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Laboratory Experiments and Field Tests of CO2 Near-Miscible Flooding for Medium-Viscosity Oil in NJH Block, Santanghu Oilfield ZHANG Qi, ZHU Yongxian, HAN Tianhui Xinjiang Petroleum Geology    2025, 46 (1): 114-120.   DOI: 10.7657/XJPG20250114 Abstract （1289）   HTML （5）    PDF（pc） （655KB）（152）       Knowledge map    Save The NJH block of the Santanghu oilfield features sandstone reservoirs containing medium-viscosity oil, with crude oil viscosity of 20.8 mPa·s. The reservoir is at medium water cut stage, with a predicted waterflood recovery factor of 22.70%, leaving a limited potential for further enhanced oil recovery. To figure out an applicable enhanced oil recovery (EOR) technique, laboratory experiments and field test were conducted on CO2 near-miscible flooding for medium-viscosity oil to understand the mass transfer patterns and EOR mechanisms of this technique, thereby determining its feasibility. The research results show that the front of the CO2 flooding mainly plays a swelling effect, and the rear exerts a stronger extraction effect than the front. Reducing the viscosity and improving the remaining oil displacement efficiency are the main stimulation mechanisms. The viscosity of surface crude oil reduced by 55%, the content of C2-C15 components increased by 18.3%, and the displacement efficiency improved by 4.6 times. Permeability ratio is found to be the primary factor influencing swept volume, with a permeability ratio of 6, leading to a recovery factor of only 13.84% in low-permeability layers. During the field test, the cumulative injected gas volume is 2.66×104 t, cumulative oil production is 0.78×104 t, and oil exchange ratio is 0.29, confirming a promising application of CO2 near-miscible flooding for medium-viscosity oil. Table and Figures | Reference | Related Articles | Metrics

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

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Exploration Progress and Potential Evaluation of Deep Oil and Gas in Turpan-Hami Exploration Area ZHI Dongming, LI Jianzhong, CHEN Xuan, YANG Fan, LIU Juntian, LIN Lin Xinjiang Petroleum Geology    2023, 44 (3): 253-264.   DOI: 10.7657/XJPG20230301 Abstract （884）   HTML （541）    PDF（pc） （2522KB）（1340）       Knowledge map    Save To realize the shift of oil and gas exploration from shallow-middle to deep strata, and from conventional to unconventional resources, and then to promote the exploration of deep oil and gas resources in the Turpan-Hami exploration area, the tectonic-lithofacies palaeogeographical evolution of Turpan-Hami basin, Santanghu basin, and Zhundong block of Junggar basin were analyzed, the characteristics and exploration potential of the petroleum systems in these basins were evaluated, the main exploration targets were determined, and the fields for strategic breakthrough were selected. In the Carboniferous-Permian period, the Turpan-Hami exploration area was a unified sedimentary basin with similar sedimentary environments and structures. In the Triassic-Jurassic period, the study area was separated into several independent foreland basins. With the tectonic-lithofacies palaeogeographical evolution, three sets of source rocks (marine-transitional facies of Carboniferous, lacustrine facies of Permian, and lacustrine-coal measure of Jurassic) were formed, contributing to three major petroleum systems. The change in exploration ideas has promoted significant progress in petroleum exploration in deep strata. Significant breakthroughs have been made in the exploration of Shiqiantan formation marine clastic oil and gas reservoirs, Permian shale oil reservoirs and conventional sandstone oil reservoirs in the Zhundong block, and the Middle-Lower Jurassic large-scale tight sandstone gas reservoirs in the Turpan-Hami basin, which enables the discovery of large-scale high-quality reserves and the orderly succession of strategic resources. Future exploration should be carried out at three levels: strategic preparation, strategic breakthrough, and strategic implementation, with a focus on 10 favorable directions. 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 （876）   HTML （14）    PDF（pc） （516KB）（526）       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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Facies-Controlled Geostatistical Inversion Method Based on Low-Frequency Model Optimization and Its Application SHI Nan, LIU Yuan, LENG Yue, WEN Yihua, PAN Haifeng, SUN Bo, WANG Bing Xinjiang Petroleum Geology    2023, 44 (3): 375-382.   DOI: 10.7657/XJPG20230316 Abstract （857）   HTML （28）    PDF（pc） （9433KB）（346）       Knowledge map    Save The oil and gas reservoirs in the Qiketai formation of Middle Jurassic in the Pubei area of Taibei sag, Turpan-Hami basin, are controlled by lithology. Early exploration confirmed that there are thin oil-bearing sand layers with the thickness of 6-15 m at the bottom of the Qiketai formation. It is difficult for conventional inversion methods to predict these sand layers and these methods often yield large errors due to the limitations of the frequency band of seismic data. In order to improve inversion accuracy, a facies-controlled geostatistical inversion method based on low-frequency model optimization was proposed. Combined with the characteristics of large structural relief and greatly varying sedimentary facies in the study area, the low-frequency model was established by combining the compaction trend correction method and the seismic attribute constraint method to obtain the deterministic inversion results. On this basis, a facies-controlled model was established for facies-controlled geostatistical inversion, thus enabling the identification of thin sand layers in the study area. This method effectively complements the low-frequency information missed in seismic signals, and improves the longitudinal resolution of the inversion results. By using this method, a thin sand layer with the thickness of 7 m can be identified, and the inversion result is basically consistent with the actual thickness of sand body, which confirms the effectiveness of this method in predicting thin sand layers in Pubei area. Table and Figures | Reference | Related Articles | Metrics

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Mineral Features of Chlorite and Laumontite and Their Impacts on Reservoir Physical Properties: A Case Study of Lower Wuerhe Formation in Western Luliang Uplift, Junggar Basin NIU Jun, WANG Cong, LIANG Fei Xinjiang Petroleum Geology    2025, 46 (1): 13-21.   DOI: 10.7657/XJPG20250102 Abstract （856）   HTML （17）    PDF（pc） （19298KB）（144）       Knowledge map    Save In order to enhance the understanding of mineral features of chlorite and laumontite in the lower Wuerhe formation of Permian in the western Luliang uplift, Junggar Basin, the chemical composition, occurrence states, and impacts on reservoir physical properties were studied by means of thin section, electron probe and X-ray diffraction. It is found that the chlorite has an trioctahedral crystal structure and occurs in three states: pore lining, particle coating, and pore filling. It is classified as an iron-magnesium transitional type, richer in magnesium. Fe replacing Mg mainly occurs in the octahedrons, with the Al/(Al+Mg+Fe) ratio ranging from 0.25 to 0.37. The forming of chlorite is attributed to the alteration of argillaceous rocks and the transformation of mafic rocks, with substantial material input from the hydrolytic dissolution of tuffaceous volcanic materials and the interconversion of clay minerals. Laumontite occurs in three states: crystal aggregate, filling, and replacement. The laumontite in crystal aggregate state is surrounded by numerous debris, which promotes the formation of laumontite. The laumontite in filling state coexists with chlorite, calcite and other minerals, which compete with them for material sources, partially inhibiting the formation of laumontite. The laumontite in replacement state is mainly formed by the replacement of feldspar and debris, resulting in high Si/Al ratio and good acid resistance, which allow the laumontite to be not easily dissolved. Chlorite and laumontite have dual effects on reservoir physical properties. Chlorite can significantly improve reservoir physical properties, resulting in the formation of high-quality reservoirs. In contrast, the effect of laumontite on reservoir properties is limited. With the increase of burial depth, the lower Wuerhe formation presents a variation in diagenetic environment from alkaline to weakly acidic and then to alkaline, with a relatively closed diagenetic system. Table and Figures | Reference | Related Articles | Metrics

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Sequence Division of Shiqiantan Formation in Shiqiantan Sag on Eastern Uplift of Junggar Basin KANG Jilun, FU Guobin, HAN Cheng, LIANG Hui, MA Qiang, LIANG Guibin, CHEN Gaochao Xinjiang Petroleum Geology    2023, 44 (3): 265-276.   DOI: 10.7657/XJPG20230302 Abstract （840）   HTML （510）    PDF（pc） （27313KB）（219）       Knowledge map    Save In order to establish a standard section of the Upper Carboniferous Shiqiantan formation in the Shiqiantan sag on the eastern uplift of the Junggar basin, and to provide a basis for the division and correlation of the subsurface strata and for the oil and gas exploration in the sag, field survey was carried out. By using geological coastean, and through comprehensive analysis on lithological characteristics, sedimentary formations, contact relationships, marker beds, and paleontological fossils, the sequence division, sedimentary facies restoration, and regional stratigraphic correlation were completed for the Shiqiantan formation. The Shiqiantan formation underwent the deposition of alluvial fan (fan delta), pre-fan lake and bay lagoon, forming three transgression-retrogradation sequences. The Shiqiantan formation can be divided into three members. The lower member is composed of conglomerate and sandy conglomerate intercalated with sandstone and siltstone in the lower part, medium-fine grained conglomerate, graywacke, and interbeds of mudstone and silty mudstone in the middle part, and silty mudstone and mudstone intercalated with sandstone and siltstone in the upper part. The middle member is composed of conglomerate, pebbly sandstone and sandstone intercalated with siltstone in the lower part, and calcareous silty mudstone, mudstone, siltstone and argillaceous limestone in the upper part. The upper member is composed of conglomerate, sandstone and interbeds of siltstone and silty mudstone in the lower part, purple-brown and brick-red mudstone and argillaceous siltstone intercalated with gravel-bearing gritstone and conglomerate in the middle part, and dark grey mudstone and silty mudstone intercalated with limestone in the upper part. Macroscopically, the lower member, middle member, and the upper part of the upper member are dark grey, and the lower part of the upper member is light brown to brick-red; all members are normally graded. The dark mudstones of pre-fan swamp-bay lagoon facies are favorable source rocks, while the sandstones and conglomerates of mid-fan and fan-apex facies are reservoir rocks. The good source-reservoir assemblage suggests favorable petroleum geology conditions. 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 （835）   HTML （9）    PDF（pc） （792KB）（1255）       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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Sensitivity Analysis on Injection-Production Parameters for CO2 EOR and Storage in Low-Permeability Reservoirs Considering Storage Mechanism LI Yuanduo, DING Shuaiwei, ZHANG Meng, XU Chuan, FAN Wenyu, QU Chuanchao Xinjiang Petroleum Geology    2024, 45 (6): 711-718.   DOI: 10.7657/XJPG20240610 Abstract （830）   HTML （12）    PDF（pc） （1795KB）（207）       Knowledge map    Save In low-permeability reservoirs, CO2 flooding can enhance oil recovery and achieve CO2 geological storage. Based on the CO2 storage mechanisms, by using a numerical simulation method, a CO2 EOR and storage model considering CO2 structural storage, residual storage, and dissolution storage mechanisms was established. This model was used to analyze the sensitivity of injection-production parameters (e.g. water injection period, CO2 injection rate, injection-production ratio, lower limit of bottomhole flowing pressure in production wells, upper limit of bottomhole flowing pressure in injection wells, number of cycles, and gas-to-water slug ratio) on CO2 EOR and CO2 storage efficiency in low-permeability reservoirs under continuous gas injection and water-alternating-gas (WAG) injection modes. The results demonstrate that CO2 storage mechanisms have significant impacts on both CO2 EOR and CO2 storage. Under the mode of continuous gas injection, CO2 residual storage aids CO2 EOR but has minimal effect on CO2 storage, while dissolution storage hinders CO2 EOR but benefits CO2 storage. Under the mode of WAG injection, the storage mechanisms are less favorable for CO2 EOR but promote CO2 storage. These findings reveal the influences of storage mechanisms on CO2 EOR and storage under different injection modes. Table and Figures | Reference | Related Articles | Metrics

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Optimization of Perforation in CBM Horizontal Wells in Southern Qinshui Basin LI Kexin, ZHANG Cong, LI Jun, LIU Chunchun, YANG Ruiqiang, ZHANG Wuchang, LI Shaonan, REN Zhijian Xinjiang Petroleum Geology    2024, 45 (5): 581-589.   DOI: 10.7657/XJPG20240510 Abstract （814）   HTML （14）    PDF（pc） （766KB）（623）       Knowledge map    Save To enhance the fracturing performance of coalbed methane (CBM) horizontal wells in the Qinshui basin, by analyzing the data of distributed optical fiber monitoring of water and gas production profiles, mud log, and well logging, the key factors influencing the fracturing performance were identified. These factors include coal quality, coal structure, drilling position, and perforation method. The middle to upper part of coal seam No. 3 in the Qinshui basin, characterized by low GR values, high coal quality, and intact coal structure, is identified as the optimal interval for fracturing stimulation. Based on the double GR curves, the drilling position of horizontal wellbore trajectory in the coal seam can be accurately determined, aiding in the selection of optimal fracturing interval and perforation method. When the drilling position is located in the middle part of the coal seam, conventional perforation method can be efficient. When the drilling position approaches the roof or is beyond the seam, downward directional perforation is preferred to effectively stimulate the high-quality upper part of the coal seam. When the drilling position is near the lower dirt band, upward directional perforation is advisable to target the high-quality middle part of the coal seam. Field application to 46 horizontal wells demonstrated that the single well production exceeded 2.5×104 m3/d and was stabilized at 2×104 m3/d, and the reservoir fracturing efficiency increased by 10% to 50%, recording a satisfactory development effect of the horizontal wells. Table and Figures | Reference | Related Articles | Metrics

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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 （812）   HTML （23）    PDF（pc） （1331KB）（707）       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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Controls of Continental Shale Lithofacies on Pore Structure of Jurassic Da’anzhai Member in Central Sichuan Basin KONG Xiangye, ZENG Jianhui, LUO Qun, TAN Jie, ZHANG Rui, WANG Xin, WANG Qianyou Xinjiang Petroleum Geology    2023, 44 (4): 392-403.   DOI: 10.7657/XJPG20230402 Abstract （794）   HTML （24）    PDF（pc） （6614KB）（861）       Knowledge map    Save The hydrocarbon storage capacity of shale reservoirs depends on their complex pore structures, which vary by lithofacies of shales. In order to clarify the control of shale lithofacies on the pore structure, the lithofaices of the shales in the Da’anzhai member of Jurassic Ziliujing formation in central Sichuan basin were determined based on total organic carbon and X-ray diffraction analyses, and the pore structure characteristics of the shales were identified by means of thin section observation, and analysis on scanning electron microscopy, low-temperature nitrogen adsorption and high-pressure mercury injection. The results show that six shale lithofacies (organic-rich clayey shale, organic-moderate clayey shale, organic-poor clayey shale, organic-moderate mixed shale, organic-poor mixed shale, and organic-poor calcareous shale) are mainly developed in the Da’anzhai member, with parallel plate-like and slit-like pores dominantly. Clayey shales mainly contain clay mineral interlayer pores, organic matter pores, and fractures induced by hydrocarbon generation pressurization; mixed shale mainly contains residual intergranular pores; and calcareous shale mainly contains a small amount of dissolution pores. For all these lithofacies, the clay mineral content is positively correlated with pore volume and specific surface area, and the TOC is positively correlated with the macropore volume of organic-rich clayey shale. The organic-rich clayey shale exhibits the largest macropore volume and trimodal pore-size distribution, making it the most favorable lithofacies for shale oil storage in the Da’anzhai member in central Sichuan basin. 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 （790）   HTML （9）    PDF（pc） （678KB）（591）       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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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 （786）   HTML （21）    PDF（pc） （4736KB）（921）       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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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 （752）   HTML （14）    PDF（pc） （794KB）（225）       Knowledge map    Save The Chang 6 reservoir in the Shuanghexi block of Yanchang oilfield in the Ordos basin is characterized by low permeability. Conventional calculation methods for development indices are not conducive to geological research, policy formulation and cost control for oilfield development. The production decline patterns, producing degree of reserves by water flooding, injection-production ratio, water cut, injected water utilization, and recovery of the Chang 6 reservoir were analyzed. The results show that the production of the Chang 6 reservoir follows a hyperbolic decline pattern. The block has significant potential for water injection development, with the current control degree and producing degree of reserves by water flooding at 74.54% and 36.94%, respectively, and an injection-production connection rate of 27.27%. The optimal injection-production ratio is approximately 2.5. As the recovery efficiency increases, the water cut rises rapidly at the first and then slows down. Based on the water retention rate, water consumption index, and water flooding index, it is evident that in the late stage of development, the water injection effectiveness improves, leading to an increase in ultimate recovery. During the development process, the water cut rise rate should ideally be kept below 6.1%, and the reasonable formation pressure should be maintained above 9.1 MPa. Under these conditions, the final recovery in the study area is approximately 23%. Table and Figures | Reference | Related Articles | Metrics

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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 （749）   HTML （6）    PDF（pc） （1695KB）（352）       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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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 （740）   HTML （20）    PDF（pc） （1855KB）（530）       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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Development Status of Logging-Based Lithology Identification Technology for Shale Formations CHEN Xiujuan, FENG Zhentao, ZENG Furong, HU Jianbo, XU Song Xinjiang Petroleum Geology    2024, 45 (6): 742-752.   DOI: 10.7657/XJPG20240614 Abstract （734）   HTML （10）    PDF（pc） （1009KB）（651）       Knowledge map    Save Shale reservoirs contribute the most promising unconventional oil and gas resources in China and have become a hotspot in unconventional oil and gas exploration and development. Shale formations in China are mostly continental, with varying lithologies, diverse minerals, poor physical properties, strong heterogeneity, and poor continuity. These characteristics make it difficult to accurately identify lithology only using conventional logging interpretation methods, which in turn hinders the effective characterization of shale reservoirs and severely constrains reserves estimation and oil/gas development activities. In order to effectively identify the lithology of shale formations, the logging-based lithology identification technologies at home and abroad were systematically reviewed, and the lithology identification technologies based on logging interpretation and logging techniques were introduced. The logging lithology identification technologies based on machine learning were dissected in respect to their principles, advantages, disadvantages, and applicability. Finally, the prospects of logging-based lithology identification technologies for shale formations were proposed. Table and Figures | Reference | Related Articles | Metrics

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Classification of Sweet Spots in Shale Oil Reservoir of Lucaogou Formation in Jimsar Sag，Jurggar Basin QI Hongyan, WANG Zhenlin, ZHANG Yanning, LIN Jingqi, HU Xuan, SU Jing, XU Rui, CAO Zhifeng Xinjiang Petroleum Geology    2025, 46 (2): 127-135.   DOI: 10.7657/XJPG20250201 Abstract （724）   HTML （34）    PDF（pc） （3916KB）（352）       Knowledge map    Save The shale oil reservoir of Permian Lucaogou formation in the Jimsar sag of the Junggar Basin can be divided into two sweet spots from top to bottom. These sweet spots vary significantly in productivity and remain unclear for controlling factors, making sweet spot prediction challenging. By using geological, petrophysical experiment, logging, and formation testing data, the enrichment mechanisms of shale oil were identified, the main factors controlling sweet spots in the shale oil reservoir were investigated, sweet spot index was constructed, and a classification standard for sweet spots was established. The research results show that the dominant reservoir rocks in the sweet spots in the study area are silty-fine sandstone and psammitic dolomite, with good pore structure, relatively abundant free oil, and moderate brittleness. The development, distribution, and effectiveness of micro-fractures in the shale oil reservoir are influenced by formation overpressure. The sweet spots in the shale oil reservoir are mainly controlled by free oil saturation, formation overpressure, and brittleness index. The sweet spot index is greater than 45 for Class Ⅰ sweet spots, 25-45 for Class Ⅱ sweet spots, and less than 25 for Class Ⅲ sweet spots. Class Ⅰ and Class Ⅱ sweet spots are considered as prime targets for horizontal wells, while Class Ⅲ sweet spots are reserved for future development. Table and Figures | Reference | Related Articles | Metrics

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