《Lithologic Reservoirs》
Published:01 September 2026
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Influence mechanism of salt minerals on large-scale hydrocarbon generation from low-abundance source rocks: A case study of Paleogene Xiaganchaigou Formation in western Qaidam Basin
WANG Bo, ZHOU Fei, TIAN Jixian, ZHANG Jing, ZHANG Tong, QI Yonggang, QIAO Baihan, FENG Dehao
2026, Vol.38(5): 1–9
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Pre-Jurassic source rock evolution features and hydrocarbon accumulation process in Taibei Sag, Turpan-Hami Basin
CHEN Xuan, YANG Bin, ZHANG Hua, GOU Hongguang, HU Jun, FU Guobin, HAO Bin, CHENG Yi
2026, Vol.38(5): 10–22
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Geological characteristics and exploration & development potential of Mesozoic composite lithologic gas reservoirs in Samandepe Gas Field, right bank of Amu Darya
LENG Youheng, YANG Yadong, WANG Qiang, LI Yunzhu, WEI Zhanjun, HUANG Feng, XUE Taofeng, LIU Yang
2026, Vol.38(5): 23–39
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Characteristics and exploration potential of coal rock gas reservoirs in Carboniferous-Permian in Yichuan area, Ordos Basin
HUANG Li, ZHAO Longmei, CHEN Dong, ZHAO Haoyang, ZHANG Yixin, SHI Shi, ZHANG Wen, JI Liang
2026, Vol.38(5): 40–50
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Structural characteristics and formation mechanisms of Bashituopu Fault in southwestern Tarim Basin
WANG Bin, CHEN Lihao, YANG Liangang, QU Yang, YANG Pengfei, TIAN Lei, WANG Hongbin, LIU Jun
2026, Vol.38(5): 51–59
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Fault evolution characteristics and their control on reservoirs of Zitong area, Sichuan Basin
JIN Zhimin, ZHANG Benjian, GUAN Xu, WANG Xiaojuan, FENG Chang, WU Changjiang, YANG Ke, MA Shijie
2026, Vol.38(5): 60–70
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Sedimentary characteristics and favorable reservoirs distribution of the first member of Leikoupo Formation in Middle Triassic， central Sichuan Basin
QING Chun, WU Xueyan, TANG Song, LIU Bowen, GAN Wenjie, YU Yan, LIANG Xinyu, LIAO Yue
2026, Vol.38(5): 71–82
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Seismic identification and favorable exploration zones of thin interbedded dolomite reservoirs in the fourth member of Triassic Jialingjiang Formation, southwestern Sichuan Basin
LI Suhua, XIAO Bin
2026, Vol.38(5): 83–93
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Reservoir characteristics and main controlling factors of interlayered shale oil in Triassic Chang 7 member of Tiebiancheng area， Ordos Basin
ZHANG Weigang, LIU Guanglin, WANG Yong, NING Fan, MA Shaohui, YAN Baiquan
2026, Vol.38(5): 94–103
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Simulation experiment on shale oil micro-migration of upper submember of the fourth member of Shahejie Formation in Paleogene of Minfeng Subsag, Dongying Sag
CHEN Yumao, LI Bin, LIU Haojie, YANG Hongwei, GAI Shanshan, HOU Qingjie, DENG Taiyu
2026, Vol.38(5): 104–114
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Application of full-azimuth migration imaging method for weak anomaly extracting and identifying in fractured-vuggy carbonate reservoirs
MU Jie, SHI Feizhou, GAO Yuhang, CHEN Shenghong, ZHU Bohua
2026, Vol.38(5): 115–124
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Sedimentary characteristics and exploration potential of the large-scale channel belt in Shan23 submember of Yan’an-Ganquan area, Ordos Basin
FAN Yujie, WAN Yongping, PU Renhai, SHE Yinnan, CUI Hongjun, GAO Xiaoping
2026, Vol.38(5): 125–135
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Evaluation methods and applications of pore structure characteristics in volcanic rock reservoirs：A case study of Carboniferous in the northern section of Hongche fault zone， Junggar Basin
SONG Yulin, FU Jian, XU Yifan, HAN Junwei, HUANG Cheng, ZHOU Huafeng, YANG Xiaofan
2026, Vol.38(5): 136–148
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Evaluation of fault sealing and trap effectiveness of Kaiping Sag, Pearl River Mouth Basin
CAI Junjie, LI Yaqi, GAO Zhongliang, JIANG Fujie, JIANG Dapeng, NIU Peng, HAO Mianzhu
2026, Vol.38(5): 149–158
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Intelligent seismic prediction method for porosity of coal rock gas reservoirs based on hybrid random forest: A case study of Carboniferous Benxi Formation 8# coal in northern Mizhi area, Ordos Basin
ZHAO Sen, CHEN Sheng, LI Xinyu, DU Wenhui, WANG Xiujiao, YANG Hao, LI Yandong, DAI Chunmeng
2026, Vol.38(5): 159–169
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Experiment on the fracability of coal rocks based on CT scanning and 3D reconstruction
ZENG Fanhui, YANG Weixin, GUO Jianchun, ZHANG Yu, ZHANG Ran
2026, Vol.38(5): 170–178
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Origin and genesis of formation water in shale oil reservoirs of Paleogene Shahejie Formation in Lijin sub-depression, Dongying Sag
SHEN Chen, SUN Yu, ZHANG Yujie, ZHU Qingli, HUO Fei, CAO Weidong, LIU Xiaoliang, SHEN Yuniang
2026, Vol.38(5): 179–190
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Prediction method for coalbed methane deliverability of Permian Taiyuan Formation in Shenfu block, Ordos Basin
LI Xinze, WU Hao, CHAO Jiahao, LI Na, WANG Suran, BAI Yuhu, FENG Ruyong, CHENG Jialu
2026, Vol.38(5): 191–200
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Influence mechanism of salt minerals on large-scale hydrocarbon generation from low-abundance source rocks: A case study of Paleogene Xiaganchaigou Formation in western Qaidam Basin
WANG Bo, ZHOU Fei, TIAN Jixian, ZHANG Jing, ZHANG Tong, QI Yonggang, QIAO Baihan, FENG Dehao
2026, Vol.38(5): 1–9
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doi: https://doi.org/10.12108/yxyqc.20260501
Paleogene-Neogene saline lacustrine basin source rocks in western Qaidam Basin are with relatively low abundance organic matter, but multiple large-scale oil and gas reservoirs have been discovered. Saline inorganic minerals in source rocks have important impacts on the hydrocarbon generation of low abundance source rocks. Through conducting simulation experiments on hydrocarbon generation from organic matter with NaCl, the influence of inorganic salts on hydrocarbon generation from organic matter in Paleogene of western Qaidam Basin was systematically evaluated, influence machenism of salt minerals was clarified, and the hydrocarbon generation model for saline lacustrine basins was established. Research results show that: （1） Paleogene-Neogene saline minerals in western Qaidam Basin are developed, with rock salt, gypsum, and glauberite as the main types, and with single layer thicknesses ranging from several centimeters to over ten meters. Salt layers are interbedded with source rock organic matters, which provides favorable conditions for the catalytic effect of salt substances. （2） Thermal simulation experiments have confirmed that the addition of chloride salts significantly promotes the hydrocarbon generation of source rocks, which can significantly enhance the generation of liquid hydrocarbons in the oil window stage and gaseous hydrocarbons in the gas window stage. With the increase of salinity, the peak yields of gaseous and liquid hydrocarbons gradually increase, and the cracking rate of liquid hydrocarbons accelerates simultaneously. （3） During the pyrolysis process of kerogen, the addition of chloride salts clearly reduces the breaking energy of C-C and C-H bonds in kerogen molecules, thereby enhancing hydrocarbon generation. The underlying mechanism may involve the alteration of molecular surface charge distribution through electronic induction effects, which accelerates specific reaction pathways and influences the pyrolysis reaction rate of kerogen. （4） Compared with the conventional hydrocarbon generation model, source rocks in saline environments have the characteristic of early hydrocarbon generation. The hydrocarbon generation of shallow soluble organic matter and deep kerogen follow a relay. When Ro is 0.5%, the secondary peak of soluble organic matter oil generation occurs, and when Ro is 0.9%-1.1%, the peak of kerogen oil generation occurs. The participation of saline substances greatly promotes the hydrocarbon generation efficiency of organic matter, ultimately achieving large-scale hydrocarbon generation from low abundance source rocks, which enable source rocks from saline lacustrine basins of western Qaidam Basin to generate a large amount of oil and gas even under the condition of low organic matter abundance.
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Pre-Jurassic source rock evolution features and hydrocarbon accumulation process in Taibei Sag, Turpan-Hami Basin
CHEN Xuan, YANG Bin, ZHANG Hua, GOU Hongguang, HU Jun, FU Guobin, HAO Bin, CHENG Yi
2026, Vol.38(5): 10–22
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doi: https://doi.org/10.12108/yxyqc.20260502
Taibei Sag in Turpan-Hami Basin is controlled by the structural framework of a large-scale wedge body, the pre-Jurassic deep to ultra-deep strata feature complex hydrocarbon accumulation process. Taking the pre-Jurassic strata with burial depth greater than 4 700 m in well LT1 of Taibei Sag as the research object, based on TOC content analysis, rock-eval pyrolysis, saturated hydrocarbon chromatography-mass spectrometry and hydrocarbon carbon isotope analysis, source rocks were evaluated and hydrocarbon origins were clarified. The thermal evolution of pre-Jurassic source rocks and hydrocarbon accumulation processes in Taibei Sag were reconstructed through fluid inclusion thermometry and basin modeling. The results show that: （1） Three sets of mode-rate to good source rocks,such as Upper Triassic Huangshanjie Formation mudstone, Lower Jurassic Lower Ba-daowan Formation coal-measure rocks, and Middle Permian Taodonggou Group mudstone, are developed in pre-Jurassic strata of Taibei Sag. Lower Badaowan Formation coal-measure rocks, and Middle Permian Taodonggou Group mudstone have entered the high-mature to over-mature evolution stage, with better hydrocarbon generation potential. （2） In the study area, pre-Jurassic crude oil is mainly sourced from Taodonggou Group lacustrine mudstone in the deep sub-sag of the northern piedmont of Taibei Sag. Natural gas is a mixture of coal-type gas and oil-type gas, which is predominantly contributed by Lower Badaowan Formation coal-measure source rocks. （3） The development of the large-scale wedge body has significantly modified the tectonic evolution, burial history and thermal evolution process of source rocks in the study area, forming three episodes of hydrocarbon accumulation and adjustment. In Middle Jurassic, source rocks of Taodonggou Group generated hydrocarbons on a large-scale, and hydrocarbons accumulated in near-source low-amplitude structures in the deep sub-sag, or migrated to higher positions along faults and detachment layers. At the end of Jurassic, the wedge body deve-loped, part of the early accumulated hydrocarbons migrated and adjusted during the wedging formation, and accumulated in Badaowan Formation reservoirs, with minor hydrocarbon charging from Taodonggou Group. After wedging, increased burial depth of Lower Badaowan Formation source rocks induced large-scale gas generation in Early Cretaceous, and natural gas charged into tight reservoirs of Badaowan Formation.
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Geological characteristics and exploration & development potential of Mesozoic composite lithologic gas reservoirs in Samandepe Gas Field, right bank of Amu Darya
LENG Youheng, YANG Yadong, WANG Qiang, LI Yunzhu, WEI Zhanjun, HUANG Feng, XUE Taofeng, LIU Yang
2026, Vol.38(5): 23–39
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doi: https://doi.org/10.12108/yxyqc.20260503
To extend the production life of Samandepe Gas Field, it is necessary to explore potential strata. Based on the Navigation Pyramid seismic processing technology, differences of hydrocarbon accumulation pathways, enrichment patterns, and development characteristics among three gas-bearing series, such as the shallow Aptian tight sandstone, the middle Callovian-Oxfordian carbonate rock, and the deep Middle-Lower Jurassic tight sandstone were systematically analyzed. A well-seismic joint quantitative evaluation method was adopted to carry out potential assessment and differentiated potential-tapping strategy studies for multi-layer gas reservoirs. The results show that: （1） Three gas-bearing series in Samandepe Gas Field exhibit differentiated accumulation models and enrichment patterns. Shallow series, controlled by both structure and lithology, are far-source secondary accumulation with localized weak enrichment. Middle series are lower-generation and upper-storage integral gas reservoirs, where the remaining gas is shielded by facies changes and interlayers, characterized by edge enrichment and scattered distribution in the main body. Deep series are self-generation and self-storage tight sandstone gas reservoirs with large-scale contiguous gas-bearing properties, and “sweet spots” are jointly controlled by high-quality sand bodies and fractures. （2） The differentiated potential-tapping scheme for the abovementioned three series in the study area is as follows: Precisely tapping of remaining gas in middle series (predicted remaining geological reserves of 256.27×108 m3) as core task; rapid production build-up by adding perforations in shallow series (predicted geological reserves of 56.90×108 m3) as near-term production replacement; and geology-engineering integrated evaluation for vertical well exploration in deep series (predicted geological reserves of 2 126.00×108 m3) as the backup plan. It is estimated that a new deliverability of 27.49×104 m3/d can be established, with a cumulative incremental gas production of 64.13×108 m3.
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Characteristics and exploration potential of coal rock gas reservoirs in Carboniferous-Permian in Yichuan area, Ordos Basin
HUANG Li, ZHAO Longmei, CHEN Dong, ZHAO Haoyang, ZHANG Yixin, SHI Shi, ZHANG Wen, JI Liang
2026, Vol.38(5): 40–50
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doi: https://doi.org/10.12108/yxyqc.20260504
Taking the No. 8 coal seam of Carboniferous Benxi Formation and the No. 5 coal seam of Permian Shanxi Formation in Yichuan area of Ordos Basin as the research targets, based on core experiment indicators such as coal composition, total sulfur content, vitrinite reflectance, gas content, and combined with well logging interpretation data, the petrology, physical properties, adsorption performance, and microfracture development characteristics of these two coal seams were systematically analyzed. Furthermore,favorable areas for coal rock gas were evaluated and predicted. The results show that: （1） The No. 8 coal seam and the No. 5 coal seam in Yichuan area are highly similar in terms of coal body structure, coal rock quality, and thermal evolution degree. Both of them are dominated by primary structural coal, with coal ranks reaching lean coal to anthracite stage, strong hydrocarbon generation potential, and average Ro values of 2.31% and 2.24%, respectively. Pore types are mainly organic matter pores, with micropore volume accounting for more than 67% of the total pore volume, and the specific surface area contribution rate exceeding 99%, which are the main space for adsorbed gas occurrence. （2） The resource abundance, reservoir thickness, and top layer sealing performance of the No. 8 coal seam in the study area are superior. The cleat and microfractures of the No. 5 coal seam are more developed. During the development, it is necessary to expand the spacing between development wells, reduce single-well production allocation, and control the fracturing scale to avoid interwell interference and formation pressure migration issues. （3） The western part of the study area is a Class Ⅰ “sweet spot”area shared by the two coal seams.The coal seam thickness of the area is greater than 5 m, the thermal evolution degree, gas content, and compressibility are all good, and the top and bottom limestone and mudstone combinations remain good sealing conditions and weak hydrodynamic forces, providing favorable conditions for vertical three-dimensional development.
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Structural characteristics and formation mechanisms of Bashituopu Fault in southwestern Tarim Basin
WANG Bin, CHEN Lihao, YANG Liangang, QU Yang, YANG Pengfei, TIAN Lei, WANG Hongbin, LIU Jun
2026, Vol.38(5): 51–59
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doi: https://doi.org/10.12108/yxyqc.20260505
Based on high-precision 3D seismic data, geometric characteristics of Bashituopu Fault in southwestern Tarim Basin are redetermined. Taking the F1 strike-slip fault and Bashituopu thrust fault on the top surface of Ordovician carbonate rocks as geological prototypes, a sandbox physical simulation model was constructed to systematically analyze the fault evolution mechanism and its controlling effect on hydrocarbon accumulation, and predict favorable exploration zones.The results show that: （1） Bashituopu fault zone is a steeply dipping strike-slip and thrust composite fault, with NE-trending transtensional strike-slip faults prominently developed. The thrust faults sections have a dip angle of 50°-65°, and the faults detach along Middle Cambrian gypsum-salt layer, presenting a typical structural feature of “lower fault and upper fold”. （2） The fault morpho-logy is controlled by the superposition of multi-stage and multi-direction compressive stress. During Caledonian period, NE-trending compression from the West Kunlun formed the prototype of strike-slip faults. In the Early Hercynian period, under SW-NE principal compressive stress, basement faults were reactivated and transformed, and large-scale strike-slip structures developed. From Late Hercynian to Indosinian period, intense SWW compression from the South Tianshan shifted the stress field from transtension to transpression, forming strike-slip and thrust composite faults, which is highly consistent with 3D seismic interpretation results. （3） The fault zone controls three stages of hydrocarbon accumulation evolution. Hydrocarbons accumulated in Cambrian subsalt strata in Caledonian period. In the Hercynian period, source-connected strike-slip faults transported hydrocarbons to Ordovician strata, forming paleo-oil reservoirs via lateral migration along unconformities,and during Himalayan period, structural adjustment transformed them into residual oil reservoirs. Multi-stage fault activities dominate hydrocarbon segmented enrichment. Fault fractures improve reservoir porosity and permeability, suprasalt thrust faults control trap morphology, segmented strike-slip faults construct charging pathways, reservoirs in high fault strain zones have optimal quality. Comprehensive analysis suggests that the eastern “beaded” reflection zone developed in deep F2 fault and secondary faults, and the source-connected strike-slip fault zone in Qungu 2 well area of Donghe sandstone intervals on the southern flank of the shallow structure, are core favorable exploration targets.
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Fault evolution characteristics and their control on reservoirs of Zitong area, Sichuan Basin
JIN Zhimin, ZHANG Benjian, GUAN Xu, WANG Xiaojuan, FENG Chang, WU Changjiang, YANG Ke, MA Shijie
2026, Vol.38(5): 60–70
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doi: https://doi.org/10.12108/yxyqc.202600506
Based on 3D seismic, core, well logging and dynamic production data of Zitong area in Sichuan Basin, the fault spatial structure and segmented activity patterns were precisely characterized, the fault evolution process was restored, and the mechanism of fault controls reservoir was analyzed.The results show that: （1） Two sets of NW-trending main faults are developed in the northeast part of Zitong area, which extend continuously in the deep layer and are distributed in segmented en-echelon patterns in the shallow layer, showing inhe-rited development and multi-stage activity characteristics. During the depositional period of the third member of Xujiahe Formation,the fault activity intensity of Weicheng No. 1 fault zone is strong in the west and weak in the east. It experienced segmented thrusting first and then strike-slip connection. During the fourth member of Xujiahe Formation, the fault activity attenuated and the fault system achieved complete through-going connection. Laoguanmiao structural belt is dominated by thrust faults, with domino-style and convergent fault assemblages developed. （2） The fault evolution in the study area primarily experienced five stages. Initially, minor pre-existing strike-slip faults were reactivated during the Indosinian Phase Ⅱ. Subsequently, thrust faults formed during Indosinian Phase Ⅲ, followed by the development of dextral en-echelon (left-stepping) strike-slip faults during Indosinian Phase Ⅳ. During Jurassic tectonic quiescent period, the stress attenuated, leading to stable sedimentation. Finally, Himalayan compression induced small-scale faulting and shaped the definitive structural framework of the entire region. （3） The third member of Xujiahe Formation, the primary reservoir in the study area, is a tight sandstone reservoir with low porosity and low permeability, where dissolution pores and filled fractures are well-developed. Fractures significantly enhance the reservoir permeability, and segmented activities of fault and differential folding structures control the reservoir distribution. （4） Hydrocarbon deliverability of the third member of Xujiahe Formation in the study area is co-controlled by the distance to faults, structural positions of folds, fault activity stages. Consequently, three types of thrust-fold reservoir-controlling models are established: broad fold, transitional fold, and tight fold models. The structural forelimbs of folds and zones with well-developed secondary faults constitute favorable areas, whereas the late-stage fault reactivation tends to tri-gger hydrocarbon dissipation. Weicheng No. 1 fault zone and its peripheries are identified as the most promising targets for natural gas exploration in the third member of Xujiahe Formation.
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Sedimentary characteristics and favorable reservoirs distribution of the first member of Leikoupo Formation in Middle Triassic， central Sichuan Basin
QING Chun, WU Xueyan, TANG Song, LIU Bowen, GAN Wenjie, YU Yan, LIANG Xinyu, LIAO Yue
2026, Vol.38(5): 71–82
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doi: https://doi.org/10.12108/yxyqc.20260507
Based on core observation， thin section identification， and logging facies analysis， a sedimentary facies classification scheme for the first member of Leikoupo Formation（Lei 1 Member）in Middle Triassic of central Sichuan Basin was established. Through cross-well profiles correlation， the distribution and evolution of sedimentary facies are systermatically analyzed. From dual perspectives of conventional and unconventional oil and gas fields， favorable reservoir zones were delineated. The results show that：（1） Lei 1 Member in central Sichuan Basin mainly develops evaporative platform and restricted platform，which can be further divided into three subfacies （evaporative tidal flat， restricted tidal flat， and intra-platform shoal） and six microfacies （gypsum flat， gypsiferous dolomite flat， dolomite flat， limestone flat， argillaceous dolomite flat， and grain shoal）. （2） Sedimentary evolution of the study area was jointly controlled by paleostructure, paleogeomorphology， and sea level changes， exhi-biting the staged sedimentary evolution sequence of “shoal and flat developed in the early stage， and evaporation enhanced in the late stage”. During the deposition of Lei 11 submember， the basin was characterized by a topography of “high west and low east” with a relatively high sea level， developing dolomite flats and grain shoals in a restricted platform setting. During the deposition of Lei 12 submember， the climate turned arid and sea level fell， leading to widespread gypsiferous dolomite flats， increased terrestrial argillaceous material input. The depositional system evolved into an evaporite‑dominated saline system， constituting a regressive sequence. （3） Reservoir characteristics in the study area show obvious stratification differences. Lei 11 submember is dominated by facies‑ controlled conventional reservoirs of grain shoals and dolomite flats， with reser-voir lithologies consisting of grain dolostone and crystalline dolostone， which were transformed into high‑quality reservoirs through penecontemporaneous exposure， early karstification， and dolomitization. Lei 12 submember features “source‑reservoir integrated” unconventional argillaceous dolomite reservoirs， with the top and bottom sealed by gypsum layers， forming a closed hydrocarbon accumulation system. （4） Moxi area is the most favorable zone for grain shoal facies. The west and south parts of central Sichuan Basin are favorable for dolomite flat facies， and Pengyang area is the “sweet spot” for unconventional exploration of argillaceous dolomite flats.
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Seismic identification and favorable exploration zones of thin interbedded dolomite reservoirs in the fourth member of Triassic Jialingjiang Formation, southwestern Sichuan Basin
LI Suhua, XIAO Bin
2026, Vol.38(5): 83–93
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doi: https://doi.org/10.12108/yxyqc.20260508
To address the identification difficulty of thin dolomite reservoirs of the fourth member of Triassic Jia-lingjiang Formation in Jingyan area of southwestern Sichuan Basin, a set of seismic identification methods for thin reservoirs was proposed to clarify the distribution characteristics of dolomite reservoirs and gypsum non-reservoirs in the fourth member of Jialingjiang Formation. Based on the structural location, reservoir thickness, fault evolution, and hydrocarbon accumulation configuration relationship, favorable exploration areas were predicted. The results show that: （1） The proposed method identifies the development characteristics of dolomite reservoirs and gypsum rocks through well-seismic calibration. Based on forward modeling, the optimal dominant frequency for identifying thin reservoirs is determined to be 60 Hz. The seismic data is processed by amplitude-preserved denoising. With the help of compressed wavelet transform harmonic decomposition and compensating high-frequency components, the bandwidth is broadened to improve the resolution. Frequency-division seismic information is integrated to carry out high resolution nonlinear neural network porosity inversion, so as to improve the prediction accuracy of thin reservoirs. （2） After amplitude-preserved denoising and improving resolution, the seismic data matches well with the 60 Hz Ricker wavelet calibration results, allowing clear identification of the interfaces of each submember in the fourth member of Jialingjiang Formation and enabling detailed stratigraphic tracking. The high resolution porosity inversion results match well with logging porosity curves, with an absolute error of 0.02% and a relative error of 0.20% in the verification well. （3） The high-quality thick-layer (16-22 m) dolomite reservoirs in the study area are mainly developed in the lower submember of the fourth member of Jia-lingjiang Formation, and are mainly distributed in the south part of the study area on the plane. The non-reservoir layers such as gypsum and dolomite gypsum in the middle and upper submember of the fourth member of Jia-lingjiang Formation, with thickness of 50-80 m, can serve as effective cap rocks. （4） The study area has experienced multi-stage tectonic movements, with two sets of faults trending NW-SE and NE-SW mostly extending into Jialingjiang Formation. The fault evolution matches the periods when Cambrian and Permian source rocks generated and expelled hydrocarbons. The south part of the study area has high structural positions, thick dolomite reservoirs, developed hydrocarbon-source faults and fractures, well-preserved gas reservoirs condition, and optimal hydrocarbon accumulation conditions, making it the favorable exploration area.
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Reservoir characteristics and main controlling factors of interlayered shale oil in Triassic Chang 7 member of Tiebiancheng area， Ordos Basin
ZHANG Weigang, LIU Guanglin, WANG Yong, NING Fan, MA Shaohui, YAN Baiquan
2026, Vol.38(5): 94–103
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doi: https://doi.org/10.12108/yxyqc.20260509
Taking interlayered shale oil reservoirs of Triassic Chang 7 member in Tiebiancheng area of Ordos Basin as the research object， reservoir sedimentary characteristics， petrology features and pore characteristics were analyzed based on core observation， thin section and scanning electron microscope analysis， physical property testing， CT scanning， mercury injection capillary pressure measurement. By discussing the differential control effects of diagenesis on reservoir densification under different sedimentary settings and the influence of physical properties on oil-bearing capacity， the main controlling factors of reservoir “sweet spots”were clarified. The results show that：（1） Chang 7 member reservoirs in Tiebiancheng area are mainly developed sedimentary microfacies such as delta front subaqueous distributary channel， mouth bar and interdistributary bay. Reservoir lothologies are mainly feldspathic sandstone and lithic feldspathic sandstone, with feldspar and quartz as the dominant mineral components， accounting for 64.99% of the total mineral composition. The content of interstitial materials is high， dominated by carbonate cements and clay minerals， and the total volume fraction of matrix and cements is 16.15%. （2） The total areal porosity of reservoir in the study area is 2.55%， indicating an overall low development degree. Intergranular pores and feldspar dissolved pores serve as the dominant pore types， with areal porosities of 1.11% and 1.10%， respectively. The pore radii mainly range from 3 μm to 18 μm， and throat radii are mostly 0.3-15.0 μm， dominated by fine throats， and connected pores volume fraction is 81.88%. Reservoirs have an average porosity of 7.5% and an average permeability of 0.15 mD， belonging to tight reservoirs. （3） The densification degree of Chang 7 reservoirs in the study area is jointly controlled by sedimentation and diagenesis. Sedimentary environments govern the primary mineral composition， grain texture and initial physical properties of reservoirs， while diagenesis determines reservoir densification degree and reservoir capacity. Oil-bearing capacity is controlled by physical properties. The central parts of thick sandbodies formed by superimposed subaqueous distributary channels and mouth bars are favorable “sweet spot” intervals.
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Simulation experiment on shale oil micro-migration of upper submember of the fourth member of Shahejie Formation in Paleogene of Minfeng Subsag, Dongying Sag
CHEN Yumao, LI Bin, LIU Haojie, YANG Hongwei, GAI Shanshan, HOU Qingjie, DENG Taiyu
2026, Vol.38(5): 104–114
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doi: https://doi.org/10.12108/yxyqc.20260510
To address the unclear enrichment patterns and difficulty in sweet spot prediction of shale oil in upper submember of the fourth member of Shahejie Formation (Es4s) in Minfeng Subsag, Dongying Sag, a geological model of the shale petroleum system was constructed by integrating well-seismic data. By employing the Easy%Ro kinetic model and the percolation method, the thermal evolution history and micro-migration process of Es4s shale were simulated, respectively. And then the shale oil enrichment model was clarified and “sweet spot” zones were predicted. The results show that： （1） Source rocks of Es4s entered the low-maturity stage during the late deposition of Shahejie Formation, reached the maturity stage during the deposition of Dongying Formation, and attained the peak hydrocarbon generation stage during the deposition of Guantao Formation, with maturity of 0.5%-1.2%, indicating oil-prone characteristics. The simulated hydrocarbon generation conversion rate was 10%-90%.The hydrocarbon generation conversion rate in the lower part was significantly higher than that in the upper part of lower submember of Es4, while the upper part had lower hydrocarbon expulsion potential, with hydrocarbon primarily retained and adsorbed. （2） Shale oil micro-migration in the study area shows significant facies-controlled characteristics,with the mixed sedimentary facies zone containing considerably more shale oil than that in the feldspar-rich and lime-rich facies zones. Fluid potential simulation confirms the development of inhe-rited low-potential accumulation areas in the eastern (FY1-2HF well area) and western (FY1-4HF well area) parts of the study area, which aligns with the productivity of high-yield wells. （3） The shale oil enrichment model in the study area is characterized by “hydrocarbon source controlled by thermal evolution, enrichment controlled by laminae, and accumulation controlled by low uplifts”. The mixed sedimentary shale in the lower part of Es4s within the eastern and western salients was identified as the sweet spot.
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Application of full-azimuth migration imaging method for weak anomaly extracting and identifying in fractured-vuggy carbonate reservoirs
MU Jie, SHI Feizhou, GAO Yuhang, CHEN Shenghong, ZHU Bohua
2026, Vol.38(5): 115–124
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doi: https://doi.org/10.12108/yxyqc.20260511
To improve the identification accuracy of small- and medium-scale fractured-vuggy bodies in carbonate reservoirs, a method for weak anomaly extracting and identifying in fractured-vuggy carbonate reservoirs based on full-azimuth migration imaging was proposed. Two sets of velocity models were constructed, and the method was validated using model forward simulation data. It was then applied to fractured-vuggy carbonate reservoirs in Shunbei area of Tarim Basin. The results show that: （1） The proposed method obtained full-azimuth common dip gathers through full-azimuth angle domain migration. Based on differences of response characteristic of various geological bodies in full-azimuth common dip gathers, the dip filtering was applied to perform weighted scattering stacking on the gathers. Combined with logging data constrained parameters, the scattering signal extraction effect was balanced. （2） Different geological bodies exhibit distinct response characteristics in full-azimuth common dip gathers. Imaging points of continuous subsurface interfaces show a funnel-shaped structure, with energy gradually weakening toward both flanks from the imaging point. Response characteristics of independent subsurface scatterers and cross-section scattering points are approximately straight lines and horizontal yet discontinuous lines, respectively, with no significant differences in scattering energy among them. （3） Model forward verification demonstrates that the weighted scattering energy extraction method based on full-azimuth common dip gathers can effectively identify the “string of beads” response characteristics of fractured-vuggy bo-dies and breakpoint boundaries, amplify the real scattering energy of fractured-vuggy, and extract weak “string of beads”responses from high-energy events. The actual application in fractured-vuggy carbonate reservoirs of Shunbei area shows that the scale and amplitude strength of fractured-vuggy bodies displayed by the scattering imaging match actual drilling production data better than conventional methods, and variation trends of main and secondary faults reflected by its amplitude change rate attribute and coherence attribute are more consistent with the actual geological conditions.
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Sedimentary characteristics and exploration potential of the large-scale channel belt in Shan23 submember of Yan’an-Ganquan area, Ordos Basin
FAN Yujie, WAN Yongping, PU Renhai, SHE Yinnan, CUI Hongjun, GAO Xiaoping
2026, Vol.38(5): 125–135
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doi: https://doi.org/10.12108/yxyqc.20260512
Based on 3D seismic, logging, core and field outcrop data, sedimentary characteristics, sand body distribution, source rock distribution and sedimentary facies models of Shan2³ submember in Yan’an-Ganquan area of Ordos Basin were systematically analyzed, and the exploration potential was clarified. The results show that: （1） Shan2³ submember in Yan’an-Ganquan area was deposited under a marine-continental transitional setting, with a weak reducing sedimentary environment and obvious differentiation of hydrodynamic conditions. Its sedimentary system is dominated by delta plains, locally develops delta front. Sedimentary microfacies are mainly distributary channels, followed by underwater distributary channels and interdistributary bays,with marshes and sheet sands locally observed. Sand bodies are superimposed in multiple stages with good lateral connectivity, and gradually pinch out from north to south. （2） The distribution of sand bodies of Shan2³ submember in the study area exhibits a large north-south trending channel belt, with a width of 10-15 km and a length of 50-60 km. Within the channel belt, sand bodies are developed on a large scale, with a thickness of 15-20 m,and mostly composed of 2 to 3 superimposed sandstone layers, thick in the central part and thinning toward the east and west sides. Outside the channel belt, sand bodies are mostly superimposed thin-layer sandstones, with thicknesses of 5-7 m. The thickness of Shan2³ submember sand bodies shows an inverse correlation with that of Taiyuan Formation. （3） Source rocks in the study area are mainly coal seams and dark mudstones. Their distribution is controlled by the channel belt, showing spatial differences both inside and outside the channel belt as well as north-south differentiation. Source rocks are sporadically developed within the channel belt but enriched on its flanks, showing thickness pattern of thick in the south and thin in the north. （4） The sedimentary facies model of Shan2³ submember in the study area is as follows: In the late depositional stage of Taiyuan Formation, large-scale regression occurred, the north-south trending fluvial-deltaic provenance system advanced towards southeastern Ordos Basin and intensely scoured the limestone of Taiyuan Formation, developing a large delta plain distributary channel belt in Shan2³ submember in the central part of the region. Residual seawater in low-lying areas on the east and west sides formed lakes and marshes,which received clastic sediments from tributary channels, forming a sedimentary system of marsh facies and small-scale delta front underwater distributary channel.
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Evaluation methods and applications of pore structure characteristics in volcanic rock reservoirs：A case study of Carboniferous in the northern section of Hongche fault zone， Junggar Basin
SONG Yulin, FU Jian, XU Yifan, HAN Junwei, HUANG Cheng, ZHOU Huafeng, YANG Xiaofan
2026, Vol.38(5): 136–148
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doi: https://doi.org/10.12108/yxyqc.20260513
Taking Carboniferous volcanic reservoir in the northern section of Hongche fault zone in Junggar Basin as an example， the volcanic lithology， physical properties and reservoir space types were analyzed. The pore structure was classified based on the capillary pressure curve characteristics， and the pore size distribution index （λ） was introduced to achieve quantitative characterization of the pore structure. The control effect of λ on the relative permeability of oil-water two-phase and hydrocarbon charging efficiency was clarified. By screening the optimal logging sensitive parameters through correlation， combining linear fitting and Powell algorithm optimization modeling， a quantitative logging prediction method for λ was constructed and applied to reservoir evaluation in the study area.The results show that：（1） Carboniferous volcanic rocks in the northern section of Hongche fault zone are mainly composed of basalt， andesite， tuff， volcanic breccia and volcaniclastic sedimentary rocks. The overall reservoir is medium-low porosity and low-permeability， with poor porosity-permeability correlation， and the reservoir space is a composite pore-fracture system consisting of secondary pores and fractures. The storage space is a pore fracture composite system composed of secondary pores and fractures.（2） The pore structures of volcanic reservoirs in the study area can be classified as three types：Type Ⅰ capillary pressure curve shows a gentle-slope， and is dominated by volcanic breccia， with the best pore structure and seepage performance. Type Ⅲ capillary pressure curve exhibits a steep-slope， and is mainly composed of basalt and andesite， with the poorest reservoir physical properties. And Type Ⅱ is intermediate between Type Ⅰ and Type Ⅲ， is dominated by tuff and volcaniclastic sedimentary rocks.The λ values of three types of reservoirs decrease sequentially， and the homogeneity degree of pores declines gradually. （3） The λ values can quantitatively characterize the homogeneity degree of pore size and fluid mobility. A larger λ value indicates higher pore homogeneity， better pore structure， superior reservoir seepage performance and higher hydrocarbon charging efficiency. （4） The multi-parameter prediction formula for λ has reliable accuracy， with an average relative error of merely 0.13. The reservoir evaluation results obtained from predicted λ values of actual wells are highly consistent with the conclusions of gas logging and oil testing.
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Evaluation of fault sealing and trap effectiveness of Kaiping Sag, Pearl River Mouth Basin
CAI Junjie, LI Yaqi, GAO Zhongliang, JIANG Fujie, JIANG Dapeng, NIU Peng, HAO Mianzhu
2026, Vol.38(5): 149–158
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doi: https://doi.org/10.12108/yxyqc.20260514
Due to the low exploration degree and the complex fault system of Kaipingnan Oilfield, it is urgent to clarify the differential fault sealing and trap effectiveness. Based on the review of fault system characteristics and trap types, the vertical and lateral sealing capacities of faults in four major structural belts within the study area were systematically evaluated by using the shale smear factor (SSF) method and the shale gouge ratio (SGR) attribute. Integrating trap closure amplitude, hydrocarbon column height, trap area and predicted effective trap area, grading and classification criteria for trap effectiveness evaluation were established, and the effective trap range was determined. The results show that: （1） The fault system in Kaiping Sag exhibits multi-phase activity characteristics. Wenchang Formation mainly develops NEE to near EW trending faults, while Enping Formation develops NNE, near EW and NW trending faults. Trap types mainly include antithetic fault traps, cross-fault block traps, and self-sealing traps. （2） The critical value of SSF for vertical sealing of fault in oil-bearing intervals of Kaiping Sag is 2.3. SSF values in 11-3 and 11-4 structural belts are less than 2.3, indicating good vertical fault sealing conducive to hydrocarbon preservation. In contrast, SSF values in the northern area (11-1 structural belt) and the western slope (10-1 structural belt) exceed 2.3, suggesting that cap rocks have been damaged and with leakage risk. The lower limit SGR value for lateral fault sealing is 26%. The average hydrocarbon column heights that can be sealed by trap-bounding faults in 11-3 and 11-4 structural belts are 90 m and 75 m, respectively. The lateral sealing capacity of trap-bounding faults in 11-3 structural belt is slightly higher, with small traps scale (trap area rangs from 0.28 km2 to 6.76 km2, predicted effective trap area is 0.22-2.90 km2), but exhibit relatively large closure amplitudes (being 32-296 m, over 60% of samples exceeding 50 m). （3） According to trap effectiveness, traps in the study area are classified into three levels from high to low: Level Ⅰ, level Ⅱ, and level Ⅲ. 6 level Ⅰ traps developed in 11-3 and 11-4 structural belts, accounting for over 60% of all evaluated traps, and there are 7 level Ⅱ traps. Among them, trap B1 and trap E1 in 11-3 structural belt are priority targets for exploration deployment.
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Intelligent seismic prediction method for porosity of coal rock gas reservoirs based on hybrid random forest: A case study of Carboniferous Benxi Formation 8# coal in northern Mizhi area, Ordos Basin
ZHAO Sen, CHEN Sheng, LI Xinyu, DU Wenhui, WANG Xiujiao, YANG Hao, LI Yandong, DAI Chunmeng
2026, Vol.38(5): 159–169
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doi: https://doi.org/10.12108/yxyqc.20260515
To address the problem that conventional methods are insufficient for accurately characterizing high‑porosity reservoirs in Carboniferous Benxi Formation 8# coal in northern Mizhi area of Ordos Basin, a “classification‑regression” two‑stage collaborative hybrid random forest porosity prediction method was proposed by selecting sensitive seismic attributes based on Spearman rank correlation analysis, and constructing a low‑redundancy input feature set. It was then compared with six conventional methods. The results show that:（1） The hybrid random forest porosity prediction method uses a class‑balanced classifier to identify invalid va-lues and output their probabilities, introduces porosity‑segmented sample weights into the regressor training to incorporate weights of low‑, medium‑, and high‑porosity intervals into optimization, and adaptively adjusts the predictions through a probability‑weighted mechanism, which suppresses false high‑porosity anomalies in non‑reservoir sections while maintaining regression accuracy in reservoir sections. （2） On the blind well test set, determination coefficient（R2）of the hybrid random forest porosity predictions is 0.864 4, which significantly outperforms single‑attribute regression (0.720 4), multi‑attribute linear regression (0.766 5), XGBoost (0.717 5), conventional random forest (0.791 0), and SMOTE + random forest (0.771 3). In the low‑porosity background interval, the bias of the proposed method is only 0.416 4%, markedly lower than that of conventional random forest (0.829 8%) and XGBoost (0.881 6%), effectively suppressing false high‑porosity anomalies. In the sweet‑spot interval (porosity ≥ 6%), it also maintains a high prediction accuracy with an MAE of 0.703 8%. （3） Well‑tie profiles and planar prediction results demonstrate that the proposed method outperforms the compared methods in lateral reservoir continuity, sweet‑spot identification, and background control, and can accurately delineate the planar distribution characteristics of porosity of Benxi Formation 8# coal.
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Experiment on the fracability of coal rocks based on CT scanning and 3D reconstruction
ZENG Fanhui, YANG Weixin, GUO Jianchun, ZHANG Yu, ZHANG Ran
2026, Vol.38(5): 170–178
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doi: https://doi.org/10.12108/yxyqc.20260516
In response to the problem that conventional fracability evaluation methods for coalbed methane reservoirs are difficult to balance fracture morphology and flow connectivity, fracturing comparison experiments were conducted using a true triaxial hydraulic fracturing system on four groups of raw coal cubic specimens with dimensions of 200 mm×200 mm×200 mm under varying conditions of fracturing fluid, in-situ stress difference, and pumping rate. Combined with high-resolution CT scanning and 3D reconstruction technology, the fracture surface area was quantitatively obtained and the 3D fractal dimension was calculated. Fracability was defined as the total fracture surface area per unit modified reservoir volume, and effects of in-situ stress conditions and fracturing fluid type on fracture development characteristics were systematically analyzed. Research results show that: （1） With low viscosity and strong diffusivity, liquid CO2 can effectively increase pore pressure and reduce breakdown pressure, thus significantly improve the fracture complexity. Compared with clear water, liquid CO2 as a fracturing fluid reduces the initiation pressure by 13.8% and increases the fracture surface area by 50.1%. （2） Fracture complexity is highly positively correlated with the 3D fractal dimension, which can be used as an effective quantitative index to characterize reservoir fracability. （3） Under the same experimental conditions, when the horizontal principal stress difference decreases from 5.00 MPa to 3.00 MPa, reservoir fracability increases by 14.7%.When the pumping rate increases from 30 mL/min to 60 mL/min, reservoir fracability increases by 11.3%. Compared with water fracturing, liquid CO2 fracturing improves reservoir fracability by 50.7%.
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Origin and genesis of formation water in shale oil reservoirs of Paleogene Shahejie Formation in Lijin sub-depression, Dongying Sag
SHEN Chen, SUN Yu, ZHANG Yujie, ZHU Qingli, HUO Fei, CAO Weidong, LIU Xiaoliang, SHEN Yuniang
2026, Vol.38(5): 179–190
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doi: https://doi.org/10.12108/yxyqc.20260517
Flowback fluids from shale oil wells have multiple sources, making it difficult to identify the source and genesis of formation water. By analyzing major ion compositions, hydrochemical coefficients, δD-δ18O and 87Sr/86Sr isotopic characteristics of more than 350 flowback fluid samples from shale oil wells of Paleogene Shahejie Formation in Lijin sub-depression of Dongying Sag, together with geothermometric indicators, geochemical characteristics, sources, and genesis types of flowback fluids from different stata were systematically identified. Research results show that: （1） Es4s-Es3x submembers of Paleogene Shahejie Formation in Lijin sub-depression of Dongying Sag contain high salinity formation water. Water samples from Es4s submember mainly display a “sickle-shaped” pattern on Novak diagram,with Na/Cl ratios less than 1.0 and desulfurization coefficients mostly below 1.0, indicating that it was formed under long-term closed conditions and underwent strong evaporative concentration and intensive water-rock interaction. Some samples from Es4scs and Es3x submembers exhibit a “dart-shaped” pattern on Novak diagram, suggesting the existence of surface water (fracturing fluids) or shallow formation water. （2） Isotopic analyses indicate that samples from Es4scx significantly away from Global Meteoric Water Line (GMWL) on the δD-δ18O crossplot,which reflect isotopic composition characteristics controlled by evaporation concentration and closed burial environment. Their 87Sr/86Sr values range from 0.709 045 to 0.710 253, which are comparable to the strontium isotopic composition of seawater in early Eocene of Paleogene, suggesting that they are dominantly derived from primary sedimentary formation water. In contrast, samples from Es4scs-Es3x submembers are generally closer to GMWL and display relatively higher 87Sr/86Sr values (0.711 016-0.711 152), indicating significant influence of hydraulic fracturing fluids or shallow formation water mixing. （3） Sources and genesises of formation water in different strata of Paleogene Shahejie Formation in the study area exhibit diffe-rences. Formation water in the submember of Es4s is dominated by primary connate water formed under strongly reducing conditions and subsequently modified by dolomitization and albitization, whereas formation water in the submember of Es3x mainly comprises of mixed origin, resulting from interaction between paleo-saline lacustrine water and freshwater or surface water.
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Prediction method for coalbed methane deliverability of Permian Taiyuan Formation in Shenfu block, Ordos Basin
LI Xinze, WU Hao, CHAO Jiahao, LI Na, WANG Suran, BAI Yuhu, FENG Ruyong, CHENG Jialu
2026, Vol.38(5): 191–200
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doi: https://doi.org/10.12108/yxyqc.20260518
During the development of deep coalbed methane, significant variability exists in single-well production, which makes it difficult to predict the deliverability. Based on actual production data of deep coalbed methane from Permian Taiyuan Formation in Shenfu block of Ordos Basin, a research path of “data purification-pattern mining-model construction” was adopted to conduct deliverability evaluation and prediction methods. The results show that: （1） Three typical deliverability patterns are identified in Shenfu block of Ordos Basin: “high production-decline”, “production ramp-up-stable production-decline”, and “dewatering-production rampup-stable production-decline”, with “dewatering-production rampup-stable production-decline” being the dominant type for deep coalbed methane wells in this area. （2） Utilizing the dynamic screening method of deliverability controlling factors and integrating the monotonicity constraint mechanism of parameters on deliverability in seepage theory, a deliverability prediction model that considers both data patterns and seepage mechanisms was constructed. （3） The main controlling factors of deliverability exhibit dynamic evolution characteristics. Initial productivity is primarily controlled by geological factors, while productivity during the stable production period is significantly affected by engineering factors. The physical-constrained Random Forest prediction model achieves a prediction accuracy of 86%, which is 64.5% higher than that of conventional multivariate linear empirical formulas. Engineering optimization strategies proposed based on the model results have effectively increased the average single-well production in the block by nearly two times.