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Architecture of Shallow-Water Delta Reservoir of Huagang Formation in C Oilfield，Xihu Sag HE Xianke, LOU Min, CAI Hua, LI Bingying, LIU Yinghui, HUANG Xin Xinjiang Petroleum Geology    2023, 44 (5): 517-527.   DOI: 10.7657/XJPG20230502 Abstract （619）   HTML （16）    PDF（pc） （7528KB）（2774）       Knowledge map    Save In order to improve the accuracy of reservoir characterization for purpose of tapping the potential of remaining oil in the middle to late oil and gas field development stage, taking the shallow-water delta reservoir of the Huagang formation in C oilfield, Xihu sag, as an example, the reservoir architecture was investigated by using core, grain size, logging, and seismic data. The architecture patterns of composite channel sandbodies of shallow-water delta facies were established, and their spatial evolution was clarified. The results show that the H3c layer represents the upper plain-channel deposit of shallow-water-delta facies, which is dominated by vertically stacked thick sandbodies; the H3b layer represents the lower plain-channel deposit of shallow-water delta facies, in which laterally-migrated medium-thick sandbodies are developed; and the H3a layer represents the shallow-water delta-front deposit, which is featured with isolated thin sandbody. The development of vertical sandbodies was controlled by middle-term base-level cycle. As the lake level rose, the shallow-water delta in the study area formed a retrogradational sequence, and sandbodies evolved from sheet-like to isolated belt-like, resulting in deteriorating reservoir connectivity. Table and Figures | Reference | Related Articles | Metrics

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Secondary Development of Mature Oilfields in China: Current Status and Prospects FU Yarong, DOU Qinguang, LIU Ze, JIAO Lifang, JI Yuxi, YANG Yajuan, YIN Houfeng Xinjiang Petroleum Geology    2023, 44 (6): 739-750.   DOI: 10.7657/XJPG20230613 Abstract （877）   HTML （9）    PDF（pc） （792KB）（1265）       Knowledge map    Save The secondary development of mature oilfields with high water cut is a revolution in the history of oilfield development and also a strategic systematic project. It plays an irreplaceable role in maintaining long-term stable oil production. From the aspects of intelligent decision-making, intelligent planning, intelligent operation, intelligent monitoring, and intelligent evaluation, and within the framework of the policies for carbon peaking and carbon neutrality, the prospects for the secondary development of mature oilfields in China were discussed. It is indicated that the secondary development of mature fields should be implemented by reconstructing underground understanding system, well pattern, and surface process, and technically by way of overall control, stratigraphic subdivision, plane reorganization, three-dimensional optimization, and deep profile control, ensuring the smooth integration of secondary development and tertiary development. Reference | Related Articles | Metrics

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3D Geological Simulation of Hydraulic Fracture Propagation and Frac-Hit Prevention in Horizontal Shale Gas Wells WANG Ting, WANG Jie, JIANG Houshun, XU Hualei, YAO Ziyi, NAN Chong Xinjiang Petroleum Geology    2023, 44 (6): 720-728.   DOI: 10.7657/XJPG20230611 Abstract （906）   HTML （21）    PDF（pc） （4736KB）（933）       Knowledge map    Save In the Sichuan basin, most of horizontal shale gas wells are stimulated by subdivided fracturing with large-stage and multi-cluster. Large-scale operations at high displacement and well infilling are often associated with severe inter-well interferences, leading to a decrease in well productivity. Optimizing stimulation treatments and well completion strategies and understanding the hydraulic fracture propagation rules are crucial to reducing the risk of inter-well frac-hit. Based on a 3D geomechanical model and with consideration to reservoir heterogeneity, in-situ stress anisotropy, interaction between fractures, and fracture network distribution, hydraulic fracture propagation and frac-hit prevention were simulated for two adjacent horizontal wells. The results show that large horizontal stress difference, natural fracture density and fluid intensity, or small approach angle and cluster spacing, may induce a high risk of frac-hit. Table and Figures | Reference | Related Articles | Metrics

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Exploration Practice and Total Petroleum System in Residual Marine Sag，Eastern Junggar Basin ZHI Dongming, CHEN Xuan, YANG Runze, LIU Juntian, YU Haiyue, MA Qiang Xinjiang Petroleum Geology    2024, 45 (2): 127-138.   DOI: 10.7657/XJPG20240201 Abstract （714）   HTML （43）    PDF（pc） （6277KB）（877）       Knowledge map    Save The Shiqiantan sag in the eastern Junggar basin is a residual marine sag. In recent years, high-yield natural gas have been obtained from many wells in the Shiqiantan formation, and oil and gas shows have been observed in different strata across the sag, indicating its excellent exploration potential and characteristics as a total petroleum system. Based on seismic, drilling, logging, and organic geochemical data, the formation and evolution of the Shiqiantan sag, the conditions for the formation of the total petroleum system, and the models of hydrocarbon accumulation are studied. The results show that during the Late Carboniferous the north Tianshan oceanic crust subduction and seawater intrusion in the region led to the development of terrigenous, marine, medium- to high-quality source rocks which are now in the mature- to high-mature stage. The reservoir contains volcanic rocks in the Carboniferous strata, marine clastic rocks in the Shiqiantan formation, and continental clastic rocks in the Permian Jingou formation, in all of which hydrocarbons were accumulated. Controlled by the hydrocarbon generation and evolution in the source rocks of the Shiqiantan formation and the characteristics of multiple types of reservoirs, a distribution pattern of shale gas reservoir in the sag-tight oil and gas reservoir in the slope-conventional oil and gas reservoir in the high position is formed, showing a total petroleum system featured with orderly symbiosis of unconventional and conventional oil and gas reservoirs. According to the theory of total petroleum system, the exploration in the Shiqiantan sag should focus on tight oil and gas reservoirs in the near-source slope area, structural-lithological oil and gas reservoirs and volcanic weathering-crust oil and gas reservoirs in the above-source fault-terrace area and structural high, and marine shale gas reservoirs within the source. The Carboniferous near-source favorable lithofacies belts, piedmont thrust fault-concealed structures, intra-basin palaeouplifts, and slope areas are favorable exploration zones in northern Xinjiang. Specifically, exploration efforts should be made towards shale oil and gas reservoirs within the sag, tight sandstone oil and gas reservoirs around the sag, conventional oil and gas reservoirs in the structural highs, and volcanic weathering-crust oil and gas reservoirs in uplifted areas. Table and Figures | Reference | Related Articles | Metrics

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Controlling Factors and Models of Hydrocarbon Accumulation in Tight Oil Reservoirs of Yao 1 Member in Gulong Sag LIU Ping Xinjiang Petroleum Geology    2023, 44 (6): 635-645.   DOI: 10.7657/XJPG20230601 Abstract （542）   HTML （28）    PDF（pc） （1024KB）（855）       Knowledge map    Save Based on the seismic, geological, geochemical, and production testing data, the types and distribution patterns of the tight oil reservoirs in the first member of Yaojia formation (Yao 1 member) in the Gulong sag were analyzed, and then the controlling factors and models of hydrocarbon accumulation in these reservoirs were clarified. The results show that five types of tight oil reservoirs are developed in the Yao 1 member such as lenticular sandstone reservoir in the Gulong syncline, updipping pinch-out lithologic reservoir, fault-lithologic reservoir, fault-block reservoir, and fault-anticline reservoir at the top of the nose-like bulge. The formation of tight oil reservoirs is jointly controlled by source rock and overpressure distribution, traps, oil-source faults, and high-quality reservoir beds. The lacustrine mudstones in the first member of Qingshankou formation (Qing 1 member) serve as the material basis for tight oil reservoirs and also create abnormally-high pressure that drove oil charging into the Gulong syncline. Before extensive hydrocarbon accumulation, various traps had been formed, including structural traps and structural-lithological traps at high positions on both sides, which act as the tight oil migration destinations and favorable accumulation sites. The reversal-stage faults that opened during the main oil accumulation phase serve as the primary pathways for vertical oil migration, and high-quality distributary-channel reservoir beds are favorable for tight oil accumulation. The structural units are different in controlling factors and models of hydrocarbon accumulation. In the Gulong syncline, the hydrocarbon accumulation model is “driven by overpressure, vertical migration along faults, and enrichment in local sweet spots”. In the Xinzhan nose-like bulge, the hydrocarbon accumulation model is “first driven by overpressure then by buoyancy, vertical migration along faults, and accumulation in favorable traps”. In the Xinzhao slope, the hydrocarbon accumulation model is “driven by overpressure + buoyancy, fault-sandbody relay-migration, and accumulation in favorable reservoir beds”. Table and Figures | Reference | Related Articles | Metrics

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Maturity Evaluation of Niutitang Formation Source Rocks in Tongren Area，Northeast Guizhou LIU Kuiyong, WU Tao, LU Shufan, PAN Yingjuan, AN Yayun Xinjiang Petroleum Geology    2023, 44 (5): 528-534.   DOI: 10.7657/XJPG20230503 Abstract （543）   HTML （16）    PDF（pc） （590KB）（828）       Knowledge map    Save To determine the exploration potential of the shale gas in the Cambrian Niutitang formation in the Tongren area, northeast Guizhou, on the basis of X-ray diffraction experiments, the maturity of the shale of Niutitang formation-Bianmachong formation from Well QTD-1 was tested by using methods of bitumen reflectance, illite crystallinity and laser Raman spectroscopy. The results show that the shale of Niutitang formation-Bianmachong formation lacks vitrinite, making its maturity difficult to be evaluated using conventional vitrinite reflectance. The shale is not evaluated satisfactorily by using the reflectance of bitumen, due to its complex genesis and the impact of bitumen heterogeneity. The illite crystallinity method can only provide a rough range of maturity, with relatively large error due to the presence of clay minerals. In contrast, the laser Raman spectroscopy method is less affected by heterogeneity and has advantages such as simple sample preparation and non-destructive testing, which proves to be a more ideal testing approach. The equivalent vitrinite reflectance of the black shale of Niutitang formation in the study area ranges from 3.41% to 3.50%, indicating a late overmature stage. 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 （1301）   HTML （38）    PDF（pc） （4805KB）（802）       Knowledge map    Save Ultra-deep strike-slip fault-controlled hydrocarbon reservoirs have been discovered as a new frontier for exploration and development in the Tarim basin. However, the complexity of these reservoirs poses a significant challenge for profitable development, necessitating enhanced foundational geological research. The strike-slip fault-controlled hydrocarbon reservoirs are commonly characterized by strong heterogeneity, intricate reservoir and fluid distribution, significant variations in hydrocarbon production, and low recovery. The great differences in faulting, reservoir characteristics, hydrocarbon accumulation, and fluid dynamics of these reservoirs between different areas present a series of exploration and development challenges. A series of models for strike-slip fault zones of different genesis and their controls on reservoirs have been established, and the mechanisms of reservoir formation along strike-slip fault zones including combined reservoir control by microfacies, strike-slip fault and dissolution, and contiguous, differential and extensive development have been revealed. Furthermore, the strike-slip fault-controlled reservoir models with “source-fault-reservoir-caprock coupling” and “small reservoir but large field” are constructed, unveiling the mechanisms of the hydrocarbon accumulation and preservation of ultra-deep strike-slip fault-controlled reservoirs. This research breaks through the limitations in theory that weak strike-slip faults in cratonic basins are difficult to form large-scale strike-slip fault-controlled reservoirs and large oil/gas fields. Finally, the genesis of large-scale strike-slip fault systems, the differential reservoir formation mechanisms within strike-slip fault zones, and the hydrocarbon enrichment patterns in cratonic basins have been clarified. Table and Figures | Reference | Related Articles | Metrics

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Precursor and Mechanism of Hydrocarbon Generation for Shale Oil in Lucaogou Formation, Jimsar Sag WANG Jian, LIU Jin, PAN Xiaohui, ZHANG Baozhen, LI Erting, ZHOU Xinyan Xinjiang Petroleum Geology    2024, 45 (3): 253-261.   DOI: 10.7657/XJPG20240301 Abstract （730）   HTML （43）    PDF（pc） （6824KB）（763）       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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Sensitivity Analysis of Injection-Production Parameters for CO2 Huff-n-Puff Flooding and Storage in Tight Oil Reservoirs：A Case From Typical Tight Reservoirs of Chang 7 Member，Ordos Basin DING Shuaiwei, ZHANG Meng, LI Yuanduo, XU Chuan, ZHOU Yipeng, GAO Qun, YU Hongyan Xinjiang Petroleum Geology    2024, 45 (2): 181-188.   DOI: 10.7657/XJPG20240206 Abstract （877）   HTML （23）    PDF（pc） （1331KB）（729）       Knowledge map    Save CO2 huff-n-puff in tight oil reservoirs can enhance oil recovery and store CO2. The existing researches on CO2 huff-n-puff flooding and CO2 storage in tight oil reservoirs rarely take parameters related to CO2 storage capacity as evaluation indicators. Taking typical tight reservoirs in the seventh member of Yanchang formation (Chang 7 member) in the Ordos basin as an example, through numerical simulation, six injection-production parameters (huff-n-puff timing, injection rate, injection time, soaking time, production time and huff-n-puff cycle) and three evaluation indicators (oil exchange rate, CO2 retention coefficient, and flooding-storage synthesis coefficient) were selected. Using single-factor control variable method and multi-factor orthogonal experimental design, together with range analysis method, the sensitivities of the six injection-production parameters to three evaluation indicators were analyzed. The results suggest that in the CO2 flooding-dominant stage, it is recommended to set an injection time of 30-60 d, injection rate of 0.001 0-0.003 0 PV/d, and huff-n-puff timing of less than 0.5 a; in the CO2 storage-dominant stage, it is recommended to set a production time of 30-230 d, injection rate of 0.007 5-0.010 0 PV/d, and injection time of 145-180 d; and in the synergistic optimization stage of CO2 flooding and storage, it is recommended to set an injection time of 30-65 d, huff-n-puff timing of 6 months earlier, and soaking time of 10-20 d. Table and Figures | Reference | Related Articles | Metrics

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Geometry of Hydraulic Fractures in Fractured Horizontal Wells in Shale Reservoirs of Jimsar Sag，Junggar Basin FANG Zheng, CHEN Mian, WANG Su, LI Jiacheng, LYU Jiaxin, YU Yanbo, JIAO Jibo Xinjiang Petroleum Geology    2024, 45 (1): 72-80.   DOI: 10.7657/XJPG20240110 Abstract （593）   HTML （13）    PDF（pc） （4519KB）（724）       Knowledge map    Save The side-view images of microseismic monitoring in horizontal wells in the shale reservoirs in the Jimsar sag of Junggar basin and in the southern Sichuan basin exhibit a phenomenon that the density and extent of the data points parallel to bedding direction are much greater than those perpendicular to the bedding direction. This phenomenon contradicts the hydraulic fracture interpretation results from conventional processing. However，there is no clear explanation for this phenomenon in terms of 3D geometry of hydraulic fractures. A method of microseismic inversion was established，and the inversion results were reconstructed to obtain 3D geometry of the fractures induced by horizontal well hydraulic fracturing in shale reservoirs. Finally，the fracture geometry and the microseismic inversion method were verified through physical simulation experiments on fracturing under true triaxial stress. The results show that the fractures from inversion primarily exhibit a geometrical pattern of one main fracture intersecting with multiple secondary fractures in three dimensional space. Combining with the results of fracturing physical simulation experiments under true triaxial stress，it is found that the hydraulic fractures are horizontally and vertically intersected. The results of acoustic emission experiments and the fracture geometry presented after true-triaxial fracturing physical simulation of outcrop samples from the Jimsar sag validate that the microseismic inversion method is reliable and the fractures induced by horizontal well hydraulic fracturing in shale reservoirs are complex. 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 （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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Methods for Calculating Oil Column Height in Reservoirs Controlled by Deep and Large Faults WANG Rujun, WANG Peijun, NIU Ge, WANG Huailong, ZHANG Jie, LIANG Ruihan, ZHAO Xinyue Xinjiang Petroleum Geology    2023, 44 (5): 608-612.   DOI: 10.7657/XJPG20230513 Abstract （747）   HTML （9）    PDF（pc） （586KB）（665）       Knowledge map    Save The reservoirs controlled by deep and large faults are generally thick and deep. Therefore, a well cannot penetrate completely through an entire reservoir. For calculating the oil column height in fault-controlled reservoirs, a physical model of oil column height in fault-controlled reservoir was established. On this basis, the idea of the wellbore temperature profile extrapolation method was discussed, a formula for calculating oil column height with the conversion method of oil-water column pressure coefficient was derived, and the dynamic reserves inverse method considering the cuboid drainage area and the equivalent flow resistance method considering the influence of gravity were proposed. The four methods were applied to two wells drilled into a fault-controlled reservoir in Fuman oilfield of Tarim basin. The results show that the oil column heights calculated by the four methods are consistent, and the average oil column heights of the two wells are 675.39 m and 634.60 m, respectively. Table and Figures | Reference | Related Articles | Metrics

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Seismic Identification of Strike-Slip Fault Damage Zones Based on Structure Tensor Analysis: A Case Study of Ultra-Deep Carbonate Rocks in Fuman Oilfield WANG Rujun, SUN Chong, YUAN Jingyi, LIU Ruidong, WANG Xuan, MA Yinglong, WANG Xupeng Xinjiang Petroleum Geology    2024, 45 (4): 475-482.   DOI: 10.7657/XJPG20240412 Abstract （523）   HTML （16）    PDF（pc） （4592KB）（651）       Knowledge map    Save Abundant hydrocarbon resources have been discovered in the ultra-deep Ordovician carbonate strike-slip fault damage zones of the Tarim basin. However, these zones cannot be accurately characterized due to the low resolution of seismic data obtained from the ultra-deep layers, thereby restricting the efficient evaluation and target selection of the strike-slip fault-controlled hydrocarbon reservoirs. According to the seismic responses of the strike-slip fault damage zones in the Fuman oilfield, and based on the structure-oriented filtering, the eigenvalues and eigenvectors were calculated by using the structure tensor method, and the projection energy along the fault direction was enhanced by selecting appropriate time windows and stacking vertical thicknesses, which accentuates the strike-slip fault damage zones, enabling a clearer delineation of their boundaries and intensities. The results show that this method provides a clearer depiction of strike-slip fault distribution, allows for the identification of smaller-scale faults, and effectively delineates the width and intensity of ultra-deep carbonate strike-slip fault damage zones, which can be used to evaluate the development degree of the strike-slip fault damage zones. This method can be employed in trap evaluation, well placement, trajectory design, and well monitoring, which will improve drilling success rates and individual well productivity. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Alkaline Minerals and Logging Evaluation of Trona in Fengcheng Formation of Mahu Sag MAO Rui, ZHAO Lei, SHEN Ziming, LUO Xingping, CHEN Shanhe, FENG Cheng Xinjiang Petroleum Geology    2023, 44 (6): 667-673.   DOI: 10.7657/XJPG20230604 Abstract （721）   HTML （24）    PDF（pc） （1727KB）（642）       Knowledge map    Save The Fengcheng formation of the Mahu sag in the Junggar basin is primarily composed of alkaline lake sediments. A large number of alkaline minerals are developed near the center of the alkaline lake. As a major type in these alkaline minerals, trona is an important industrial resource worthy of development. Currently, the trona intervals are mainly qualitatively evaluated by using the crossplot method, and a quantitative evaluation method is required. Based on core analysis and thin-section identification on alkaline minerals, together with previous research findings, the alkaline minerals in the Fengcheng formation are classified into four categories: trona, shortite; huntite, and searlesite, and their physical properties and impacts on both reservoir properties and oil-bearing property are identified. The influence of trona content on logging responses is analyzed, and a predictive model for trona content is developed by using the deep-to-shallow resistivity ratio. Core data uninvolved in the modeling are used for verifying the predictive model. It is found that the trona content predicted by the model and the trona content measured in the sample are in good agreement, with an average relative error of 5.67%, meeting the requirements for precise mineral content calculations. Finally, based on the logging evaluation results of trona content from eleven wells, the distribution of trona in the Fengcheng formation is clarified. The research results may provide a theoretical and technical support for trona resource evaluation. 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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Water Production Mechanism in Tight Sandstone Gas Reservoirs After Fracturing in Linxing Gas Field SHI Xuefeng, YOU Lijun, GE Yan, HU Yunting, MA Litao, WANG Yijun, GUO Sasa Xinjiang Petroleum Geology    2024, 45 (1): 81-87.   DOI: 10.7657/XJPG20240111 Abstract （821）   HTML （9）    PDF（pc） （678KB）（606）       Knowledge map    Save The tight sandstone gas reservoirs in the Linxing gas field，Ordos basin，are key targets for onshore gas development. Due to the structural complexity，reservoir physical properties，and complicated gas-water relationship，most gas wells produce water continuously after fracturing，and their water production rates are very different. Understanding the reasons for irreducible water saturation variation after fracturing is of great significance for formulating effective water control and gas recovery measures to increase well productivity. In this study，representative tight sandstone samples from the Linxing gas field were tested by using the gas displacement method to clarify how reservoir properties，production pressure difference，and fracturing fluid affect irreducible water saturation. The results show that the difference in the irreducible water saturation between matrix and fractures is 13.32%~18.36% for Class Ⅰ reservoirs，28.28%~34.19% for Class Ⅱ reservoirs，and 39.10%~48.15% for Class Ⅲ reservoirs. Hydraulic fractures can significantly improve the water flow capacity of reservoirs，and provide additional water flow pathways. The increased production pressure difference，reduced flow pressure loss and weakened hydrophilic degree are the main mechanisms leading to the weakening capacity of the reservoir in bounding water and water production of gas wells after fracturing. To control water and produce gas efficiently in tight sandstone gas reservoirs with high water cut after fracturing，measures such as controlling fracturing scale，optimizing production systems，and adjusting fracturing additive amount can be implemented，which will help delay the onset of water breakthrough in gas wells and reduce the overall water production. 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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Numerical Simulation of Factors Influencing Hydraulic Fracture Propagation in Sandstone-Mudstone Interbedded Reservoirs LYU Zhao, PAN Liyan, HAO Lihua, ZOU Nana, ZOU Zhikun Xinjiang Petroleum Geology    2023, 44 (6): 729-738.   DOI: 10.7657/XJPG20230612 Abstract （691）   HTML （10）    PDF（pc） （853KB）（604）       Knowledge map    Save It is difficult to conduct hydraulic fracturing in sandstone-mudstone interbedded reservoirs. Investigating the factors influencing hydraulic fracture propagation in such reservoirs is beneficial for optimizing fracturing parameters and enhancing vertical producing degree of reservoir. The propagation of hydraulic fractures in sandstone-mudstone interbedded reservoirs is primarily influenced by rock mechanics between layers, differences in formation stress, and engineering parameters. The cohesive elements of hydraulic fracture and layer interface are embedded into ABAQUS software to analyze how the displacement and viscosity of fracturing fluid, mudstone-sandstone elastic modulus ratio, tensile strength, and formation stress difference affect vertical fracture propagation. The results show that interface fractures hinder the primary fracture propagation through beds but contribute to reducing the pressure for hydraulic fracture propagation, thereby promoting the formation of fracture network. High displacement and low viscosity of fracturing fluid can promote fracture propagation through beds and accelerate the opening of interface fractures. When the mudstone-sandstone elastic modulus ratio is less than 0.6, the mudstone barrier has a significant shielding effect, and the hydraulic fractures are primarily reverse-H-shaped and weak in prorogation through beds. When the formation stress difference is greater than the tensile strength difference between mudstone and sandstone, fractures propagate greatly in vertical direction, which can serve as a preliminary criterion for assessing the potential of hydraulic fractures to propagate through beds. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Fractures and Their Controls on Yanchang Formation Reservoir in Ordos Basin XIAO Zhenglu, LU Jungang, LI Yong, ZHANG Hai, YIN Xiangdong, ZHOU Xiang Xinjiang Petroleum Geology    2023, 44 (5): 535-542.   DOI: 10.7657/XJPG20230504 Abstract （528）   HTML （13）    PDF（pc） （1050KB）（585）       Knowledge map    Save In order to determine the temporal continuity and spatial orderliness of hydrocarbon charging and accumulation in fault areas, taking the Shangzhenzi farm-Zhuanjiao area at the southern margin of the Ordos basin as an example, the relationship between fracture formation period and reservoir distribution was analyzed, and the controls of fractures on Yanchang formation reservoir was discussed. The study shows that the fractures of three periods (Yanshanian movement episode II and III, and Himalayan movement) are developed in Yanchang formation, showing varying impacts on hydrocarbon migration and accumulation. Near-source oil reservoirs captured all the hydrocarbons generated from the source rocks in immature and mature stages, which were subsequently destroyed during the Yanshanian episode III and the Himalayan movement, leading to oil migration towards the areas far away from source rocks. In the southern part of the study area, close to the Weibei uplift, fractures are well connected longitudinally and sand bodies are well developed, allowing oil enrichment primarily in reservoirs far away from source rocks. In the northern part of the study area, oil is predominantly retained in reservoirs near source rocks. Consequently, fractures and sand bodies are connected to form a transport network that plays a role in adjusting reservoirs. By virtue of multi-stage fractures, resources in reservoirs near or far away from source rocks can be complemented and integrated. Table and Figures | Reference | Related Articles | Metrics

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Pore Throat Structures and Fluid Occurrences of Reservoirs in Fengcheng Formation, Mahu Sag ZHU Yue, WU Shunwei, DENG Yusen, LIU Lin, LEI Xianghui, NIU Youmu Xinjiang Petroleum Geology    2024, 45 (3): 286-295.   DOI: 10.7657/XJPG20240305 Abstract （677）   HTML （15）    PDF（pc） （4537KB）（579）       Knowledge map    Save In order to reveal and compare the microstructures of sandstone and shale reservoirs, and the fluid occurrences within different sizes of pores in the Fengcheng formation of the Mahu sag, the experiments including high-pressure mercury intrusion (HPMI), nuclear magnetic resonance (NMR), and large-view splicing SEM were conducted to quantitatively characterize the pore throat size and fluid occurrence characteristics of the two types of reservoirs. The NMR experimental results and the HPMI experimental results before and after extraction of the original samples and the pressurized oil-saturated sample were compared to reveal the distributions of bound and movable fluids within pores of different sizes. The results indicate that sandstone and shale do not differ significantly in the sizes of pores and throats, which are dominantly 0.01-10.00 μm in pore diameter and <10.00 nm in throat radius, respectively, indicative of mesopores and fine throats. Shale has slightly larger pore diameters but smaller throat radii than sandstone. Shale mainly develops tubular pores such as intercrystalline pores and honeycomb-like dissolution pores. Sandstone has an equal distribution of tubular and spherical pores, with the proportion of spherical pores such as intergranular pores and intergranular dissolution pores increasing as the pore size increases. Fluid occurrence and mobility are controlled by multiple factors such as mineral composition and pore size. The oil-wet properties of organic matter, dolomite and pyrite, and the strong capillary confinement of intergranular pores in clay minerals, reduce the mobility of shale oil, and the movable fluids are mainly distributed in mesopores-macropores with diameters greater than 300 nm. Combining the reservoir physical properties and movable fluid distribution, it is determined that the favorable shale oil block in the study area is the Ma 51X well block, both shale and sandstone in the well block are favorable targets for development. Table and Figures | Reference | Related Articles | Metrics

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A New Method for Characterizing Remaining Oil in High Water-Cut Reservoirs ZHAO Chenyun, DOU Songjiang, DOU Yu, LIU Chaoyang, HUANG Bo, WANG Zhenyu, LI Gang Xinjiang Petroleum Geology    2023, 44 (6): 690-695.   DOI: 10.7657/XJPG20230607 Abstract （559）   HTML （11）    PDF（pc） （1450KB）（572）       Knowledge map    Save Remaining oil aggregation is a key indicator for evaluating the recovery effect and potential of high water-cut reservoirs. In this study, the dominant reserves zones within the reservoir are determined based on remaining reserves abundance. The weights of indicators are determined with the entropy weight method by using block area, distribution density and shape index. Finally, the remaining oil aggregation is characterized. The results show that, for a reservoir under steady development, the dispersion and accumulation of remaining oil can be divided into four stages: primary dispersion, rapid separation, fluctuating accumulation and dispersion, and secondary dispersion. Utilizing these characterization indicators, an evaluation was conducted on the Nm3-4-1 layer in No.7 fault block in Block 2 of the East Dagang Development Area, Dagang oilfield. The results show that the remaining oil aggregation in Nm3-4-1 decreased steadily with the progress of development, and it starts to rise owing to injection-production structure and well pattern adjustments. Table and Figures | Reference | Related Articles | Metrics

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Genesis of Barriers/Interlayers in Braided-River Reservoirs and Its Controls on Remaining Oil Distribution：A Case of N1gⅡ3 in Liuguanzhuang Area of Dagang Oilfield LI Hang, LI Shengli, ZHOU Lianwu, MA Shuiping, HUANG Xiaodi, HAN Bo, LI Ning Xinjiang Petroleum Geology    2024, 45 (1): 94-101.   DOI: 10.7657/XJPG20240113 Abstract （756）   HTML （16）    PDF（pc） （2302KB）（568）       Knowledge map    Save In order to clarify the controls of barriers/interlayers on the distribution of remaining oil in the braided-river reservoirs，taking the sand set Ⅱ in the third member of the Guantao formation （N1gⅡ3） in the Liuguanzhuang area of Dagang oilfield as an example，and using the data of core，testing，logging，and production performance，the criteria for quantitative identification of barriers/interlayers were established for the target interval in the study area，and the hierarchy，genesis of barriers/interlayers and their controls on remaining oil distribution were determined. In the study area，the barriers/interlayers in the target interval can be divided into 3 categories such as barriers between sand sets，interlayers between sand bodies，and interlayers within a sand body，which are developed near the architecture boundaries of the 7th-，8th-，and 9th-order sand bodies，respectively. The barriers between sand sets are dominated by floodplain mudstones and silty mudstone，with the thickness ranging from tens of centimeters to several meters. They can efficiently seal oil and gas vertically and allow the edge water to advance preferentially along the formation during development，leading to severe water flooding，and thus the remaining oil is mostly distributed in the upper parts of the complex mid-channel bars and braided channels far from water injection wells. The interlayers between sand bodies are mainly composed of fine-grained sediments in abandoned channels and gullies，with the thickness typically ranging from 0 to 2 meters. They locally hinder vertical fluid migration and laterally control the distribution of remaining oil in different sand bodies，leading to two remaining oil distribution patterns：one is controlled by abandoned channel and the other by gully. The interlayers within a sand body are primarily associated with lateral accreted and interchannel mud deposits，and fall-silt seam，with the thickness reaching tens of centimeters，leading to three remaining oil distribution patterns，which are controlled by laterally-accreted mudstone，fall-silt seam，and interchannel mudstone，respectively. 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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Distribution and Potential Tapping Strategies of Remaining Gas in Tight Sandstone Gas Reservoirs SHI Yaodong, WANG Liqiong, ZANG Yicheng, ZHANG Ji, LI Peng, LI Xu Xinjiang Petroleum Geology    2023, 44 (5): 554-561.   DOI: 10.7657/XJPG20230506 Abstract （814）   HTML （21）    PDF（pc） （1855KB）（557）       Knowledge map    Save The Su 36-11 block in the central area of Sulige gas field has been developed for 17 years, with high degrees of development and reserves producing. The strong reservoir heterogeneity in this block leads to uneven producing of reserves and complex distribution of remaining gas. Distribution determination and potential tapping of the remaining gas are crucial for maintaining stable production in the gas field. By accurately characterizing the reservoir architecture, the main factors influencing remaining gas distribution were identified, the distribution patterns of different types of remaining gas were determined, and corresponding strategies for recovering the remaining gas were proposed. The research results show that the gas-bearing sand bodies in the study area are mainly distributed in the 4th-order architecture units, such as channel bar and point bar, these sand bodies are significantly affected by various levels of flow barriers, with small overall scale, poor connectivity, width of 150-500 m and length of 300-800 m. The main NE-SW sand belt in the block has been developed the most, with low formation pressure, and the remaining gas is mainly distributed in the lower He 8 member in the northwestern part of the block. Remaining gas, whose distribution is mainly influenced by reservoir heterogeneity and uneven development, can be divided into five types: gas uncontrolled by well pattern, gas in composite sand body flow barrier, gas in secondary pay zone unexploited by horizontal well, gas in unperforated gas-bearing layer in vertical well, and gas unproduced. Four potential tapping measures were proposed, including well infilling, reperforation, sidetracking and potential tapping in exsisting wells. According to the adjusted development plan, it is predicted that stable production can be maintained for 7 years with the recovery efficiency reaching 45%. 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 （725）   HTML （323）    PDF（pc） （821KB）（547）       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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Practice of Water Injection Development in Ultra-Deep Fault-Controlled Fractured-Vuggy Reservoirs in Shunbei Oilfield LI Xiaobo, WEI Xuegang, LIU Xueli, ZHANG Yixiao, LI Qing Xinjiang Petroleum Geology    2023, 44 (6): 702-710.   DOI: 10.7657/XJPG20230609 Abstract （554）   HTML （11）    PDF（pc） （1673KB）（536）       Knowledge map    Save The geological and development characteristics of ultra-deep fault-controlled fractured-vuggy reservoirs in Shunbei oilfield were comprehensively analyzed, and insufficient natural energy was determined to be the main reason for the rapid production decline and formation oil degassing in the weakly volatile oil reservoirs in the Shunbei No.1 fault zone. Through numerical simulation, it is clarified that water injection is the optimal development method currently. The research results show that gravity differentiation is the main mechanism of water injection in the ultra-deep fault-controlled fractured-vuggy reservoirs in Shunbei oilfield, and water injection can effectively restore formation energy. The waterflooding connectivity and energy balance capability in the fault zone’s pull-apart segments are much stronger than those in the compression segments. Water injection development of the ultra-deep fault-controlled fractured-vuggy reservoirs features rapid water channeling along fault zone and small swept area. Water injection enables good development effect, with the reservoir pressure restored by 14.78 MPa averagely, the annual decline rate of the block decreasing from 48.6% to 15.9%, and the staged cumulative oil production increased by 13.10×104 tons. Table and Figures | Reference | Related Articles | Metrics

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Experimental Study on CO2 Flooding and Storage in Chang 8 Ultra-Low Permeability Reservoir in District Huang 3，Jiyuan Oilfield CHEN Xiaodong, WANG Jin, SONG Peng, LIU Jian, YANG Weiguo, ZHANG Baojuan Xinjiang Petroleum Geology    2023, 44 (5): 592-597.   DOI: 10.7657/XJPG20230511 Abstract （601）   HTML （12）    PDF（pc） （630KB）（533）       Knowledge map    Save In order to determine CO2 flooding and storage mechanisms in the ultra-low permeability reservoir in Jiyuan oilfield, long core experiments were performed to understand the performance of enhanced oil recovery (EOR) and CO2 storage under different flooding techniques. The results show that the CO2-water alternating injection after water flooding yields the highest recovery factor, followed by CO2-water alternating flooding, while continuous CO2 injection exhibits the lowest recovery factor. CO2 breakthrough is a crucial factor influencing recovery factor, and alternating injection can suppress gas channeling. CO2 is dominantly stored in the large pores of the reservoir, and the CO2-water alternating flooding is more conducive to CO2 storage in the small pores than pure CO2 flooding. Continuous CO2 injection, CO2-water alternating flooding, CO2-water alternating injection after water flooding, and CO2 injection after water flooding exhibit a descending order in CO2 storage efficiency. Table and Figures | Reference | Related Articles | Metrics

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Diagenetic Evolution and Its Significance of Zeolites in Sedimentary Rocks ZUO Rusi, ZENG Xiang, CAO Zhongxiang, CAI Jingong, ZHANG Kuihua, ZHANG Guanlong Xinjiang Petroleum Geology    2023, 44 (5): 543-553.   DOI: 10.7657/XJPG20230505 Abstract （739）   HTML （21）    PDF（pc） （4982KB）（532）       Knowledge map    Save Zeolites are widely distributed in sedimentary rocks, and they are diverse in genesis and complex in evolution characteristics. Controlled by sedimentary environment and diagenetic conditions, zeolites of different genesis are formed in different diagenetic sequences, and exhibit distinct combinations, occurrences, and frameworks. Zeolites can be divided into primary zeolites, hydrothermal zeolites, volcanic-altered zeolites, and mineral-transformed zeolites. Zolite framework can be characterized by the Si/Al ratio, based on which the zeolites are categorized into high-silica and low-silica zeolites. Zeolites play a strong catalytic role in hydrocarbon generation from source rocks. High-silica zeolites have lower catalytic activity, but slower deactivation rate than low-silica zeolites, and exhibit good selectivity. Zeolite cementation and dissolution have constructive and destructive effects on reservoirs, respectively. In different diagenetic sequences, zeolites show varying impacts on reservoir properties. The transformation of clay minerals to zeolites enhances the brittleness and water sensitivity of shale. Brittleness will increase the fracability of shale reservoirs, while water sensitivity will reduce reservoir permeability. Table and Figures | Reference | Related Articles | Metrics

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Comparison of Petroleum Resources/Reserves Classification Systems ZHOU Liming, ZHANG Daoyong, JIANG Wenli, ZHANG Chen, ZHANG Chenshuo, ZHANG Haoze, ZHENG Yuanyuan Xinjiang Petroleum Geology    2023, 44 (6): 751-756.   DOI: 10.7657/XJPG20230614 Abstract （954）   HTML （14）    PDF（pc） （516KB）（532）       Knowledge map    Save To further understand the petroleum resources/reserves classification system and its development trend, China’s petroleum resources/reserves classification system is reviewed with respect to its development history and characteristics, and compared with the Petroleum Resources Management System (PRMS) and the United States Securities and Exchange Commission’s standard classification system. The research reveals that the three systems are significantly different in evaluation purpose, reserves definition, and evaluation approach. China’s classification system focuses on the discovered petroleum originally-in-place, emphasizes the total quantity of resources, and serves for the overall benefits and long-term planning of petroleum exploration and development. PRMS, a project-based classification system, facilitates international communication and cooperation, and considers the attributes of petroleum as both resource and asset. It centers on the remaining commercially recoverable reserves and emphasizes the commercial value of resources. The SEC standard classification system provides a benchmarking platform for petroleum companies, and ensures consistent disclosure of reserves information to the public. It also centers on remaining economically recoverable reserves, paying more attention to the attribute of petroleum as asset. These classification systems maintain their distinct features while borrowing from and integrating with each other. Table and Figures | Reference | Related Articles | Metrics

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Shale Gas Accumulation Characteristics of Wufeng Formation-Longmaxi Formation in Luzhou Area LIU Honglin, WANG Huaichang, LI Xiaobo Xinjiang Petroleum Geology    2024, 45 (1): 19-26.   DOI: 10.7657/XJPG20240103 Abstract （656）   HTML （16）    PDF（pc） （3755KB）（531）       Knowledge map    Save To find favorable areas for shale gas accumulation in the Wufeng formation-Longmaxi formation in the Luzhou area of the Sichuan basin，fluid inclusion detection，shale micropore observation，and gas bubble-pore evolution simulation were performed. On this basis，the tectonic burial process and the hydrocarbon generation and thermal evolution process in the Luzhou area were investigated，and the characteristics and patterns of shale gas accumulation in the Luzhou area were summarized. The results show that the Wufeng formation-Longmaxi formation in the Luzhou area has a set of thick organic-rich shales. During the Permian to Early Triassic，oil was generated from the shale which then experienced two tectonic uplift events during the Middle Triassic and the Yanshanian-Himalayan movement. The gentle uplifting of the formation in the Middle Triassic did not induce extensive hydrocarbon loss，while the uplifting during the Yanshanian-Himalayan movement was later than that of the structure in the southeastern part of Sichuan basin，with a small magnitude，which was favorable for shale gas preservation. The organic pores in the shales were developed as a result of the fact that the uplifting with short duration and low intensity in the Middle Triassic did not cause massive hydrocarbon expulsion，leaving a large quantity of liquid hydrocarbons in the reservoirs and allowing well preservation of organic pores during the Late Triassic to Middle Cretaceous，when liquid hydrocarbons were cracked to gas along with deep burial，and the strata were universally under overpressure. Although the Triassic uplifting in the Luzhou area was short-lived and of low intensity，the simulation results suggest that it led to crude oil thickening and gas pore formation，which was beneficial for shale gas accumulation. The uplifting in the Indosinian period resulted in crude oil thickening，facilitating shale gas accumulation. The late strata uplifting together with a short period of shale gas loss，developed low-angle bedding fractures，and fewer vertical fractures all contribute to the formation of overpressured shale gas accumulation zones in the Luzhou area. The proposed patterns of shale gas accumulation in the Wufeng formation-Longmaxi formation in the Luzhou area are of great reference significance in guiding oil and gas exploration for similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Regulation of CO2 on Physical Properties of Heavy Oil Reservoir and EOR of CO2-Assisted Steam Flooding WEI Hongkun, WANG Jian, XU Tianhan, LU Yuhao, ZHOU Yaqin, WANG Junheng Xinjiang Petroleum Geology    2024, 45 (2): 221-227.   DOI: 10.7657/XJPG20240211 Abstract （768）   HTML （18）    PDF（pc） （862KB）（518）       Knowledge map    Save It is necessary to improve development efficiency of heavy oil reservoirs in the late stage of steam flooding. In this paper, considering the application of the technology of carbon capture, utilization and storage, and enhanced oil recovery （CCUS-EOR）, and taking the J6 block of Karamay oilfield as an example, four components of heavy oil were analyzed before and after CO2 treatment, and the changes in saturation pressure, expansion coefficient, viscosity, and density were tested to investigate the regulation of CO2 on physical properties of heavy oil. Parallel core physical simulation experiments were performed to understand the performance of CO2-assisted steam flooding in improving oil recovery. The results show that the viscosity of heavy oil is mainly affected by the contents of resin and asphaltene. As the volume of CO2 dissolved in heavy oil increases, the saturation pressure rises from 2.08 MPa to 11.11 MPa, and the expansion coefficient shows an upward trend, with an increase of 7.6%; meanwhile, the viscosity and density of the heavy oil decrease by 30.5% and 3.5%, respectively. This indicates that CO2 can effectively improve the physical properties of heavy oil by optimizing the expansion coefficient, viscosity, and density while increasing the saturation pressure. In addition, the application of CO2-assisted steam flooding enables the recovery of heavy oil to increase from 38.55% to 46.46% under the effect of CO2 dissolution for viscosity reduction and demulsification, representing an increase of 7.91% compared to pure steam flooding. This study provides a theoretical and experimental basis for the application of CO2-assisted steam flooding in enhancing the recovery of heavy oil, offering insights for similar heavy oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Main Controlling Factors of Shale Oil and Gas Enrichment in Chang 7 Member， Southeastern Ordos Basin SONG Haiqiang, LIU Huiqing, WANG Jing, SI Shanghua, YANG Xiao Xinjiang Petroleum Geology    2024, 45 (1): 27-34.   DOI: 10.7657/XJPG20240104 Abstract （490）   HTML （8）    PDF（pc） （728KB）（507）       Knowledge map    Save In order to clarify the main controlling factors of shale oil and gas enrichment，the degree and mechanisms of shale oil and gas enrichment in the Chang 7 member in southeastern Ordos basin were analyzed using the data of drilling，logging，and core. Desorbed shale gas content is positively correlated with the total organic carbon content (TOC) of source rocks，the organic matter content controls the total content of shale oil and gas，and abundant pores are developed in organic matter，and shale oil and gas exist in both adsorbed and free states in these organic pores. The pore structure and porosity of the reservoir affect the content and occurrence state of shale oil and gas. Adsorbed oil and gas mainly exist in micropores，while free oil and gas in mesopores and macropores. The content of free gas in mesopores is higher than that in macropores，and the larger the porosity，the higher the absolute content of oil and gas in shale. The configuration between sandstone interlayers and organic-rich shale controls the enrichment positions of shale oil and gas. Based on the distribution of siltstone，fine sandstone and shale in the reservoir，the shale oil and gas in Chang 7 member can be classified into two types：near-source and in-source. The in-source shale oil and gas can be further divided into hydrocarbons from sandstone interbedded with shale，shale intercalated with sandstone，and pure shale. Sand bodies underlying the organic-rich shale and lenticular sand bodies exhibit the best potential of oil and gas，followed by sand bodies overlying the organic-rich shale or those tongue-shaped or finger-shaped ones in contact with shale. Table and Figures | Reference | Related Articles | Metrics

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Enhanced Oil Recovery by CO2 Huff-n-Puff in Tight Oil Reservoirs in Mazhong Block，Santanghu Basin LI Shirui, ZHAO Kai, XU Jiangwei, Murzhaty ASKUR, XU Jinlu, ZHANG Xing Xinjiang Petroleum Geology    2023, 44 (5): 572-576.   DOI: 10.7657/XJPG20230508 Abstract （656）   HTML （9）    PDF（pc） （596KB）（505）       Knowledge map    Save The tight oil reservoirs in the MZ block of the Santanghu basin are characterized by medium-high porosity, ultra-low permeability, and high oil saturation. In the initial development stage, high production rate was achieved by virtue of volume fracturing in horizontal wells, but declined greatly. In the late stage, the reserves were effectively produced through water huff-n-puff. After years of development, the effect of water huff-n-puff became worse. The current recovery percent of reserves is only 5.6%. For further enhancing the oil recovery, CO2 huff-n-puff experiments were conducted in five horizontal wells. The results show that CO2 plays a pivotal role in enhancing recovery in tight oil reservoirs through the mechanisms such as swelling, energy augmentation, viscosity reduction, light component extraction, and fluid mobility improvement. The impact of CO2 varies throughout the injection, soaking, and production stages, leading to alteration in crude oil properties. CO2 can enhance oil recovery and also demonstrate a high storage rate, offering both economic and social benefits. CO2 huff-n-puff is adaptable and promising for tight oil reservoir development. 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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A Data-Driven Method to Reconstruct Reservoir Flow Field FENG Gaocheng, LI Jinman, LIU Yuming, YIN Yanjun, WEI Zhiyong, ZHANG Qiang, MENG Fankun Xinjiang Petroleum Geology    2023, 44 (5): 598-607.   DOI: 10.7657/XJPG20230512 Abstract （655）   HTML （14）    PDF（pc） （4395KB）（499）       Knowledge map    Save The production stabilization and water-cut control of multilayer clastic reservoirs have always been a hot topic in oilfield development. At the medium-high water-cut development stage, oilfields usually exhibit obvious decline of production, scattered distribution of remaining oil, and prominent development conflicts between layers. For these oilfields, there is an urgent need for appropriate optimization and control methods to achieve sustained and stable production. Based on the Bayesian posterior probability method and reservoir streamline simulator, by applying a random maximum likelihood function, the history matching problem was solved and a space data set was constructed. Furthermore, by using finite-memory quasi-Newton gradient method, the data space set was inverted to predict the future. The transient flow velocity of the reservoir flow field was characterized by integrating Pollock streamline tracing method. Thus, a reservoir flow field reconstruction method based on data space inversion was proposed. This method allows real-time optimization of the reservoir injection-production parameters without the need for complex and repetitive calculations. It overcomes the limitations of traditional optimization methods in finely describing flow field evolution and fills the gap in the application of data space inversion in flow field optimization. Taking reservoir B in the Bohai oilfield as an example, the proposed method was used to reveal the mechanism of the reservoir injection-production structure optimization and intuitively demonstrate the process of reservoir flow field optimization. The field application results show that the overall water cut of the reservoir is relatively steady, the scattered remaining oil in the target flooding unit is effectively exploited, and the swept area of water flooding expands by 24.85%, indicating a remarkable flow field control effect. These digitalization efforts for reservoirs will provide valuable reference for the development and data-driven flow field control of similar medium-high water-cut oilfields. 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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Comprehensive Determination of Oil-Water Boundary in Eastern Transitional Zone of Daqing SN Oilfield LIANG Yu, YANG Huidong, FU Xiandi, CAI Dongmei, WANG Yanhui, SUN Yanmin Xinjiang Petroleum Geology    2024, 45 (2): 213-220.   DOI: 10.7657/XJPG20240210 Abstract （508）   HTML （19）    PDF（pc） （4907KB）（486）       Knowledge map    Save In order to determine the oil-water contact in the eastern transitional zone of the Daqing SN oilfield, based on the drilling, logging, and seismic data, together with the core oil occurrence analysis and the reinterpretation of oil/water layers in existing wells, a comprehensive method for determining the oil-water boundary in the extension zone of structural reservoirs was discussed by using the techniques such as hydrocarbon detection through post-stack seismic attributes based on dual-phase medium theories and fluid identification based on pre-stack seismic waveform indication inversion. The oil-water interface in the study area exhibits the following characteristics: (1) oil patch or higher level occurs in cores; (2) oil layers or oil-water layers are extrapolated on the basis of logging interpretation; (3) in post-stack attributes, the energy ratio of low frequency to high frequency is greater than 0.85; and (4) the predicted water saturation from pre-stack inversion is less than 75%. Therefore, following the principle of “depth of oil-water contact determined by well data, boundaries of oil and water distribution determined by seismic data, and validation by well performance”, and through comprehensive analysis from point to line, plane, and then space, the final position of the oil-water interface was determined. The research results effectively guide the extention deployment and evaluation in the study area, and are referential for delineating the oil-water boundaries in similar structural reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Optimization of Geological Sweet Spots for Shale Oil in Fengcheng Formation in Well Maye-1, Mahu Sag LI Na, LI Hui, LIU Hong, CHEN Fangwen, YANG Sen, ZOU Yang Xinjiang Petroleum Geology    2024, 45 (3): 271-278.   DOI: 10.7657/XJPG20240303 Abstract （653）   HTML （16）    PDF（pc） （940KB）（478）       Knowledge map    Save The Fengcheng formation in the Mahu sag is a typical alkaline lacustrine deposit characterized by mixed provenance, complex lithology, overall oil possibility, and scattered sweet spots. To efficiently explore and develop the shale oil, it is necessary to optimize geological sweet spots for the shale oil. Based on the results of high-pressure mercury injection and rock pyrolysis experiments, the reservoir and shale oil mobility of the Fengcheng formation in Well Maye-1 were evaluated, a model for optimizing geological sweet spots for the shale oil was constructed, and the vertical distribution of geological sweet spots for the shale oil was assessed. The results show that porosity, total organic carbon content, brittle mineral content, and difference between free hydrocarbon content and 100 times of total organic carbon content are parameters for respectively evaluating the reservoir performance, oil-bearing property, brittleness, and shale oil mobility of the Fengcheng formation. A model for optimizing geological sweet spots for the shale oil was constructed by using these four parameters, with sweet spot factors for Class Ⅰ, Ⅱ, and Ⅲ shale oil geological sweet spots in Well Maye-1 being greater than 0.282 3, ranging from 0.011 1 to 0.282 3, and less than 0.011 1, respectively. Class Ⅰ shale oil geological sweet spots in the Fengcheng formation in Well Maye-1 are mainly distributed in the upper part of the second member of Fengcheng formation and in the third member of Fengcheng formation, with lithology dominated by mudstone and dolomitic mudstone. Table and Figures | Reference | Related Articles | Metrics

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Water Invasion Characteristics and Residual Gas Distribution in Fractured-Porous Carbonate Reservoirs XIE Peng, CHEN Pengyu, ZHAO Hailong, Xu Jianting Xinjiang Petroleum Geology    2023, 44 (5): 583-591.   DOI: 10.7657/XJPG20230510 Abstract （583）   HTML （16）    PDF（pc） （1507KB）（476）       Knowledge map    Save Water channeling often occurs in gas wells during the production of fractured-porous carbonate gas reservoirs with edge/bottom water. A simulation experiment on water invasion mechanism was performed by using a visualized microscopic model and under the formation conditions simulated by the high-temperature high-pressure online nuclear magnetic resonance detection system, to study the distribution of residual gas. The distribution of intrusive water was characterized by the T2 spectrum obtained from pulse sequence testing. The results show that the pore-throat ratio, coordination number, and fracture width have significant impacts on water invasion and residual gas distribution. In porous reservoirs, invasion water first enters large pores and then small pores. In fractured-porous reservoirs, where the distribution of fractures has an influence on the water invasion mode, intrusive water enters the fractures and then the medium-large pores. In water-invaded porous reservoirs, 37.7% of the residual gas exists in small pores, and 62.3% in large pores. In water-invaded fractured-porous reservoirs, a little residual gas is in fractures, 4.8%-26.8% of the residual gas in small pores (where the residual gas is difficult to recover), and 94.7%-69.2% in medium-large pores. The residual gas saturation index was evaluated with the water invasion proportion in medium-large pores as an objective function, and the main controlling factors include fracture penetration degree, water volume ratio, fracture width and gas production rate. The well trajectory should be optimized in the fracture zones and kept away from the fractures that communicate with edge/bottom water. Furthermore, well production rate should be optimized to delay water breakthrough. After water breakthrough in gas wells, the gas production rate should be appropriately reduced to drive intrusive water into medium-large pores and reduce residual gas in the medium-large pores, thus enhancing the gas recovery. 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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Seismic Frequency Enhancement Processing Based on Multi-Layer Residual Network and Its Application to Identification of Thin Reservoirs ZHANG Wenqi, LI Chunlei Xinjiang Petroleum Geology    2024, 45 (1): 102-108.   DOI: 10.7657/XJPG20240114 Abstract （543）   HTML （15）    PDF（pc） （4839KB）（462）       Knowledge map    Save The seismic frequency enhancement processing method based on multi-layer residual network combines high-frequency well logging information with seismic data through an intelligent network. This method effectively improves vertical resolution while maintaining lateral continuity，facilitating the identification of thin reservoir beds. In the AMH area，the seismic data processed by conventional techniques enable only the identification of carbonates thicker than 30 m，but not of thinner beds. The seismic frequency enhancement processing method based on multi-layer residual network was proposed for application in this area. First，a training was performed using the multi-layer residual network，a deep learning network，with the near-wellbore seismic amplitudes as training data and the relative wave impedance data from well logging as training labels. Thus，a predictive model for relative wave impedance curve was obtained. By using seismic data as input，the deep network training model was solved to obtain a relative wave impedance data cube，and then a data cube of reflection coefficient corresponding to the frequency-enhanced seismic data cube was obtained. After analyzing the geological conditions of the target area，appropriate wide-frequency wavelet was extracted after calibration，and then convolved with the reflection coefficient cube，so that a frequency-enhanced seismic data cube was obtained. Reservoir inversion was performed using the frequency-enhanced seismic data cube. The inversion results are of high resolution vertically，well matching the main target beds，and can be identifiable and traceable laterally. Ultimately，the identification of thin beds in the AMH area was realized through the application of high-resolution seismic inversion results. The seismic frequency enhancement processing based on multi-layer residual network together with the corresponding high-resolution model inversion can identify beds thicker than 10 m in the AMH area. This method effectively addresses the problem of infeasible thin bed identification using low-resolution seismic data，and improves the accuracy in predicting thin beds. It is referential for identifying similar thin beds. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of Rock Mechanical Parameter Profile to Tight Reservoirs in Yongjin Oilfield GAI Shanshan, WANG Zizhen, LIU Haojie, ZHANG Wensheng, YU Wenzheng, YANG Chongxiang, WANG Yuping Xinjiang Petroleum Geology    2024, 45 (3): 362-370.   DOI: 10.7657/XJPG20240314 Abstract （586）   HTML （14）    PDF（pc） （3814KB）（459）       Knowledge map    Save In order to study the fracability evaluation method for low-permeability tight reservoirs, experiments were conducted on six core samples from Well Y301 and Well Y3 in the Yongjin oilfield, Shawan sag, Junggar basin, and the parameters such as rock mineral composition, porosity, stress-strain curves, P-wave velocity, and S-wave velocity were obtained. The experiment results agreed well with logging data, and an empirical rock mechanical model was established for the study area. Meanwhile, based on the equivalent medium model, a new model considering mineral composition and pore structure characteristics was developed for calculating rock brittleness index. Then, a method for constructing the rock mechanical parameter profile of low-permeability tight reservoirs based on logging data was established and applied in Well Y301. The application results show that the Qigu formation in Well Y301 has good fracability, which lays a foundation for the comprehensive evaluation of fracability of tight sandstone reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Distribution Patterns and Significance of Salt in Deep Cretaceous Subsalt Reservoirs in Kuqa Depression，Tarim Basin LUO Danting, LUO Jinglan, DENG Chao, NIAN Tao, HAN Jianfa, CHENG Daojie, YUAN Long Xinjiang Petroleum Geology    2024, 45 (1): 1-12.   DOI: 10.7657/XJPG20240101 Abstract （663）   HTML （21）    PDF（pc） （2908KB）（456）       Knowledge map    Save The Cretaceous Bashijiqike formation in the Kelasu structural belt in the Kuqa depression of Tarim basin hosts a number of high- and steady-yield subsalt gas reservoirs in ultra-deep，high-temperature，and overpressure environment. For these subsalt tight sandstone reservoirs，the higher the porosity，the higher the salt content and the lower the apparent resistivity. The distribution of salt in the reservoirs not only significantly affects fluid identification but also has a noticeable impact on the reservoir physical properties. The distribution of salt in the subsalt reservoirs in the Bashijiqike formation were systematically analyzed based on the data of cores，cast thin sections，scanning electron microscopy，salt content，and conventional logs. According to the differences in salt content，resistivity，and salt source，three distribution patterns of salt in subsalt reservoirs were proposed: top source，lateral source and local sealing. For the top and lateral source patterns，the reservoir resistivity is only affected by salt content. In the reservoirs with the top source pattern，the salt content shows a vertical zonality，and the reservoir resistivity increases as the salt content decreases. In the reservoirs with the lateral source pattern，the salt content shows a lateral zonation，and the reservoir resistivity shows a trend of high to low and then to high value from the edge of structural belt towards its center. In the reservoirs with the local sealing pattern，the resistivity is influenced jointly by stress and salt content，and changes greatly because the distribution of salt content is sporadic. According to well logging responses，the reservoir is divided into intervals for each pattern. In an ideal top source pattern，the reservoir comprises a salt interval，a mudstone barrier，an interval strongly affected by saturated salt，an interval strongly affected by unsaturated salt，a transition interval affected by unsaturated salt，and a salt-unaffected interval from top to bottom. In an ideal lateral source pattern，there are several intervals affected by oversaturated salt. In an ideal local sealing pattern，the reservoir includes a salt interval，a mudstone barrier，a salt-unaffected interval with strongly compressed stress，a salt-stress hybrid affected interval，and a salt-stress unaffected interval. 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 （795）   HTML （14）    PDF（pc） （1650KB）（456）       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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Establishment and Application of Generalized Characteristic Curves of Gas-Water Miscible Flooding JIA Rui, YUAN Quan, TANG Xin, LYU Qiqi, GAO Wenjun Xinjiang Petroleum Geology    2023, 44 (5): 562-571.   DOI: 10.7657/XJPG20230507 Abstract （458）   HTML （16）    PDF（pc） （769KB）（455）       Knowledge map    Save Considering the limited methods for evaluating reservoir development performance using gas-water miscible flooding characteristic curves, a concept of underground water-gas cut was introduced. By analogy with the generalized mathematical model of water cut variation in water flooding reservoirs, generalized gas-water miscible flooding characteristic curves and the corresponding generalized mathematical models of underground gas-water cut variation were established. The generalized gas-water miscible flooding characteristic curve is a Type A water-alternating-gas (WAG) injection characteristic curve when n=0 and m=0, and a Type B WAG injection characteristic curve when n=1 and m=0. By varying the values of n and m, the generalized gas-water miscible flooding characteristic curve can be transformed into S-shaped, convex, S-convex, S-concave, and concave gas-water miscible flooding characteristic curves. For purpose of field application, a general formula for the generalized gas-water miscible flooding characteristic curve and solution method for the corresponding mathematical model combining underground gas-water cut variation were provided. The application to the evaluation of the development performance of WAG injection in the reservoir of Sanjianfang formation in Pubei oilfield, and of gas cap gas + edge water displacement in S31 reservoir in Jinzhou oilfield shows a high fitting accuracy. This method can be a reference for other reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Segmented Structural Characteristics and Growth Mechanism of Transtensional Strike-Slip Fault Zone in Tazhong Uplift BAI Bingchen, WU Guanghui, MA Bingshan, ZHAO Xingxing, TANG Hao, SHEN Chunguang, WANG Xupeng Xinjiang Petroleum Geology    2024, 45 (4): 409-416.   DOI: 10.7657/XJPG20240404 Abstract （532）   HTML （12）    PDF（pc） （5426KB）（451）       Knowledge map    Save In the Tarim basin, transpressional strike-slip faults are developed under oblique compression in the Ordovician carbonate rocks, but a series of transtensional strike-slip faults have been discovered in the Tazhong uplift, significantly controlling the hydrocarbon accumulation. Using the 3D seismic data from the western Tazhong uplift, as well as the attributes such as coherence and curvature, the kinematic parameters of the strike-slip faults were statistically analyzed. Through structural analysis of the strike-slip faults, the FⅡ21 strike-slip fault zone in the Tazhong uplift was optimally selected for segmented modeling, and its growth mechanism was investigated. The results show that the FⅡ21 strike-slip fault zone is segmented horizontally and stratified vertically. Various structural forms such as linear, en echelon, horsetail, wingtip, braided, and overlapping structures are found at the top of the Ordovician carbonates. The characteristics of altitude differences of the fault zone reveal segmentation and tail-end expansion as the growth mechanisms, elucidating its role as a transform fault that regulates the reverse contraction deformation on either side of the strike-slip fault zone, and clarifying its evolution process including stages of en echelon fracturing, growth and linkage, and reactivation. 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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Oil-Water Two-Phase Flow Behaviors in Fracture-Cavity Carbonate Reservoirs With Fluid-Solid Coupling LIU Qiang, LI Jing, LI Ting, ZHENG Mingjun, XU Mengjia, WANG Xuan, WU Mingyang Xinjiang Petroleum Geology    2024, 45 (4): 451-459.   DOI: 10.7657/XJPG20240409 Abstract （542）   HTML （14）    PDF（pc） （4788KB）（430）       Knowledge map    Save To enhance the recovery of fracture-cavity carbonate reservoirs and investigate the oil-water two-phase flow behaviors under fluid-solid coupling effect, a Darcy-Stokes two-phase flow model was established based on the fluid flow patterns in different media. According to the principles of effective stress and the generalized Hooke’s law, an oil-water two-phase Darcy-Stokes coupled mathematical model suitable for fracture-cavity carbonate reservoirs was developed. Macroscopic and microscopic simulations of oil-water two-phase flows were conducted for carbonate reservoirs with and without fluid-solid coupling effect. The results show a significant difference in oil-water two-phase flow behaviors within the matrix zones of reservoirs with and without fluid-solid coupling effect, but a small difference within cavities. Water injection rate greatly influences oil-water flows in fracture-cavity carbonate reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Mechanical Mechanism of Karst Cave Collapse in Carbonate Reservoirs ZHANG Jiyue, KANG Zhihong, CHEN Huaxin, KANG Zhijiang Xinjiang Petroleum Geology    2023, 44 (5): 618-625.   DOI: 10.7657/XJPG20230515 Abstract （591）   HTML （8）    PDF（pc） （2016KB）（427）       Knowledge map    Save To determine the collapse mechanism of karst caves in carbonate reservoirs, through stress field simulation, and based on orthogonal two-dimensional sections of the karst caves, a two-dimensional mechanical model was established to simulate the stress distribution characteristics of the carbonate karst caves under negative pressure. By multiple linear regression on controlling variables, a karst cave collapse model coupling with the stress function of the critical fracture point was constructed to predict the relationships among cave collapse and stress, depth and width. It is found that the most important factors influencing cave rock burst and collapse are overlying formation pressure, reservoir compressive strength and flexural strength. For two caves superimposed vertically, when their vertical distance is less than 0.3 times the cave radius, the partition between the two caves breaks, leading to the cave connection. During the collapse and rupture, the cave height changes obviously, while the width changes slightly. Table and Figures | Reference | Related Articles | Metrics

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Productivity Evaluation of Condensate Gas Wells With Water and High Condensate Oil Content in Shunbei Oil and Gas Field LI Dongmei Xinjiang Petroleum Geology    2023, 44 (6): 696-701.   DOI: 10.7657/XJPG20230608 Abstract （532）   HTML （9）    PDF（pc） （567KB）（423）       Knowledge map    Save The wells drilled in the fault-karst condensate gas reservoirs in Shunbei oil and gas field of Tarim basin exhibits significant formation pressure fluctuations, making conventional well testing interpretation methods based on constant formation pressure inapplicable. Additionally, due to the presence of water and high contents of condensate oil in gas wells, the evaluation results of open flow rates of the wells deviate significantly. Based on systematic well testing data that are corrected with elastic productivity in the well testing stage, this paper presents a productivity evaluation method for the condensate gas wells with water and high content of condensate oil. The field application validates that this evaluation method is applicable for assessing the open flow rate of condensate gas wells in the Shunbei oil and gas field to provide a quantitative understanding on the productivity of condensate gas wells with water and high content of condensate oil in Shunbei area. Table and Figures | Reference | Related Articles | Metrics

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Horizontal Well Infilling and Water Flooding Tracking Adjustment for Production Increase in Low Permeability Reservoirs in X Oilfield ZHOU Jiamei Xinjiang Petroleum Geology    2023, 44 (5): 577-582.   DOI: 10.7657/XJPG20230509 Abstract （470）   HTML （9）    PDF（pc） （552KB）（422）       Knowledge map    Save In X oilfield, the reservoirs exhibit poor physical properties, a small number of layers vertically, and the presence of small faults in complex distribution, which lead to poor effect of vertical well development and ineffecient displacement of the existing well pattern. Based on the successful development of pre-existing horizontal wells and infilled horizontal wells in the pilot test in 2014, a study was conducted on horizontal well infilling and tracking adjustment techniques in the areas with inefficient waterflooding by vertical wells and in the unswept areas near fault zones. Through logging-seismic combination and comprehensive dynamic-static analysis, the areas with stable reservoirs, low water-out risk, and enriched remaining oil were identified for well infilling. By optimizing the orientation and horizontal section length of horizontal wells, the fracturing density and fracture length were optimized to enhance the productivity of horizontal wells. The injection-production process was optimized by implementing the waterflooding tracking adjustment strategy of early-stage intermittent water injection and weak injection via the injector in an adjacent row + strong injection via the injector in a row apart. Following these approaches, a total of 19 infilling horizontal wells were drilled in the X oilfield in 2019, achieving a sandstone-encountered rate of 83.0%. The initial daily oil production per well reached 7.4 t, with a comprehensive water cut of 28.8%. An effective displacement system was established, resulting in an increase in the oilfield’s production rate from 0.8% to 1.5%, and improving the overall development effect of X oilfield. Table and Figures | Reference | Related Articles | Metrics

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Simultaneous CO2 Huff-n-Puff Test in Highly Sensitive Reservoirs in Upper Wuerhe Formation, Mahu Sag SONG Ping, CUI Chenguang, ZHANG Jigang, LIU Kai, DENG Zhenlong, TAN Long, YU Xike Xinjiang Petroleum Geology    2024, 45 (3): 355-361.   DOI: 10.7657/XJPG20240313 Abstract （683）   HTML （7）    PDF（pc） （2185KB）（411）       Knowledge map    Save In order to explore the post-fracturing EOR technologies for efficient development of highly sensitive tight conglomerate oil reservoirs in horizontal wells in the Mahu sag, a simultaneous CO2 huff-n-puff test was carried out in the Mahu 1 well block. The results show that simultaneous CO2 huff-n-puff can enhance oil recovery of highly sensitive tight conglomerate reservoirs, and its oil displacement mechanisms mainly include extraction, miscibility, competitive adsorption, and expansive displacement. Fracture communication is the main cause of gas channeling. Through field regulation and control, synchronous soaking of well groups and gas channeling wells was achieved, ensuring the field implementation effect. Soaked by fracturing fluid, the clay minerals in the tested well group hydrate and expand, causing pore throat blockage, which affects CO2 swept range and results in a low interim oil exchange ratio. The simultaneous CO2 huff-n-puff test achieved favorable stimulation effects, with an interim oil increment of 3,983 tons and an oil exchange ratio of 0.36 in the tested well group. This test provides technical ideas and field experience for horizontal wells in enhancing oil recovery of highly sensitive tight conglomerate reservoirs after fracturing. Table and Figures | Reference | Related Articles | Metrics

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Imbibition Replacement Rules of Bedding Shale in Lucaogou Formation in Jimsar Sag，Junggar Basin TIAN Gang, ZHU Jian, PU Pingfan, XIA An, DONG Zhuo, WU Jiayi, WANG Fei Xinjiang Petroleum Geology    2024, 45 (3): 346-354.   DOI: 10.7657/XJPG20240312 Abstract （511）   HTML （14）    PDF（pc） （1041KB）（403）       Knowledge map    Save In order to investigate the production of crude oil during the imbibition period after hydraulic fracturing of the bedding shale in the Permian Lucaogou formation in the Jimsar sag, core imbibition replacement experiments and nuclear magnetic resonance (NMR) technology were combined to quantitatively describe the relative content of crude oil in different pores. Cores from the upper sweet spot in Jimsar sag were used in the experiments to identify the impacts of gravity, anisotropy, gravity differentiation, and hydraulic fracture width on imbibition replacement and quantitative characterization was conducted. The results show that during the spontaneous imbibition process of bedding shale, gravity plays a dynamic role, and the recovery of top imbibition is higher than that of horizontal imbibition. Anisotropy has a significant impact on imbibition of bedding shale, with a larger imbibition displacement of fracturing fluid into parallel bedding and a shorter period to reach imbibition equilibrium compared to vertical bedding, and imbibition recovery of parallel bedding is higher than that of vertical bedding. Gravity differentiation means that during the imbibition at the bottom of the core, the crude oil is displaced by imbibition and stays on the surface of the core to form an oil film, which prevents the fracturing fluid from further entering the matrix, deteriorating the imbibition effect. The recovery of imbibition at the bottom differs by 14.12% from the recovery of imbibition at the top. Given a simulated hydraulic fracture width of 2 mm, the volume of liquid involved in imbibition replacement is limited, causing a rapid decline of water saturation within the simulated fracture, which restricts further imbibition. Therefore, the fracture height should be oriented to pass through parallel bedding, so that the fracture width and the stimulated reservoir volume can be increased. 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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Architectures of and Remaining Oil Potential Tapping in Heavy Oil Reservoirs of Panyu Oilfield Group TU Yi, DAI Jianwen, YANG Jiao, WANG Yahui, WANG Hua, TANG Zhonghao, LI Qi Xinjiang Petroleum Geology    2024, 45 (2): 189-198.   DOI: 10.7657/XJPG20240207 Abstract （493）   HTML （44）    PDF（pc） （1918KB）（395）       Knowledge map    Save Due to the low oil recovery percent of reserves, developed barriers/interlayers, and difficult remaining oil prediction in the heavy oil reservoirs in the Panyu oilfield group, it is urgent to improve the accuracy of reservoir architecture analysis and prediction. Based on geological, seismic and logging data, together with GR return rate and big data statistical technologies, the 3rd-, 4th-, and 5th-order architecture boundaries in the reservoirs were identified, the distribution patterns of interlayers were studied, the internal structure of reservoir architecture units and the distribution of interlayers were quantitatively characterized, the main controlling factors and occurrence patterns of the remaining oil were analyzed, and the control of architecture boundary on remaining oil was clarified. The results show that the 3rd-order oblique progradational interlayers in the reservoirs can slow down vertical fluid flow, and the 4th-order superimposed horizontal interlayers can prevent vertical fluid channeling. The energy and direction of remaining oil migration are mainly constrained by the 3rd- and 4th-order interlayers and the rhythm differences. Ten ineffective and inefficient wells were sidetracked, which revealed an initial cumulative oil production of 680.00 m3/d, five times that before sidetracking. 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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A Production Formula for Fractured Vertical Wells LI Chuanliang, PANG Yanming, ZHOU Yongbing, ZHAN Jianfei, ZANG Wei, LU Huimin, ZHU Suyang Xinjiang Petroleum Geology    2023, 44 (6): 683-689.   DOI: 10.7657/XJPG20230606 Abstract （566）   HTML （13）    PDF（pc） （639KB）（393）       Knowledge map    Save Fluid flow in the reservoir is no longer merely linear or radial after fracturing, instead, the flow field becomes complex and cannot be directly solved using analytical methods. In order to derive a production formula for fractured vertical wells, the complex flow field in the reservoir was decomposed into three simple flow patterns: outer radial flow, middle linear flow, and fracture linear flow. Each of these flow patterns was separately solved, and by applying the principles of fluid-electric similarity and equivalent flow resistance method, a production formula for fractured vertical wells was analytically derived. This formula can be used to calculate and predict the production of fractured vertical wells, and also to determine the fracture length and fracturing effect. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Dominant Flowing Channels and Throat Volume of Multi-Layer Sandstone Reservoirs in Liuzan Oilfield CAO Tongfeng, GAO Donghua, LI Zhandong, WANG Tianyang, JIANG Feng Xinjiang Petroleum Geology    2024, 45 (1): 53-57.   DOI: 10.7657/XJPG20240107 Abstract （452）   HTML （6）    PDF（pc） （1018KB）（389）       Knowledge map    Save For continental reservoirs with strong heterogeneity，long-term water injection may create dominant flowing channels，which will cause rapid water breakthrough in oil wells，thereby reducing the displacement efficiency and resulting in poor development results. Taking the Paleogene Oligocene Shahejie formation of Liuzan oilfield as an example，the litho-electric logging responses，reservoir heterogeneity，injection-production performance，and reservoir pore characteristics were analyzed，the characteristics of dominant flowing channels in the multi-layer sandstone reservoirs of the oilfield were described，and the conditions for the formation of dominant flowing channels in this area were determined. A calculation method for the throat volume of dominant flowing channels was established. With this method，the amount of profile control agent used in the subsequent operations was clarified to effectively plug the channels. The research results provide a technical support for subsequent oil production stabilization and water control in oilfields. 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 （720）   HTML （14）    PDF（pc） （960KB）（387）       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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Study on Water Flooding With Self-Emulsification in Heavy Oil Reservoirs SHI Lanxiang, TANG Wenjun, ZHOU You, WANG Bojun Xinjiang Petroleum Geology    2024, 45 (2): 228-234.   DOI: 10.7657/XJPG20240212 Abstract （539）   HTML （8）    PDF（pc） （1281KB）（385）       Knowledge map    Save Influenced by crude oil properties, water flooding with self-emulsification in heavy oil reservoirs is different from conventional water flooding, and the conventional theories for light oil water flooding are not applicable to heavy oil reservoirs. Taking a heavy oil reservoir with self-emulsification water flooding and the reservoir fluid parameters in China as cases, the water flooding with heavy oil self-emulsification was studied through laboratory experiments and numerical simulations to clarify key mechanisms and main influencing factors. The new numerical simulation method reveals that the stable displacement stage of the self-emulsification water flooding is a quasi-piston oil displacement pattern. The development process can be divided into four stages, namely pure oil, transition, plateau and rapid WOR increase. Permeability ratio and crude oil viscosity are the main factors affecting the water cut in self-emulsification water flooding, followed by permeability and water injection rate. 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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Origin of Crude Oil From Coal Mine of Yan’an Formation in Huangling-Tongchuan Area，Ordos Basin KONG Lingyin, LI Jianfeng, WU Kai, MA Jun Xinjiang Petroleum Geology    2024, 45 (1): 35-46.   DOI: 10.7657/XJPG20240105 Abstract （539）   HTML （10）    PDF（pc） （1020KB）（372）       Knowledge map    Save To clarify the geochemical characteristics and origin of the crude oil from the coal mine in Yan’an formation in Huangling-Tongchuan area，southeastern Ordos basin，a comparative study was conducted on the biomarker compositions and carbon isotope distribution of n-alkane monomers in extracts from crude oil，coal，and mudstone in the study area using gas chromatography，chromatography-mass spectrometry，and isotope mass spectrometry techniques. The oil from coal mine is characterized by equilibration of pristane and phytane，high sesquiterpene content，relatively high Ts/Tm and C29Ts/C29 norhopane ratios，relatively low ratios of C30 moretane/C30 hopance，C30 norhopane/C30 hopance，and 22S/(22S+22R) for C31 homohopane and C32 homohopane，“V”-shaped distribution of ααα-20R regular sterane，and relatively light carbon isotopic values of crude oil and n-alkane monomers. The extracts from the Jurassic coal-bearing source rocks exhibit high Pr/Ph ratio，low sesquiterpene content，low Ts/Tm and C29Ts/C29 norhopane ratios，relatively high ratios of C30 moretane/C30 hopance，C30 norhopane/C30 hopance，and high 22S/(22S+22R) values for C31 homohopane and C32 homohopane，inverted “L”-shaped distribution of ααα-20R regular sterane，and relatively heavy carbon isotopic values of crude oil and n-alkane monomers. The characteristics of crude oil significantly differ from those of the potential coal-bearing source rocks，which is consistent with the deep lacustrine source rocks and the generated hydrocarbons of Chang 7 member in the basin. The coal of the Jurassic Yan’an formation is at a low maturity stage，and it is incapable of expelling liquid hydrocarbons，since the generated liquid hydrocarbons cannot even fully meet its adsorption needs. The crude oils in the Cuijiagou Coal Mine in Tongchuan and the Diantou Coal Mine in Huangling are both originated from the source rocks of the underlying Chang 7 member. Table and Figures | Reference | Related Articles | Metrics

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Numerical Simulation of Grid-Like Fragmented Structure of Fault-Karst Reservoirs in Southern Tuoputai Block ZHANG Rujie, YUE Ping, ZHANG Ying, LI Xiaobo, HUANG Nan, ZHAO Liming, FAN Qingzhen Xinjiang Petroleum Geology    2024, 45 (1): 58-64.   DOI: 10.7657/XJPG20240108 Abstract （462）   HTML （3）    PDF（pc） （3074KB）（371）       Knowledge map    Save The fault-karst reservoirs in the southern Tuoputai block of the Tahe oilfield exhibit a high initial production capacity，but a sharply declining production in the late development stage due to serious water flood and rapid water breakthrough occurred in many wells. There is no efficient simulation method for this phenomenon. Based on the karst features，seismic characteristics，actual well-reservoir configuration，and three-zone structure of fault-karst reservoirs，a grid-like fragmented structure of the fault-karst reservoirs was proposed. Accordingly，by combining the automatic fault extraction (AFE) technology with the ant body attributes，the fracture indicator was derived for characterizing the grid-like fragmented reservoir. Tensor attributes were used for characterizing the karst-vug reservoir，and a dual-porosity compositional model was established for numerical simulation. The results indicate that the grid-like fragmented structure serves as the primary flow channel in fault-karst reservoirs. The fracture indicator is better applicable to characterize the grid-like fragmented structure than AFE and maximum likelihood，and it is highly compatible with tensor attributes in water source zone but poorly compatible in other areas. Compared to single-porosity model，the dual-porosity model based on the grid-like fragmented structure can offer higher matching accuracy and better reflect the production performance of the fault-karst reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Numerical Simulation of One-Hole Multi-Target Staged Fracturing in Fractured-Vuggy Reservoirs GENG Yudi, LIU Lijun, WANG Lijing, GUO Tiankui Xinjiang Petroleum Geology    2023, 44 (6): 711-719.   DOI: 10.7657/XJPG20230610 Abstract （692）   HTML （17）    PDF（pc） （3598KB）（371）       Knowledge map    Save Based on the discrete fractured-vuggy reservoir model, an oil-water two-phase flow model and a numerical simulation method considering matrix-fracture flow and vug free flow were established to analyze the performance of one-hole multi-target staged fracturing in fractured-vuggy reservoirs, and the impacts of natural fracture development degree, bottom water, and number of fracturing clusters on the fracturing performance were identified. The results show that, in the absence of bottom water, the natural fracture development degree only affects production rate but has a minor impact on the ultimate oil recovery; and in the presence of bottom water, the bottom water rising along natural fractures displaces the crude oil in cavities, leading to an increase in oil production with the increase of natural fracture density. Vug size and hydraulic fractures significantly affect the productivity of fractured-vuggy reservoirs. When natural fractures are highly developed, the difference between the performance of fracturing by single cluster in one stage and by multiple clusters in one stage decreases significantly, indicating that a single cluster hydraulic fracture can effectively control the entire sweet spot area in the fractured-vuggy reservoir. Table and Figures | Reference | Related Articles | Metrics

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Thermally Recovered Reservoir Management and EOR for a Multi-Layered Sandstone Oilfield LYU Xiaoguang, LI Wei Xinjiang Petroleum Geology    2024, 45 (1): 65-71.   DOI: 10.7657/XJPG20240109 Abstract （504）   HTML （8）    PDF（pc） （674KB）（368）       Knowledge map    Save This paper presents the characteristics and development history of the multi-layered sandstone heavy oil reservoirs in the Kern River field，USA，and specifically discusses the practices of thermally recovered reservoir management and enhanced oil recovery (EOR). The Kern River field is a monocline reservoir of hydrodynamic trap. In the late stage of steam flooding，the practices such as C/O spectral logging，4D time-lapse dynamic surveillance during thermal recovery，injector-producer performance monitoring，isolated single-channel sandbody identification and tracking，and full-field 3D geological modeling and numerical simulation lay a basis for identifying remaining oil and enhancing oil recovery. Artificial intelligence，steam-foam flooding，and layered steam injection through dual-tubing completion are proved technologies for expanding the swept volume of steam flooding. Infill drilling，horizontal well drilling，and horizontal sidetracking in shallow oil reservoirs provide additional opportunities for significantly increasing the recoverable reserves. These technologies enable the production of horizontal well to be more than three times that of adjacent vertical wells. To exploit “cold reservoirs” near the oil-water contact in the downdip zone of the reservoir，water producers are drilled in the downdip aquifer zone to release reservoir pressure，allowing the remaining oil in this zone to be effectively swept by steam. 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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Microscopic Oil Mobility in Tight Conglomerate Reservoirs Under Different Development Modes, Mahu Sag WAN Tao, ZHANG Jing, DONG Yan Xinjiang Petroleum Geology    2024, 45 (3): 327-333.   DOI: 10.7657/XJPG20240309 Abstract （550）   HTML （10）    PDF（pc） （2794KB）（358）       Knowledge map    Save In order to evaluate the oil mobility in the tight sandy conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu sag, the distribution characteristics of movable oil in typical rock samples from Type Ⅰ and Type Ⅱ reservoirs were compared through imbibition, centrifugation, and huff-n-puff tests. For the low-permeability conglomerate reservoirs in the Mahu sag, the imbibition oil recovery is related to the pore structure of the rock. The higher the proportion of small pores, the better the imbibition effect. After 144 hours of oil displacement by imbibition, the recovery rate can reach 30.9%, but the oil displacement process is slow, with low utilization of large pores. Under reservoir pressure of 40 MPa and reservoir temperature, during three cycles of CO2 huff-n-puff process, the recovery percent of each round increase, with the highest increase observed in the first cycle, reaching an oil exchange ratio of 27%. As the huff-n-puff cycle increases, the increment in recovery percent gradually decreases, and the oil exchange ratio of N2 huff-n-puff in the first cycle is 15%. Therefore, CO2 huff-n-puff has the best development effect. Table and Figures | Reference | Related Articles | Metrics

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Layered Modeling Algorithms and Cases for Different Reservoir Development Stages ZUO Yi, SONG Jing, SHI Zhuoli, QIAO Jingxuan, ZU Xiuran, ZHENG Jie Xinjiang Petroleum Geology    2024, 45 (1): 118-125.   DOI: 10.7657/XJPG20240116 Abstract （791）   HTML （6）    PDF（pc） （1695KB）（354）       Knowledge map    Save The simulation methods and model precision adopted for layered modeling in 3D geological modeling vary with reservoir characteristics and research purposes at different development stages. From the perspective of 3D geological modeling，the reservoir development can be divided into three stages: reservoir evaluation，new block development，and existing block adjustment. The layered modeling algorithms were analyzed and selected for the 5th fault block in Gangdong district 2. It is proposed that the Kriging algorithm should be used for modeling at the reservoir evaluation stage，with a grid resolution of 100 m × 100 m × 5.0 m；the Kriging or Global B-spline algorithm should be used for modeling at the new block development stage，with a grid resolution of 50 m × 50 m × 1.5 m；and the Local B-spline or Converging average algorithm should be used for modeling at the existing block adjustment stage，with a grid resolution of 10 m × 10 m × 0.5 m. This modeling approach can provide results in more coincidence with actual geological conditions and can meet requirements for reservoir research at each stage. Table and Figures | Reference | Related Articles | Metrics

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Well Location Optimization and Potential Tapping Strategy for Reservoirs With Narrow Oil Ring and Gas Cap in JZ-X Oilfield, Bohai Bay Basin YUE Baolin, MENG Zhiqiang, FANG Na, ZHENG Yang, QU Zhaozhao, WANG Shuanglong Xinjiang Petroleum Geology    2024, 45 (1): 88-93.   DOI: 10.7657/XJPG20240112 Abstract （459）   HTML （9）    PDF（pc） （2148KB）（348）       Knowledge map    Save The development of the reservoirs with narrow oil ring, gas cap, and bottom water is often challenged by water coning, gas channeling, and complex remaining oil distribution. This paper discusses the well location optimization and potential tapping strategy for horizontal well development in the Bohai Bay basin. In the basic well pattern arrangement stage, in plane, horizontal wells are arranged perpendicular to the structural lines and penetrating multiple layers for enhancing the recovery of reserves, and the separated-layer production string with intelligent sliding sleeve is equipped to alleviate inter-layer contradiction; vertically, horizontal wells are arranged parallel to the fluid interface and at 1/3 of the oil column height from the water-oil contact for gas channeling prevention and water control. In the comprehensive adjustment stage, according to the numerical reservoir simulation, the remaining oil is enriched in inter-well retention zone in plane in the middle-late development stage, and is vertically enriched in the upper part of the reservoir due to the subsequent dominance of water drive in the late stage. Comparing the oil increment indexes under the schemes of inter-well sidetracking, gas reinjection into the gas cap, and barrier water injection, the former two schemes are preferred for tapping the potential remaining oil. Ineffective and inefficient wells are sidetracked to the zones at high positions between wells, with the expected net oil increment of 3.4×104-4.2×104 m3 per well. For gas reinjection into the gas cap, existing gas production wells are converted for gas reinjection to replenish the energy of the gas cap, so as to displace the remaining oil in the upper part of horizontal wells and enhancing the oil recovery, with the expected net oil increment of 5.2×104 m3 per well. Table and Figures | Reference | Related Articles | Metrics

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Genesis of Tilted Oil-Water Contact of Heavy Oil Reservoir in Shawan Formation, Chunfeng Oilfield, Junggar Basin ZHANG Deyao Xinjiang Petroleum Geology    2024, 45 (2): 205-212.   DOI: 10.7657/XJPG20240209 Abstract （510）   HTML （23）    PDF（pc） （3330KB）（338）       Knowledge map    Save The oil-water relationship of the heavy oil reservoir in the first member of the Neogene Shawan formation （Sha 1 member） in Chunfeng oilfield is complex and cannot be explained from the traditional viewpoint of oil-water contact （OWC）, which affects the exploration and development process of the oilfield. Taking the P601-20 block with prominent contradiction in oil-water relationship as an example, researches on seismic-geology and pool-forming dynamics were conducted, and combining with the reservoir performance during development, the oil-water relationship of the heavy oil reservoir in Sha 1 member and its genesis were analyzed. It is found that the complex oil-water relationship in this oilfield is caused by the presence of a tilted OWC in the reservoir which is a structural-lithological reservoir with bottom/edge water. In terms of reservoir physical property, fault, formation pressure, tectonic movement, etc., the presence of the tilted OWC should be attributed to the adjustment of the reservoir due to tectonic movements, and the crude oil densification and flat strata intensified the lag of OWC adjustment. This reservoir can be classified as an unsteady oil and gas reservoir. 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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Breakthrough and Implication of Oil and Gas Exploration in Permian Upper Wuerhe Formation in Fukang Sag, Junggar Basin LIU Chaowei, LI Hui, WANG Zesheng, WANG Qiuyu, XIE Zhiyi, HUANG Zhiqiang, ZHANG Rong Xinjiang Petroleum Geology    2024, 45 (2): 139-150.   DOI: 10.7657/XJPG20240202 Abstract （636）   HTML （25）    PDF（pc） （9344KB）（321）       Knowledge map    Save The confirmation of 100-million-ton reserves in the Permian upper Wuerhe formation in the Kangtan-1 well area of Fukang sag, Junggar basin, demonstrates the excellent hydrocarbon accumulation conditions and huge exploration potential of the deep layers in the sag. Summarizing the exploration experience and theoretical understanding of the upper Wuerhe formation in the Fukang sag will be significant to guide the exploration of clastic reservoirs in other hydrocarbon-rich sags. Using the data of drilling, reservoir rock thin section, porosity-permeability analysis and formation testing, a systematic analysis was conducted on the exploration breakthrough of the upper Wuerhe formation in the Fukang sag. It is indicated that the oil and gas in the uplift and slope zones around the Fukang sag are mainly products of source rocks in the early maturity stage, and the hydrocarbons generated in the high maturity stage of source rocks are mainly found in the sag area. Controlled by the paleogeomorphology during deposition, retrogradational sand bodies in lowstand systems tract （LST） were developed in the upper Wuerhe formation in the Fukang sag, forming superimposed continuous large-scale reservoirs in the paleo-trough area. Overpressure is commonly found in the sag, which is conducive to the preservation of primary pores in deeply buried sandstones and also to the formation of microfractures, enhancing the permeability of reservoirs and making the deep reservoirs more effective. The upper Wuerhe formation in the Fukang sag has large exploration potential for achieving reserves increment due to the late-stage charging of hydrocarbons generated from highly mature sources rocks in the Lucaogou formation, the large-scale retrograditional sedimentation, and the pore preservation and permeability increasement caused by overpressure. Table and Figures | Reference | Related Articles | Metrics

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A Logging-Based Method for Calculating Water Saturation in Continental Shale Reservoirs: A Case Study of Lianggaoshan Formation in Fuxing Block, Southeastern Sichuan Basin CHENG Li, YAN Wei, LI Na Xinjiang Petroleum Geology    2024, 45 (3): 371-377.   DOI: 10.7657/XJPG20240315 Abstract （502）   HTML （6）    PDF（pc） （717KB）（319）       Knowledge map    Save Continental shale reservoirs are characterized by low porosity, ultra-low permeability, high clay mineral content, rapid mineral composition variation, and strong formation heterogeneity. Therefore, the water saturation calculated with Archie formula or conventional mathematical statistical models often introduces large errors. To improve the calculation accuracy of water saturation in continental shale reservoirs, taking the shale from Lower Jurassic Lianggaoshan formation in the Fuxing block of southeastern Sichuan basin as an example, the limitations of existing methods for calculating water saturation were analyzed, and the feasibility of applying the composite wave impedance reconstructed from the combination of P wave and S wave in array acoustic logging and logging density to calculate water saturation was demonstrated. Based on this analysis, a method for calculating water saturation in continental shale reservoirs was proposed. This method considers the influence of rock minerals and effectively avoids the limitations of electrical logging and non-electrical logging, and finally improving applicability. The application of this method has yielded favorable results in multiple wells in the shale reservoirs of Lianggaoshan formation, southeastern Sichuan basin, with calculated water saturation closely matching those from core analysis, and absolute errors ranging from 1.3% to 2.2%, meeting the requirements for well logging evaluation. 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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Identification of Fluid in Highly Saline Tight Reservoirs of Fengcheng Formation in Maxi Slope Area MAO Rui, BAI Yu, WANG Pan, HUANG Zhiqiang Xinjiang Petroleum Geology    2024, 45 (3): 279-285.   DOI: 10.7657/XJPG20240304 Abstract （419）   HTML （12）    PDF（pc） （2125KB）（303）       Knowledge map    Save The Permian Fengcheng formation in the Maxi slope area of the Junggar basin is characterized by highly saline tight reservoirs deposited in alkaline lakes, and the relationship between oil and water in these reservoirs is complicated, which leads to difficulties in fluid identification. A thermal neutron macroscopic capture cross-section of the highly saline formation was constructed by using lithoscanner logging data, and an oil-sensitive factor was constructed by using the difference between the thermal neutron macroscopic capture cross-section from logging and the thermal neutron macroscopic capture cross-section of the brine-saturated formation. Furthermore, a salinity-sensitive factor was constructed by using the ratio of chlorine element relative yield to total porosity. Then, a fluid identification chart was established by intersecting the oil-sensitive factor with the salinity-sensitive factor. The actual application shows that this fluid identification chart can accurately assess reservoir fluid properties and provide a basis for selecting formation test layers. 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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Multilayer Superimposition Patterns of Strike-Slip Fault Zones and Their Petroleum Geological Significance in Platform Area, Tarim Basin YANG Haijun, NENG Yuan, SHAO Longfei, XIE Zhou, KANG Pengfei, YUAN Jingyi, FU Yonghong Xinjiang Petroleum Geology    2024, 45 (4): 387-400.   DOI: 10.7657/XJPG20240402 Abstract （582）   HTML （24）    PDF（pc） （33226KB）（289）       Knowledge map    Save In recent years, with the progress of oil and gas exploration in the Tarim basin, large-scale strike-slip fault systems have been discovered in the Paleozoic strata of the platform area in the basin and a new type of fault-karst reservoir has been identified. Due to multiple tectonic movements in the basin, these strike-slip faults exhibit multilayer structures featured with multiple phase superimposition. Based on high-quality 3D seismic data, drilling data, and petroleum geological data, the multilayer superimposition of large-scale strike-slip faults in the basin and its controls over hydrocarbon accumulation were investigated. The research results show that the strike-slip fault zones in the platform area of the Tarim basin primarily develop five structural layers in the Paleozoic: Lower Cambrian pre-salt structural layer, Middle Cambrian salt structural layer, Upper Cambrian-Middle Ordovician carbonate structural layer, Upper Ordovician-Carboniferous clastic structural layer, and Permian magmatite structural layer. Affected by multiple tectonic movements and strike-slip fault activities, these layers exhibit characteristics of banded spatial distribution, vertical superposition, and differential superimposition. The superimposition patterns can be broadly categorized into four types: connection, overlapping, inverse superimposition, and inverse reformation. These superimposition patterns have significant impacts on hydrocarbon accumulation, and three types of reservoirs such as TypeⅠ (Ordovician carbonate reservoirs), Type Ⅱ (Ordovician carbonate, Silurian clastic, and Permian magmatite reservoirs), and Type Ⅲ (Cambrian pre-salt dolomite reservoirs) are formed. Table and Figures | Reference | Related Articles | Metrics

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Optimized Laboratory Experiment on Interlayer Interference in Heterogeneous Reservoirs WANG Jie, LI Hongyu, LYU Dongliang, QIAN Chuanchuan, ZHOU Qunmao Xinjiang Petroleum Geology    2024, 45 (2): 199-204.   DOI: 10.7657/XJPG20240208 Abstract （576）   HTML （11）    PDF（pc） （869KB）（289）       Knowledge map    Save During the development of multi-layer heterogeneous reservoirs through commingled injection and production, interference between layers occurs due to various factors such as reservoir lithology, petrophysical properties, formation pressure, and fluid properties. The previous laboratory experiments on parallel displacement failed to effectively simulate fluid exchange between layers during the commingled production of multiple layers, and the physical meaning of the defined interference coefficient does not align with the flow process in water injection development. In this paper, an experimental model of series-parallel combined displacement was established to simulate the variation of lithology within the reservoir layers. The oil production, water cut, and recovery rate of cores with different permeabilities in the experiments were investigated to verify and re-understand the interference coefficient. The results show that interlayer interference is essentially a phenomenon that the variation of flow resistance of reservoir layers with time leads to alteration in flow distribution within the layers. Reservoir heterogeneity is identified as a key factor in forming dominant flow channels during commingled production. The research results provide a reference for designing interlayer interference experiments and developing heterogeneous reservoirs rationally and efficiently. 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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Dynamic Model and Sensitivity Analysis of High-Pressure Water Injection for Capacity Expansion of Fractured-Vuggy Reservoirs ZHANG Rujie, CHEN Lixin, YUE Ping, XIAO Yun, WANG Xia, LYU Yuan, YANG Wenming Xinjiang Petroleum Geology    2024, 45 (4): 460-469.   DOI: 10.7657/XJPG20240410 Abstract （483）   HTML （11）    PDF（pc） （964KB）（278）       Knowledge map    Save High-pressure water injection for capacity expansion is an effective method to enhance the recovery of fractured-vuggy reservoirs. However，the injection-production process during high-pressure water injection remains unclear. In this paper，three modes of high-pressure water injection for capacity expansion were proposed. Based on a dynamic model of high-pressure water injection for capacity expansion，the impacts of sensitivity parameters on the injection-production process during high-pressure water injection were simulated. The three modes of high-pressure water injection for capacity expansion were analyzed using actual wells drilled in the fractured-vuggy reservoirs in Halahatang oilfield. The high-pressure water injection for capacity expansion conforms to three modes：far-end low-energy，flow barrier，and near-end small reservoir. All three modes can realize effective production of far-end reservoirs to improve recovery efficiency. Flow barrier mode has the optimal EOR effect. The size of the near-end reservoir affects the time at which the water-injection indicator curve inflects，and the size of the far-end reservoir influences the difficulty degree of water injection after the water-injection indicator curve inflects. The fluid exchange index in the water injection process is greater than that in the production process，which indicates that the high-pressure water injection for capacity expansion is effective. The smaller the fracture closure pressure and stress sensitivity coefficient，the earlier the water-injection indicator curve inflects，and the higher the cumulative liquid production. Table and Figures | Reference | Related Articles | Metrics

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Enhanced Recovery in Middle and Late Stages of Depletion Development of Condensate Gas Reservoirs With Oil Ring HUANG Zhaoting, LI Chuntao, WANG Bin, QIAO Xia, FU Ying, YAN Bingxu Xinjiang Petroleum Geology    2024, 45 (4): 470-474.   DOI: 10.7657/XJPG20240411 Abstract （639）   HTML （15）    PDF（pc） （549KB）（275）       Knowledge map    Save The depletion development of Y5 condensate gas reservoir in the Tarim basin encounters the challenges such as rapid decline in both reservoir pressure and well productivity, gradual decrease in produced gas-oil ratio, increase in condensate oil density and viscosity, and fast downgrading of development performance. Combining performance analysis and reservoir fluid component evaluation, the Y5 condensate gas reservoir was redefined as a layered condensate gas reservoir with oil ring and edge water and the thickness of the oil ring was determined through numerical simulation. To improve the development performance and enhance the condensate oil/gas recovery, a systematic investigation was conducted on the mechanism of enhanced recovery in the middle and late stages of depletion development of the condensate gas reservoir with oil ring. It is found that optimizing the well pattern and implementing cyclic gas injection can significantly improve oil and gas recovery. Gravity-assisted gas drive is recommended, with CO2 being the optimal injection medium, followed by reservoir gas. Based on reservoir type and enhanced recovery mechanism, a scheme of cyclic gas injection for enhancing the recovery of Y5 condensate gas reservoir was developed, with an expected oil recovery 29.96% higher than that of depletion development alone. Under this scheme, a cumulative gas volume of 0.19×108 m3 was injected, the reservoir pressure restored by 4.31 MPa, and the well productivity increased by 3.09 times compared to that before the scheme was implemented. The research results provide valuable reference for enhancing recovery in the middle and late development stages of similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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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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Influences of Low-Temperature Oxidation on Oil Recovery During Oxygen-Reduced Air Flooding in Guo-8 Block of Yuguo Oilfield XIAO Zhipeng, ZHANG Yanbin, LI Qihang, LI Yiqiang, HAN Jifan, YAN Qian, WU Yong’en Xinjiang Petroleum Geology    2024, 45 (3): 334-339.   DOI: 10.7657/XJPG20240310 Abstract （545）   HTML （9）    PDF（pc） （964KB）（270）       Knowledge map    Save Oxygen-reduced air injection is an effective technique for developing low-permeability oil reservoirs. Under reservoir conditions, oxygen-reduced air can undergo low-temperature oxidation reaction with crude oil, thereby enhancing oil recovery. Regarding the inadequate understanding of the mechanism underlying the oxygen-reduced air flooding for enhanced oil recovery (EOR) in the Guo-8 block of the Yuguo oilfield, isothermal oxidation experiments and long-core displacement experiments were conducted to investigate the influences of oil oxidation process and generated substances on EOR. The results of the isothermal oxidation experiments indicate that sedimentary substances are generated during the low-temperature oxidation process of light oil. With the increase of temperature, the degree of oxidation significantly increases, with the sedimentation of heavy components reaching 1.25×10-3 g/g at 89°C, 3.43×10-3 g/g at 100°C, and 5.02×10-3 g/g at 120 ℃. The results of the long-core displacement experiments demonstrate that the sedimentation of heavy components at different oxidation temperatures affects EOR. With temperature increasing, the timing of gas channeling delays, the sweeping effect improves, and the final recovery increases to 52.77%, 58.89%, and 65.23% at temperatures of 89°C, 100°C, and 120°C, respectively. Table and Figures | Reference | Related Articles | Metrics

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Natural Gas Enrichment in Carbonate Gas Reservoirs of Taiyuan Formation in Yishaan Slope，Ordos Basin LI Yanrong, LI Jing, SU Wenjie, SHI Lei, SUN Rui, ZHU Yushuang Xinjiang Petroleum Geology    2023, 44 (5): 509-516.   DOI: 10.7657/XJPG20230501 Abstract （671）   HTML （28）    PDF（pc） （18631KB）（270）       Knowledge map    Save To determine the distribution of the carbonate gas reservoirs in Permian Taiyuan formation in Yishaan slope of the Ordos basin, based on the data of drilling, well testing, logging, and formation testing, the carbonate gas reservoirs in Taiyuan formation were analyzed using field outcrops, core samples, thin sections, electron microscopy scanning, high-pressure mercury intrusion, and fluid inclusion temperature measurements, and then sedimentary microfacies, petrographic characteristics, physical properties, pore structures, and fracture distribution were studied of the reservoir. The results indicate that the carbonate gas reservoirs in Taiyuan formation are low-porosity and low-permeability lithological gas reservoirs. Favorable plays control the reservoir distribution and gas enrichment. The gas reservoirs `are mainly distributed in the bioherm and bioclastic shoal microfacies zones. Bioherms are found in the eastern part of the study area, including Jiaxian, Zizhou, and Qingjian, while bioclastic shoals are developed in the western part of the study area, including Hengshan, Jingbian, and Pingqiao, exhibiting an obvious zoning of facies from west to east. The carbonate rocks in Taiyuan formation consist of micritic bioclastic limestone and algal-bounded limestone, in which biogenic pores, intercrystalline pores, dissolution pores, and microcracks serve as accommondation. Fractures play a crucial role in migration of oil and gas, and their development contributes significantly to the natural gas enrichment in the reservoirs. 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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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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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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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