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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 （544）   HTML （18）    PDF（pc） （6207KB）（239）       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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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 （462）   HTML （36）    PDF（pc） （1595KB）（462）       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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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 （397）   HTML （14）    PDF（pc） （3481KB）（138）       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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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 （389）   HTML （7）    PDF（pc） （2297KB）（216）       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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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 （369）   HTML （15）    PDF（pc） （10863KB）（126）       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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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 （359）   HTML （9）    PDF（pc） （691KB）（195）       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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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 （358）   HTML （10）    PDF（pc） （936KB）（349）       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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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 （356）   HTML （25）    PDF（pc） （4043KB）（163）       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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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 （346）   HTML （9）    PDF（pc） （8075KB）（117）       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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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 （344）   HTML （5）    PDF（pc） （4771KB）（111）       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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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 （340）   HTML （9）    PDF（pc） （9852KB）（130）       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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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 （339）   HTML （12）    PDF（pc） （8122KB）（97）       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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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 （329）   HTML （12）    PDF（pc） （8021KB）（126）       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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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 （321）   HTML （5）    PDF（pc） （2707KB）（128）       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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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 （313）   HTML （14）    PDF（pc） （3008KB）（169）       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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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 （310）   HTML （11）    PDF（pc） （3445KB）（95）       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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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 （308）   HTML （8）    PDF（pc） （1240KB）（122）       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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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 （305）   HTML （8）    PDF（pc） （1682KB）（132）       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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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 （296）   HTML （9）    PDF（pc） （1365KB）（80）       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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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 （292）   HTML （11）    PDF（pc） （2606KB）（216）       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