《Lithologic Reservoirs》
Published:01 May 2026
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Development characteristics and hydrocarbon exploration potential of Ordovician dome structures in northern Tarim Basin
YUN Lu, CAO Zicheng, LI Haiying, GENG Feng, LIU Yongli, WEI Huadong, HUANG Cheng, ZHANG Di
2026, Vol.38(3): 1–11
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Research progress of velocity modeling and imaging techniques using vertical seismic profile (VSP)
SU Qin, FENG Gang, LI Yanpeng, YANG Zhe, LIU Wenqing
2026, Vol.38(3): 12–23
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Stratigraphic division of Permian and its exploration significance of Bogda piedmont, northern margin of Tuha Basin
CHEN Xuan, HAO Bin, GOU Hongguang, ZHANG Jing, XU Xiongfei, YANG Zhanlong, HU Jun, HE Changsong
2026, Vol.38(3): 24–37
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Hydrocarbon accumulation conditions and exploration implication of Archean metamorphic buried hill reservoirs in Binxian uplift, Dongying Sag, Bohai Bay Basin
HUO Aimin
2026, Vol.38(3): 38–53
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Characteristics and lower limit of movable pore throat of shale reservoir of the lower Es3 submember of Paleogene in Bonan subsag, Bohai Bay Basin
JIANG Long, CHENG Ziyan, SUN Hongxia, LIU Zupeng, LI Zhongxin, TIAN Xuanhua, PENG Linxiong, ZHU Li
2026, Vol.38(3): 54–66
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Reservoir development characteristics and main controlling factors of the second member of Lower Triassic Jialingjiang Formation in Puguang area, Sichuan Basin
ZHOU Kai, QI Renli, XU Wenli, YIN Qing, GAO Lu, LI Shuangshuang, HUANG Qinyang, QUAN Hao
2026, Vol.38(3): 67–78
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Shale reservoir characteristics and hydrocarbon accumulation conditions of Cambrian Qiongzhusi Formation in southwestern Sichuan Basin
ZHENG Majia, LIU Yong, WU Ya, CHEN Junyu, CHEN Ying, ZHONG Ziyue, ZHAN Lin, FAN Cunhui
2026, Vol.38(3): 79–93
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Intelligent logging identification method for shale lithofacies of Silurian Longmaxi Formation in Hechuan area, central Sichuan Basin
LIU Ruotong, ZHANG Dazhi, SUI Liwei, XIAO Limei, TIAN Ya, SUN Shan, PENG Dandan, LI Jianzhi
2026, Vol.38(3): 94–106
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Reservoir characteristics and main controlling factors of Upper Triassic Xujiahe Formation in Shuangyushi area, northwestern Sichuan Basin
XU Zhongfan, DING Xiong, YIN Hong, TIAN Yunying, SONG Yi, YANG Xiran
2026, Vol.38(3): 107–119
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Geochemical characteristics and enrichment rule of natural gas in Ordovician of Weiyuan area, Sichuan Basin
GOU Zhepei, WEI Qianqian, YAN Xueqi, LONG Hui, LU Jiaxun, GAO Xuanbo, TANG Yinhai, TAN Xianfeng
2026, Vol.38(3): 120–131
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GPU-accelerated source scanning algorithm for real-time 3D microseismic monitoring and its application
CAO Libin, ZHENG Majia, CHEN Qian, WU Ya, CHENG Limin
2026, Vol.38(3): 132–140
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Structural framework and hydrocarbon accumulation models of Zhongjiannan Basin in the western edge of the South China Sea
YANG Jinhai, YU Yixin, OUYANG Jie, XU Maguang, JIN Feng, ZHANG Yuhang, YU Lang
2026, Vol.38(3): 141–148
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Distribution characteristics and controlling factors of helium in Yanchang exploration area of Ordos Basin
BAI Yiyuan, GONG Hujun, WANG Dongxu, LI Yuan, LUO Fenhong, WANG Junjun
2026, Vol.38(3): 149–161
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Characteristics, enrichment conditions and exploration implications of helium-rich gas reservoirs in Chu-Sarysu Basin, Kazakhstan
NIE Minglong, LIU Haoyuan, WANG Zhaoming, ZHAO Shumao, YU Taiji
2026, Vol.38(3): 162–172
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Pressure dynamic characteristics of CO2 flooding in dual porosity media reservoirs
CAO Xiutai, ZHONG Huiying, SUN Yuxin, ZHOU Hongliang, FU Jing
2026, Vol.38(3): 173–181
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Simulation experiment on phase behavior variation in multi-cycle injection and production of oil-ring type condensate gas reservoirs
ZHANG Xiaoyan, LIU Sihong, CAO Qingbin, LEI Tian, WANG Yue, TANG Lei, XIE Yuxin, YAN Jian
2026, Vol.38(3): 182–189
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Four-dimensional in-situ stress evolution and optimization method for refracturing timing in shale oil reservoir horizontal wells： A case study of Triassic Chang 7 member in Qingcheng Oilfield, Ordos Basin
REN Jiawei, LI Li, WANG Deyu, BAI Xiaohu, KANG Bo, BAI Yuen, BAI Jianwen, CHEN Junbin
2026, Vol.38(3): 190–200
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Development characteristics and hydrocarbon exploration potential of Ordovician dome structures in northern Tarim Basin
YUN Lu, CAO Zicheng, LI Haiying, GENG Feng, LIU Yongli, WEI Huadong, HUANG Cheng, ZHANG Di
2026, Vol.38(3): 1–11
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doi: https://doi.org/10.12108/yxyqc.20260301
Ordovician carbonate strata of Shunbei-Tahe area of Tarim Basin widely develop dome structures， several wells have obtained high-yield industrial oil and gas flows， which shows good resource potential. Based on data of high-precision 3D seismic， well logging， and core testing analysis， taking 150 dome structures from the periphery of well H1 and the southeastern slope zone of Akekule uplift in Shunbei area as examples， the geometric characteristics， genesis mechanisms， and reservoir features of dome structures were systematically analyzed. The results show that：（1） Ordovician dome structures in northern Tarim Basin are concentric-ring-shaped in plan view， which can be classified into four types：R-type， T-type， contraction-type， and composite-type. In cross-section， they exhibit a torch-like shape of “narrow at the bottom and wide at the top”. （2） The main body of dome structures formed during Middle Caledonian episode Ⅰ-Ⅱ， as a result of the combined effects of regional shear stress field and lithological differences, and is a genesis mechanism of “shear stress induction-interlayer slip-local uplift”. （3） The dome structure reservoir is a “fracture-cavity and pore-cavity” composite reservoir system， cha-racterized by the advantages of “faults connecting to the source， vertical migration and accumulation, surrounding rock sealing， and independent hydrocarbon accumulation”， with large resource scale. It is a significant new frontier for deep to ultra deep petroleum exploration.
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Research progress of velocity modeling and imaging techniques using vertical seismic profile (VSP)
SU Qin, FENG Gang, LI Yanpeng, YANG Zhe, LIU Wenqing
2026, Vol.38(3): 12–23
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doi: https://doi.org/10.12108/yxyqc.20260302
Vertical seismic profile (VSP) technology leverages the advantages of downhole observation to provide critical velocity constraints and high-resolution data for imaging complex geological structures. Based on a comprehensive literature review, the technological evolution of core components in VSP, current research focuses, and future development directions were summarized. The results show that: (1) Velocity modeling methods have advanced from first-arrival/reflected-wave ray-based tomography to full waveform inversion (FWI), significantly improving the accuracy of parameter inversion around the borehole. However, these methods remain constrained by acquisition fold and initial model accuracy, and still face challenges such as non-uniqueness. Migration imaging techniques have evolved from stacking mapping, ray-based migration methods, to wave-equation-based migration algorithms, overcoming the limitations of simplified medium and enabling accurate imaging of steeply dipping complex structures,still facing challenges such as computational efficiency, noise suppression, and insufficient utilization of the full wavefield. (2) Current research focuses on enhancing amplitude fidelity through least-squares reverse time migration (LSRTM), expanding illumination via full-wavefield collaborative imaging, and promoting deep integration of FWI and LSRTM to achieve unified velocity modeling and seismic imaging. (3) Future progress will rely on the synergistic development of novel sensing technologies, intelligent algorithms and increased computational power. By advancing integrated borehole-surface seismic surveys, high-precision velocity models will be constructed to support detailed reservoir characterization, dynamic monitoring, and the exploration of deep oil and gas resources.
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Stratigraphic division of Permian and its exploration significance of Bogda piedmont, northern margin of Tuha Basin
CHEN Xuan, HAO Bin, GOU Hongguang, ZHANG Jing, XU Xiongfei, YANG Zhanlong, HU Jun, HE Changsong
2026, Vol.38(3): 24–37
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doi: https://doi.org/10.12108/yxyqc.20260303
Through comprehensive analysis of palynological assemblages, zircon U-Pb ages, and sedimentary sequences from Permian outcrops in Bogda piedmont on the northern margin of Tuha Basin, the stratigraphic attribution was re-evaluated, the lithofacies paleogeography during the deposition of Lucaogou Formation/Ta’erlang Formation around Bogda mountains was reconstructed, and the exploration potential of the area was discussed. The results show that: （1） The palynological assemblages originally assigned to Ta’erlang Formation in Zhaobishan and Ertanggou sections are significantly different from those of Ta’erlang Formation/Lucaogou Formation in Ta’erlanggou and eastern Junggar Basin, but consistent with those of Wutonggou Formation in eastern Junggar Basin, and thus should be revised as Wutonggou Formation. The regional dark strata originally placed at the top of Yierxitu Formation whose sedimentary sequence and volcanic rock ages can be compared with those of Lucaogou Formation around Bogda mountains, and should be classified as Ta’erlang Formation. Zircon ages indicate Early Permian, earlier than the previously considered Middle Permian. （2） During the deposition of Ta’erlang Formation, Bogda mountains served as the depositional center, and the piedmont zone was in the environment of saline semi-deep-lake to deep-lake facies to half saline semi-deep lake,with the potential to form high-quality source rocks. （3） Permian source rocks in Taibei Sag are of relatively good quality, especially those in the northern part of the sag. The northern piedmont zone lies above the hydrocarbon generation center and contains numerous untested structural traps. The wedge-shaped structures and piedmont deep layer are the prospective areas for new breakthroughs of the mature Permian petroleum system in Tuha Basin.
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Hydrocarbon accumulation conditions and exploration implication of Archean metamorphic buried hill reservoirs in Binxian uplift, Dongying Sag, Bohai Bay Basin
HUO Aimin
2026, Vol.38(3): 38–53
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doi: https://doi.org/10.12108/yxyqc.20260304
By comprehensively utilizing technologies such as core observation, physical property testing, conventional logging, and imaging logging, reservoir formation conditions and hydrocarbon accumulation models of the buried hill in Binxian uplift of Dongying Sag in Bohai Bay Basin were systematically analyzed. Research results show that: （1） Archean reservoir types of Binxian uplift in Dongying Sag are fractured reservoirs and weathered crust reservoirs,with the weathered crust exhibiting a double-layer structure of dissolution layer and disintegration layer. Dissolution layers are mostly distributed in the lower part of the slope, making them optimal reservoirs. （2） The buried hill oil source of the study area comes from the third member of Shahejie Formation（Es3） and the fourth member of Shahejie Formation （Es4） source rocks in Lijin sub-depression, which has undergone two stages of hydrocarbon generation. The reservoir is dominated by weathered crust dissolution layers, with high-conductivity fractures and dissolution fractures as main reservoir spaces. Caprocks are thick dark mudstones of Es3 and Es4,with good sealing capacity. Migration pathways include two types: vertical migration along faults and lateral migration along unconformity surfaces. （3） The source-reservoir configuration relationship of buried hills in the study area has significant impacts on the reservoir formation. Paleogeomorphology and fracture density have controlling effects on reservoir quality. Faults and fractures are main migration channels for oil and gas. There are two types of oil and gas reservoirs,including “new source and old reservoir-lateral pinch out” type and “new source and old reservoir-buried hill top” type. The former is distributed in the central slope zone, where hydrocarbons migrate laterally from source rocks into buried hill reservoirs in contact with mudstones. The latter is distributed near large faults in the eastern slope zone, where oil and gas migrate vertically along faults to the top of the buried hill. （4） Compared with Shulu buried hill in Jizhong Depression, the study area exhibit an obvious double-layer structure of weathered crust, with lateral pinch out accumulation model as the dominant model and hydrocarbon properties being unitary. Five favorable zones are identified, among which Zone Ⅱ and Zone Ⅲ located in the central slope zone of the buried hill have optimal reservoir formation conditions and represent the most favorable exploration targets.
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Characteristics and lower limit of movable pore throat of shale reservoir of the lower Es3 submember of Paleogene in Bonan subsag, Bohai Bay Basin
JIANG Long, CHENG Ziyan, SUN Hongxia, LIU Zupeng, LI Zhongxin, TIAN Xuanhua, PENG Linxiong, ZHU Li
2026, Vol.38(3): 54–66
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doi: https://doi.org/10.12108/yxyqc.20260305
There are abundant shale oil and gas resources in the lower third member of Shahejie Formation （Es3） in Paleogene of Bonan subsag of Bohai Bay Basin. By various testing methods such as core observation, casting thin section identification, scanning electron microscopy, X-ray diffraction analysis, high pressure mercury injection, nuclear magnetic resonance and elastic depressurization mining simulation, petrological characteristics and microscopic pore structure characteristics of shale reservoirs in the study area were clarified, and the lower limit of movable pore throat under ideal conditions and elastic depressurization mining conditions was determined. The results show that: （1） Shale sedimentary structures of the lower Es3 in Bonan subsag are mainly laminated, layered-laminated, layered and weakly laminated, accounting for 22.12%, 19.67%, 52.80% and 5.38%, respectively. Dominant lithofacies are laminated cryptocrystalline argillaceous limestone, layered cryptocrystalline argillaceous limestone and laminated cryptocrystalline calcareous mudstone, accounting for 33.30%, 13.20% and 17.70%, respectively. The mineral composition is mainly composed of 4 types: carbonate minerals, felsic minerals, clay minerals, and pyrite, with carbonate minerals as the main component and with the volume fraction of nearly 50%. （2） Pore types of shale matrix are mainly intergranular pores and intercrystallite pores. Overall physical properties of the reservoir are poor, dominant lithofacies have an average porosity of 3.50%-4.00% and permeability mainly ranging from 0.010 mD to 0.100 mD. Differences of average porosity and permeability among different dominant lithofacies are relatively small. Pore throat connectivity and fluid availability of laminated cryptocrystalline argillaceous mudstone reservoirs are better. （3） Lower limits of movable pore throat for three dominant lithofacies in the study area are as follows: layered cryptocrystalline argillaceous limestone > laminated cryptocrystalline argillaceous limestone > laminated cryptocrystalline calcareous mudstone. Under ideal conditions, the lower limit of movable pore throat of shale reservoir is less than 10.00 nm. Under the condition of elastic depressurization mining, the lower limit of movable pore throat in shale reservoir can be increased by nearly one order of magnitude. Among them, the lower limit of movable pore throat in layered cryptocrystalline argillaceous limestone can reach 35.52 nm.
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Reservoir development characteristics and main controlling factors of the second member of Lower Triassic Jialingjiang Formation in Puguang area, Sichuan Basin
ZHOU Kai, QI Renli, XU Wenli, YIN Qing, GAO Lu, LI Shuangshuang, HUANG Qinyang, QUAN Hao
2026, Vol.38(3): 67–78
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doi: https://doi.org/10.12108/yxyqc.20260306
Comprehensively utilizing data from core observation, thin section identification, logging interpretation, physical property analysis, and geochemical testing, reservoir characteristics and main controlling factors of carbonate reservoirs in the second member of Lower Triassic Jialingjiang Formation in Puguang area of Sichuan Basin were systematically analyzed. The coupling mechanism between tidal flat deposition controlled by paleogeomorphology and multi-stage diagenetic modifications was clarified, an evolution model for high-quality reservoirs was established, and favorable exploration areas were predicted. The results show that: （1） In Puguang area, reservoir rocks of the second member of Lower Triassic Jialingjiang Formation are dominated by granular dolomite and silt-sized crystalline dolomite, reservoir spaces mainly include intergranular dissolved pores, intercrystalline dissolved pores, and fractures. Reservoirs are generally of low porosity and low permeability, with local occurrences of high porosity and high permeability or low porosity and high permeability. （2） In the study area, compaction and cementation lead to the reduction of primary pores, while dolomitization forms intercrystalline pores and enhances compaction resistance. The seepage-reflux model and evaporation-pumping model represent formation mechanisms of the silt-sized crystalline dolomite and micritic dolomite, respectively. Penecontemporaneous meteoric freshwater dissolution superimposed with burial-stage organic acid dissolution significantly improves the pore structure, and the high-angle fracture network formed by tectonic fracturing enhances reservoir porosity and permeability. （3） Reservoir development of the second member of Jialingjiang Formation in the study area is dually controlled by sedimentary microfacies and diagenesis. Relatively high-quality reservoirs are mainly formed in granular shoal and dolomitic flat microfacies. Dolomitization and dissolution are key factors to the development of high-quality reservoirs, and fracturing improves reservoir connectivity. （4） Class I favorable exploration areas of the second member of Jialingjiang Formation in the study area are mainly distributed in Shuangmiaochang area, which are subfacies of intra platform shoals. There are 5 favorable exploration areas of Class Ⅱ, which develop intra platform beach facies, and distribute in Shuangmiao-chang, Qingxichang, Maoba, and Fenshuiling areas. There are 3 favorable exploration areas of Class Ⅲ, with the development of dolomitic flat, gray flat microfacies or intra platform beach subfacies, which distribute in Chuanfu 85 well area, Ming Ⅰ well area, and Leiyinpu area.
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Shale reservoir characteristics and hydrocarbon accumulation conditions of Cambrian Qiongzhusi Formation in southwestern Sichuan Basin
ZHENG Majia, LIU Yong, WU Ya, CHEN Junyu, CHEN Ying, ZHONG Ziyue, ZHAN Lin, FAN Cunhui
2026, Vol.38(3): 79–93
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doi: https://doi.org/10.12108/yxyqc.20260307
The shale gas of Cambrian Qiongzhusi Formation in southwestern Sichuan Basin exhibits significant exploration potential. Based on well logging, master logging and seismic data, combined with experimental methods such as thin-section observation, physical property testing, and scanning electron microscopy, a comprehensive analysis was conducted on its reservoir characteristics and hydrocarbon accumulation conditions. The results show that: （1） The shale of Qiongzhusi Formation in southwestern Sichuan Basin can be classified into black organic-rich shale and gray silty shale. Pores are dominated by inorganic pores (macropores), supplemented by organic pores. Fractures are mainly high-angle shear fractures and tensile fractures filled with calcite and bitumen, along with developed bedding micro-fractures and minor intergranular fractures. The brittle mineral content in the reservoir is high, with mass fraction ranging from 62.9% to 86.5%, averaging 72.0%. The reservoir quality within the rift trough is superior to that outside the trough. （2） The paleotectonic sedimentary framework of“rift trough and paleouplift” in the study area controls the macroscopic distribution of the reservoir. High-quality reservoirs developed in the deep-water shelf facies within the rift trough. Shale with high TOC content and Type-I kerogen in the trough provide gas sources for shale gas reservoirs. High porosity and high brittleness are conducive to gas storage and reservoir transformation. Fracture networks serve as key seepage pathways for gas migration and enrichment. （3） Favorable exploration targets for shale gas in Qiongzhusi Formation of the study area are overlaped zones of trough and uplift (Class I), with large reservoir thickness, high abundance and thermal evolution degree organic matter, relatively good physical properties, and high gas abundance. Followed by areas within the trough outside the overlaped zone (Class Ⅱ), and areas over the paleo-uplift outside the overlaped zone (Class Ⅲ).
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Intelligent logging identification method for shale lithofacies of Silurian Longmaxi Formation in Hechuan area, central Sichuan Basin
LIU Ruotong, ZHANG Dazhi, SUI Liwei, XIAO Limei, TIAN Ya, SUN Shan, PENG Dandan, LI Jianzhi
2026, Vol.38(3): 94–106
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doi: https://doi.org/10.12108/yxyqc.20260308
Silurian Longmaxi Formation shale in Hechuan area of central Sichuan Basin is widely distributed, with good quality source rock, which makes it a key target for shale gas exploration. Based on core experiment analysis and logging data, lithofacies were classified and logging intelligently was identified through mineral composition and TOC content. Lithofacies types and spatial distribution characteristics of Longmaxi Formation were clarified, and favorable lithofacies zones were delineated. The results show that: (1) Longmaxi Formation of Hechuan area in central Sichuan Basin has developed seven types of shale lithofacies, primarily dominated by organic-rich and organic-poor felsic shale lithofacies, organic-rich and organic-poor argillaceous-felsic mixed shale lithofacies, and organic-poor argillaceous shale lithofacies, with minor development of organic-rich mixed shale lithofacies and organic-rich calcareous-felsic mixed shale lithofacies. Among them, the organic-rich felsic shale lithofacies, organic-rich mixed shale lithofacies, and organic-rich calcareous-felsic mixed shale lithofacies are favorable targets for exploration. (2) The intelligent logging identification method involves introducing BSMOTE algorithm to balance minority lithofacies samples, constructing an ensemble learning model to achieve primary classification of mineral composition, and using a Principal Component Analysis-based Support Vector Regression (PCA-SVR) model to predict TOC content for secondary classification. BSMOTE-AdaBoost model was identified as the optimal model for primary lithofacies classification, while PCA-SVR model demonstrated high accuracy in secondary classification. Blind well verification confirmed an overall lithofacies identification accuracy of 86.7%, indicating strong regional applicability. (3) Shale lithofacies distribution of Longmaxi Formation in Hechuan area is controlled by paleo-water depth and provenance supply. Vertically, the lithofacies exhibit an evolutionary trend from organic-rich felsic shale facies to organic-poor mixed shale facies from the bottom towards the top. On the plane, favorable lithofacies migrate from NW to SE. The continuous distribution zone of organic-rich felsic facies in Long 11¹ sublayer represents the key target for exploration.
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Reservoir characteristics and main controlling factors of Upper Triassic Xujiahe Formation in Shuangyushi area, northwestern Sichuan Basin
XU Zhongfan, DING Xiong, YIN Hong, TIAN Yunying, SONG Yi, YANG Xiran
2026, Vol.38(3): 107–119
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doi: https://doi.org/10.12108/yxyqc.20260309
Based on data，such as logging, core, thin section, scanning electron microscopy, and mercury injection, sedimentary facies, reservoir characteristics, and main controlling factors of Upper Triassic Xujiahe Formation in Shuangyushi area of northwestern Sichuan Basin were analyzed, favorable exploration areas were further delineated. The results show that: （1） Sedimentary characteristics of Triassic Xujiahe Formation in Shuang-yushi area of northwestern Sichuan Basin are generally characterized by an evolution from a marine continental transitional facies (shoreline-shallow sea) to a terrestrial delta-alluvial fan system. Sandstone reservoirs are dominated by light-gray fine to medium grained feldspar lithic sandstone and lithic feldspar sandstone. And the storage space is mainly intergranular/intragranular dissolved pores, with an average porosity of 5.13% and an average permeability of 0.420 mD. Overall, it belongs to a medium low porosity and low-permeability reservoir. The conglomerate are mainly brownish gray carbonate conglomerate, with underdeveloped pores and a small number of fractures. （2） Sedimentary facies is one of the main controlling factors of reservoirs, forming the initial porosity of rocks. Relatively high-quality reservoirs are mainly distributed in high-energy microfacies, such as distributary channels in fan delta front, mouth bars, and nearshore-foreshore, while conglomerate reservoirs are mainly distributed in high-energy channel sedimentary microfacies near provenance. Compaction and cementation reduce reservoir space, while dissolution contributes to reservoir improvement. （3） Relatively high-quality sandstone reservoirs are mainly concentrated in delta front-plain channel sand bodies in the second member of Xujiahe Formation. Local beach bars/nearshore sand bodies in the first member of Xujiahe Formation, and local front sand bodies in the third member of Xujiahe Formation are with good quality.
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Geochemical characteristics and enrichment rule of natural gas in Ordovician of Weiyuan area, Sichuan Basin
GOU Zhepei, WEI Qianqian, YAN Xueqi, LONG Hui, LU Jiaxun, GAO Xuanbo, TANG Yinhai, TAN Xianfeng
2026, Vol.38(3): 120–131
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doi: https://doi.org/10.12108/yxyqc.20260310
In recent years, natural gas resources have been successively discovered in marine carbonate rocks of Ordovician Honghuayuan Formation (O1h) and Baota Formation (O2b) in Weiyuan area of Sichuan Basin, which shows favorable exploration potential. Based on integrated analyses of composition and carbon isotopes of natural gas, source rock features, fluid inclusion characteristics and burial-thermal evolution, the origin of natural gas and hydrocarbon charging episodes in the study area were determined, and hydrocarbon accumulation models along with its controlling factors for Ordovician natural gas were explored. The results show that： （1） Ordovician O1h and O2b natural gases in Weiyuan area exhibit high dryness coefficient, with an average value of 0.995 8，and belong to over-mature oil-type gas, they are mixed gases derived from both kerogen cracking and crude oil cracking, formed at different stages but from the same source. The carbon isotope reversal in the natural gas primarily results from thermochemical sulfate reduction (TSR) and over-mature background. Hydrocarbon source rocks of Є1q serve as the main hydrocarbon supply layers for the natural gas in O1h and O2b. Є1q source rocks have medium-good quality, with an average total organic carbon (TOC) of 1.90% and a mean hydrocarbon generation potential (S1 + S2) of 0.27 mg/g. The organic matter type is Type I, indicating over-maturity, with Ro of 2.74%-3.28% and Tmax of 397-499 ℃. （2） In the study area, O1h and O2b formed paleo-oil reservoirs and paleo-gas reservoirs during Late Permian and Early Cretaceous, respectively. After the Himalayan orogeny, gas reservoirs underwent structural adjustment, forming structural-stratigraphic-lithological composite reservoirs controlled by large-scale anticline and strike-slip fault system. Reservoir rocks developed in upper O1h and O2b predominantly composed of dolomite, while the lower Є1q supplied hydrocarbons, forming a hydrocarbon accumulation model of “lower-generation and upper-storage”. （3） Hydrocarbon accumulations of Ordovician O1h and O2b are mainly controlled by the quality of dolomite reservoirs, and the migration capacity of strike-slips and reverse faults. The “sweet spots” for natural gas enrichment are overlapping zones of high parts of anticlinal traps and the faults along the aulacogen margin.
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GPU-accelerated source scanning algorithm for real-time 3D microseismic monitoring and its application
CAO Libin, ZHENG Majia, CHEN Qian, WU Ya, CHENG Limin
2026, Vol.38(3): 132–140
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doi: https://doi.org/10.12108/yxyqc.20260311
Microseismic monitoring technology faces challenges, such as difficulty in weak signal identification, low real-time processing efficiency, and weak microseismic response to fractures in shale gas fracturing ope-rations. To address these issues, a high-precision microseismic event identification method was proposed based on source scanning algorithm (SSA), incorporating a multi-level collapse grid search approach. Real-time loca-lization was achieved using GPU parallel computing technology. The results show that:（1）Through the wavefield energy scanning and superposition mechanism, dynamic correction and coherent superposition are performed on virtual sources to enhance characteristics of weak P-wave signals. Combined with the multi-level collapsing grid search strategy of “coarse grid global scanning + fine grid local precise searching”, the positioning efficiency and accuracy are improved simultaneously. After introducing the GPU-parallelized narrow band fast marching method (FMM), the traveltime calculation efficiency is increased by about 16 times. （2） Numerical experiments show that under low signal-to-noise ratio conditions, the positioning result of the multi-level collapse grid search is close to the real source, and its accuracy is superior to that of the single coarse grid search. In the application of a drilling platform, event points obtained by this method and the conventional method show a northeastward zonal distribution, the event depth can extend up to 300-400 m, the hydraulic fracture event points are more concentrated around the wellbore, and more weak energy events can be identified. （3） In the monitoring of shale gas fracturing construction in Sichuan, characteristics of hydraulic fractures and induced natural fractures can be distinguished from multiple dimensions. Spatially, the former gathers near the wellbore of the current fracturing section with regular morphology, while the latter is far from the fracturing section with irregular and asymmetric distribution. Temporally, events of the former are concentrated during the fracturing construction period, while the latter has significant aftereffect and continues to occur within 30 minutes after pump shutdown. In terms of waveform, the former has high dominant frequency, clear direct wave and simple structure, while the latter has low dominant frequency, long energy duration and multiple subsequent waves. In terms of relative magnitude, the former is generally low, while the latter is high, corresponding to a larger fracture scale. Combined with the relative magnitude and spatial distribution characteristics of events, distribution models of “natural fracture response zone” and “fracturing main control zone” can be constructed, providing a reliable basis for fracturing effect evaluation and geological interpretation.
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Structural framework and hydrocarbon accumulation models of Zhongjiannan Basin in the western edge of the South China Sea
YANG Jinhai, YU Yixin, OUYANG Jie, XU Maguang, JIN Feng, ZHANG Yuhang, YU Lang
2026, Vol.38(3): 141–148
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doi: https://doi.org/10.12108/yxyqc.20260312
The low exploration level of Zhongjiannan Basin in the western edge of the South China Sea has constrained the progress of hydrocarbon exploration. By integrating 2D seismic data and exploration achivement from different periods in Zhongjiannan Basin, stratigraphic development characteristics and structural patterns of Miocene to Eocene were systematically analyzed, and geological conditions and hydrocarbon accumulation mo-dels were explored. The results show that： （1） Five major regional unconformities, such as the bottom boundary of Eocene, the bottom boundary of Miocene Sanya Foumation, Rizhao Formation bottom boundary, Chongyun Formation bottom boundary, and the bottom boundary of Pliocene Zhongjian Formation, are developed in Zhongjiannan Basin. Extensional and strike-slip faults are mainly distributed in the near SN, NE, and NW directions. And the near SN and NE-trending faults control the pattern of uplifts and depressions in the basin. Upon that, Zhongjiannan Basin can be divided into six first-order structural units of “three depressions, two uplifts, and one slope”. （2） There are three main sets of hydrocarbon source rocks developed in Zhongjiannan Basin, including middle Eocene lacustrine source rocks, Upper Eocene-Oligocene lacustrine and marine-terrestrial source rocks, and Lower-Middle Miocene marine source rocks. Hydrocarbon migrate laterally along structural ridges and large-scale unconformities, and transport vertically along major oil-source faults. Structures, strata, and lithology under the regional mudstone cover of Upper Neogene and Quaternary are favorable places for hydrocarbon enrichment and accumulation. The structural and stratigraphic traps of the western slope, northern uplift, and southern uplift, lithological trap groups of the northern and central depressions, as well as reef reservoirs developed in the high parts of local structures of the western slope and central uplift, all have certain exploration potential.
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Distribution characteristics and controlling factors of helium in Yanchang exploration area of Ordos Basin
BAI Yiyuan, GONG Hujun, WANG Dongxu, LI Yuan, LUO Fenhong, WANG Junjun
2026, Vol.38(3): 149–161
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doi: https://doi.org/10.12108/yxyqc.20260313
Based on the testing and analyses on helium volume fraction, isotopic composition, and mass fractions of uranium (U) and thorium (Th) in source rocks of 91 natural gas samples from drilling wells and 68 helium source rock samples from Yanchang exploration area of Ordos Basin, the distribution and origin of helium, helium-supplying potential of various helium source rock types were clarified, main controlling factors for helium enrichment were systematically discussed. The results show that: （1） The volume fraction of helium of Yanchang exploration area of Ordos Basin ranges from 0.009% to 0.217%, with an average of 0.059%. Among them, 6.5% of samples meet the high-helium standard (≥ 0.1%). On the plane, the helium abundance shows a pattern of “high in the south and low in the north”, with Luochuan and Fuxian being high-helium areas, and Zizhou, Jingbian being helium-poor areas. Vertically, the helium content shows little variation across different strata, indicating stable distribution. （2） The helium in the study area is a typical crust-derived helium, with helium isotope R/Ra values all less than 0.1, and the crustal contribution proportion reaching 99.73%. Multiple sets of helium source rocks, including Precambrian crystalline basement, Changcheng system, and Upper Paleozoic, are developed in the area. The helium generation of Precambrian basement and Changcheng system far exceeds that of Upper Paleozoic, with basement helium generation of 3 164.04×108 m3, accounting for 95.99% of the total helium generation. （3） Regarding main controlling factors for enrichment, Precambrian and Changcheng system in the study area serve as main helium sources, with Upper Paleozoic helium source rocks as back-up. Facilitated by deep and large faults in the basin, a dual-source helium supply model of “dominant deep sources and auxiliary Upper Paleozoic sources” has been formed. Deep and large faults are the key pathways connecting deep helium sources, while the strong dilution effect on helium production caused by the hydrocarbon generation of Upper Paleozoic source rocks is the core factor leading to the differential accumulation of helium between the south and the north.
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Characteristics, enrichment conditions and exploration implications of helium-rich gas reservoirs in Chu-Sarysu Basin, Kazakhstan
NIE Minglong, LIU Haoyuan, WANG Zhaoming, ZHAO Shumao, YU Taiji
2026, Vol.38(3): 162–172
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doi: https://doi.org/10.12108/yxyqc.20260314
Chu-Sarysu Basin in Kazakhstan is a helium-rich basin. Through the geological characteristic analysis of helium-rich gas reservoirs in different tectonic units and different horizons of the basin, helium enrichment conditions of the basin was discussed, a helium enrichment model jointly controlled by helium sources and caprocks was established, revealing the direction of helium exploration in China. The results show that: （1） Helium has been found in all 5 sets of reservoir-cap combinations in different depressions of Chu-Sarysu Basin, showing the characteristic of helium enrichment throughout the basin. Helium enrichment is positively correlated with nitrogen and has no direct relationship with tectonic units or gas reservoir types, but shows differential enrichment among different horizons. The reservoir-cap combination composed of Lower Carboniferous Serpukhovian limestone-mudstone has the lowest helium content but the highest hydrocarbon gas content. While Permian subsalt sandstones have the highest helium content, with a volume fraction up to 0.68%, and low hydrocarbon gas content. （2） The Precambrian ancient uranium-rich bedrock, tectonic uplift since Triassic, poor source rocks, and multiple sets of caprocks development in the study area are basic conditions for helium enrichment in the basin. Helium coexists with sandstone type uranium deposits, and the development of sandstone type uranium deposits has an indicative effect on helium enrichment. Multiple sets of caprocks, such as salt rocks, gypsum rocks, and mudstones, combined with the small molecular size and strong diffusion capacity of helium, are important reasons for the formation of multi-layered helium enrichment. Meanwhile, the dilution of helium by hydrocarbon carrier gas is also an important factor causing differential helium enrichment in different horizons. （3） The basement and tectonic evolution of Junggar Basin in China are similar to those of Chu-Sarysu Basin. Carboniferous in eastern Junggar, Lunan, Shinan, and Santanghu basins represent promising targets for future helium exploration.
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Pressure dynamic characteristics of CO2 flooding in dual porosity media reservoirs
CAO Xiutai, ZHONG Huiying, SUN Yuxin, ZHOU Hongliang, FU Jing
2026, Vol.38(3): 173–181
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doi: https://doi.org/10.12108/yxyqc.20260315
Shale oil reservoirs subjected to complex hydraulic fracturing are prone to evolve into dual porosity media. Due to differences in matrix-fracture seepage behavior and the areal heterogeneity of “concentration-viscosity” after CO2 injection, the pressure-response mechanism of CO2 flooding becomes highly complex, resulting in insufficient accuracy in pressure-transient characterization and parameter inversion. Fick’s law was employed to investigate the CO2 distribution characteristics. A dual porosity flow model was established by simultaneously accounting for concentration-viscosity-pressure coupling and the matrix threshold pressure gradient. The governing flow equations are solved numerically to generate pressure-transient curves for CO2 flooding in dual porosity reservoirs, and effects of the matrix threshold pressure gradient, elastic storativity ratio, interporosity-flow coefficient, injection rate, and diffusion coefficient on the pressure-transient behavior were analyzed. The results show that: (1) A larger matrix threshold pressure gradient leads to a more pronounced late-time upturn of both pressure and pressure-derivative curves on the well testing curve. （2） A smaller elastic storativity ratio produces a wider and deeper “trough” in the pressure-derivative curve during the interporosity-flow stage. （3） With decreasing interporosity-flow coefficient, matrix-to-fracture crossflow slows down,the “trough” in the pressure-derivative curve moves to the right and becomes deeper. A larger interporosity-flow coefficient makes the late-time upturn in the pressure curve more evident. （4） A higher injection rate increases both pressure and pressure-derivative levels over the entire testing period and narrows the “trough” during the interporosity-flow stage. （5） The diffusion coefficient mainly influences the radial-flow stage of the composite system in the late stage: a larger diffusion coefficient causes this stage to occur earlier, reduces flow resistance, and shifts the pressure and pressure-derivative curves downward. （6） The proposed model enables quantitative characterization of pressure-transient features during CO2 injection in fractured wells of Daqing Oilfield.
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Simulation experiment on phase behavior variation in multi-cycle injection and production of oil-ring type condensate gas reservoirs
ZHANG Xiaoyan, LIU Sihong, CAO Qingbin, LEI Tian, WANG Yue, TANG Lei, XIE Yuxin, YAN Jian
2026, Vol.38(3): 182–189
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doi: https://doi.org/10.12108/yxyqc.20260316
Based on the principle of conventional PVT phase behavior testing, a high-temperature and high-pressure formation fluid phase behavior apparatus was used to simulate the oil-ring type condensate gas reservoir. Take multiple samples from the top condensate gas and the bottom oil-ring by conducting constant-volume depletion experiments and multi-cycle injection and production experiments, and analyses were carried out on their phase behavior changes during depletion and multi-cycle injection and production process, as well as their impact on recovery rate. The results show that: （1） After natural depletion of the oil-ring type condensate gas reservoir, the oil-ring saturation increased from 3.4% to 13.2%. The presence of the oil-ring results in more condensate oil remaining in the reservoir, and the condensate oil recovery rate under natural depletion is only 24.3%. (2) After 5 cycles injection and production, the recovery rate of condensate oil increased by 25.3%, and the saturation of the bottom oil-ring decreased from 13.2% to 2.9%. The first 2 cycles of injection and production showed significant effects, and the injected gas could effectively extract and vaporize the bottom oil-ring into gas phase, mainly extracting the intermediate hydrocarbons of C3-C10 in the oil-ring. （3） With the number of injection and production cycles increases, the composition of the top condensate gas and the injected gas tends to be consistent, and their phase diagrams continuously shrink to the lower left, resulting in an increasing difference from the oil-ring composition. That weakens the evaporation effect of the injected gas on the oil-ring, and the ability of the oil-ring to dissolve gas gradually decreases.
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Four-dimensional in-situ stress evolution and optimization method for refracturing timing in shale oil reservoir horizontal wells： A case study of Triassic Chang 7 member in Qingcheng Oilfield, Ordos Basin
REN Jiawei, LI Li, WANG Deyu, BAI Xiaohu, KANG Bo, BAI Yuen, BAI Jianwen, CHEN Junbin
2026, Vol.38(3): 190–200
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doi: https://doi.org/10.12108/yxyqc.20260317
Based on the concept of geology-engineering integration, a multi-physics field coupled model of fracture network-seepage-stress applicable to the entire development cycle of shale oil old wells in Qingcheng Oilfield of Ordos Basin was established. Multi-field coupled numerical simulations of refracturing in shale oil horizontal wells were conducted, and a stress recovery index along with an optimization method for refracturing timing was proposed. The results show that: （1） By establishing a seepage model, stress model, and their data interface program, the multi-physics field coupled model of fracture network-seepage-stress was solved by using cross coupling iterative algorithm, with history-matching accuracy of 93%, verifying the accuracy of the model and effectively applying it to the development and production of shale oil reservoirs in Qingcheng Oilfield, Ordos Basin. （2） After six years of production in the target well of Qingcheng Oilfield, the reservoir pressure near hydraulic fractures decreased by 1 MPa, while the maximum and minimum horizontal principal stresses declined by 2.6 MPa and 4.2 MPa, respectively, and the maximum principal stress direction rotated by 84°. Following pre-fracturing energy supplement of 10 000 m³, the maximum principal stress deflection angle decreased from 84° to 20°, resulting in a significant increase in the length and volume of refracturing-induced fractures, and that further proves the importance of implementing pre-fracturing energy supplement. （3） The stress recovery index can be proposed to cha-racterize the degree of in-situ stress recovery during development process of Qingcheng Oilfield, and a stress recovery index of 0.70 was identified as the optimal time for refracturing implementation. The influencing factors of refracturing timing include natural fracture density, matrix permeability, and initial hydraulic fracturing scale.