《Lithologic Reservoirs》
Published:01 July 2026
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Natural gas accumulation conditions in Jurassic-Paleogene of the northern margin of Qaidam Basin and exploration discovery of well Lutan-1
XUE Jianqin, MA Feng, LONG Guohui, SUN Xiujian, WANG Aiping, ZHU Shifa, WU Yunzhao, YOU Renzong
2026, Vol.38(4): 1–11
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Sedimentary models and fine characterization of subtle organic reefs in Permian Changxing Formation, Yuanba area, Sichuan Basin
WANG Zheng, XU Shoucheng, HU Xiuquan, LING Hang, TU Wenmao, ZHOU Yue, ZHANG Xiaoqing, SUN Wenna
2026, Vol.38(4): 12–22
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Characteristics and main controlling factors of Permian Qipan Formation reservoirs in Kekeya structural belt, southwestern Tarim Basin
HUANG Qiao, LUO Shunshe, ZHANG Liang, HUANG Li, GUO Kang, ZHU Liye, NAN Junwu
2026, Vol.38(4): 23–37
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Metallogenic potential and exploration direction of Jurassic potash in Qiangtang Basin
ZHANG Jiezhi, ZHU Guangyou, JI Changjun, LI Xi, LI Huan, WEN Chen, GAO Heting, ZHENG Kaihang
2026, Vol.38(4): 38–52
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Determination of hydrocarbon accumulation time of Guantao Formation in the south slope of Qikou Sag, Bohai Bay Basin
XU Haoxuan, FU Guang
2026, Vol.38(4): 53–62
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Rock physics modeling method for overpressure reservoirs of Miocene Huangliu Formation in Ledong slope, Yinggehai Basin
CHEN Hao, HUANG Handong, ZHANG Tieming, CUI Gang, PENG Jiahui
2026, Vol.38(4): 63–76
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Sedimentary evolution characteristics and hydrocarbon accumulation models of Paleogene in Sanmenxia Basin
LU Ziqi, LI Yuanhao, ZHU Yanhe, CHEN Xiaozhi, PAN Xinzhu, ZHAI Wenbin, CHANG Yirong, SHAN Chang’an
2026, Vol.38(4): 77–90
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Quantitative characterization method for clastic rock components based on improved electrical imaging logging mineral probability spectrum
REN Yufei, YAN Jianping, YAN Ke, HUANG Lisha, WANG Min, GENG Bin
2026, Vol.38(4): 91–100
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Sedimentary characteristics and controlling factors of carbonate-evaporite rocks in Triassic Jialingjiang Formation, southeastern Sichuan Basin
ZHANG Yuqing, ZHAO Zhongxiang, WANG Wei, HE Youbin, LUO Jinxiong, HU Mingyi, YANG Xingyu, WU Lianhua
2026, Vol.38(4): 101–114
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Oil and gas charging episodes and reservoir formation models of Ordovician Lianglitage Formation carbonate rocks in Tazhong area
SUN Yangzhen, YANG Peng, JIA Kun, QIN Shuxin, LIU Keyu
2026, Vol.38(4): 115–125
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Reconstruction and petroleum exploration potential of the Permian prototype basin in the periphery of Fukang fault zone, Junggar Basin
WANG Yanjun, BIAN Baoli, XIANG Hui, ZHANG Yongjun, SUN Yongxing, XU Xuelong, MA Delong, LI Yun
2026, Vol.38(4): 126–136
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Restoration and geological implications of paleogeomorphology during the depositional period of Triassic Feixianguan Formation in Puguang area, northeastern Sichuan Basin
YANG Weiqiang, LI Zhongchao, ZHANG Jixi, WANG Yi, ZHAO Zhen
2026, Vol.38(4): 137–147
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Sedimentary characteristics and hydrocarbon significance of Sinian Doushantuo Formation in the periphery of Hannan paleo-uplift, northwestern Sichuan Basin
LI Hongxi, LI Zhuzheng, CAO Yonghong, ZHAO Lei, FU Yu, XING Chaochao, NING Meng
2026, Vol.38(4): 148–156
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Accumulation characteristics and exploration potential of Jurassic low-rank coalbed methane in Santanghu Basin
WANG Jingguo, ZHAO Zhengwei, QIN Dapeng, GAO Lei, BAI Shuai, PAN Xiaofei, AN Qing, XIAO Fuqiang
2026, Vol.38(4): 157–169
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Occurrence state and evolution of remaining oil after water flooding characterized by high-precision CT scanning: A case study from Cretaceous Sa-Pu reservoir, eastern Daqing placanticline, Songliao Basin
LI Zhaoyong, LUO Diao, CHI Bo, LIU Shuang, ZHAO Jiuyu
2026, Vol.38(4): 170–179
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Experimental characterization of dynamic injection-production capacity behavior in offshore discontinuous chemical flooding
WEI Zhijie, LIU Ben, ZHANG Jian, ZHOU Wensheng, YONG Wei, LIU Yuyang
2026, Vol.38(4): 180–190
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Fine geological modeling method for Jurassic Sangonghe Formation condensate gas reservoir in Mobei uplift of Junggar Basin
DING Yajie, LI Xiang, HAN Zijian, XIE Lei, WEI Pu, WEI Ting, LUO Yang, MA Xinzhao
2026, Vol.38(4): 191–200
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Natural gas accumulation conditions in Jurassic-Paleogene of the northern margin of Qaidam Basin and exploration discovery of well Lutan-1
XUE Jianqin, MA Feng, LONG Guohui, SUN Xiujian, WANG Aiping, ZHU Shifa, WU Yunzhao, YOU Renzong
2026, Vol.38(4): 1–11
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doi: https://doi.org/10.12108/yxyqc.20260401
Recent deployed well Lutan-1 in the northern margin of Qaidam Basin has achieved successive breakthroughs in Jurassic Dameigou Formation sandstone and Paleogene Lulehe Formation, revealing significant exploration potential for lithologic gas reservoirs in the slope-sag belt of this region. Based on the whole petroleum system accumulation theory, geological conditions and main controlling factors of natural gas accumulation were systematically analyzed, and the direction for further exploration was clarified. The results show that: (1) Major hydrocarbon-generating sags such as Yibei Sag are well preserved, and Jurassic coal-measure source rocks widely distributed, with large thickness and high maturity, providing abundant gas sources for natural gas accumulation. (2) Controlled by paleo-gully and slope-break geomorphology, Paleogene Lulehe Formation and Jurassic Dameigou Formation developed large area sandstone reservoirs in the slope zone, forming sand-rich belts. Lulehe Formation mudstone and Jurassic Dameigou Formation mudstone are efficient regional caprocks, while the regional unconformity at Paleogene base serves as a key migration pathway, jointly controlling the continuous accumulation of sandstone reservoirs in the stable slope. The breakthrough of well Lutan-1 marks a shift in exploration strategy from uplift to slope-sag zones in this area, confirming the accumulation model of “unconformity network migration, near-source efficient charging, high-quality caprock sealing, and paleo-geomorphology controlling sandstone enrichment”， which is conducive to the exploration and study of the whole petroleum system for coal-measure gas in the northern margin of Qaidam Basin. （3） According to the new exploration concept of “moving down slope and into sags, searching for gas near sources”, four major paleo-slope zones on the periphery of Yibei Sag have great exploration potential and may be the key areas for future large-scale reserves expansion.
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Sedimentary models and fine characterization of subtle organic reefs in Permian Changxing Formation, Yuanba area, Sichuan Basin
WANG Zheng, XU Shoucheng, HU Xiuquan, LING Hang, TU Wenmao, ZHOU Yue, ZHANG Xiaoqing, SUN Wenna
2026, Vol.38(4): 12–22
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doi: https://doi.org/10.12108/yxyqc.20260402
Based on drilling, logging, and seismic data, distribution patterns and enrichment mechanisms of uranium in the overlying uranium-rich layers of subtle organic reefs in Permian Changxing Formation of Yuanba area in Sichuan Basin，were systematically analyzed. An “anoxic sealed” sedimentary model for overlying uranium-rich layers of subtle organic reefs was established. Guided by the model, an integrated technical system of “seismic target processing-uranium-rich layer constraint-fine characterization” was constructed, which achieved the detailed characterization of such reefs and predicted favorable development areas. The results show that: （1） Based on the vertical distribution of uranium content, the upper Changxing Formation in Yuanba area can be divided into three types, such as stable, top-enriched, and overall-enriched, among which the top-enriched type is the key indicator for identifying subtle organic reefs. Under the guidance of “anoxic sealed” sedimentary model, during the late depositional stage of Changxing Formation， the barrier effect of the platform-margin reef belt generated restricted anoxic environment in its back-reef area, reefs growth ceased and reefs were subsequently capped by uranium-rich layers, forming the vertical architecture of “uranium-rich layer-subtle reef ”. （2） The integrated “seismic target processing-uranium-rich layer constraint-fine characterization” technical system improves imaging quality through geological target-driven seismic processing, uses uranium enrichment distribution to focus on target areas, and then establishes a subtle organic reef seismic identification model combined with forward modeling, achieving fine characterization of the spatial morphology of reefs. According to the plane distribution characteristics of subtle organic reefs characterized by the integrated technical system, subtle organic reefs are relatively concentrated and larger in scale in W104-W11 well area and north of well W123 on the landward side, with individual reef areas of 0.36-1.25 km2. In contrast, reefs are more scattered and smaller in scale towards the inner platform, with individual reef areas less than 0.40 km2. （3） For the first well W102-4H drilled on the subtle organic reefs in the uranium-rich overlayer of the study area, tested natural gas production reached 65.50×104 m3/d, with calculated open-flow capacity of 265.12×104 m3/d. The south of well W104 and well W11 are also favorable targets for subtle organic reefs, with an estimated gas production excee-ding 100.00×104 m3/d.
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Characteristics and main controlling factors of Permian Qipan Formation reservoirs in Kekeya structural belt, southwestern Tarim Basin
HUANG Qiao, LUO Shunshe, ZHANG Liang, HUANG Li, GUO Kang, ZHU Liye, NAN Junwu
2026, Vol.38(4): 23–37
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doi: https://doi.org/10.12108/yxyqc.20260403
Based on field outcrops and detailed characterization of key single wells, combined with thin section petrography, X-ray diffraction (XRD) analysis, physical property analysis, and mercury intrusion porosimetry, the characteristics of Permian Qipan Formation clastic reservoirs of Kekeya area in southwestern Tarim Basin were systematically analyzed, classified and evaluated, and the main controlling factors governing reservoir development were clarified. The results show that: （1） Qipan Formation of Kekeya area develops a depositional system of braided-river delta plain, delta front, and shallow-marine mixed shelf from southeast to northwest. Five microfacies are recognized, including delta-plain distributary channels and interdistributary bays, as well as delta-front subaqueous distributary channels, mouth bars, and subaqueous interdistributary bays, which correspond to five types of sedimentary reservoirs. （2） The five types of sedimentary reservoirs of the study area exhibit significant differences in petrological characteristics, physical properties, reservoir space, and pore structure. The subaqueous distributary channel reservoir is predominantly composed of lithic feldspathic sandstone, with the lowest lithic fragment content, the highest degree of sorting and rounding, large thickness, and the best physical properties and pore structure, classified as type Ⅰ high-quality reservoir. The interdistributary bay and subaqueous interdistributary bay reservoirs are mainly composed of lithic sandstones, with higher lithic fragment content, the poorest compositional and textural maturity, small thickness, and the worst physical properties and pore structure, clasified as type Ⅲ poor reservoirs. The distributary channel and mouth bar reservoirs display intermediate thickness, physical properties, and pore structure,which are between type Ⅰ and Ⅲ, and clasified as type Ⅱ reservoir. （3） The development and distribution of reservoirs in the study area are jointly controlled by sedimentation and diagenesis. Depositional hydrodynamic conditions determine the material basis and macro-distribution patterns of reservoir development, while diagenesis modulates pore evolution. The favorable reservoirs of subaqueous distributary channel developed under high-energy and stable hydrodynamic conditions, are primarily distributed in the northwestern part of the study area.
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Metallogenic potential and exploration direction of Jurassic potash in Qiangtang Basin
ZHANG Jiezhi, ZHU Guangyou, JI Changjun, LI Xi, LI Huan, WEN Chen, GAO Heting, ZHENG Kaihang
2026, Vol.38(4): 38–52
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doi: https://doi.org/10.12108/yxyqc.20260404
Based on comprehensive literature review, conditions and controlling factors of salt-forming, distribution patterns of potash deposits, and the coupling relationship between salt structures and hydrocarbon accumulation of Jurassic in Qiangtang Basin were systematically examined, and exploration deployment was discussed. The results show that: （1） The formation of Jurassic marine evaporites in Qiangtang Basin was primarily controlled by the coupling of material supply, arid climate, and restricted tectonic settings. Seawater influx and terrigenous input constituted the principal sources of salt-forming materials. Restricted to semi-restricted depositional environments associated with the evolution of the Tethyan tectonic domain, together with arid climate, provided favorable conditions for salt-forming, while tectonic movements related to Tethyan evolution governed the spatiotemporal distribution of salt deposits. (2) The distribution pattern of Jurassic potash in the study area follows the model of “tectono-sedimentary control-material evaporation and concentration-paleoclimate-driving”. Vertically, Jurassic Xiali Formation and Suowa Formation represent the most prospective potash-bearing stratigraphic intervals. Laterally, the most favorable areas for marine potash mineralization are located along the southern margin of North Qiangtang Depression. The large evaporite-platform facies belt in northwestern Anduo county, salt-spring concentration development zones within the basin, and the Bandaohu-Puruogangri basement uplift and its adjacent large sags are exploration targets for marine potash resource. （3） Salt structures and hydrocarbon resources in the study area exhibit multiple levels of interaction, including depositional paragenesis, sealing protection, reservoir modification, and structural control. Salt structures can not only provide migration pathways for oil and gas, but also form effective hydrocarbon traps. Distribution patterns of salt deposits exert a fundamental control on hydrocarbon accumulation within suprasalt, intrasalt, and subsalt petroleum systems. (4) Potash research in the study area can focus on the evolution of evaporite depositional systems and sediment sources, mechanisms controlling salt deposits preservation under late stage tectonic modification, and promote research of “integrated exploration for hydrocarbons and potash resources”.
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Determination of hydrocarbon accumulation time of Guantao Formation in the south slope of Qikou Sag, Bohai Bay Basin
XU Haoxuan, FU Guang
2026, Vol.38(4): 53–62
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doi: https://doi.org/10.12108/yxyqc.20260405
Based on seismic, drilling, well logging and geochemical testing and analysis, the method for determining the accumulation time of hydrocarbon transported by sandstone-fault system to shallow layers was proposed. The accumulation time of oil transported by the lower submember of the first member of Shahejie Formation （Es1x） sandbody-Zhaobei Fault transport system to Guantao Formation was clarified, and the relationship between the accumulation time and hydrocarbon distribution of Guantao Formation and its upper reservoirs was analyzed.Research results show that: （1） The method for determining the accumulation time of hydrocarbon transported by sandstone-fault system to shallow reservoirs is as follows: the hydrocarbon transport time of sandbody is obtained by superimposing the formation time of sandbody, the duration of sealing capacity of overlying mudstone caprock (the period from the synchronization of mudstone and sandbody sealing indices to present), the sandbody tilting time during the last fault activity, and the hydrocarbon expulsion time of source rock. By restoring the paleo-thickness of mudstone caprock and paleo-fault throws of faults in different geological periods, and calculating their difference, the paleo-residual thickness of mudstone caprock in each period can be obtained. The hydrocarbon migration time of fault is the time interval from the time corresponding to the maximum residual thickness required for the fault to penetrate mudstone caprocks, to the termination of fault activity. The superposition of hydrocarbon transport time by sandbody and by fault is the final accumulation time of hydrocarbon transported by sand-fault system to shallow layers. （2） In the study area, the hydrocarbon migration time through the sandbody pathway of Es1x is the sedimentary period of Minghuazhen Formation. The time when Zhaobei Fault simultaneously cut through mudstone caprocks of the middle submember of the first member of Shahejie Formation (Es1z) and the second member of Dongying Formation (Ed2) was from the middle sedimentary period to the end of Minghuazhen Formation. The accumulation time of oil transported to the shallow Guantao Formation via Es1x sandbody-Zhaobei Fault system was from the middle sedimentary period to the end of Minghuazhen Formation, which is consistent with the hydrocarbon charging time obtained from the homogenization temperature of fluid inclusions in Guantao Formation combined with burial-thermal history. （3） The limited duration of oil transportation to Guantao Formation via Es1x sandbody-Zhaobei Fault system in the study area, is the fundamental reason for the current restricted occurrence scale of hydrocarbon in Guantao Formation near Zhaobei Fault. Zhaobei Fault did not cut through the mudstone caprock of Minghuazhen Formation, so there is no hydrocarbon accumulation above Minghuazhen Formation.
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Rock physics modeling method for overpressure reservoirs of Miocene Huangliu Formation in Ledong slope, Yinggehai Basin
CHEN Hao, HUANG Handong, ZHANG Tieming, CUI Gang, PENG Jiahui
2026, Vol.38(4): 63–76
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doi: https://doi.org/10.12108/yxyqc.20260406
Existing rock physics models cannot accurately characterize the variation of elastic parameters in overpressure reservoir, which limits the precision of overpressure reservoir characterization. Taking overpressure re-servoirs of Miocene Huangliu Formation in Ledong slope of Yinggehai Basin as an example, a multi-porosity rock physics model for overpressure reservoirs was proposed, and its application performance was analyzed. Based on the proposed model, the influence factors of elastic parameters in overpressure reservoirs were analyzed, and a rock physics template incorporating formation effective stress and porosity parameters were established. The results show that: （1） The multi-porosity overpressure rock physics modeling method is proposed based on the multi-porosity theory by comprehensively considering effects of soft pores, stiff pores, and bound-water. By introducing the formation pressure coefficient and effective stress into the pore-space stiffness theory, and employing a gradient-based optimization algorithm to adaptively optimize pore aspect ratios, the model captures the variation of elastic parameters with effective stress under complex pore structures. （2） The predicted P-wave and S-wave velocities of Huangliu Formation in Ledong slope area by this model are in high agreement with well logging interpretations, with prediction errors below 8%. Compared with conventional models, the proposed model achieves the best fitting performance, with the highest R2 values of 0.920 and 0.937, respectively. （3） In overpressure reservoirs, rock elastic parameters are jointly controlled by five factors, including effective stress, soft-pore proportion, clay content, bound-water porosity, and movable-fluid porosity. In overpressure formations, with increasing pore pressure and decreasing effective stress, the P-wave to S-wave velo-city ratio (vp/vs) increases. Compared with sandstone, mudstone exhibits lower velocity and higher vp/vs values. The vp/vs ratio is the sensitive parameter for distinguishing sandstone from mudstone in overpressure clastic reservoirs. In the study area, the discriminant threshold of vp/vs for sandstone and mudstone is approximately 1.64 in the normal-pressure section, and 1.70-1.75 in the overpressure section. （4） The sandstone reservoir distribution predicted by the vp/vs section inverted on the basis of the proposed multi-porosity overpressure rock physics model is basically identical with the gas logging interpretation conclusion.
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Sedimentary evolution characteristics and hydrocarbon accumulation models of Paleogene in Sanmenxia Basin
LU Ziqi, LI Yuanhao, ZHU Yanhe, CHEN Xiaozhi, PAN Xinzhu, ZHAI Wenbin, CHANG Yirong, SHAN Chang’an
2026, Vol.38(4): 77–90
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doi: https://doi.org/10.12108/yxyqc.20260407
Sanmenxia Basin has considerable hydrocarbon exploration potential， but its overall exploration degree remains low. Focusing on Wumu Sag and Pinglu Sag， combined with measurements of source rock organic matter abundance， development characteristics of Paleogene sedimentary systems and source rocks were analyzed， and tectono-sedimentary evolution models and hydrocarbon accumulation conditions were clarified based on field outcrop observations， 2D seismic data， and drilling data. The results show that： （1） Paleogene in Sanmenxia Basin deve-loped five sedimentary facies and nine subfacies. Menli Formation is dominated by alluvial fan deposits. Podi Formation develops alluvial fan， fan delta， and lacustrine deposits. Xiao’an Formation is dominated by lacustrine deposits， and Liulinhe Formation mainly develops alluvial fan and braided river deposits. Different sags show significant differences in sedimentary filling， and facies belts are generally narrow and laterally migrate rapidly. （2） The tectono-sedimentary evolution of the basin has gone through 4 stages of “syn-rift to post-rift depression”. During the initial rifting stage， corresponding to Menli period， strong extension produced several isolated deep sags. During the intense rifting stage， corresponding to Podi period， basement experienced significant differential subsidence， leading to lake basin expansion and short-term lacustrine flooding. During the rift-depression transition stage， corresponding to Xiao’an period， the basin became interconnected and entered a relatively stable depositional stage， and the deep-lake reached its maximum scope. During the depression-subsidence stage， corresponding to Liulinhe period， tectonic activity tended to stabilize， and the lake basin gradually shrank and eventually disappeared. （3） Source rocks in the study area are mainly developed in the deep-lake black mud shale of Podi Formation and the deep to semi-deep lake gray-black mudstone of Xiao’an Formation. High-quality source rock samples account for 25% of the total， with Xiao’an Formation representing the principal source rock interval. In Wumu Sag， TOC values of Xiao’an Formation range from 0.29% to 31.10%， with an average of 2.06%， TOC values of Podi Formation range from 0.40% to 22.00%， with an average of 5.33%. The anomalously high TOC values or large fluctuations observed in some samples are related to outcrop preservation conditions and the development of coal streaks. （4） The study area mainly develops three types of hydrocarbon accumulation assemblages， including “self generation and self storage”， “lower generation and upper storage”， and locally “upper generation and lower storage”. Overall， it is characterized by near-source hydrocarbon supply and short-distance migration for reservoir formation， and the central structural belt represents the favorable exploration zone.
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Quantitative characterization method for clastic rock components based on improved electrical imaging logging mineral probability spectrum
REN Yufei, YAN Jianping, YAN Ke, HUANG Lisha, WANG Min, GENG Bin
2026, Vol.38(4): 91–100
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doi: https://doi.org/10.12108/yxyqc.20260408
To address the strong heterogeneity of mineral components in deep complex clastic reservoirs and the limited accuracy of conventional logging methods, a quantitative calculation method based on improved electrical imaging logging mineral probability spectra was proposed, achieving continuous and precise determination of key mineral contents such as feldspar, calcite, and clay. The research findings indicate: （1） The resistivity data of electrical imaging was converted into standardized pixel values, and pixel waveform spectra were constructed through histogram equalization and normal distribution processing. Subsequently, based on Archie’s formula and the parallel conductivity model, porosity contribution corrections were applied to the pixel values to extract imaging mineral spectra reflecting pure mineral components. （2） The imaging mineral spectra were calibrated using whole-rock X-ray diffraction (XRD) analysis data from core samples. The optimal segmentation algorithm was employed to determine the optimal pixel value thresholds for distinguishing mud, feldspar, and calcite (calcite/felsic mineral boundary at 15%; felsic mineral/clay boundary at 70%), thereby establishing a quantitative calculation model from imaging mineral spectra to mineral content. （3） In practical single-well applications, the electrical imaging mineral calculation model significantly improved mineral identification accuracy, with correlation coefficient R2 between calculated mineral content and XRD measured data greater than 0.800 0, which can identify low physical property intervals caused by calcareous cementation, and is conducive to the detailed evaluation of complex clastic reservoirs.
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Sedimentary characteristics and controlling factors of carbonate-evaporite rocks in Triassic Jialingjiang Formation, southeastern Sichuan Basin
ZHANG Yuqing, ZHAO Zhongxiang, WANG Wei, HE Youbin, LUO Jinxiong, HU Mingyi, YANG Xingyu, WU Lianhua
2026, Vol.38(4): 101–114
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doi: https://doi.org/10.12108/yxyqc.20260409
Lower Triassic Jialingjiang Formation in Sichuan Basin is an important natural gas reservoir system, where typical carbonate-evaporite paragenesis systems are widely developed. Based on core, thin section, and master logging data, the classification of paragenesis system types, sedimentary microfacies identification, and main controlling factors of sedimentary evolution of Triassic Jialingjiang Formation in the southeastern Sichuan Basin were systematically conducted, and distribution patterns of carbonate-evaporite paragenesis systems were clarified. The results show that： （1） Carbonate-evaporite paragenesis systems of Triassic Jialingjiang Formation in the southeastern Sichuan Basin can be classified into three major categories and five subcategories: overlapped type (carbonate rock overlying evaporite and evaporite overlying carbonate rock), interbedded type (carbonate rock and evaporite interbedded ), and intercalated type (evaporite intercalated with carbonate rock and carbonate rock intercalated with evaporite). A total of 11 paragenesis system microfacies types were identified, including gypsum, gypsiferous dolomite, gypsiferous limestone, micritic dolomite, finely crystalline dolomite, granular dolomite, and bioclastic limestone, and 7 types of microfacies associations were summarized. （2） The formation and distribution of the carbonate-evaporite paragenesis systems in the study area are controlled by the coupling of sea level fluctuations and paleogeomorphology. High-frequency sea level cycles dominate the vertical evolutionary sequence, while the paleogeomorphological framework shaped by paleo-uplifts and paleo-depressions constrained the lateral distribution patterns of paragenesis systems. （3） The “carbonate rock overlying evaporite”subtype within the overlapped category and the interbedded paragenesis systems exhibit good reservoir-caprock configurations and relatively superior preservation conditions.
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Oil and gas charging episodes and reservoir formation models of Ordovician Lianglitage Formation carbonate rocks in Tazhong area
SUN Yangzhen, YANG Peng, JIA Kun, QIN Shuxin, LIU Keyu
2026, Vol.38(4): 115–125
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doi: https://doi.org/10.12108/yxyqc.20260410
Based on in-situ calcite U-Pb dating, fluid inclusion analysis, and basin modelling, the petrological and fluid activity characteristics of Ordovician Lianglitage Formation in Tazhong area were delineated. The oil and gas charging episodes were systematically analyzed, and reservoir formation models were characterized. Research results show that: （1） Main rock types of Ordovician Lianglitage Formation reservoir in Tazhong area are granular limestone and biogenic limestone, and storage space types include pores, karst caves, and fractures. （2） Two phases of calcite cements develop in the reservoir, with the first phase of calcite cement emitting bright red catho-doluminescence light, and the corresponding U-Pb age of 427.0 ± 4.2 Ma, and the second phase of calcite cement displaying orange-yellow cathodoluminescence light, and the corresponding U-Pb age of 369.0 ± 14.0 Ma. (3) Two types of oil inclusion assemblages (OIA) have been identified. Type I OIA emits yellow and pale yellow fluorescence, corresponding to the oil charge timing of 425.0-410.0 Ma. Type Ⅱ OIA emits blue fluorescence, corresponding to the oil charge timing of 325.0-320.0 Ma. (4) Lianglitage Formation reservoir in the study area has mainly experienced two episodes of oil charging and one episode of natural gas charging. The first episode of oil charging occurred in the late Caledonian period, the second episode of oil charging occurred in the middle Hercynian period, and the natural gas charging occurred in the late Himalayan period. The formation of this oil and gas reservoir is the result of synergistic effects of multiple factors, including high-quality reservoirs, multi-stage hydrocarbon supply, efficient transportation, effective sealing, and favorable structural backgrounds.
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Reconstruction and petroleum exploration potential of the Permian prototype basin in the periphery of Fukang fault zone, Junggar Basin
WANG Yanjun, BIAN Baoli, XIANG Hui, ZHANG Yongjun, SUN Yongxing, XU Xuelong, MA Delong, LI Yun
2026, Vol.38(4): 126–136
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doi: https://doi.org/10.12108/yxyqc.20260411
To define the distribution range and resource exploration potential of Permian Lucaogou Formation source rocks in Fukang fault zone and its surrounding areas, based on the latest data of seismic, drilling, and high-precision gravity, the geological structure and tectonic evolution of Bogda piedmont were clarified. The basin configuration of Early-Middle Permian was reconstructed, and the resource scale of source rocks was assessed. Research results show that： （1） During Early-Middle Permian, Bogda and its adjacent areas underwent the evolution from a rift basin to a post-rift depression lacustrine basin, forming an paleo tectonic pattern of “alternating uplifts and sags”,which can be divided into four secondary tectonic units: Xiaoquangou uplift, Funan Sag, Jinan uplift and Jinan Sag, with the subsidence center of the lacustrine basin located south of the present-day Bogda Mountain. （2） From late Middle Permian to Himalayan period, multiple orogenic movements caused the structural inversion and dismemberment of the original lacustrine basin center,with continuous uplift of Bogda Mountain, resulting in a total horizontal shortening of about 62.2 km. （3） During the sedimentary period of Permian Lucaogou Formation, a deep lacustrine post rift depression lake basin was developed around Fukang fault zone. The total area of the prototype basin is about 153 7 km2, the resource scale of Lucaogou Formation in Jinan Sag is about 2.4 times that of Jimsar Sag, making it 10×108 ton oil shale exploration area. The reservoir formation model is “bilateral hydrocarbon supply, multi-layered stratified accumulation”. Jimsar Sag and Jinan Sag, serving as dual hydrocarbon source centers, have developed a vertically multi-stacked and laterally interconnected stratified accumulation system around Carboniferous volcanic paleo-uplifts weathered crusts, Middle Permian Lucaogou Formation shale oil, and Upper Permian Wutonggou Formation lithologic-stratigraphic traps.
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Restoration and geological implications of paleogeomorphology during the depositional period of Triassic Feixianguan Formation in Puguang area, northeastern Sichuan Basin
YANG Weiqiang, LI Zhongchao, ZHANG Jixi, WANG Yi, ZHAO Zhen
2026, Vol.38(4): 137–147
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doi: https://doi.org/10.12108/yxyqc.20260412
Paleogeomorphologic framework exerts significant control on the spatial distribution of facies-controlled carbonate reservoirs. Based on geophysical data such as core thin sections, conventional logging data, the original thickness of individual wells in Triassic Feixianguan Formation was restored in Puguang area through analysis of differential compaction and pressure dissolution of lithofacies. Combined with 3D seismic data, the paleogeomorphology was reconstructed, and the structural subsidence of individual wells was identified using the INPEFA curve. The decompaction and pressure dissolution restoration results were integrated to further refine the paleogeomorphology during the depositional period. Research results show that: （1） Feixianguan Formation in Puguang area develop seven major rock types, including granular dolomite, micritic-granular dolomite, crystalline dolomite, micritic dolomite, granular limestone, micritic-granular limestone, and micritic limestone. Based on compaction recovery coefficients and pressure dissolution recovery coefficients, decompaction coefficients of different lithofacies were calculated. Granular dolomite exhibits the smallest decompaction coef-ficient of 1.25, indicating little change between its present-day thickness and original sedimentary thickness, whereas micritic limestone exhibits a relatively large decompaction coefficient of 3.09, with its present-day thickness differing by more than two times from the original thickness. （2） The identification of tectonic subsidence using the INPEFA method is a single-well sequence identification technique based on GR curve trend spectrum analysis. Combined with Walther’s law, the key mechanism of this method for identifying tectonic subsidence was clarified, and the INPEFA mean value of 0.5 was used as the threshold to distinguish normal sedimentary areas and tectonic subsidence areas. （3） The distribution of shoal deposits is controlled by paleogeomorphology and tectonic subsidence. In tectonic stable areas, shoal deposits are concentrated in high parts of the paleogeomorphology; whereas in tectonic active areas, shoal deposits develop in regions with positive paleogeomorphology and the INPEFA mean value of less than 0.5. （4） The accuracy of paleogeomorphology restored through decompaction, pressure dissolution, and tectonic subsidence analysis has been significantly improved, which can effectively identify and eliminate spurious topographic highs caused by differential subsidence, thus more clearly revealing controlling effects of paleogeomorphology on the development of high-quality reservoirs.
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Sedimentary characteristics and hydrocarbon significance of Sinian Doushantuo Formation in the periphery of Hannan paleo-uplift, northwestern Sichuan Basin
LI Hongxi, LI Zhuzheng, CAO Yonghong, ZHAO Lei, FU Yu, XING Chaochao, NING Meng
2026, Vol.38(4): 148–156
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doi: https://doi.org/10.12108/yxyqc.20260413
In recent years, significant progress has been made in hydrocarbon exploration of Sinian Doushantuo Formation in the Yangtze craton. Combided field outcrop profiles observations and laboratory analysis, the stratigraphic distribution and sedimentary characteristics of Doushantuo Formation in the periphery of Hannan paleo-uplift in northwestern Sichuan Basin were systematically summarized, and the control mechanism of the tectonic on the development of source rocks in Doushantuo Formation were revealed. Research results show that: （1） Diffe-rent sedimentary systems were developed during the sedimentary period of Doushantuo Formation in the eastern and western sides of Hannan paleo-uplift. The western side developed a stable gentle slope sedimentary system characterized by mixed clastic and carbonate rocks,while the eastern side underwent a complete sedimentary succession of “slope filling-stable shelf-carbonate gentle slope”. （2） The sedimentary differentiation characteristics of both sides of Hannan paleo-uplift are controlled by the subduction-transition boundary of Panxi-Hannan island arc.The western side corresponds to the subduction boundary,with wide and gentle sedimentary terrain.The eastern side is located at the transition boundary, with steep slopes and continuous subsidence, providing favorable tectonic-paleogeographic conditions for deep-water anoxic environments and the development of high-quality source rocks. （3） The eastern side of Hannan paleo-uplift (Zhenba-Chengkou area) contains high-quality source rocks, with high TOC values (2.75%-4.76%) due to earlier-initiated tectonic activity, continuous subsidence, oxygen deficient reducing environment, and high paleoproductivity driven by hydrothermal activity. Due to constraints such as tectonic stability and poor preservation conditions, the western side develops limited-scale, medium-poor quality source rocks, with average TOC values of 1.20%-1.65%.
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Accumulation characteristics and exploration potential of Jurassic low-rank coalbed methane in Santanghu Basin
WANG Jingguo, ZHAO Zhengwei, QIN Dapeng, GAO Lei, BAI Shuai, PAN Xiaofei, AN Qing, XIAO Fuqiang
2026, Vol.38(4): 157–169
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doi: https://doi.org/10.12108/yxyqc.20260414
Jurassic low-rank coalbed methane resources are rich in Santanghu Basin. Based on drilling data and coal rocks experimental analysis data， development characteristics of Jurassic coal seam and geological conditions for coalbed methane accumulation were systematically analyzed. Coalbed methane accumulation models and resource potential were clarified， and favorable exploration areas were predicted. The results show that： （1） Two sets of coal-bearing strata， Badaowan Formation and Xishanyao Formation， are developed in Jurassic of Santanghu Basin. Thick coal seams are mainly developed in coal accumulation centers such as Hanshuiquan Sag， Shitoumei Uplift， Tiaohu Sag， Malang Sag and Naomaohu Sag. Coal rocks are mainly primary structure, and organic components of coal rocks are mainly vitrinite， followed by inertinite. The maximum vitrinite reflectance is 0.22%-0.77%， which belongs to low-rank lignite and long flame coal. （2） Coal rock reservoirs have good physical pro-perties and belong to medium porosity and low-medium permeability reservoir， mainly develop mesopores， with pore size ranging from 3 nm to 10 nm. （3） The mass volume of coal methane in the study area is 0.11-7.68 m3/t， and gas components are mainly N2， CO2 and CH4. Among them， the content of CH4 is the highest， with a volume fraction of 85.50%-91.24%. Gas-bearing conditions of coal rock in Malang Sag and Naomaohu Sag are the best. （4） There are four types of top and bottom plate assemblages in the study area， including type of mudstone at top and bottom， type of mudstone at top and sandstone at bottom， type of sandstone at top and mudstone at bottom， type of sandstone at top and bottom. The type of mudstone at top and bottom has the best sealing performance for coalbed methane. Coalbed methane enrichment and accumulation models include sag retention enrichment and accumulation model， reverse fault lithology plugging accumulation model and uplift runoff dissipation model. （5） Coalbed methane resources in the study area are 4 750×108 m3， with an average resource abundance of 0.80×108 m3/km2. Deep parts of Tiaohu Sag， Malang Sag and Naomaohu Sag are Class Ⅰ favorable areas for coalbed methane exploration.
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Occurrence state and evolution of remaining oil after water flooding characterized by high-precision CT scanning: A case study from Cretaceous Sa-Pu reservoir, eastern Daqing placanticline, Songliao Basin
LI Zhaoyong, LUO Diao, CHI Bo, LIU Shuang, ZHAO Jiuyu
2026, Vol.38(4): 170–179
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doi: https://doi.org/10.12108/yxyqc.20260415
Focusing on Cretaceous Sa-Pu reservoir in eastern Daqing placanticline, the occurrence state and evolution of microscopic remaining oil under different permeability conditions were systematically investigated by integrating high-resolution computed tomography （CT） scanning with water flooding experiments. Numerical simulations of relative permeability and wettability were conducted to formulate strategies for enhanced oil recovery. The results show that: （1） Cretaceous Sa-Pu reservoir in eastern Daqing placanticline is characterized by an average pore-throat radius of 6.1-8.0 μm, pore-throat ratioof 2.1-2.4, and connected porosity exceeding 95%. The pore throat structure of high permeability reservoirs (> 150.0 mD) is relatively homogeneity and well connected, while low-permeability reservoirs (< 50.0 mD) with strong heterogeneity, a disparity that fundamentally go-verns oil-water two-phase flow behavior and remaining oil spatial distribution. （2） The water flooding experiment and CT scanning results of core samples in the study area show that: microscopic remaining oil was identified as four types of occurrence state, such as network-like, pore-clustered, oil-film, and isolated-droplet forms. During water flooding, the remaining oil morphology evolves primarily from network-like to pore-clustered. In the early stage of displacement, well-connected network-like oil is dominated, and the recovery factor increases rapidly. As displacement progresses, in the middle and later stages, remaining oil becomes predominantly trapped in pore throats as pore clusters, resulting in a significant decline in oil displacement efficiency and a rapid rise in water-cut. Reservoir permeability is a key factor in controlling the evolution of the remaining oil morphology. High permeability reservoirs have longer low water-cut periods and higher ultimate recovery factor due to the more developed initial network-like oil. (3) Numerical simulations reveal Sa-Pu reservoir’s strong oil-wet nature, demonstrating that wettability reversal technology significantly enhances oil-phase mobility, with an average reduction in trapped oil saturation of 8.9%. (4) Differentiated development strategies based on permeability grading are proposed in the study area. Well pattern optimization is recommended at the high water-cut stage for high-permeability reservoirs, followed by wettability reversal and chemical flooding at the extra-high water-cut stage. Wettability reversal is implemented during the medium water-cut stage for medium-permeability reservoirs, and wettability reversal combined with chemical flooding are implemented during medium-to-low water-cut stages for low-permeability reservoirs.
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Experimental characterization of dynamic injection-production capacity behavior in offshore discontinuous chemical flooding
WEI Zhijie, LIU Ben, ZHANG Jian, ZHOU Wensheng, YONG Wei, LIU Yuyang
2026, Vol.38(4): 180–190
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doi: https://doi.org/10.12108/yxyqc.20260416
In response to challenges such as declining injection-production capacity and limited sweep efficiency in conventional polymer flooding of offshore high water-cut oilfields, the experimental study on variation patterns of injection-production capacity in discontinuous chemical flooding was conducted. Through core flooding experiments, two-dimension physical plate model simulations, and numerical simulation, dynamic response characteristics and mechanisms of discontinuous injection methods were revealed. The results show that: （1） Using discontinuous chemical flooding technology in high water-cut offshore oilfields, through the synergistic slug action of “high-concentration plugging and low-concentration displacement”, the distribution of displacement pressure within the reservoir was optimized. The recovery degree of low-permeability layers increased by 8.4% and the recovery factor of high-permeability layers increased by 7.4%. （2） The discontinuous injection method significantly improved the injection-production capacity, with water absorption index decreasing by 4.18% du-ring the high-concentration slug injection stage and water absorption index increasing by 14.41% during the low-concentration slug injection stage, resulting in an overall increase of 5.12%. （3） The concentration gradient control effectively improves sweep efficiency, increasing the liquid intake volume of low-permeability layers by 3.6%, and enhancing the synchronous fluid movement across layers with different permeabilities. （4） Numerical simulation results verified the effectiveness of the discontinuous injection method. In the experiment, the distribution of reservoir pressure field and flow field was reconstructed. The crude oil viscosity degradation and the formation of “oil bank”were effectively suppressed by appyling the discontinuous chemical flooding technology. The “plugging-diversion” synergistic mechanism can achieve balanced displacement and efficient development in high water-cut offshore oilfields.
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Fine geological modeling method for Jurassic Sangonghe Formation condensate gas reservoir in Mobei uplift of Junggar Basin
DING Yajie, LI Xiang, HAN Zijian, XIE Lei, WEI Pu, WEI Ting, LUO Yang, MA Xinzhao
2026, Vol.38(4): 191–200
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doi: https://doi.org/10.12108/yxyqc.20260417
In the middle to late stage of low-permeability condensate gas reservoirs development， rapid deliverability decline and reduced recovery due to condensate oil blockage often occur. Taking No. 1 sandbody in the second member of Jurassic Sangonghe Formation in Qianshao 4 well block in Mobei uplift of Junggar Basin as an example， a high-precision numerical simulation model was established by combining multi-scale parameters integration with wellstream phase-behavior correction， and remaining gas distribution prediction and potential-tapping schemes evaluation were conducted. The results show that：（1） The thickness of No. 1 sandbody in the second member of Jurassic Sangonghe Formation in Qianshao 4 well block in Mobei uplift of Junggar Basin is about 20 m，the average porosity is about 12%， the average permeability is about 1.5 mD， with strong heterogeneity and poor local connectivity. （2） Using data collaboration to constrain sandbodies distribution and porosity/permeability parameters， combining fluid composition inversion in condensate gas wells and bottomhole pressure coupling， an integrated model of “geology-phase behavior-wellbore” was established，significantly improving the characterization accuracy of sandbody architecture and porosity/permeability parameters. The correlation coefficients between the modeling porosity/permeability and measured values were greater than 0.99. The fitting accuracy between the calculation results of the model and historical condensate gas production is greater than 96%， revealing that the high part of well Qianshao 401 in the study area represents a typical remaining gas enrichment zone of “high gas saturation but poor connectivity”. （3） Based on remaining gas distribution， the proposed lateral drilling potential-tapping scheme for well Qianshao 401，can provide an additional recoverable reserve of 0.37×108 m3 and increase daily gas production by 4×104 m3. The prediction results suggest that the well can achieve stable production until 2030 if the constant gas recovery rate of 5.1% is maintained.