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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 （1289）   HTML （5）    PDF（pc） （655KB）（152）       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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Research Progress and Trend of Ultra-Deep Strike-Slip Fault-Controlled Hydrocarbon Reservoirs in Tarim Basin WANG Qinghua, CAI Zhenzhong, ZHANG Yintao, WU Guanghui, XIE Zhou, WAN Xiaoguo, TANG Hao Xinjiang Petroleum Geology    2024, 45 (4): 379-386.   DOI: 10.7657/XJPG20240401 Abstract （1229）   HTML （38）    PDF（pc） （4805KB）（798）       Knowledge map    Save Ultra-deep strike-slip fault-controlled hydrocarbon reservoirs have been discovered as a new frontier for exploration and development in the Tarim basin. However, the complexity of these reservoirs poses a significant challenge for profitable development, necessitating enhanced foundational geological research. The strike-slip fault-controlled hydrocarbon reservoirs are commonly characterized by strong heterogeneity, intricate reservoir and fluid distribution, significant variations in hydrocarbon production, and low recovery. The great differences in faulting, reservoir characteristics, hydrocarbon accumulation, and fluid dynamics of these reservoirs between different areas present a series of exploration and development challenges. A series of models for strike-slip fault zones of different genesis and their controls on reservoirs have been established, and the mechanisms of reservoir formation along strike-slip fault zones including combined reservoir control by microfacies, strike-slip fault and dissolution, and contiguous, differential and extensive development have been revealed. Furthermore, the strike-slip fault-controlled reservoir models with “source-fault-reservoir-caprock coupling” and “small reservoir but large field” are constructed, unveiling the mechanisms of the hydrocarbon accumulation and preservation of ultra-deep strike-slip fault-controlled reservoirs. This research breaks through the limitations in theory that weak strike-slip faults in cratonic basins are difficult to form large-scale strike-slip fault-controlled reservoirs and large oil/gas fields. Finally, the genesis of large-scale strike-slip fault systems, the differential reservoir formation mechanisms within strike-slip fault zones, and the hydrocarbon enrichment patterns in cratonic basins have been clarified. Table and Figures | Reference | Related Articles | Metrics

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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 （857）   HTML （17）    PDF（pc） （19298KB）（144）       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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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 （830）   HTML （12）    PDF（pc） （1795KB）（207）       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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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 （814）   HTML （14）    PDF（pc） （766KB）（623）       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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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 （753）   HTML （14）    PDF（pc） （794KB）（225）       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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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 （734）   HTML （10）    PDF（pc） （1009KB）（651）       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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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 （725）   HTML （34）    PDF（pc） （3916KB）（352）       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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NMR Logging-Based Productivity Analysis and Sweet Spot Evaluation for Shale Oil QIN Jianhua, LI Yingyan, DU Gefeng, ZHOU Yang, DENG Yuan, PENG Shouchang, XIAO Dianshi Xinjiang Petroleum Geology    2024, 45 (3): 317-326.   DOI: 10.7657/XJPG20240308 Abstract （724）   HTML （14）    PDF（pc） （1650KB）（443）       Knowledge map    Save Shale oil horizontal wells in the Lucaogou formation within the Jimsar sag vary greatly in productivity, with notable differences in water production rate. Main factors controlling this phenomenon remain unclear. Moreover, the existing sweet spot classification criteria fail to meet the requirements for fine development of shale oil in this area, and the interpretation of oil saturation and mobility based on the cutoff values from nuclear magnetic resonance (NMR) logging cannot realize precise identification of shale oil sweet spots. In this paper, based on the results of NMR logging and laboratory NMR testing, and through frequency division processing, NMR logging-based pore structure characterization by fluids, and elastic oil displacement simulation, the distribution of different types of fluids in shale oil reservoirs was characterized detailedly. The pore sizes for oil/water occurrence were delineated, and a model for evaluating movable oil amount was established to quantitatively characterize the fluid occurrence, pore size distribution, movable oil quantity, and other parameters. By integrating single-well testing and production data, the factors controlling horizontal well productivity were elucidated. The results show that horizontal well productivity is much more correlated to the large-pore light oil proportion (LOP) and movable oil porosity (MOP) than to porosity, oil saturation, NMR MOP and other parameters. The water influence index reflects the extent of formation water’s impact on shale oil flow, and given the same MOP, a smaller water influence index corresponds to a higher productivity and a lower water cut of a horizontal well. Based on large-pore LOP, water influence index and MOP, the shale oil sweet spots are classified into Class Ⅰ, Class Ⅱ and Class Ⅲ, with rapid decline in daily oil production and significant rise in water cut, which can serve as the basis for finely evaluating shale oil sweet spots in the Lucaogou formation. Table and Figures | Reference | Related Articles | Metrics

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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 （692）   HTML （3）    PDF（pc） （3888KB）（235）       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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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 （687）   HTML （4）    PDF（pc） （1046KB）（227）       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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Dynamic Reserves Calculation Method for Fault-Controlled Carbonate Reservoirs GENG Jie, YUE Ping, YANG Wenming, YANG Bo, ZHAO Bin, ZHANG Rujie Xinjiang Petroleum Geology    2024, 45 (4): 499-504.   DOI: 10.7657/XJPG20240415 Abstract （686）   HTML （14）    PDF（pc） （960KB）（380）       Knowledge map    Save Fault-controlled carbonate reservoirs are highly heterogeneous, with interweaving development of pores, fractures, and vugs of various sizes. For this kind of reservoirs, the dynamic reserves calculated using conventional material balance methods may be larger than the static reserves. By incorporating water-oil ratio and considering rock compressibility coefficients for different pore-fracture-vug media, a comprehensive compressibility coefficient suitable for the fault-controlled reservoirs was derived. On this basis, a new flow material balance equation was established for the fault-karst reservoir, and its accuracy and applicability were verified using numerical simulation. The research results show that the dynamic reserves calculated by the new equation have an error of only 0.1099% with the static reserves obtained from numerical simulation, confirming the new equation’s reliability and accuracy. In the Halahatang area, the relative error between the dynamic reserves calculated using the new equation and the static reserves derived from geological modeling for multiple wells ranged from -4.82% to -0.15%, which is significantly lower than that calculated using the conventional material balance equation. The results obtained from the new equation are closer to actual conditions, making it more suitable for calculating the reserves of the fault-controlled carbonate reservoirs in the Halahatang area. Table and Figures | Reference | Related Articles | Metrics

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Thermal Evolution History of Shale in Da’anzhai Member and Its Petroleum Geological Significance in Central Sichuan Basin JIANG Qijun, LI Yong, XIAO Zhenglu, LU Jungang, QIN Chunyu, ZHANG Shaomin Xinjiang Petroleum Geology    2024, 45 (3): 262-270.   DOI: 10.7657/XJPG20240302 Abstract （681）   HTML （323）    PDF（pc） （821KB）（525）       Knowledge map    Save The Da’anzhai member of the Lower Jurassic Ziliujing formation is the most favorable layer for the development of continental shale oil in the Sichuan basin, and has huge potential in shale oil exploration. However, there is a lack of systematic research on the thermal evolution history of this formation. Using the simulation system for petroliferous basins, the differences in the thermal evolution and hydrocarbon generation of the shales in Da’anzhai member between the northern part and the central part of the central Sichuan basin were comparatively analyzed, and their impacts on shale oil enrichment were discussed. The thermal evolution degree of the shale of Da’anzhai member in the study area gradually increases from southwest to northeast, and the shale can be divided into a highly matured zone and a matured zone on the plane. The highly matured zone is located in the northern part of the study area, with vitrinite reflectance ranging from 1.3% to 1.7%, mainly developing Type Ⅲ organic matter. The early oil generation occured in the early Late Jurassic, and the oil generation peaked at the end of Late Jurassic, experiencing two phases of hydrocarbon generation. The matured zone is located in the central to southern parts of the study area, with vitrinite reflectance ranging from 0.9% to 1.3%, mainly developing Type Ⅱ1-Ⅱ2 organic matter. The sedimentary thickness of the Jurassic is relatively small, the early oil generation occured at the end of the Late Jurassic and reached the peak in the Early Cretaceous, with only one period of hydrocarbon generation. Compared with the northern area, a large set of organic-rich shales deposited in the central area, which provieded a solid material basis for shale oil in the Da’anzhai member. However, the tectonic uplift and stratum erosion since the Paleogene posed a certain destructive effect on the preservation of oil and gas in this area. Table and Figures | Reference | Related Articles | Metrics

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Precursor and Mechanism of Hydrocarbon Generation for Shale Oil in Lucaogou Formation, Jimsar Sag WANG Jian, LIU Jin, PAN Xiaohui, ZHANG Baozhen, LI Erting, ZHOU Xinyan Xinjiang Petroleum Geology    2024, 45 (3): 253-261.   DOI: 10.7657/XJPG20240301 Abstract （664）   HTML （43）    PDF（pc） （6824KB）（756）       Knowledge map    Save In order to clarify the differences in hydrocarbon-generating precursor and mechanism of the shale oil between the upper and lower sweet spots of the Lucaogou formation, the source rocks of the Lucaogou formation in the Jimsar sag were characterized ultra-microbiologically using field emission scanning electron microscopy, electron probe, and Fourier transform infrared spectroscopy experiments. The results show that the main hydrocarbon-generating precursor of the shale oil in the upper sweet spot is lamalginite (Microcystis), with straight-chain aliphatic series in dominance, and the main hydrocarbon-generating precursor in the lower sweet spot is telalginite (Tasmanian algae), which is rich in branched-chain aliphatic, aromatic, and sulfoxide functional groups. Due to the significantly higher activation energy required for the cleavage of long straight-chain saturated hydrocarbons than that for branched-chain hydrocarbons, as well as the lower bond energies of carbon-sulfur and carbon-nitrogen bonds, the activation energy of the precursor of the shale oil in the lower sweet spot is lower than that in the upper sweet spot. Consequently, early-stage hydrocarbon generation occurs, leading to the formation of high-density crude oil rich in non-hydrocarbon bitumen at low maturity, which is the primary reason for the relatively heavy and viscous nature of the crude oil in the lower sweet spot. Table and Figures | Reference | Related Articles | Metrics

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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 （647）   HTML （10）    PDF（pc） （5722KB）（258）       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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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 （625）   HTML （22）    PDF（pc） （20255KB）（135）       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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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 （621）   HTML （10）    PDF（pc） （3488KB）（279）       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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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 （618）   HTML （6）    PDF（pc） （1786KB）（244）       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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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 （611）   HTML （10）    PDF（pc） （597KB）（346）       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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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 （611）   HTML （10）    PDF（pc） （3783KB）（574）       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