clustering algorithm, the classification criteria for energy replenishment via water injection was established. Based on the analysis results of clustering center, the quantitative threshold for injection effectiveness was determined, that is, a well is deemed effective if the pressure increment exceeds 8.7 MPa and the daily oil production increment is not less than 15.2 t; otherwise, it is considered ineffective. Using the established classification criteria, 12 water injection wells in the study area were evaluated, focusing on key influencing factors such as soaking time, cumulative injected water volume per cycle, injection-production ratio per cycle, ratio of oil production increment after water injection to cumulative water injection volume, and water consumption per unit of pressure recovery. A case study of Well SHB5-4H in the Shunbei No.1 fault zone elucidates the causes of waterflooding failure, providing a theoretical foundation for designing water injection strategies and optimizing remediation measures for ineffective wells in the fault-controlled fractured-vuggy reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Lithofacies and Architecture of Meandering River Reservoirs in Permian Shanxi Formation, Sulige Gas Field MA Zhixin, LI Jinbu, FU Bin, BAI Hui, LI Fuping, MA Shenghui, JIA Jin’e Xinjiang Petroleum Geology    2025, 46 (3): 280-287.   DOI: 10.7657/XJPG20250304 Abstract （340）   HTML （4）    PDF（pc） （3234KB）（149）       Knowledge map    Save Conventional characterization of meandering river reservoirs typically relies on data from densely-spaced vertical wells, but insufficient inter-well data results in unreliable planar combinations of architectural elements. Taking the SSF-AH horizontal well + large well group targeting the Permian Shanxi formation in Sulige gas field as an example, and by integrating horizontal and vertical well data, the lithofacies of the meandering river reservoirs were identified, and the reservoir architecture was analyzed. The results demonstrate that the lithofacies in the study area can be classified into four types. Type Ⅰ to Ⅳ shows a gradually decreasing hydrodynamic force during deposition. Types Ⅰ and Ⅱ constitute the main gas-bearing lithofacies, while Types Ⅲ and Ⅳ are generally non-productive. Three combination patterns of architectural elements of the meandering river reservoir are identified: transverse-spanning, longitudinal-spanning, and intercrossing. The sand bodies of the meandering river channels are 900-1 100 m wide; the sand bodies of point bars are 650-800 m long (avg. 720 m) and 800-1 000 m wide (avg. 910 m); and the width of abandoned channels are generally less than 100 m. The point bars are typically composed of 4-5 stages of lateral accretion sand bodies, with the thickness ranging from 0.4 to 1.5 m individually and the planar width ranging from 120 to 220 m. The lateral acceretion mudstones are 0.2-0.4 m thick, with a vertical density of 0.5-0.8 beds per meter and a planar density of 0.011 beds per meter. The integration of horizontal wells with large well groups can improve the accuracy of architecture characterization. Table and Figures | Reference | Related Articles | Metrics

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Determination of Reasonable Well Pattern Density for Tight Gas Reservoirs in Sulige Gas Field LI Peng, FAN Qianqian, XU Wen, LIU Lili, FAN Jiwu, BAI Hui Xinjiang Petroleum Geology    2025, 46 (3): 382-387.   DOI: 10.7657/XJPG20250316 Abstract （293）   HTML （2）    PDF（pc） （617KB）（148）       Knowledge map    Save Well pattern optimization for tight gas reservoirs is generally implemented at the overall deployment stage. In the central Sulige gas field, which is now in mid-to-late development stage, the productivity construction enters the well infilling stage. To ensure the performance of infill wells, it is essential to evaluate the reasonable well pattern density under varying reservoir conditions, infill timing, and natural gas prices. In this study, typical well blocks with different reserves abundances in the central Sulige gas field were selected for numerical simulation. By analyzing development indicators of gas wells and gas reservoirs under different well pattern densities, the degree of gas well interference and formation pressure distribution of existing wells at different production stages were assessed. Based on these findings, the ultimate cumulative gas production of infill wells was predicted. By integrating economic parameters such as natural gas prices, the reasonable well pattern density for different infill timings was determined, enabling economically well infilling. The application in the Sulige gas field demonstrates that, at a natural gas price of 1.119 yuan/m3, a reasonable well pattern density of 4.5 well/km2 can be deployed in non-producing areas; for infill drilling near existing wells within 3 years of production, the well density can be increased to 3.5 well/km2; if the gas price rises to 1.550 yuan/m3, infill drilling near wells within 5 years of production can reach 5.0 well/km2. Table and Figures | Reference | Related Articles | Metrics

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Five-Dimensional Seismic Fracture Prediction Technology in Shunbei Oil and Gas Field LI Zongjie, LI Hongyan, YANG Wei, GONG Wei, GAO Lijun Xinjiang Petroleum Geology    2025, 46 (4): 403-409.   DOI: 10.7657/XJPG20250402 Abstract （432）   HTML （15）    PDF（pc） （10863KB）（144）       Knowledge map    Save The Shunbei oil and gas field develops fault-controlled fractured-vuggy reservoirs characterized by varying storage spaces, complex structures, deep burial, and strong heterogeneity, and also has multiple surface sand dunes, and high and steep strike-slip fault zones. These features greatly challenge the seismic acquisition and processing, leading to the difficulties in reservoir prediction and description. With the advancement of seismic technology, wide-azimuth three-dimensional seismic acquisition has become a key technique, and seismic interpretation has also transited from three dimension to five dimension. For fractured reservoirs, this study deals with fracture prediction based on five-dimensional seismic data. Firstly, noise suppression and residual normal moveout (NMO) correction are performed on the pre-stack five-dimensional gathers to improve the data quality, and the optimized data are stacked by azimuths. Then, high-precision enhanced coherence is extracted from seismic data at different azimuths, and azimuth fusion is conducted to achieve fault characterization. Secondly, based on the pre-stack data, the azimuthal elastic impedance (AEI) equation in the Fourier series form is derived, the second-order Fourier coefficient is used to indicate the fracture density, and azimuth fusion is performed to achieve the characterization of fractured reservoirs. Finally, the prediction results of multiple attributes are fused using the kernel principal component analysis (KPCA) based on ensemble learning to enable a comprehensive characterization of fractures at different levels. The application of the technology in the Shunbei oil and gas field realizes fine characterization of faults and fractured reservoirs, providing valuable reference for the prediction and description of similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Trajectory Adjustment Technology for Long Horizontal Wells in Chang 7 Shale Oil Reservoirs, Qingcheng Oilfield YANG Yongxing, ZHU Guanchen, WANG Degang, ZHU Jialiang, REN Yilin, WANG Bo Xinjiang Petroleum Geology    2025, 46 (3): 367-374.   DOI: 10.7657/XJPG20250314 Abstract （419）   HTML （5）    PDF（pc） （2707KB）（143）       Knowledge map    Save The shale reservoirs of the Chang 7 member in the Qingcheng oilfield are characterized by the combination of mud shale and multi-stage thin layers of fine to silty sandstone, posing significant challenges for optimizing and adjusting long horizontal well trajectories, which in turn affects the overall oilfield development effect. Four mature trajectory adjustment techniques, i.e. logging-seismic combined frequency-division attribute fusion, fine 3D geological modeling constrained by seismic structure, trajectory-stratigraphy matching, and curve shifting, were described with the adjustment success rates of 87.9%, 88.3%, 89.8% and 92.5%, respectively. Furthermore, the 3 techniques were evaluated regarding application scope, advantage, and limitation. Based on the evaluation results, a comprehensive analysis method was proposed for complex and challenging wells. The performances of these techniques were evaluated with respect to 11 parameters for 268 horizontal wells in the central Huachi area of Qingcheng oilfield. It is found that the application of the conventional mud-logging geosteering technique in conjunction with one trajectory adjustment technique increases the reservoir encountered rate to 79.4%, while the comprehensive analysis method improves the reservoir encountered rate to 84.2%. Table and Figures | Reference | Related Articles | Metrics

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Effects and Controlling Factors of Nitrogen Injection in Fractured-Vuggy Carbonate Reservoirs of Tahe Oilfield JIANG Lin, WEI Xuegang, GUO Chen, ZHU Lele, ZENG Qingyong, LIU Xueli Xinjiang Petroleum Geology    2025, 46 (4): 457-464.   DOI: 10.7657/XJPG20250408 Abstract （367）   HTML （9）    PDF（pc） （1240KB）（143）       Knowledge map    Save The fractured-vuggy carbonate reservoirs formed under different karst geological backgrounds in Tahe oilfield are being developed by nitrogen injection, with varying effects and unknown controlling factors, which will affect overall planning and deployment of subsequent nitrogen injection. On the basis of revealing main mechanism of nitrogen injection to enhance oil recovery in fractured-vuggy reservoirs, by using the “two baselines and three zones” economic evaluation method for nitrogen injection and field statistics method, the effects of nitrogen injection in these fractured-vuggy reservoirs were clarified, and the key controlling factors were analyzed on the basis of the dynamic and static parameters of the reservoirs. The results indicate some differences in various reservoirs: for weathered crust reservoirs, the proportion of ineffective wells is 40% for individual wells, and 31% for well groups, demonstrating the problems such as long gas injection time and difficulty in continuing conventional gas injection; for composite reservoirs, the proportion of ineffective wells is 24% for individual wells, and 27% for well groups, remaining in the stage of low-cycle gas injection and promising for nitrogen injection in the future; and for fault-controlled reservoirs, the proportion of ineffective wells is 57% for individual wells, and 66% for well groups, recording the poorest adaptability to gas injection. Key factors controlling the single-well gas flooding effect are determined as the reservoir type, attic size, reservoir compartmentalization, structural amplitude, remaining oil reserves at the vug top, energy of the bottom water, and injection/production parameters. Key factors controlling the nitrogen injection effect of well-groups are clarified as the injection-production site, dominant channel between wells, aquifer volume multiple, injection/production parameter, and injector pattern. Table and Figures | Reference | Related Articles | Metrics

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Inter-Well Connectivity and Controlling Factors of Ultra-Deep Fault-Controlled Fractured-Vuggy Reservoirs in the Shunbei No.1 Fault Zone, Traim Basin LUO Rong, CHEN Shuyang, HE Yunfeng, WANG Zhou, LI Wenliang, LIU Gangbo, WANG Xiao Xinjiang Petroleum Geology    2025, 46 (4): 438-447.   DOI: 10.7657/XJPG20250406 Abstract （412）   HTML （12）    PDF（pc） （8021KB）（142）       Knowledge map    Save Ultra-deep fault-controlled fractured-vuggy reservoirs are typically characterized by deep and large fault-controlled hydrocarbon accumulation and preservation. Under the influence of multi-stage tectonism and paleokarstification, the reservoirs have strong heterogeneity and stress sensitivity, leading to unclear inter-well connectivity during the oilfield development process and complex inter-well connection modes, which greatly affect the performance of water/gas injection in production wells. As a fundamental task guiding the waterflooding development of fault-controlled fractured-vuggy carbonate reservoirs, the judgment of the inter-well connectivity is of vital significance. This paper proposes a dynamic-static collaborative analysis method by multi-source data fusion. Based on the division results of statically connected units, using the production performance data and pressure data, several methods such as static pressure analysis, quasi-interference analysis, and production feature similarity, are combined with the well test responses to judge the dynamic connectivity of the statically connected units in the study area. Meanwhile, the changes in the connectivity are analyzed. The proposed method gets ride of the problems of insufficient multi-source data fusion and low efficiency of development data existing in conventional inter-well connectivity analysis. Table and Figures | Reference | Related Articles | Metrics

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Occurrence Space and Mobility of Shale Oil in Fengcheng Formation, Mahu Sag, Junggar Basin YANG Wangwang, WANG Zhenlin, SU Jing, HU Xuan, HUANG Yuyue, LAI Jin, WANG Guiwen Xinjiang Petroleum Geology    2025, 46 (2): 192-200.   DOI: 10.7657/XJPG20250208 Abstract （723）   HTML （22）    PDF（pc） （20255KB）（141）       Knowledge map    Save To clarify the occurrence space and mobility of the shale oil in the Fengcheng formation of the Mahu sag, Junggar Basin, the data of rock thin section, SEM and NMR, and experiments such as total scanning fluorescence were used, together with 2D NMR logging data, to systematically characterize the microscopic pore structure and crude oil occurrence characteristics of the shale reservoir, and identify the factors controlling oil mobility. The storage space of the shale reservoir of the Fengcheng formation in the study area is mainly composed of intergranular pores, intercrystalline pores, dissolution pores, organic pores, and microfractures, with dissolution pores and fractures in dominance. The mobility of shale oil varies significantly in reservoirs with different lithofacies. The best mobility is found in the felsic shale rich in terrigenous clastic silt-sand bands, followed by the dolomitic shale with well-developed dolomitic laminae, and the worst mobility is found in the mixed shale rich in clay minerals. Organic matter abundance, depositional fabric, and pore structure are key factors controlling the mobility of shale oil in the Fengcheng formation. When total organic carbon (TOC) content of the shale in the study area ranges from 0.5% to 1.5%, the oil saturation index reaches its maximum range, indicating good mobility of the shale oil. In thin-bedded felsic shale and laminated dolomitic shale, pores (mainly residual intergranular pores and dissolution pores) and microfractures are developed, with a high proportion of large pores, which facilitates the formation of favorable occurrence space and flow channels for shale oil, promoting the enrichment of mobile oil. Table and Figures | Reference | Related Articles | Metrics

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Reservoir Evaluation and Sweet Spot Optimization for Coal Rock Gas in Benxi Formation, Eastern Ordos Basin ZHANG Zhengtao, FEI Shixiang, LUO Wenqin, ZHONG Guanghao, LAN Tianjun, WANG Ye, CUI Yuehua, WANG Shujie, ZHANG Fang Xinjiang Petroleum Geology    2025, 46 (3): 263-272.   DOI: 10.7657/XJPG20250302 Abstract （439）   HTML （10）    PDF（pc） （8075KB）（140）       Knowledge map    Save To determine the factors influencing coal rock gas productivity in the Carboniferous Benxi formation in the eastern Ordos Basin and identify favorable target areas for production, based on the fundamental geological characteristics and test data of the study area, the No. 8 coal seam was taken as an example for detailed reservoir characterization and analysis of factors controlling gas accumulation. A high-precision 3D geological model was constructed, and sweet spot areas were identified. The study area is a gently west-dipping monocline as a whole. The No. 8 coal seam is well developed and stable, with a thickness ranging from 6.0 to 12.0 m. The reservoir-caprock assemblage primarily consists of coal and mudstone, and the coal structure is mainly classified as Type Ⅰ and Type Ⅱ. In plane, coal rocks are distributed in a banded pattern, with a high gas content averaging 23.17 m3/t. The key factors controlling gas content include burial depth, thermal maturity, positive structure, fracture development, and reservoir-caprock assemblage. Based on the analyses of lithofacies, gas content, rock mechanics, in-situ stress, and fracture characteristics, and considering resources, structural features, coal seam properties, and stress regimes at the roof/bottom, a scheme for sweet spot optimization was proposed. As a result, approximately 777 km2 Class Ⅰ sweet spots and 560 km2 Class Ⅱ sweet spots were delineated. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Maze Karst Cave System in Lianglitage Formation of Tahe Oilfield, Tarim Basin ZHANG Changjian, JIANG Lin, WANG Yan, ZENG Qingyong, MA Xuejian Xinjiang Petroleum Geology    2024, 45 (5): 522-532.   DOI: 10.7657/XJPG20240503 Abstract （530）   HTML （10）    PDF（pc） （7293KB）（136）       Knowledge map    Save To understand the styles and structures of the maze karst cave system in the Upper Ordovician Lianglitage formation in the Tahe oilfield, Tarim basin, the palaeohydrological and geomorphological restoration, karst framework construction, karst cave identification, and genetic model analysis were performed for Block 11 of the oilfield by using the methods such as paleolandform restoration, paleo-water system characterization, log-based stratigraphic correlation, structural fracture analysis, and seismic attribute characterization. The results show that during the Episode Ⅱ of the Middle Caledonian, the southern Tahe oilfield was higher in the northwest than in the southeast geomorphically, with developed NNW-SSE dendritic incised valleys. A subhorizontal maze karst cave system with closed conduit structures and high intensity of erosion are found in the Lianglitage formation, which is a typical maze karst cave system formed by epigenetic karst diffusion and infiltration and shares similarities in genesis with the Bullita karst cave system in the Judbarra region of Australia. The mudstone interval in the Upper Ordovician Qiaerbake formation serves as an aquiclude, which controls the lateral erosion of the karst cave system in the Lianglitage formation. The faults connecting surface water systems provide primary channels for karst water infiltration and erosion. As the regional base level drops, karst water infiltrates downwards along the fractures into the Middle Ordovician strata, forming fault-karst reservoirs in the Yijianfang formation. Understanding the “double-layer” maze epigenetic karst cave system of the Episode Ⅱof the Middle Caledonian in the Tahe oilfield is crucial for the development of Upper Ordovician reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Sedimentary Facies of Yangxia Formation Around Yakela Fault-Bulge in Tarim Basin YANG Yufang, XIAO Qiang, SU Rongkun, LIU Hongping, ZHANG Li, MENG Luying Xinjiang Petroleum Geology    2024, 45 (6): 650-658.   DOI: 10.7657/XJPG20240603 Abstract （573）   HTML （12）    PDF（pc） （10719KB）（134）       Knowledge map    Save The Jurassic strata in the areas around the Yakela fault-bulge in the northern Tarim basin are critical targets for hydrocarbon exploration, where a near-source alluvial fan-fan delta system with the fault-bulge as a provenance is developed. This cannot explain the extensive development of the sandbodies in Jurassic in the southern Yakela fault-bulge. Based on the analysis of the tectonic evolution of the Yakela fault-bulge, together with the seismic and core data and the reservoir characteristics, a comprehensive analysis was conducted on the sedimentary facies to determine the spatial distribution patterns of the sedimentary facies in the Jurassic Yangxia formation around the Yakela fault-bulge. It is found that during the Jurassic deposition the Yakela fault-bulge as a whole was higher in the west than in the east, with erosion occurring in the west and a peneplain state in the east at the late stage of Yangxia formation deposition. The sedimentary system primarily comprises two parts: one sourced from the western Yakela fault-bulge, forming an apron-like distribution of the near-source fan delta deposits along the fault-bulge; the other sourced from the southern Tianshan Mountains, forming a braided river delta system extending from north to south in the eastern Yakela fault-bulge. From the perspective of reservoir characteristics, the fan delta system is characterized by coarse lithology, mainly including conglomerates and gravel-bearing medium-coarse sandstones, with low textural and compositional maturities and poor physical properties. In contrast, the braided river delta system predominantly consists of gravel-bearing medium-fine sandstones, and records a long transport distance, with high textural and compositional maturities and good physical properties. The Yangxia formation in the eastern Yangxia sag may be a potential favorable exploration target. Table and Figures | Reference | Related Articles | Metrics

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Bottom Water Injection Method and Its Application in Low-Permeability Bottom-Water Reservoirs SONG Peng, ZHANG Xingang, YANG Weiguo, WANG Nan, SHI Jian, XIE Qichao, DUAN Wenhao Xinjiang Petroleum Geology    2025, 46 (3): 375-381.   DOI: 10.7657/XJPG20250315 Abstract （340）   HTML （2）    PDF（pc） （911KB）（132）       Knowledge map    Save The Jurassic bottom-water reservoirs in the Ordos Basin suffer from insufficient natural energy, low pressure coefficient, low permeability, and strong reservoir heterogeneity, and they exhibit a rapid rise in water cut and low recovery when developed by conventional water injection process. To improve the development effects of such reservoirs, the concept of bottom water injection was proposed. In respect of five key factors influencing the development effects of bottom-water reservoirs, i.e. bottom-water energy, permeability anisotropy, barrier permeability, interlayer frequency, and sedimentary rhythm, oil-layer water injection and bottom water injection were compared for recovery by using reservoir numerical simulation. The results indicate that bottom water injection effectively enhances bottom water energy, facilitates uniform elevation of the oil-water contact, and significantly extends oil production period with medium-low water-cut. Compared with oil-layer water injection, bottom water injection improves ultimate oil recovery by more than 10%. Table and Figures | Reference | Related Articles | Metrics

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Fault Characteristics and Influences on Jurassic Reservoirs in the Yanwu Area, Ordos Basin LONG Shengfang, HOU Yunchao, ZHAO Yuhua, ZHANG Jie, HAO Jinxin, GU Zhaoxing Xinjiang Petroleum Geology    2025, 46 (3): 329-337.   DOI: 10.7657/XJPG20250309 Abstract （290）   HTML （6）    PDF（pc） （5715KB）（130）       Knowledge map    Save A number of Jurassic reservoir groups have been discovered in the southern part of the Tianhuan depression in the Ordos Basin, highlighting significant oil and gas exploration potential. Taking the Yanwu area as an example, by integrating the data of 3D seismic, drilling, core, and production performance, the fault characteristics were investigated, and the controls of these faults on the Jurassic Yan’an formation reservoir were analyzed. The results indicate that the Mesozoic in the Yanwu area develops three groups of major faults trending in NW-SE, NEE-SWW, and nearly E-W, which are primarily sub-vertical strike-slip faults featured with lateral zonation and vertical stratification. The NW-SE faults in the Triassic Yanchang formation were formed during the Indosinian Movement. The NEE-SWW and nearly E-W faults in the Jurassic Yan’an formation were mainly formed during the Yanshanian Movement, with the highest fault density in the Jurassic, and some discontinuous minor faults connected and extended through the Late Yanshanian to Himalayan to create the main fault belt. The NEE-SWW strike-slip faults vertically communicate source rocks and reservoir rocks, facilitating hydrocarbon migration and accumulation in the Jurassic. The trap-controlling faults near the main displacement zone, which exhibit large fault throws, resulted in hydrocarbon escape during multiple phases of activity, compromising reservoir preservation. Fractures are developed at fault ends or in overlapping zones. These fault-related fractured reservoir may suffer water front advancing, significantly impacting waterflooding effect in the reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Differences in Natural Fracture Development in Ultra-Deep Carbonate Reservoirs: A Case Study of YUEM Area in Tarim Basin LI Hui, NING Yaxin Xinjiang Petroleum Geology    2025, 46 (2): 144-153.   DOI: 10.7657/XJPG20250203 Abstract （528）   HTML （17）    PDF（pc） （13373KB）（130）       Knowledge map    Save The carbonate reservoirs in the YUEM area of Tarim Basin show differences in natural fracture development. Using the data of outcrop, core, thin section, logging, seismic, and production performance, the differences of natural fractures in development characteristics, formation periods, genesis, and spatial distribution were clarified through fracture parameter statistics, sensitivity analysis of seismic attributes, and numerical simulation of tectonic stress field. Three types of fractures, i.e. diagenetic fractures, tectonic fractures, and composite fractures, corresponding to three development periods are found in the study area. The development of these fractures is controlled by the coupling of tectonics, sedimentation, and karstification. Favorable fracture development zones are identified in oblique-overlap zones, intersections of major and secondary faults, fault tips, algal reef facies belts, and tops and bottoms of karst caves. Table and Figures | Reference | Related Articles | Metrics

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Main Controlling Factors and Development Practice of Shale Oil Sweet Spots in the Lucaogou Formation, Jimsar Sag, Junggar Basin JIN Zhijun, CAO Yan, ZHANG Hong, TANG Yong, QIN Zhijun, LIU Kouqi, LIANG Chenggang, LI Guanfang, HE Wenjun Xinjiang Petroleum Geology    2025, 46 (6): 647-658.   DOI: 10.7657/XJPG20250601 Abstract （254）   HTML （12）    PDF（pc） （5499KB）（127）       Knowledge map    Save The Permian Lucaogou formation in the Jimsar sag, Junggar Basin, represents one of the most significant continental shale oil plays in China. However, uncertainties remain regarding the primary geological controls of “sweet spots”, incomplete evaluation frameworks, and discontinuous distribution of productive intervals. Clarifying the formation mechanisms and identification criteria of the sweet spots is critical for advancing shale oil exploration theory and guiding efficient development. Based on core, well logging, and experimental data, this study systematically investigates the controlling factors of shale oil sweet spots in the Lucaogou formation from four dimensions (reservoir capacity, oil-bearing capacity, mobility, and fracability). The results indicate that the Lucaogou formation can be divided into upper, middle, and lower sweet-spot intervals, among which the middle interval remains largely undeveloped yet holds substantial potential. Siltstone and calcareous-felsic shale which are characterized by abundant macropores, high free hydrocarbon content, and strong mobility constitute the most favorable lithofacies. Intervals with moderate total organic carbon (TOC) content, moderate maturity, and high brittle-mineral content are more conducive to forming fracable sweet spots. A four-property coupling evaluation highlights the middle interval as a prime development target which is further validated by the high-yield performance of Well JHW85-71. This study provides a scientific foundation for sweet spot identification and development planning of shale oil in the Lucaogou formation in the Jimsar sag. Table and Figures | Reference | Related Articles | Metrics

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Water Invasion Characteristics and Stable Production Strategies in Kelasu Ultra-Deep Gas Field, Kuqa Depression LIU Liwei, ZHOU Hui, YAN Bingxu, JIAO Yuwei, QU Yuanji, JIN Jiangning, PAN Yangyong Xinjiang Petroleum Geology    2025, 46 (1): 71-77.   DOI: 10.7657/XJPG20250109 Abstract （549）   HTML （12）    PDF（pc） （18385KB）（126）       Knowledge map    Save The Kelasu ultra-deep gas field in the Kuqa depression of the Tarim Basin is challenged by severe water invasion, leading to rapid decline in production. Through analysis on surface seismic data and imaging logging data, the distribution patterns of faults and fractures were determined. Combining with the production performance of the gas field, three types of water invasion were identified in the Kelasu ultra-deep gas field: fault-communicated edge or bottom water, non-uniform water invasion along fractures, and occluded water invasion due to locally incomplete displacement. The former two types are dominant in the gas field. The three types differ significantly in characteristics and influence range. On one hand, the ability to communicate with edge or bottom water along the trend of second-order faults and vertically is strong, but water invasion perpendicular to the trend of faults has a minor, localized impact. On the other hand, fractures are oriented and distributed regularly, showing a feature of “zones generally and belts locally”. The differences in the internal connectivity of the gas reservoir, the order and the speed of water invasion in the gas reservoir are the external manifestations of the division and zonation of fractures, which have a global effect on water invasion in the gas reservoir. Considering the water invasion characteristics and development status of the gas field, strategies were proposed to optimize well pattern according to spatial distribution of fractures, and to strengthen researches on two supporting gas production technologies: chemical water plugging and gas injection to alleviate water lock. Table and Figures | Reference | Related Articles | Metrics

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Sweet Spot Prediction of Shale Gas Reservoirs in Wulalike Formation, Majiatan Area, Ordos Basin ZHAO Yuhua, WANG Yating, HUANG Yan, ZHAO Deyong, CAO Yongliang Xinjiang Petroleum Geology    2025, 46 (3): 273-279.   DOI: 10.7657/XJPG20250303 Abstract （402）   HTML （5）    PDF（pc） （4771KB）（126）       Knowledge map    Save The Middle Ordovician Wulalike formation is the primary target for marine shale gas exploration in the Majiatan area of the Ordos Basin. The reservoir is dominated by siliceous shale and characterized by thin layers and strong horizontal heterogeneity, seriously challenging the seismic identification. By utilizing geological, logging, and core data from the Majiatan area, a petrophysical analysis was performed on the marine shale reservoir, a shear-wave prediction method was proposed, and the optimal petrophysical parameters for characterizing the sweet spots of the marine shale gas reservoir were identified. By integrating drilling and gas testing results, the evaluation criteria for geological and engineering sweet spots of the marine shale gas reservoir were established. By combining post-stack seismic waveform-indicated simulation with self-organizing neural network fusion techniques, the distribution of sweet spots in the shale gas reservoirs was predicted. The results show that the geological and engineering sweet spots are primarily distributed in a band-like pattern in the western and central parts of the study area. The drilling results confirm that the seismic prediction method for sweet spots of shale gas reservoirs is worthy of promotion. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Ordovician Karst Reservoirs in Ma 4 Block of Hetianhe Gas Field and Its Influences on Well Productivity LI Chongyue, XU Wensheng, HAN Fuqiang, YANG Yan, ZHOU Lang, ZHANG Hu, YU Bingyue Xinjiang Petroleum Geology    2025, 46 (5): 553-559.   DOI: 10.7657/XJPG20250504 Abstract （405）   HTML （11）    PDF（pc） （3445KB）（119）       Knowledge map    Save The Ordovician carbonate reservoirs are the main development targets in the Hetianhe gas field. Taking the Ma 4 block as an example, the paleokarst characteristics were investigated based on core, thin section, logging, drilling and fluid data. The relationship between fractures and paleokarstifcaiton or filling was analyzed, the main factors controlling gas well production were evaluated, and the favorable targets for tapping the potential of the karst reservoirs were clarified. The research results show that the characteristics of fracture development in the vertical flow zone are not only related to tectonic characteristics, but also to surface karstification and filling processes. The activity of bottom water in the gas reservoir is related to the burial dissolution. Karst zonation is the main cause for the dual structure of karst reservoirs. The fracture zone is not the active water zone. The production effect of a single well mainly depends on two factors, namely burial dissolution and fracture development in the vertical flow zone. Table and Figures | Reference | Related Articles | Metrics

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Dolomitization and Main Controlling Factors of Penglaiba Formation Reservoir in Tarim Basin YAN Bo, LUO Fuwen, CAO Yang, CHENG Linfeng Xinjiang Petroleum Geology    2025, 46 (4): 419-428.   DOI: 10.7657/XJPG20250404 Abstract （404）   HTML （12）    PDF（pc） （8122KB）（119）       Knowledge map    Save The dolomites in the Lower Ordovician Penglaiba formation in the Tarim Basin have undergone a complex diagenetic evolution characterized by multi-stage and multi-genesis. To systematically study their petrological features, dolomitization mechanisms, and main factors governing reservoir quality, investigations were conducted using outcrops, core samples, thin sections, and geochemical tests. The results show the presence of four major dolomite types in the Penglaiba formation, including micritic dolomite, fine- to medium-grained dolomite, coarse-grained dolomite, and porphyritic dolomite, all of which are genetically controlled by penecontemporaneous-shallow burial and burial dolomitizations. Fine- to medium-grained dolomites display abundant intercrystalline pores with high euhedral degree, whereas coarse crystalline dolomites retain some intercrystalline pores and have strong compaction resistance. The dolomites generally formed through replacement or recrystallization under burial conditions, with Early Ordovician seawater serving as the primary dolomitizing fluid, variably modified by deep hydrothermal fluids and evaporite-derived brines. Grain-shoal deposits provide the most favorable sedimentary microfacies for reservoir development because the early intergranular pores not only act as pathways for fluid migration but also serve as initial storage space, thereby accelerating dolomitization. Sea-level fluctuations modulated the physical and chemical conditions of dolomitization by altering hydrodynamic regimes, fluid-migration patterns, and the karstification processes. Palaeogeomorphic highs experienced more intense dolomitization, and well-developed stratiform dissolution pores and vugs provide favorable conditions for high-quality reservoirs. These insights provide a sound basis for deep dolomite exploration in the Ordovician strata of the Tarim Basin, clarify dolomitization mechanisms and main reservoir-controlling factors, and offer practical guidance for future exploration and development. Table and Figures | Reference | Related Articles | Metrics

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Tectonic-Paleogeographic Restoration and Basin-Range Coupling Reappraisal of the Paleogene in Southwestern Tarim Basin GENG Feng, CAO Zicheng, WANG Arui, CAO Kai, YAO Junzhe, XU Yadong, WANG Guocan Xinjiang Petroleum Geology    2026, 47 (2): 127-136.   DOI: 10.7657/XJPG20260201 Abstract （199）   HTML （14）    PDF（pc） （1915KB）（114）       Knowledge map    Save The Paleogene strata in the southwestern Tarim Basin record the transgression-regression process of the Tarim Basin and the early Cenozoic orogenesis of the Pamir-West Kunlun orogenic belt. Thus, restoring the tectonic-paleogeographic framework of the Paleogene in the southwestern Tarim Basin is significant for understanding the paleogeographical and paleoenvironmental changes in central Asia. Based on the geological survey on the Qimugan section of the Paleogene in the southwestern Tarim Basin, together with available drilling and outcrop data, the stratigraphic framework and sedimentary sequence of the Paleogene were investigated, the tectonic-lithofacies paleogeography of the Paleogene was mapped, and the basin-range coupling process of the Paleogene was analyzed. The results show that the southwestern Tarim Basin had a higher topography in the east than in the west in the Paleogene. During the Paleocene-Late Eocene, the southwestern Tarim Basin was dominated by marine sediments in the western part, marine-continental transitional sediments in the central part, and delta sediments in the eastern part. During the Late Eocene-Oligocene, the southwestern Tarim Basin witnessed a further uplift in the southern part, together with expanded delta sediments, and a dominance of shallow lake and near-shore submarine fan sediments in the western part and of lakeside sediments in the eastern part. As a whole, the southwestern Tarim Basin fully transformed into a lacustrine depositional environment. Generally, the southwestern Tarim Basin experienced two cycles of transgression-regression during the Paleogene. After the second regression, the sea water completely retreated from the southwestern Tarim Basin. The spatio-temporal coincidence of the regression with the crustal thickening and shortening of Pamir and the global sea level drop suggests that the final regression of the Tarim Basin is probably a result of the combined effect of tectonic and climatic changes. Table and Figures | Reference | Related Articles | Metrics

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Waterflooding Characteristics of Extra-Low Permeability Reservoirs in Chang 6 Member, Ansai Oilfield DUAN Wenbiao, ZHANG Yongqiang, GAO Chunning, ZHANG Jie, WANG Jinghua, ZHOU Jin, ZHANG Chuanbao, ZENG Shan Xinjiang Petroleum Geology    2025, 46 (3): 353-359.   DOI: 10.7657/XJPG20250312 Abstract （340）   HTML （4）    PDF（pc） （2344KB）（109）       Knowledge map    Save To understand the sweep efficiency and water washing behaviors during waterflooding of extra-low permeability reservoirs in the Chang 6 member of the Ansai oilfield, 9 sealed coring inspection wells were systematically deployed at different orientations around Well W16-15 in the WY block. Using logging and scanning electron microscopy (SEM) data, the water washing behaviors, sweep efficiency, and microstructural changes in the reservoir were examined. The results show that the Chang 61-21 sublayer with good physical properties is strongly water washed, whereas the Chang 61-31 sublayer with poor physical properties is weakly or not water washed. The smaller the angle between the producer orientation and the principal stress direction or the closer to the injector, the greater the water washing degree and the water-washed reservoir thickness. The vertical sweep efficiency of the inspection well group in Chang 61 is 0.51, closely matching the calculated sweep efficiency (0.55) of the original well group. In the medium water-washed and strongly water-washed intervals of Chang 6 reservoir, long-term washing by injected water leads to the migration and swelling of clay minerals, enhancing the reservoir heterogeneity. Table and Figures | Reference | Related Articles | Metrics

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Establishment of a New Production Decline Equation and Its Theoretical Basis: A Case Study of Unconventional Reservoirs in Tuha Oilfield JI Fei, SUN Xinxin, ZHANG Qi Xinjiang Petroleum Geology    2024, 45 (6): 696-702.   DOI: 10.7657/XJPG20240608 Abstract （516）   HTML （9）    PDF（pc） （684KB）（108）       Knowledge map    Save The Duong production decline model and modified Duong production decline model widely used for unconventional oil and gas reservoirs are disadvantageous in some aspects, such as incorrect definitions of characteristic parameters, inability to take zero as an independent variable, and lack of flow theoretical basis as a mathematical model. To address these problems, a new production decline equation was proposed by improving the mathematical model of relative permeability of oil phase in fractured reservoirs, and integrating the more applicable water phase relative permeability relational expression and the Welge equation. The new equation is similar in form to the modified Duong model, and can be transformed into the Arps production decline equation when the characteristic parameter A is zero, indicating that the new equation is a generalized production decline equation. The application of the new equation to the tight tuff oil reservoir of the Tiaohu formation in Block Ma56 of Tuha oilfield demonstrated a favorable effect, providing a valuable reference for similar unconventional reservoirs. Table and Figures | Reference | Related Articles | Metrics

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CO2 Injection for Flow Field Reconstruction in Jurassic Bottom Water Reservoirs， Ordos Basin ZOU Jiandong, TAN Xiqun, ZHANG Jiaosheng, LI Chao, LIU Jungang, LYU Wei, ZHAO Haifeng Xinjiang Petroleum Geology    2025, 46 (5): 560-566.   DOI: 10.7657/XJPG20250505 Abstract （320）   HTML （15）    PDF（pc） （1831KB）（107）       Knowledge map    Save Edge and bottom water are found in the Jurassic oil reservoirs in the Ordos Basin. In this kind of reservoirs, rapid water cut rise and low recovery by water flooding occur after initital production. In order to explore new methods for enhanced oil recovery in such reservoirs and find new ways to increase production by carbon sequestration in near-abandoned reservoirs, a pilot test was conducted on top CO2 injection for flow field reconstruction in the Y9 reservoir in the X1 block of Jiyuan oilfield. Through the mechanism analysis of CO2-assisted gravity drainage, multiphase and multi-component numerical simulation was performed to understand the sensitivity and adaptability of the reservoir's geological parameters, and the reservoir engineering parameters were also optimized for the test area. The results show that the residual oil in the Jurassic bottom water reservoirs after waterflooding mainly exists in three forms: thick oil ring in the zone between injection and production wells after the invasion of bottom water, thin oil ring in the zone from the outer oil-bearing edge to the oil production well due to bottom water coning and edge water intrusion, and residual oil after waterflooding. Injecting CO2 at the reservoir top is an effective way to inhibit bottom water coning. As an artificial gas cap forms and exaggerates, gas-oil contact moves downwards, and accordingly oil-water contact becomes lower, alleviating bottom water coning. The main factors affecting CO2-assisted gravity drainage include formation dip, reservoir thickness, permeability, heterogeneity, crude oil properties, and oil saturation, etc. Simulation studies and pilot tests indicate that CO2-assisted gravity drainage at the reservoir top can effectively reconstruct the flow field in waterflooding reservoirs, thereby enhancing the ultimate recovery. Table and Figures | Reference | Related Articles | Metrics

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Methods of Reasonable Productivity Determination for Ultra-Deep Fault-Controlled Fractured-Vuggy Gas Reservoirs in Shunbei Area YU Tengfei, HUANGFU Jingjing, CHEN Zhihui, WANG Hong Xinjiang Petroleum Geology    2025, 46 (4): 505-511.   DOI: 10.7657/XJPG20250415 Abstract （331）   HTML （3）    PDF（pc） （1283KB）（105）       Knowledge map    Save The ultra-deep fault-controlled fractured-vuggy gas reservoirs in the Tarim Basin represent a principal option for increasing gas reserves and production. It is crucial to determine the reasonable productivity of gas wells for the efficient development of gas reservoirs. Shunbei ultra-deep fault-controlled fractured-vuggy gas reservoir is characterized by strong heterogeneity, high stress sensitivity, and varying physical properties, therefore, conventional methods for determining reasonable productivity of the reservoir need to be improved. Based on geological and production data, the reservoirs in the F1 zone of the Shunbei gas reservoir can be divided into three types: fault + cavity, fault + pore, and fault/fracture. According to the calculation by the binomial productivity equation for wells in high-pressure gas reservoirs, the fault + cavity reservoir show the highest absolute open flow potential (AOFP), followed by the fault + pore reservoir, and then the fault/fracture reservoir. The productivity test curves show 3 shapes such as linear, upward curved, and downward convex, with the reasonable choke as the largest choke within the testing range for the former two shapes, and as the choke at the inflection for the downward convex shape. The pressure drop method shows that, within the testing range, a larger reasonable choke is preferred for the fault + cavity reservoir, and a smaller reasonable choke for the fault + pore and fault/fracture reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Lithological Differences of Chang 7 Mud-Shale System and Their Controls on Shale Oil Content in Ansai Area, Ordos Basin SHI Liang, ZHANG Yaxiong Xinjiang Petroleum Geology    2025, 46 (3): 308-317.   DOI: 10.7657/XJPG20250307 Abstract （291）   HTML （4）    PDF（pc） （1843KB）（105）       Knowledge map    Save Affected by source input and sedimentary cycles, continental mud-shale systems are lithologically complex and diverse. To elucidate the lithological differences of these systems and their controls on shale oil content, the mud-shale system in the 7th member of the Yanchang formation (Chang 7 member) in the Ansai area of Ordos Basin was selected for detailed analysis. By comparing petrological and geochemical characteristics, the development features of mudstone, shale, sandstone, and sand-laminated shale in the study area were identified. Through quantitative evaluation of shale oil content and analysis of geological parameters, the differences in shale oil content between different lithologies and the controlling factors were revealed. The results indicate that shale has the highest content of shale oil, with a poor mobility; sandstone and sand-laminated shale contain moderate content of shale oil, with a good mobility; and mudstone has the lowest content of shale oil, with the poorest mobility. For shale, mudstone, and sand-laminated shale, the higher the total organic carbon content and pyrolysis peak temperature, the higher the shale oil content; the better the organic matter types, the higher the shale oil content. For sandstone, the higher the porosity and permeability, the higher the shale oil content. Table and Figures | Reference | Related Articles | Metrics

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Source-Reservoir Coupling and Sweet Spot Formation Mechanism of Continental Laminated Shale Oil: A Case Study of the Fengcheng Formation, Junggar Basin CAO Jian, QIN Zhijun, WEI Chao, XIANG Baoli, LIU Jin Xinjiang Petroleum Geology    2025, 46 (6): 668-683.   DOI: 10.7657/XJPG20250603 Abstract （290）   HTML （6）    PDF（pc） （20647KB）（104）       Knowledge map    Save Significant breakthroughs have been made in the exploration of continental shale oil in China. However, the strong heterogeneity and complex source-reservoir coupling in these shales have hindered the understanding of sweet spot formation mechanism. In this paper, taking the Permian Fengcheng formation in the Junggar Basin as an example, the characteristics of shale laminae and their controls on shale oil sweet spots were systematically investigated using multiple techniques such as large-area thin-section scanning, scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), confocal laser scanning microscopy (CLSM), and organic geochemical analysis. The results indicate that the lacustrine shales of the Fengcheng formation are well-laminated. The laminae can be classified into six types: silt-grade felsic lamina (SFL), argillaceous-grade felsic lamina (AFL), sparry dolomitic lamina (SDL), sparry calcite lamina (SCL), spherulitic siliceous lamina (SSL), and alkaline mineral lamina (AML). Two predominant laminated shale combinations are identified, i.e., SFL + AFL, and SCL/SDL + AFL. These lamina types exhibit significant variations in source-reservoir characteristics. AFL and SSL, characterized by high organic matter (OM) contents and the presence of high-quality hydrocarbon precursors such as laminated algae and rhodophyta spores, serve as the primary hydrocarbon-generating laminae. In contrast, SFL exhibits well-developed micropores and nanopores, including quartz/feldspar intercrystallline pores and feldspar intragranular dissolved pores, with a high proportion of free oil, rendering it favorable reservoir lamina. The superimposition of multiple lamina types governs organic-inorganic interactions, reservoir space characteristics, and hydrocarbon micro-migration processes, ultimately leading to differential enrichment of shale oil across various intervals. It is noted that the SFL + AFL combination represents the optimal source-reservoir configuration, demonstrating excellent overall oil content and forming an enrichment model characterized by oil generation in argillaceous lamina and accumulation in silty lamina. This combination is identified as a favorable target for shale oil exploration and development. Table and Figures | Reference | Related Articles | Metrics

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Mechanism of Microbially Activated Water Flooding in Ultra-Low Permeability Reservoirs ZHANG Yongqiang, ZHANG Xiaobin, XUE Shuwen, XU Feiyan Xinjiang Petroleum Geology    2025, 46 (3): 338-343.   DOI: 10.7657/XJPG20250310 Abstract （346）   HTML （6）    PDF（pc） （751KB）（103）       Knowledge map    Save During water flooding in ultra-low permeability reservoirs, crude oil within the swept area is preferentially produced, leaving a high residual oil saturation with the potential for further recovery. Microbially activated water flooding is an effective reservoir development technology; however, its mechanism in ultra-low permeability reservoirs remains unclear. By integrating geophysics, microbiology, and reservoir engineering, the group components and microbial diversity of crude oil were tracked and analyzed. Then, using production performance data, the mechanism of microbially activated water flooding was investigated. The results indicate that in relatively homogeneous reservoir regions, surface tension of produced fluids remains stable, biomarkers in crude oil show no significant degradation, and oil viscosity exhibits no substantial changes. MEOR in the study area is mainly realized with the mechanism of microscopic profile control, supplemented by displacement efficiency enhancement and viscosity reduction. During field applications, this finding was validated by using reservoir microbial variations and production data. Table and Figures | Reference | Related Articles | Metrics

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Prediction of Structural Fractures in Deng 4 Member Reservoirs in the Shehong-Yanting Block, Penglai Gas Field, Sichuan Basin LI Gao, SHANGGUAN Ziran, YANG Xu, LI Hongtao, LI Ze, WANG Qiutong Xinjiang Petroleum Geology    2025, 46 (2): 136-143.   DOI: 10.7657/XJPG20250202 Abstract （500）   HTML （21）    PDF（pc） （11883KB）（102）       Knowledge map    Save In order to determine the distribution of the fractures in the fourth member of the Dengying formation (Deng 4 member) in the Shehong-Yanting block of the Penglai gas field, Sichuan Basin, a statistical analysis was conducted on the structural fracture parameters. Based on rock rupture criteria, occurrence evolution conditions, and present-day stress field characteristics, a quantitative prediction of fractures in the ultra-deep carbonate reservoirs of the Deng 4 member were performed through tectonic stress field inversion. The results show that structural shear fractures are well developed in the Deng 4 member, oblique fractures are concentrated in the southeastern structural highs, while high-angle and vertical fractures are mostly distributed near faults. The fracture strikes are predominantly NW-SE, NE-SW and NNW-SSE. The linear density of fracture is generally low in the southeast and high in the northwest, while the fracture aperture shows an opposite distribution pattern. The fracture porosity reflects a relatively small variation. Fracture parameters exhibit different distribution characteristics within fault zones, near faults, and in non-fault areas, with the predicted results being largely consistent with the measured data. The fracture dip, aperture, and porosity significantly influence gas well productivity. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2026, 47 (1): 1-10.   DOI: 10.7657/XJPG20260101 Abstract （206）   HTML （18）    PDF（pc） （6979KB）（102）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Identification of Fault-Karst Bodies in Permian Maokou Formation in Jingyan Area, Southwestern Sichuan Basin LI Suhua, LU Qijun, HU Hao, LI Rong, SU Chengpeng, JIANG Nengchun Xinjiang Petroleum Geology    2025, 46 (5): 544-552.   DOI: 10.7657/XJPG20250503 Abstract （294）   HTML （23）    PDF（pc） （35146KB）（99）       Knowledge map    Save The distribution of fault-controlled karst reservoirs in the Permian Maokou formation in the Jingyan area of southwestern Sichuan Basin remains unclear. A seismic identification model for faults and fault-karst bodies in the Maokou formation was established using drilling, geological, seismic and other data. The differences in seismic reflections between faults and fault-karst bodies were analyzed through forward modelling. On this basis, multi-stage superimposed faults were identified using seismic structural attributes such as coherence, maximum likelihood, dip angle and gradient structure tensor etc., and interlayer fault-karst bodies were recognized from seismic texture attributes such as entropy and energy. Then the distribution of Maokou formation fault-controlled karst reservoirs was accurately determined, and a geological development model was established. The results indicate that the study area mainly develops two types of fault-controlled karst reservoirs: multi-stage superimposed fault-karst bodies, which are observed in the southern part of the study area, and interlayer fault-karst bodies, which are developed in the eastern part of the study area. The seismic structural attributes can be used to accurately recognize high, steep and upright multi-stage superimposed fault-karst bodies that exhibit significant differences in the continuity of seismic waveforms, while the seismic texture attributes can be used to accurately represent gentle and low-angle interbedded fault-karst bodies with obvious changes in reflection amplitude energy of seismic waveforms. The predicted results are consistent with actual drilling results, and the research results can guide the future exploration deployment. Table and Figures | Reference | Related Articles | Metrics

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A Displacement Limit Characterization Method for Waterflooding in Ultra-Low Permeability Reservoirs CHEN Lin, XU Qianwen, CHEN Kun, CHEN Xiaodong, LIU Wen, WEN Lin, LIU Bin Xinjiang Petroleum Geology    2025, 46 (3): 388-394.   DOI: 10.7657/XJPG20250317 Abstract （353）   HTML （3）    PDF（pc） （1225KB）（99）       Knowledge map    Save Ultra-low permeability reservoirs are typically developed by waterflooding, which yet is highly complex in the factors influencing displacement limits. To establish a waterflood displacement limit characterization method for ultra-low permeability reservoirs, 12 parameters were considered, including porosity, permeability, pore-throat radius, and heterogeneity coefficient. These parameters are classified into three categories：porosity-permeability, heterogeneity, and pore-throat radius. By using the Pearson correlation coefficient method, the optimal characterization parameters were identified from each category, and a characteristic displacement index was then constructed based on the selected parameters. Waterflooding experiments were conducted to determine displacement limits for different core samples, and a characterization model was established by fitting the displacement limits with the characteristic index. The results indicate that, among the influencing parameters, permeability, variation coefficient, and weighted average pore-throat radius can effectively characterize the displacement limits of ultra-low permeability reservoirs. By fitting the displacement limits with the selected characterization parameters, a reliable waterflood displacement limit characterization model for ultra-low permeability reservoirs can be developed. Table and Figures | Reference | Related Articles | Metrics

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Calculation Methods and Influencing Factors of Gas Field Decline Rate FAN Youhong, LIU Zhijun, PEI Ze, REN Chaofeng Xinjiang Petroleum Geology    2025, 46 (5): 600-605.   DOI: 10.7657/XJPG20250510 Abstract （338）   HTML （3）    PDF（pc） （545KB）（95）       Knowledge map    Save Accurate evaluation of performance decline is crucial for efficient development of gas fields and ensuring stable energy supply. Production decline rate and productivity decline rate are two commonly used parameters for presenting performance decline in gas fields from different perspectives, but their definitions are different. In order to understand the physical meanings of production decline rate and productivity decline rate and clarify their inherent relationship and influencing factors, the calculation method of gas field decline rate was analyzed, and the influencing factors were identified. The results indicate that, for exponential decline, the productivity decline rate are consistent with the production decline rate, while for hyperbolic decline, the productivity decline rate is always greater than the production decline rate, and the difference between the two decline rates increases with the increase of decline index and initial decline rate, and the two rates gradually tend to be consistent with each other with the extension of production time. The concept of gas field exploitation intensity was introduced to eliminate the fluctuations in production decline rate caused by downstream gas consumption changes. A new method of production/productivity prediction was proposed. Specifically, an exponential decline model is used at the early stage of decline, and a harmonic decline model is used at the mid to late stage of decline; then, the average of the two model results is taken as the lower limit, and the result obtained from the harmonic decline model as the upper limit. The research results are of great significance to accurately analyze the decline behaviors of gas fields and scientifically formulate development plans. Table and Figures | Reference | Related Articles | Metrics

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A Method for Optimizing Depth Domain Velocity Inversion LI Jiwei, LI Guangpeng, DU Jiajun, FENG Rongchang, DUAN Xiaoxu Xinjiang Petroleum Geology    2025, 46 (1): 97-104.   DOI: 10.7657/XJPG20250112 Abstract （509）   HTML （5）    PDF（pc） （10898KB）（95）       Knowledge map    Save Seismic data from piedmont areas typically suffers from low signal-to-noise ratio (SNR), making it challenging to pick residual velocity fields and causing difficulties in iterative convergence of the depth domain velocity field to its optimal value. All these factors impede accurate migration and imaging of the seismic data from piedmont areas. By using the interpolation techniques in five-dimensional data regularization, the data from the original common midpoint (CMP) gathers prior to migration were reconstructed. By altering observation system, the bin attributes were enhanced to improve the SNR of the seismic data for iterative inversion of the pre-stack depth migration (PSDM) velocity field. To ensure the fidelity of the migrated data, the high-SNR CMP gathers obtained from data interpolation were used solely as inputs for the iterative inversion of the depth domain velocity field, while the original CMP gathers were preserved for the final PSDM imaging. This method enables fast and accurate iterative convergence of the depth domain velocity field. The actual application demonstrates that the method is highly feasible, and yields accurate final migrated velocity field through iterative updates and well-aligned reflections of migrated seismic profiles. This method provides a valuable reference for PSDM velocity modeling in the piedmont areas. Table and Figures | Reference | Related Articles | Metrics

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A New Method for Identifying Fluid Types in Ultra-Deep Reservoirs in Shunbei Area, Tarim Basin DU Huanfu, WANG Chunwei, XU Ming, HAN Junwei, ZHANG Fengjiao, CHEN Xinyi, YANG Xudong Xinjiang Petroleum Geology    2025, 46 (4): 512-518.   DOI: 10.7657/XJPG20250416 Abstract （338）   HTML （9）    PDF（pc） （1365KB）（90）       Knowledge map    Save The ultra-deep oil and gas reservoirs in the Shunbei area have undergone multi-period hydrocarbon charging and migration, with complex oil/gas distribution patterns, making it difficult to identify reservoir fluid types. In order to accurately evaluate the fluid types in ultra-deep reservoirs in the Shunbei area, based on the data of well drilling, logging and production test, a comprehensive correction method for the key influencing factors of gaseous hydrocarbon data was established. A new method for identifying fluid types with a three-dimensional model incorporating coefficients of oil, gas and water contents was proposed. The results indicate that the comprehensive correction method based on the gray correlation algorithm for the factors affecting gaseous hydrocarbon data, such as drilling time, bit diameter, drilling fluid displacement, drilling coring, and drilling fluid density, has improved the comparability and accuracy of gaseous hydrocarbon data. Because the C1 content in typical gas layers is close to the total hydrocarbon content, and the heavy hydrocarbon content is relatively high in oil layers, while relatively low in water layers, a three-dimensional model using the coefficients of oil, gas and water contents is established to accurately determine the fluid types in ultra-deep reservoirs. The study results provide a basis for later decision-making on well drilling and oil and gas reservoir development. Table and Figures | Reference | Related Articles | Metrics

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Quantitative Characterization of Fractures and Vugs in Carbonate Rocks Based on Rock Surface Resistivity Measurements LI Mengfan, TANG Jun, ZHENG Chenchang, DU Guohao, WANG Caiwei Xinjiang Petroleum Geology    2025, 46 (5): 614-621.   DOI: 10.7657/XJPG20250512 Abstract （260）   HTML （5）    PDF（pc） （8629KB）（89）       Knowledge map    Save The significant heterogeneity of the carbonate reservoirs in the Sinian Dengying formation in the Sichuan Basin poses substantial challenges to interpretation of microresistivity scanning image logging for the fractured-vuggy reservoirs. To enhance the accuracy of imaging logging in evaluating fractured-vuggy carbonate reservoirs, a core surface electric field measurement device was customized based on AutoScan-Ⅱ core planar resistivity scanning experiments. Using this device, experiments on rock surface resistivity measurement and imaging were conducted to quantitatively analyze the imaging response characteristics of vugs and fractures. A calibration method for fracture-vug parameters based on rock surface resistivity distribution was established. The results show that the computed vug diameter and plane porosity increase linearly as the core-measured vug diameter and plane porosity increase, and the computed fracture width and the surface fracture ratio increase logarithmically as the core-measured fracture width and surface fracture ratio increase. The laboratory-based rock surface resistivity experiments effectively reduce the discrepancies between core measurements and imaging logging calculations, enabling precise calibration and quantitative evaluation of plane porosity of fractures and vugs. This study provides a methodological framework for improving the reliability and accuracy of imaging logging in evaluating fractured-vuggy reservoirs, and offers technical support for the evaluation and development of carbonate reservoirs. Table and Figures | Reference | Related Articles | Metrics