《Lithologic Reservoirs》
Published:01 March 2026
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New method for resource evaluation of Devonian oil shale in Appalachian Basin, North America
MA Feng, HU Fei, XUE Luo, CHEN Ruiyin, LIU Zhaojun, LEI Ming, ZHENG Xi
2026, Vol.38(2): 1–11
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Geological features and hydrocarbon exploration directions of medium to small-scale basin group, onshore China
YANG Zhanlong, HAO Bin, TAN Kaijun, ZHANG Jing, ZHANG Liping, LIAO Jianbo, LI Zaiguang, SHI Jianglong
2026, Vol.38(2): 12–31
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Lithofacies combination characteristics and hydrocarbon accumulation condition of lacustrine shale in Lower Jurassic, eastern Sichuan Basin
YU Chuan, WU Xiaochuan, WANG Wei, WANG Shengxiu, ZHANG Yuelei, GUO Dongxin, LIU Aihua
2026, Vol.38(2): 32–43
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Tectonic evolution of strike-slip faults and its impact on hydrocarbon migration and accumulation in Fuman Oilfield， Tarim Basin
CHANG Shaoying, DONG Keliang, ZENG Jianhui, YANG Jining, WANG Mengxiu, LIU Lingli
2026, Vol.38(2): 44–55
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Main controlling factors of hydrocarbon accumulation and exploration directions of the second member of Triassic Jialingjiang Formation, southern Sichuan Basin
GU Wen, CHEN Hui, ZHU Yadong, WU Furong, ZHAO Zhou, WANG Shuyan, WANG Wei
2026, Vol.38(2): 56–64
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Main controlling factors for hydrocarbon accumulation of Triassic Chang 81 reservoir in Huanxi area， Ordos Basin
LONG Liwen, XIAO Wenhua, YAN Baonian, WANG Jianguo, LI Shaoyong, LI Conglin, GUO Yaoxuan, REN Xueyao
2026, Vol.38(2): 65–75
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Fluid activity attribute-constrained inversion method for tight reservoirs of Jurassic Ahe Formation in Dibei gas reservoir, Kuqa Depression
PENG Fen, REN Dengfeng, PENG Jianxin, WEI Hongxing
2026, Vol.38(2): 76–85
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Sedimentary environment and hydrocarbon geological significance of Lower Triassic Baikouquan Formation in Mabei slope, Junggar Basin
ZHANG Hong, ZOU Niuniu, YIN Yuanyan, YE Zhilong
2026, Vol.38(2): 86–96
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Heterogeneity and oil control effects of Triassic Chang 7 shale in Zhidan area, Ordos Basin
GUO Yuxin, BAI Yubin, ZHAO Jingzhou, ZHANG Jun, CAO Dandan
2026, Vol.38(2): 97–110
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Intelligent identification of fluid logging in tight sandstone reservoirs based on GWO-XGBoost model: A case study of Triassic Chang 8 member in Hongde area, Ordos Basin
XUE Bowen, ZHANG Zhaohui, ZHANG Jiaosheng, ZOU Jiandong, ZHANG Wenting
2026, Vol.38(2): 111–121
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Distribution characteristics and controlling factors of evaporites in Member 5 of Ordovician Majiagou Formation, central and eastern Ordos Basin
ZHOU Wenjuan, PU Renhai, LU Zixing, WANG Kangle, ZHANG Peng, WEN Xingyu, WANG Tong, GUAN Yunwen
2026, Vol.38(2): 122–133
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Characteristics and oil-source correlation of Triassic Chang 7 member source rocks in Huanxian area, Ordos Basin
LI Tao, MA Guofu, ZHAO Leyi, YUAN Li, MA Qilin, XIE Jingyu, ZHANG Bo, LI Henan
2026, Vol.38(2): 134–144
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Tectonic characteristics of Miaoxinan area at the margin of Bohai Bay Basin and their controls on hydrocarbon accumulation
ZHAO Ye, XU Peng, HU Hewei, WANG Hang, YANG Jiaojiao
2026, Vol.38(2): 145–152
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Optimized logging interpretation for tight glutenite reservoir based on beluga whale algorithm
PANG Zhichao, ZHANG Ben, DANG Wandi, GAO Ming, MAO Chenfei, CHEN Guojun
2026, Vol.38(2): 153–161
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Sedimentary characteristics and reservoir evaluation of Jurassic Quemocuo Formation in Maqu area, eastern part of North Qiangtang Depression
ZHAN Wangzhong, SUI Boyu, WANG Zhongwei, HUO Fei, QI Jun, XIE Shangke, ZENG Shengqiang, HOU Qian
2026, Vol.38(2): 162–177
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Prediction method of water-to-gas gravity displacement efficiency and interface stability of high-dip angle reservoirs：A case study of Paleogene Shahejie Formation reservoir in Liuzan area of Bohai Bay Basin
XIONG Yu, ZHANG Weicen, LI Yamei, GENG Wenshuang, WU Daoming, MU Dan, LIU Tong
2026, Vol.38(2): 178–193
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Evaluation method for water influx in fault-karst reservoirs: Taking Ordovician Yijianfang Formation reservoir in Shunbei-1 area as an example
LIU Hong, ZHANG Wenxue
2026, Vol.38(2): 194–200
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New method for resource evaluation of Devonian oil shale in Appalachian Basin, North America
MA Feng, HU Fei, XUE Luo, CHEN Ruiyin, LIU Zhaojun, LEI Ming, ZHENG Xi
2026, Vol.38(2): 1–11
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doi: https://doi.org/10.12108/yxyqc.20260201
For the evaluation of oil shale resources in basins with medium-low exploration levels, traditional volumetric methods and geological parameter analogy methods have limitations. An indirect parameter volumetric method is more suitable for resource evaluation of Appalachian Basin in North America. Based on the good positive correlation between total organic carbon content (TOC) of shale and its oil content, the threshold value and oil content range of oil shale were determined, and the correction coefficient was calculated. The correction coefficient was further applied to obtain the thickness, area, and pyrolysis hydrocarbon quantity (S2) of oil shale, thereby the oil resource of oil shale was estimated. The results show that: （1） Oil shale resources in Appalachian Basin of North America are primarily distributed in the western Ohio area. The main formation of Ohio area is the Upper Devonian Ohio shale, which can be further divided into three submembers from bottom to top: Huron, Chagrin, and Cleveland. The lithology is predominantly deep gray to black shale, with thin interbeds of siltstone.（2） TOC of Ohio shale in the study area is 1%-12%, with oil content ranging from 0.33% to 9.31%. The oil content of oil shale ranges from 3.50% to 9.31%, S2 is 35.2-95.7 mg/g and correction coefficient is 0.647. （3） Multiplying the mud shale thickness by the correction coefficient obtain the oil shale thickness of 10-80 m in the study area. Convert TOC contour lines into oil content contour lines, and the area delineated by an oil content of 3.50% is the oil shale area, which is 46,120 km2. （4） Using the indirect parameter volumetric method, the estimated oil resource of surface dry distillation and in-situ transformation oil shale in the study area are 202×108 t and 173×108 t, respectively, with corresponding recoverable resources of 86×108 t and 39×108 t, respectively.
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Geological features and hydrocarbon exploration directions of medium to small-scale basin group, onshore China
YANG Zhanlong, HAO Bin, TAN Kaijun, ZHANG Jing, ZHANG Liping, LIAO Jianbo, LI Zaiguang, SHI Jianglong
2026, Vol.38(2): 12–31
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doi: https://doi.org/10.12108/yxyqc.20260202
The overall understanding of medium to small-scale basins onshore China is low, with not high degree exploration, and hydrocarbon potential and exploration direction remain unclear, but some basins have achieved large-scale oil and gas discoveries. By incorporating medium to small-scale basins across the country into a same basin type for overall systematic comparison, key geological factors for hydrocarbon accumulation in medium to small-scale basins were explored, and then strategic selection and favorable basin optimization for exploration in medium to small-scale basins were carried out to clarify the exploration direction. The results show that: （1） Tectonic domain and their activity process are key controlling factors that determine geological features of medium to small-scale basins in group. Primary basin groups are mainly developed in periphery of the relative large and stable tectonic domain, transformed remnant basins are mainly developed within the tectonically active zones and superimposed basins are mostly developed in areas experienced multi-phase tectonic activity. （2） Primary basins mainly develop Meso-Cenozoic lake-marsh coal measure strata and lacustrine mudstone source rocks, mainly with Ⅱ-Ⅲ type organic matter, and the abundance in some of basins are more than 0.5%, but the maturity in different basins, different strata and different parts of the same strata varies greatly. Partial transformed remnant basins develop source rock of Paleozoic marine or marine-terrestrial transitional carbonate and mudstone, mainly with Ⅰ-Ⅱ type organic matter, and the abundance in some of basins are more than 0.3%, and the overall maturity is high and in maturity to over-maturity phase. Source rocks in superimposed basins mainly develop within middle to lower assemblages. （3） Main factors that determine the enrichment of hydrocarbon in some medium to small-scale basins include: The primary basin has undergone a complete lake-basin infilling evolution, the uplift and erosion to the transformed remnant basin did not destroy the main part of high-quality source rocks, the late transformation of superimposed basin are favorable for the maturing and preserving of high-quality source rock. Which have undergone deep burial in late period. The basin region has deep thermal background, characterized by high geothermal gradients, which are conducive to the maturing of source rocks, large-scale migration of hydrocarbon and effective preservation of generated hydrocarbons. （4） Primary basins surrounding Ordos Basin, some transformed remnant basins in Pan-Hexi region, some strike-slip and pull apart basins along Tan-Lu fault zone, some Paleozoic remnant basins with lower degree of late modification and Cenozoic primary basins in the South, and middle to lower assemblages of some superimposed basins in stable areas of West are favorable for hydrocarbon exploration onshore China. The near-source exploration or along dominant paths of fluid migration is the key to hydrocarbon exploration in medium to small-scale basins, medium to small-scale basins have become an important replacement domain for onshore hydrocarbon exploration strategic selection of China.
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Lithofacies combination characteristics and hydrocarbon accumulation condition of lacustrine shale in Lower Jurassic, eastern Sichuan Basin
YU Chuan, WU Xiaochuan, WANG Wei, WANG Shengxiu, ZHANG Yuelei, GUO Dongxin, LIU Aihua
2026, Vol.38(2): 32–43
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doi: https://doi.org/10.12108/yxyqc.20260203
Lower Jurassic Lianggaoshan Formation and Ziliujing Formation lacustrine facies dark mud shales widely develop in eastern Sichuan Basin, making them key fields for shale oil and gas exploration. Through the description and sampling analysis of key drilling and typical stratigraphic profiles, lithofacies combinations of terrestrial shale were classified, and comparative analyses were conducted on reservoir formation conditions of shale oil and gas in different lithofacies. The results show that: （1） Lower Jurassic terrestrial shale series in eastern Sichuan Basin exhibit fast sedimentary facies changes and complex lithofacies combinations. Compared with Lower Paleozoic marine shales, they have geological characteristics of “multiple development layers, large cumulative thickness (40-115 m), small single-layer thickness (< 25 m), poor continuity”. （2） Lower Jurassic continental shale in the study area can be divided into three categories: siliceous shale, clayey shale, and shell calcareous shale. Lithological characteristics of different lithofacies types vary greatly and are mainly controlled by their original sedimentary environment. （3） The hydrocarbon generation capacity and storage performance of laminated carbon-bearing clayey shale and carbon-bearing shell-bearing clayey shale are relatively good, organic types of the shale are mainly mixed type of sapropelic mud (mainly type Ⅱ1), with TOC generally exceeding 1.2%. Organic matter pores and microcracks are well-developed, with effective poro-sity mostly above 3.0%, which have favorable conditions for hydraulic fracturing and transformation, and also are favorable lithofacies types for oil and gas enrichment and accumulation. （4） Favorable areas for shale hydrocarbon accumulation in Lianggaoshan Formation of the study area are distributed in Wanzhou-Liangping area and Dianjiang-Fengdu area. Favorable areas for hydrocarbon accumulation in Da’anzhai section of Ziliujing Formation are distributed in Liangping-Kaijiang-Wanzhou area. Favorable areas for hydrocarbon accumulation in Dongyuemiao section of Ziliujing Formation are distributed in Dianjiang-Liangping-Zhongxian area.
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Tectonic evolution of strike-slip faults and its impact on hydrocarbon migration and accumulation in Fuman Oilfield， Tarim Basin
CHANG Shaoying, DONG Keliang, ZENG Jianhui, YANG Jining, WANG Mengxiu, LIU Lingli
2026, Vol.38(2): 44–55
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doi: https://doi.org/10.12108/yxyqc.20260204
Multi-stage activities of strike-slip faults of Fuman Oilfield in Tarim Basin significantly control hydrocarbon migration and accumulation in deep to ultra-deep reservoirs. Based on 3D seismic data interpretation of Fuman Oilfield， structural characteristics and tectonic evolution of FI 5 fault， FI 7 fault， FI 16 fault， and FI 17 fault were delineated， and their influences on hydrocarbon migration and accumulation were analyzed. The results show that： （1） FI 5 fault， FI 7 fault， FI 16 fault， and FI 17 fault primarily underwent four stages of tectonic evolution： Early Caledonian， episode Ⅰ of middle Caledonian， episode Ⅲ of middle Caledonian， and late Caledonian-early Hercynian. Among them， episode Ⅰ of middle Caledonian and episode Ⅲ of middle Caledonian were the main active periods. FI 5 fault and FI 17 fault were more active than FI 7 fault and FI 16 fault, with FI 16 fault exhibi-ting the weakest activity. （2） FI 5 fault and FI 17 fault have source connectivity and improve the reservoir property. FI 7 fault has no source connectivity， but its conductivity and reservoir improvement ability are good， while FI 16 fault has poor source connectivity， conductivity, and reservoir improvement ability. （3） During late Caledonian， oil and gas underwent certain scale vertical charging along FI 5 fault and FI 17 fault， while migration and enrichment rarely occurred along FI 7 fault， and the scale of vertical charging along FI 16 fault zone was relatively small. In late Hercynian， large-scale vertical hydrocarbon migration and accumulation occurred along FI 5 fault and FI 17 fault. FI 7 fault did not connect to hydrocarbon source， resulting in limited vertical migration and accumulation of oil and gas along it. Lateral migration and accumulation may have occurred and had a certain scale， while the scale of vertical migration and accumulation along FI 16 fault was relatively small. （4） During Himalayan， Lower Cambrian source rocks in the eastern part of Fuman area entered the over-mature gas generation stage. While Middle Cambrian gypsum-salt layers failed to form an effective seal， leading to significant gas washing in petroleum reservoirs near FI 16 fault and FI 17 fault， resulting in an overall increase in gas-oil ratio.
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Main controlling factors of hydrocarbon accumulation and exploration directions of the second member of Triassic Jialingjiang Formation, southern Sichuan Basin
GU Wen, CHEN Hui, ZHU Yadong, WU Furong, ZHAO Zhou, WANG Shuyan, WANG Wei
2026, Vol.38(2): 56–64
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doi: https://doi.org/10.12108/yxyqc.20260205
Natural gas exploration and development of Triassic Jialingjiang Formation in Sichuan Basin have a long history, with cumulative proven reserves exceeding 100 billion cubic meters. Based on the latest drilling, logging, 2D and 3D seismic data, a systematic study of hydrocarbon accumulation conditions of the second member of Jialingjiang Formation in Sichuan Basin was conducted, focusing on sedimentary reservoirs, paleostructural evolution, and source-reservoir matching, and favorable exploration zones were indentified.The results show that: （1） Gas reservoirs of Triassic Jialingjiang Formation in southern Sichuan Basin are characte-rized by strong reservoir heterogeneity and long-distance hydrocarbon accumulation. Fault systems provide critical migration pathways and storage spaces, while paleostructural highs are essential for hydrocarbon accumulation. （2） Jialingjiang Formation in southern Sichuan Basin possesses favorable hydrocarbon accumulation conditions, such as multiple hydrocarbon sources, large-scale development of high-quality beach facies reservoirs, location in paleo and present structural highs, and effective connectivity to source rocks via source-connecting faults. The hydrocarbon accumulation model is “paleo-reservoir controlling scale, paleo-uplift controlling storage, faults connecting sources, and fractures controlling enrichment”. （3） Structural synclines and slope areas in southern and eastern Sichuan Basin, characterized by shallow burial depth and great exploration potential, are favorable targets for further exploration of Jialingjiang Formation in Sichuan Basin.
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Main controlling factors for hydrocarbon accumulation of Triassic Chang 81 reservoir in Huanxi area， Ordos Basin
LONG Liwen, XIAO Wenhua, YAN Baonian, WANG Jianguo, LI Shaoyong, LI Conglin, GUO Yaoxuan, REN Xueyao
2026, Vol.38(2): 65–75
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doi: https://doi.org/10.12108/yxyqc.20260206
Through a large number of drilling core experiments and seismic data interpretation， depositional cha-racteristics and reservoir characteristics of Triassic Chang 81 in Huanxi area of Ordos Basin were analyzed， main controlling factors for hydrocarbon accumulation were explored， and oil and gas accumulation models were summurized. The results show that： （1） Triassic Chang 81 of Huanxi area develop delta plain sediments， with braided channels as the main reservoirs. The average porosity of the eastern reservoir is 7.9%， and the average permeability is 0.43 mD. The average porosity of the western reservoir is 15.8%， and the average permeability is 12.00 mD. （2） Du-ring the period of large-scale hydrocarbon expulsion， the paleostructure of Chang 81 in the study area exhibited the morphology of east-west high and middle low， with structural traps developed in the southwest，northwest and axial parts of Tianhuan Depression, providing the setting for oil and gas accumulation. The eastern part of Chang 7 has developed black mudstone shale，which belongs to high-quality source rock. The western part of Chang 7 has developed dark mudstone，which belongs to poor-medium source rock. On the plane，the thickness of source rocks gradually decreases from east to west， and source rocks in high parts of the western structure is not developed. Sand body thickness of Chang 81 reservoir in the west is large， with an average thickness of 24 m. Sand body thickness of axial parts of Tianhuan Depression is the largest， with the gradual thinning and pinch out of the sand body from the axial part to the western wing. （3） Crude oil of Chang 81 in the eastern part of the study area comes from the overlying Chang 7 black shale，which has the characteristics of upper generation and lower storage， near-source accumulation. Crude oil of Chang 81 in the western part of the study area comes from the black shale of Chang 7 in the east and the mudstone of Chang 7 in the west， with mixed source characteristics. Northwest trending faults and thick sand bodies of the axial part provide channels for hydrocarbon migration. Oil reservoirs can be divided into three categories： First， structural oil reservoirs developed in the axial part of Tianhuan Depression，with anticline traps as the main targets for exploration. Second， sandstone updip pinch out reser-voirs under the structural background of the developed west wing of Tianhuan Depression，north-south sandstone pinch out zones are the main exploration direction. Third， tight lithological oil reservoirs in the eastern region，with sand bodies close to source rocks as the main targets for exploration.
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Fluid activity attribute-constrained inversion method for tight reservoirs of Jurassic Ahe Formation in Dibei gas reservoir, Kuqa Depression
PENG Fen, REN Dengfeng, PENG Jianxin, WEI Hongxing
2026, Vol.38(2): 76–85
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doi: https://doi.org/10.12108/yxyqc.20260207
Tight sandstone gas reservoirs generally suffer from poor physical properties and strong heterogenei-ty, and conventional seismic inversion methods have poor performance in fluid identification in such reservoirs. Based on matching pursuit, ensemble empirical mode decomposition, fluid activity attribute extraction, and Bayesian theory, a regularized inversion method constrained by fluid activity attributes was proposed. The method was validated through model data testing and applied to predict tight sandstone reservoirs in Jurassic Ahe Formation of Dibei gas reservoir in Kuqa Depression. The results show that: （1） The main idea of fluid activity attribute-constrained inversion is to perform time-frequency analysis using MP-EEMD technique to extract fluid activity attributes, and to construct the inversion objective function under Bayesian theory, in which the norma-lized fluid activity attributes are incorporated as soft constraints. (2) Model data tests show that MP-EEMD time-frequency spectrum overcomes multi-frequency interference, achieving higher resolution in both time and frequency domains. Furthermore, the inversion results with fluid constraints demonstrate superior predictive performance for fluid-bearing formations compared with conventional inversion. (3) The application of fluid activity attributes-constrained inversion in Jurassic Ahe Formation reservoirs in Dibei gas field of Kuqa Depression shows that： inverted P-wave velocity results exhibit higher consistency with well-logging interpretations, and with improved thin-bed characterization, achieving higher vertical resolution compared with conventional methods.
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Sedimentary environment and hydrocarbon geological significance of Lower Triassic Baikouquan Formation in Mabei slope, Junggar Basin
ZHANG Hong, ZOU Niuniu, YIN Yuanyan, YE Zhilong
2026, Vol.38(2): 86–96
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doi: https://doi.org/10.12108/yxyqc.20260208
Based on rock major and trace elements testing, the sedimentary environment, provenance characte-ristics, and their controlling effects on sedimentary evolution of Lower Triassic Baikouquan Formation glutenite reservoirs in Mabei slope of Junggar Basin were investigated. The results show that: （1） The reservoir lithology of Lower Triassic Baikouquan Formation in Mabei slope of Junggar Basin is dominated by gray to grayish-green sandy conglomerate. Interstitial materials are mostly argillaceous, with porphyritic cementation as the main cementation type. Grain size probability curves exhibit two-segment or three-segment characteristics. （2） The provenance tectonic setting of Lower Triassic Baikouquan Formation in Mabei slope of Junggar Basin is an active continental margin. The parent rock composition is mainly felsic rocks. Triassic in the northwestern margin of Junggar Basin located in a large thrust nappe fault zone, with intense syndepositional faulting activity at the basin margin, leading to the uplift and erosion of Hala’alat Mountain, which provided sufficient clastic materials for Baikouquan Formation of Mahu Sag. （3） The average chemical index of alteration (CIA) of rock samples from Baikouquan Formation in the study area is 68.53%, the average C value is 0.96, and the average Sr/Cu ratio is 2.45, indicating a warm and humid climate during the deposition. The average Sr/Ba ratio is 0.47, the average mass fraction of Ni is 11.41×10-6, and the average mass fraction of Li is 19.78×10-6, showing sedimentary waterbody as freshwater environment. The average Mn/Fe ratio is 0.06, and combined with the variation trends of Rb/Zr and Sr/Ba ratios, it reveals that the lake basin waterbody is generally shallow, with a continuously slow-rising lake level during the deposition. The average U/Th ratio is 0.12, the average Ni/Co ratio is 1.8, and the average value of δU is 0.54, indicating that the overall water environment are oxidizing condition. （4） The average porosity of Baikouquan Formation reservoir in the study area is 9.7%, and the average permeability is 0.53 mD, belonging to a low-porosity and low-permeability reservoir. The warm and humid climate, moderate weathering, sufficient provenance supply, and shallow water oxidizing environment during the deposition period of Baikouquan Formation are all conducive to the large-scale development of retrogradational fan deltas. As the sedimentary facies evolved from fan delta plain to fan delta front, the sediment grain size exhibited a positive cyclothem characteristic of gradual fining from bottom to top, forming a good reservoir-cap assemblage, providing favorable geological conditions for the large-scale fan-controlled hydrocarbon accumulation in Triassic Baikouquan Formation.
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Heterogeneity and oil control effects of Triassic Chang 7 shale in Zhidan area, Ordos Basin
GUO Yuxin, BAI Yubin, ZHAO Jingzhou, ZHANG Jun, CAO Dandan
2026, Vol.38(2): 97–110
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doi: https://doi.org/10.12108/yxyqc.20260209
The shale oil resource potential of continental petroliferous basins in China is significant，and heterogeneity of the mud shale reservoir controls its oil-bearing and fracability. Based on testings, such as core observation, total organic carbon (TOC) and pyrolysis, whole rock and clay mineral X-ray diffraction analysis, high-pressure mercury intrusion and nitrogen (N2) adsorption experiment, heterogeneity characteristics of Triassic Chang 7 shale reservoir in Zhidan area of Ordos Basin were systematically revealed, and its control effect on shale oil enrichment was discussed. The results show that: （1） Triassic Chang 7 in Zhidan area of Ordos Basin is mainly composed of dark mudstone and black shale, which can be divided into felsic mudstone facies, clayey mudstone facies, and mixed shale facies. The macroscopic heterogeneity of different lithofacies is mainly influenced by terrestrial input,volcanic activity frequency, and sedimentary environments, manifested as the greater frequency of bedding distribution and more frequent changes in lithology, and stronger heterogeneity. On a microscopic level, from clayed mudstone, felsic mudstone to mixed shale, the heterogeneity gradually increases with the increasing frequency of bedding. （2） The mineral composition and TOC content of different lithologies vary significantly, exhibiting strong heterogeneity characteristics. （3） The pore types of Chang 7 mud shale re-servoir in the study area are diverse, including intergranular pores, intragranular pores, clay mineral intercrystalline pores, pyrite intercrystalline pores, and microfractures. The pore structure is mainly mesoporous, with pore diameters ranging from 10 to 100 nm, developing “ink bottle” shaped pores and parallel plate-shaped pores. （4） Lithology, mineral content, TOC content, and pore structure all have controlling effects on Chang 7 shale oil in the study area. Among them, lithofacies, TOC content and average pore diameter have relatively obvious positive correlations with oil-bearing property indicators, which are the main controlling factors for shale oil enrichment. The “sweet spot” segment of shale oil enrichment can be predicted by integrating the heterogeneity characteristics of mud shale, oil-bearing property, brittleness index and movable oil evaluation criteria.
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Intelligent identification of fluid logging in tight sandstone reservoirs based on GWO-XGBoost model: A case study of Triassic Chang 8 member in Hongde area, Ordos Basin
XUE Bowen, ZHANG Zhaohui, ZHANG Jiaosheng, ZOU Jiandong, ZHANG Wenting
2026, Vol.38(2): 111–121
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doi: https://doi.org/10.12108/yxyqc.20260210
Traditional logging interpretation methods exhibit low accuracy in identifying fluid properties in tight sandstone reservoirs, in response to such problem, an intelligent identification method for reservoir fluid based on GWO-XGBoost model was proposed, and it was applied to Triassic Chang 8 tight sandstone reservoirs in Hongde area of Ordos Basin. The results show that: （1） Taking actual well testing data of Triassic Chang 8 tight sandstone reservoir in Hongde area of Ordos Basin as the target variable, nine logging curves, including acoustic, spontaneous potential, density, caliper, neutron, natural gamma, and three resistivity logs (AT 20, AT60, and AT90)，were selected as features parameters through principal component analysis. Then, key hyperpara-meters of XGBoost model were globally optimized using grey wolf optimization (GWO) algorithm. （2） GWO-XGBoost model has an accuracy of 96.55% in identifying reservoir fluid types, which is significantly higher than XGBoost, Random Forest (RF), and Support Vector Machine (SVM) models by 6.03%, 6.89%, and 22.41%, respectively. （3） In practical single-well applications, GWO-XGBoost model, through comprehensive analysis and nonlinear feature learning of multi-dimensional logging responses, effectively overcomes the common misclassification between low-resistivity oil layers and high-resistivity water layers in manual interpretation. This model exhibits high stability and reliability under complex reservoir conditions, providing effective technical support for improving the efficiency of tight sandstone oil and gas exploration and development.
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Distribution characteristics and controlling factors of evaporites in Member 5 of Ordovician Majiagou Formation, central and eastern Ordos Basin
ZHOU Wenjuan, PU Renhai, LU Zixing, WANG Kangle, ZHANG Peng, WEN Xingyu, WANG Tong, GUAN Yunwen
2026, Vol.38(2): 122–133
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doi: https://doi.org/10.12108/yxyqc.20260211
Evaporites (gypsum-salt rocks) in Ma54 and Ma56 submembers of Ordovician Majiagou Formation in central and eastern Ordos Basin provide a good sealing for the formation and preservation of high-pressure gas reservoir in the dolomite of Ma55 submember. Evaporites in Ma54 and Ma56 submembers were identified using logging and core analysis data, and their distribution patterns and controlling factors were studied. The results show that: （1） During the depositional period of Ma56-Ma54 submembers of Ordovician Majiagou Formation in central and eastern Ordos Basin, the central-eastern basin was characterized by an eastward-dipping gentle slope superimposed with a paleo-structural framework of “three uplift zones and two sags”. From west to east, they are Wushenqi uplift, Western shallow sag, Hengshan uplift, Eastern deep sag, and Lüliang uplift. These secondary uplifts acted as hydrodynamic barriers, leading to differentiation of evaporite facies，and with characteristics of two lagoons and two evaporite deposition centers. （2） Ma54 and Ma56 submembers are depositions characterized by“double-barrier and double-lagoon”carbonate rocks and evaporite restricted-evaporite platform. These five paleo-structural units correspond to the following sedimentary facies belts: dolomicrite flat, anhydritic dolomicrite flat, gypsum-salt lagoon, inner barrier anhydritic dolomicrite flat, halite lagoon, and outer barrier anhydritic dolomicrite flat. （3） Under the combined control of paleo-structure, paleogeography, paleoclimate, and sea-level fluctuations, the distribution of gypsum rock and salt rock differs. During the humid-climate period, Ma55 submember deposited carbonate rocks. During the arid-climate period，Ma56 and Ma54 submembers deve-loped gypsum rock in the highstand systems tract (western shallow lagoon) and salt rock in the lowstand systems tract (eastern medium-deep lagoon). （4） Thick anhydrite layers in the western Ma54 shallow subsag inhibited dolomitization of Ma55 submember, limiting the development of high-quality reservoirs; whereas the combination of the Ma54 salt rock pinch-out zone and NWW-trending faults provided key pathways for vertical migration and lateral accumulation of oil and gas in Ma55 reservoir, thereby forming the Mizhi high-pressure gas reservoir.
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Characteristics and oil-source correlation of Triassic Chang 7 member source rocks in Huanxian area, Ordos Basin
LI Tao, MA Guofu, ZHAO Leyi, YUAN Li, MA Qilin, XIE Jingyu, ZHANG Bo, LI Henan
2026, Vol.38(2): 134–144
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doi: https://doi.org/10.12108/yxyqc.20260212
Triassic Chang 7 member shale is the main source rock in Huanxian area of the western Ordos Basin. Through rock pyrolysis, total organic carbon measurement, gas chromatography-mass spectrometry, and AI-assisted comprehensive biomarker analysis， geochemical characteristics of crude oils and source rocks were systematically studied，the origin of crude oil and the proportion of hydrocarbon supply from mudstones and shales were clarified, and their hydrocarbon accumulation models were explored. The results show that： （1） Triassic Chang 7 member in the eastern Huanxian area is primarily developed shale,characterized by high organic matter abundance, favorable organic matter type, significant hydrocarbon generation potential. In contrast, the western part is dominated by dark mudstone, with TOC values ranging from 0.40% to 6.23%, hydrocarbon generation potential （S1 + S2） of 0.50-13.13 mg/g, organic matter types of TypeⅡ and Ⅲ, and an average vitrinite reflectance (Ro) of 0.84%, indicating a mature stage. It belongs to a medium-poor source rock with relatively lower hydrocarbon generation potential compared to shale. （2） Biomarker compositions of eastern shales and western mudstones are fundamentally similar, but significant differences exist in certain biomarker parameter ratios. Eastern shales exhibit low Pr/Ph ratios, high Ts/Tm, C29Ts/C29H, C30*/C29H, and C30*/C30H values. In contrast, western dark mudstones display relatively high Pr/Ph ratios, low Ts/Tm, C29Ts/C29H, C30*/C29H, and C30*/C30H values. These differences reflect the controlling effect of paleo-sedimentary environments on the development of mudstones and shales in the study area. （3） Chang 8 member in the study area develops three types of crude oil: Type A is crude oil predominantly from the eastern Chang 8 member, exhibiting high Ts/Tm and C29Ts/C29H values, along with relative high C30*/C29H and C30*/C30H values, type A is primarily derived from eastern shales. Type C, though currently less abundant, is characterized by low Ts/Tm, C29Ts/C29H, C30*/C29H, and C30*/C30H values, predominant sourcing from western mudstone. Type B, found in the western Chang 8 member, displays intermediate biomarker between type A and type C, with moderate Ts/Tm, C29Ts/C29H, C30*/C29H, and C30*/C30H values. It is a mixed crude oil composition dominantly contributed by eastern shales.
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Tectonic characteristics of Miaoxinan area at the margin of Bohai Bay Basin and their controls on hydrocarbon accumulation
ZHAO Ye, XU Peng, HU Hewei, WANG Hang, YANG Jiaojiao
2026, Vol.38(2): 145–152
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doi: https://doi.org/10.12108/yxyqc.20260213
Using three-dimensional seismic data, drilling and logging data, and geochemical testing data，the depression structure, structural evolution characteristics, source rock distribution, and controlling effects of hydrocarbon accumulation in Miaoxinan area of Bohai Bay Basin were studied. The results show that: （1） Miaoxinan area is a transformed depression formed by the Tan-Lu strike-slip fault. During Middle-Late Eocene, the near east-west regional compression movement led to the transformation of the depression structure from NWW to NEE, the fourth section of Shahejie Formation (E2s4) was gradually weakened in erosion intensity from east to west, and source rocks of E2s4 in south sag of Miaoxi Sag on the east side were completely eroded. The high-sulfur and salty high-quality source rocks of E2s4 in the east sag of Huanghekou Sag on the west side have been preserved. （2） The east sag of Huanghekou Sag has developed long-term active faults that extend deep into source rocks of E2s3 and E2s4, oil and gas migrate and accumulate upward along the source-connecting faults, demonstrating the characteristics of deep and shallow compound hydrocarbon accumulation. （3） The south sag of Miaoxi Sag has only developed low-maturity hydrocarbon source rocks in E2s3, and the late stage activity of source-connecting faults is poor, oil and gas are difficult to break through the thick mudstone cap of Dongying Formation, and natural gas reserves have only been discovered in deep E2s1 and E2s2. In Middle-Late Eocene, the near east and west compression activities of eastern China played an important controlling role in the structure of basin margin depression, the distribution of source rocks and the accumulation of oil and gas.
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Optimized logging interpretation for tight glutenite reservoir based on beluga whale algorithm
PANG Zhichao, ZHANG Ben, DANG Wandi, GAO Ming, MAO Chenfei, CHEN Guojun
2026, Vol.38(2): 153–161
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doi: https://doi.org/10.12108/yxyqc.20260214
To address the challenges of determining mineral composition and improving porosity estimation in deep glutenite reservoirs, taking the tight glutenite reservoirs of Cretaceous Qingshuihe Formation in the southern margin of Junggar Basin as an example, an optimized logging interpretation method based on the beluga whale optimization (BWO) algorithm was proposed, and the computational results of this method demonstrate higher consistency with the laboratory analysis data of core samples. The results show that: （1） The process of BWO-based optimized logging interpretation for reservoirs is as follows: By integrating data of core, thin section, and scanning electron microscopy, a multi-composition volumetric physical model of the study area is established; based on conventional logging data, a logging response equation is established and then solve it with BWO algorithm; with the least squares method as the basic theory, an optimized logging objective function is established by combining multiple volumetric physical model and logging response equation. （2） The proposed method demonstrates excellent global and local search capabilities, fast convergence, high computational accuracy, and strong scalability. Test simulations showed that the objective function stabilizes after approximately 40 iterations during logging curve inversion. The calculated mineral contents show good correlation with actual data, with mean absolute errors below 1.50% and mean relative errors below 11.50%. （3） The primary minerals of deep glutenite reservoir in the southern margin of Junggar Basin are quartz, feldspar, calcite, dolomite, and clay. The absolute errors for mineral content and porosity calculated by the BWO-based optimized logging interpretation method and the measured core data are less than 3.00% and 0.26%, respectively, significantly outperforming conventional methods.
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Sedimentary characteristics and reservoir evaluation of Jurassic Quemocuo Formation in Maqu area, eastern part of North Qiangtang Depression
ZHAN Wangzhong, SUI Boyu, WANG Zhongwei, HUO Fei, QI Jun, XIE Shangke, ZENG Shengqiang, HOU Qian
2026, Vol.38(2): 162–177
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doi: https://doi.org/10.12108/yxyqc.20260215
Jurassic Quemocuo Formation in North Qiangtang Depression has developed large-scale coarse clastic rocks and gypsum-salt rocks. Through detailed characterization of field geological profiles and analysis of drilling cores, the sedimentary characteristics, reservoir features, and main controlling factors of Quemocuo Formation in Maqu area of the eastern part of North Qiangtang Depression were systematically revealed. The results show that: （1） Sedimentary facies of Quemocuo Formation have experienced the evolution of braided river，carbonate tidal flat，delta，open platform，clastic tidal flat upward, with 7 subfacies and 7 microfacies being identified at Ren’aibo section in Maqu area, North Qiangtang Depression. And in well QZ-16, sedimentary facies of Quemocuo Formation have experienced the evolution of meandering river，evaporative platform，restricted platform， clastic tidal flat, with 7 subfacies and 6 microfacies being identified. Quemocuo Formation as a whole is a transgressive sequence with gradually deepening water upwards, but lateral variations in sedimentary characteristics exist due to differences of paleogeography. （2） Lithologies of Quemocuo Formation clastic reservoir in the study area are primarily lithic quartz sandstone, feldspar lithic sandstone, lithic sandstone, and sandy siltstone. The storage space of reservoir is primarily composed of intergranular dissolved pores and intragranular dissolved pores. The average porosity and permeability are 2.89% and 0.024 mD, respectively, and the overall reservoir can be classified as an ultra-low porosity and ultra-low permeability reservoir. Simultaneously, the displacement pressure ranges from 0.71 to 41.00 MPa, with the average median pore-throat radius of 0.088 μm and sorting coefficients all greater than 1.5, significant variation in mercury injection difficulty, small pore-throat radius, and poor sorting. The overall reservoir has strong heterogeneity, belongs to medium-poor tight to extremely tight reservoir. （3） The reservoir quality of Quemocuo Formation in the study area is significantly influenced by sedimentary microfacies and diagenesis. Subaqueous distributary channel sand bodies in the delta front exhibit best properties, followed by sand bodies of the distributary channel in the delta plain and the low-tidal flat in the intertidal zone, sand bodies of the point bar-natural levee in the meandering river have the poorest reservoir quality. Dissolution plays a constructive role for the reservoir property, while compaction and cementation primarily have destructive effects on the reservoir.
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Prediction method of water-to-gas gravity displacement efficiency and interface stability of high-dip angle reservoirs：A case study of Paleogene Shahejie Formation reservoir in Liuzan area of Bohai Bay Basin
XIONG Yu, ZHANG Weicen, LI Yamei, GENG Wenshuang, WU Daoming, MU Dan, LIU Tong
2026, Vol.38(2): 178–193
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doi: https://doi.org/10.12108/yxyqc.20260216
By conducting nuclear magnetic resonance analysis and displacement experiments on core samples with different physical properties, the influence of formation dip angle and water cut on oil displacement efficiency in Es32+3 reservoir of Paleogene Shahejie Formation in Liuzan area of Bohai Bay Basin was explored, and a two-dimensional model focusing on injection-production parameters was established to reveal the key factors affecting gas-liquid interface stability and displacement efficiency. The results show that: （1） During the transition from water flooding to gas flooding in high-dip angle reservoirs of northern Liuzan area, the top gas injection technology improves oil displacement efficiency by 20% approximately，controlled by the stable gas cap formed by gravity differentiation and the immiscible displacement mechanism dominated by it, while the improvement of oil displacement efficiency by direct gravity is relatively limited. （2） Appropriately increasing the injection-production ratio can enhance gas cap pressure and the ability of gas to penetrate micro-pores, thereby improving gas-liquid interface stability. （3） The equation for stable gas injection rate can effectively predict the optimal range of gas injection rate for gravity drive，and can analyze the development dynamics of gas injection in real time.
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Evaluation method for water influx in fault-karst reservoirs: Taking Ordovician Yijianfang Formation reservoir in Shunbei-1 area as an example
LIU Hong, ZHANG Wenxue
2026, Vol.38(2): 194–200
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doi: https://doi.org/10.12108/yxyqc.20260217
The fault-karst reservoir of Shunbei-1 area in Tarim Basin exhibits a non-monotonic trend in formation pressure, initially decreasing and then rebounding as cumulative production increases. This phenomenon cannot be explained by traditional water influx models， but aligns more closely with progressive development behavior. Based on the concept of “sequential mobilization” and material balance theory, the water influx process is divided into pre-water influx and post-water influx, with evaluation models respectively established for dynamic reserves and aquifer volume. The results show that： （1） Ordovician reservoir in Shunbei Oilfield is a typical fault-karst reservoir, characterized by a stereoscopic model of narrow horizontal strips and large vertical spans. It is controlled by the NE-trending strike-slip fault system. The carbonate reservoir of Yijianfang Formation is a “fault-karst” type reservoir with poor physical properties, and fault-karst bodies are continuously distributed along major fault zones. （2） The newly established water influx evaluation model can be used to calculate dynamic reserves, water influx rate, and dynamic aquifer volume of fault-karst reservoirs in the research area, thereby determining single-well controlled geological reserves and aquifer size. The plot of cumulative liquid production (subsurface volume) versus dynamic reserves exhibits a plateau segment, with the plateau onset indicating the start of water influx. The dynamic reserves at this point represent the single-well controlled geological reserves. The plot of cumulative liquid production (subsurface volume) versus mobilized oil-water volume ratio also shows a plateau at its terminus. The plateau height minus 1 yields the aquifer volume ratio. （3） In the study area application, the model successfully calculated a maximum dynamic reserves of 126.17×104 m3 and a maximum mobilized aquifer volume of 182 times the geological reserves. The model provides a rational explanation for the pressure variations observed during water influx in fault-karst reservoirs.