《Lithologic Reservoirs》
Published:01 January 2026
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Geological characteristics and genesis of trona deposit in Cretaceous Yixian Formation of Naiman Sag, Kailu Basin
HU Changhao, PEI Jiaxue, YANG Xue, CAI Guogang, FAN Jiaming, LI Li
2026, Vol.38(1): 1–12
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Development characteristics and main controlling factors of natural fractures of Jurassic Qigu Formation in Yongjin area， Junggar Basin
MENG Yang, CAO Xiaopeng, ZHAO Hao, YANG Minglin, LI Zhipeng, TIAN Zhenlei, WU Hongcui, JIANG Yue
2026, Vol.38(1): 13–25
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Reservoir formation condition and favorable areas optimization of coalbed methane of Jurassic Yaojie Formation in Yaojie mining area, Minhe Basin
MA Daibing, MA Wentao, HAN Wenyuan, CHEN Shangbin, GUO Xingxing
2026, Vol.38(1): 26–37
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Progress in high-frequency sequence stratigraphy of clastic lakes: Implications from ancient sedimentary sequences
ZAVALA Carlos, LIU Huaqing, LI Xiangbo, YANG Zhanlong, LI Yang, WANG Jing, TROBBIANI Valentin, ARCURI Mariano
2026, Vol.38(1): 38–54
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Evaluation method for oil saturation in low resistivity reservoirs based on random forest optimization algorithm
YIN Jiang, JIAO Xuejun, LI Xiaolong, LI Taifu, SHEN Zhanyong, LI Mengxi, SUN Rui, ZHU Yushuang
2026, Vol.38(1): 55–66
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Geological condition for coalbed methane accumulation of Permian Longtan Formation in the central part of Northwest Guizhou
YAO Jiayu, CAO Wenjie, WANG Wenqiang, MAO Lixin, LUO Bin
2026, Vol.38(1): 67–77
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Seismic prediction method for thin sandstone reservoirs in shallow water delta front： A case study of the second member of Jurassic Penglaizhen Formation in Western Sichuan Depression
TIAN Wenzhong, QIAO Lin, YUAN Jian, LI Xingwen, XIANG Lei, WANG Changcheng, LU Gang, LU Xihe
2026, Vol.38(1): 78–88
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Origin and accumulation mechanism of hydrocarbon of Oligocene Lingshui Formation in the southern slope of Baodao Sag, Qiongdongnan Basin
LIU Haiyu, LI Shanshan, GUO Xiaoxiao, LUO Wei, LIANG Gang, WANG Biwei
2026, Vol.38(1): 89–99
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Coal measure shale reservoir characteristics and exploration potential of Permian Leping Formation in Pingle Depression of Lower Yangtze region
XIAO Fuqiang, XIAO Weidong, JIANG Zhidong, GAO Lei, ZHAO Zhengwei, PAN Xiaofei, CHEN Fugui, ZOU Yongjun
2026, Vol.38(1): 100–114
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Reverse-time migration in TI media based on optical flow vector
FENG Yancang, LIU Wenqing, ZHANG Huixing, WU Jie, LI Dongsheng
2026, Vol.38(1): 115–125
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A method for assessing fault lateral sealing based on high-resolution geological modeling: A case study of Archean buried hill reservoir in Xinglongtai structural belt of Liaohe Depression
LI Bin, MIN Zhongshun, MENG Lingna, ZHANG Yuanli, YIN Jianfeng, ZHOU Peijie
2026, Vol.38(1): 126–135
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Characterization of fracture-cavity carbonate karst system and main controlling factors for hydrocarbon enrichment： A case study of Ordovician in Lungu Oilfield, Tabei area
GUAN Baozhu, WANG Aiping, YANG Xinying, PEI Mingli, WAN Chaofan, NI Xianglong, ZHANG Qiang, YANG Wei
2026, Vol.38(1): 136–145
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Paleogeomorphologic characteristics and sand control mechanisms of Cretaceous Shahezi Formation in Lishu fault depression, southern Songliao Basin
XIAO Meng, ZHOU Yong, WANG Ke, YAN Jingchi, ZHANG Yuejie
2026, Vol.38(1): 146–161
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Seismic prediction technology for coal rock gas reservoir of Carboniferous Benxi Formation in northern Mizhi area, Ordos Basin
ZHANG Mengbo, PENG Jiankang, CUI Xiaojie, ZHANG Dong, NI Na, LONG Shengfang, WEI Penghui
2026, Vol.38(1): 162–171
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Numerical simulation on the coupling of flow and geomechanics during CO2 huff and puff in shale oil reservoirs
ZHANG Qingfu, ZHANG Shiming, CAO Xiaopeng, LYU Qi, LI Zongyang, YU Jinbiao, WANG Yong
2026, Vol.38(1): 172–179
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Research progress on retention effects of pre-CO2 fracturing fluid of shale oil reservoirs
ZHANG Yanjun, LIU Zhengjun, XU Hao, HE Wenjie, LIU Yaru, XING Liang, ZHOU Desheng, WANG Zhen
2026, Vol.38(1): 180–190
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A new method for splitting the production of fractured horizontal wells in strong heterogeneous gas reservoirs:Taking Permian He1 member gas reservoir in Dongsheng Gasfield of Ordos Basin as an example
XUN Xiaoquan, LI Hongtao, LI Changping, YANG Fan, LIU Xiong
2026, Vol.38(1): 191–200
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Geological characteristics and genesis of trona deposit in Cretaceous Yixian Formation of Naiman Sag, Kailu Basin
HU Changhao, PEI Jiaxue, YANG Xue, CAI Guogang, FAN Jiaming, LI Li
2026, Vol.38(1): 1–12
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doi: https://doi.org/10.12108/yxyqc.20260101
Naiman Sag of Kailu Basin has developed unique trona deposit, which is paragenetically associated with salt and crude oil. Based on the data of seismic, logging data, drilling core laboratory analysis, the lithology assemblage, ore characteristics, deposit features and distribution patterns of the trona deposit in Cretaceous Yixian Formation were clarified. Meanwhile, the genesis and patterns of the deposit were investigated in terms of paleostructure, paleoclimate, sources of ore-forming materials, and their coupling relationships. The research results indicate that: (1) The Yixian Formation deposit of Cretaceous in Naiman Sag is characterized by deep burial, steep dip, fault development, thin individual layers and numerous interbeds. Ore body shape is approximately elliptical, with a north-south distribution direction and a lenticular distribution pattern featuring thickened centers and thinning edges. Two sedimentary sequences are developed: A soda-lake type sequence (mudstone-dolomite → trona → mudstone) dominates the deposit margins, while a saline-lake type sequence (mudstone-dolomite → trona → halite → trona → mudstone) prevails in the central zone. On the plane, trona-saline trona-salt distribute in an annular pattern. (2) The deposits are generally oil-bearing. Within mudstone layers, crude oil occurs in intergranular pores of fine clastics, inter-crystalline pores of clay minerals, fractures, and kerogen. In trona and salt layers, hydrocarbons primarily reside in mineral inter-crystalline pores and fractures, cleavage fractures, inclusions, and lattice defects. (3) The trona deposit in the study area is a ternary coupled mineral model of “paleogeomorphology-paleoclimate-volcanic activity”, the deposition of Yixian Formation constituted a closed lacustrine basin. Sodium ions (Na⁺) were continuously supplied to the basin by sodium-rich andesitic rocks in the periphery. The decomposition of organic-rich mudstone produces considerable CO2, which increases the concentration of CO2 in brine. The frequent volcanic activities during the Yanshan period led to the upwelling of deep-seated hydrothermal fluids and mantle-derived gas through faults, providing a large amount of CO2 and Na+ -rich hydrothermal fluid. A persistent arid climate towards the end of Yixian Formation resulted in extreme concentration of the lake water, reaching saturation and precipitating trona or halite. Subsequent diagenesis formed the present trona deposit.
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Development characteristics and main controlling factors of natural fractures of Jurassic Qigu Formation in Yongjin area， Junggar Basin
MENG Yang, CAO Xiaopeng, ZHAO Hao, YANG Minglin, LI Zhipeng, TIAN Zhenlei, WU Hongcui, JIANG Yue
2026, Vol.38(1): 13–25
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doi: https://doi.org/10.12108/yxyqc.20260102
The development degree of natural fractures is a critical factor affecting single-well productivity of Jurassic Qigu Formation in Yongjin area， Junggar Basin. Based on data of field outcrops， cores， thin sections， well logging and experiment， genesis types， development characteristics， and main controlling factors of natural fractures in tight sandstone of Qigu Formation were studied, and favorable development areas were predicted. The results show that：（1） Genesis types of natural fractures in tight sandstone reservoirs of Jurassic Qigu Formation in Yongjin area， Junggar Basin are various， mainly including diagenetic fractures， a small number of structural fractures and abnormal overpressure fractures. The diagenetic fractures are mainly bedding fractures， and a small number of marginal and intragranular fractures are developed. Natural fractures are one of the important factors in the formation of deep high-quality reservoirs. （2） The development of fractures in Qigu Formation in the study area is primarily controlled by sedimentation, tectonic stress， and overpressure. Sedimentary microfacies control the degree of fracture development by controlling factors such as lithology， mineral composition， and sedimentary structure. The medium-fine grained sandstone in the middle to upper parts of the diversion sand dam is a favorable location for fracture development. The near north-south structural compression stress during Himalayan tectonic period acts as a key driving force for the initiation and propagation of structural fractures and bedding fractures， and fractures are more developed within 1 km of the fault. Abnormal overpressure exerts a critical influence on the formation of overpressure fractures and bedding fractures， as well as the preservation of fractures. In the northern part of the study area， abnormal overpressure is highly developed， reservoir fractures are relatively developed. （3） The effective natural fractures of Qigu Formation in the study area primarily develop in the layered distributary sand dam in the northern part of the fault, where the pressure coefficient exceeds 1.6.
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Reservoir formation condition and favorable areas optimization of coalbed methane of Jurassic Yaojie Formation in Yaojie mining area, Minhe Basin
MA Daibing, MA Wentao, HAN Wenyuan, CHEN Shangbin, GUO Xingxing
2026, Vol.38(1): 26–37
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doi: https://doi.org/10.12108/yxyqc.20260103
Yaojie mining area in Minhe Basin has good exploration potential for coalbed methane. Using drilling, logging, and experimental testing data, the distribution and hydrocarbon generation capacity of coal seams in Yaojie mining area of Minhe Basin were systematically analyzed, and the coalbed methane accumulation condition and accumulation models of Jurassic No. 2 coal seam were clarified, and favorable areas were predicted. The results show that: （1） Yaojie mining area in Minhe Basin has been transformed by multi-stage tectonic movements, forming a coal-controlled fault of “first reverse and then positive”.The sedimentary facies are mainly river-swamp-lacustrine facies, No. 2 coal seam is distributed in a “thick in the east and thin in the west” belt shape and belongs to medium-stage fat coal, with longitudinal thermal evolution degree and vitrinite increa-sing with the increase of burial depth. The coal rock is dominated by semi-dark to semi-bright primary structural coal, with relatively developed pores but poor permeability. （2） The total mass volume of gas in the air-dried basis of No. 2 coal seam in the study area is 6.10-8.78 cm3/g, with an average of 7.53 cm3/g. The mass volume of methane is 1.18-6.72 cm3/g, with an average of 4.46 cm3/g. The gas component is dominated by CH4, CO2 and N2. Vertically, the proportion of CH4 increases as the burial depth increases and temperature-pressure rises. Horizontally, methane content shows a distribution pattern of high-values in the middle (Haishiwan syncline axis) and decreasing towards the north and south. （3） In the study area, the thickness of No. 2 coal seam is relatively large, mostly greater than 10 m, and No. 2 coal seam has a high degree of thermal evolution (Ro up to 1.12%), providing material foundation for coalbed methane enrichment. Vertically, increased vitrinite content and decreased ash content optimize storage conditions. Carbonaceous mudstone/mudstone roof/bed plates, sealed water bodies, boundary fault zones, and Haishiwan syncline jointly ensure the accumulation of coalbed methane. The areas with high thermal evolution degree, sufficient gas source, proximity to syncline core and far away from faults are geological class Ⅰ “sweet spot” zones.
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Progress in high-frequency sequence stratigraphy of clastic lakes: Implications from ancient sedimentary sequences
ZAVALA Carlos, LIU Huaqing, LI Xiangbo, YANG Zhanlong, LI Yang, WANG Jing, TROBBIANI Valentin, ARCURI Mariano
2026, Vol.38(1): 38–54
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doi: https://doi.org/10.12108/yxyqc.20260104
Sequence stratigraphic concepts and methods provide novel tools for performing stratigraphic analysis, allowing us to improve our understanding of depositional models and basin evolution. Main controls and depositional elements (e.g. surfaces, systems tracts, parasequences, etc.) recognized in conventional sequence strati-graphy are designed for marine-related systems. In contrast, the sequence stratigraphy of lacustrine successions is much more complex, because it is not driven by sea-level changes, but by a complex interaction between tecto-nics and high-frequency climatic cycles. Through systematic analysis of lacustrine sedimentary systems, the re-levant concepts of lacustrine sequence stratigraphy were clarified. The controlling effects of allocyclic cycles on lacustrine sedimentation and sequence stratigraphy, accommodation space types of lacustrine basins and their significance for sequence stratigraphy and hydrocarbon genesis were explored.The results show that： （1） The lacustrine sedimentary conditions can be classified as three types: Underfilled, balanced-fill and overfilled lakes. There are significant differences in water salinity, sedimentary sequences, and system tracts under different lacustrine sedimentary conditions. Underfilled lakes are hydrologically closed lakes, and consequently, the lake-level can highly fluctuate, driven by high-frequency wet-dry climatic cycles. During wet periods, rivers supply water and sediments, resulting in fining-and thinning-upward elementary depositional sequences (EDS) accumulated during the transgressive systems tract (TST). In contrast, dry periods are characterized by a relative lake-level fall with the subaerial exposure of lake margin areas during the regressive systems tract (RST). Lake water salinity are brackish to hypersaline. Balanced-fill lakes are partially closed lakes, and consequently, they have characteristics of both underfilled and overfilled lakes. During the TST, the lake is in underfilled condition, and consequently, the introduction of water and sediment will accumulate a fining-upward interval until reaching the spill point during the maximum flooding. The RST is accumulated under an overfilled lake condition, with coarsening-upward progradational littoral deltas and related subaqueous delta deposits. Lake water salinity are brackish to freshwater. Overfilled lakes are hydrologically open lakes. Most deposits accumulate during the RST, forming coarsening-upward progradational littoral deposits, with associated subaqueous deltas. All overfilled lakes are freshwater lakes. （2） Subsidence is crucial for allowing the long-term preservation of lacustrine depo-sits. Lakes can temporarily store water and sediments in areas that lack subsidence, but these deposits will not be preserved in the stratigraphic record. Subsiding lakes develop permanent accommodation space and hanging lakes develop temporary accommodation space. Although hanging lakes cannot permanently store sediments,they can flood subsiding lakes with the near-instantaneous release of a substantial volume of water, creating favorable conditions for the accumulation of organic-rich shales. This rapid flooding from hanging lakes induced a forced transgression (FT), which is a large-scale rapid transgression (xenoconformity) not related to the normal sediment and water supply from local source areas.
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Evaluation method for oil saturation in low resistivity reservoirs based on random forest optimization algorithm
YIN Jiang, JIAO Xuejun, LI Xiaolong, LI Taifu, SHEN Zhanyong, LI Mengxi, SUN Rui, ZHU Yushuang
2026, Vol.38(1): 55–66
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doi: https://doi.org/10.12108/yxyqc.20260105
To address the challenges in interpreting oil saturation in low resistivity reservoirs using conventional electrical logging methods, an evaluation method based on a random forest optimization algorithm was proposed, and was applied in low resistivity reservoirs of Jurassic Yan’an Formation, Huanqing area, Ordos Basin. The results show that: (1) An oil saturation interpretation model was established using random forest regression algorithm, the Nutcracker Optimizer Algorithm (NOA) was introduced to optimize the hyperparameter tuning of the random forest. By integrating core and logging data through machine learning training, an NOA-optimized random forest saturation model (NOA-RF) was established. (2) NOA method accelerates the training speed of the random forest model, it takes 26.17 minutes to identify the globally optimal hyperparameter combination,which is 36.18 minutes faster than conventional grid search. It also improves the fitting accuracy of the oil saturation model by 96.6%, outperforming grid search by 83.9% and Archie’s method by 45.2%. (3) NOA-RF model achieved a correlation coefficient up to 0.977 9 between predicted and core actual oil saturation in Huanqing area low resistivity reservoirs, with oil-water layer identification accuracy of 93.33%, representing 53.33% improvement over Archie’s method.
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Geological condition for coalbed methane accumulation of Permian Longtan Formation in the central part of Northwest Guizhou
YAO Jiayu, CAO Wenjie, WANG Wenqiang, MAO Lixin, LUO Bin
2026, Vol.38(1): 67–77
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doi: https://doi.org/10.12108/yxyqc.20260106
Northwest Guizhou hosts vast coal reserves and abundant coal-measure gas resources, demonstrating promising development prospect. Based on coal-proximate analysis, scanning electron microscope, isothermal adsorption, gas-composition analysis and gas-content measurements, reservoir formation condition of coalbed methane (CBM) of Permian Longtan Formation in the central part of Northwest Guizhou was studied from four aspects: gas-generation condition, reservoir properties, reservoir-cap assemblages and gas-bearing properties. The results show that: （1） Coal rocks in the central part of Northwest Guizhou are of high quality, mainly formed in water-inundated and humid settings. They are dominated by type Ⅲ organic matter, with an average organic matter abundance of 63.25%. Thermal maturity is high, with vitrinite reflectance (Ro) ranging from 2.54% to 3.50%, indicating strong hydrocarbon generation potential. （2） CBM in the study area is mainly methane,with dryness coefficient greater than 0.99，and mass volume of 5.68-20.12 cm³/g, exhibiting a distribution characteristic of “high in the north and low in the south”. （3） Coal rocks in the study area mainly develop three types of pore: intercrystalline pores, organic matter pores and microfractures. The reservoirs show strong adsorption capacity but weak seepage ability, and exhibit strong fracturing potential. （4） During the sedimentary period of Longtan Formation in the study area, two types （coal mudstone and coal siltstone） of reservoir-cap assemblages mainly formed under the influence of marine-continental transitional environment, which is the reservoir formation model of “self generation and self storage”.
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Seismic prediction method for thin sandstone reservoirs in shallow water delta front： A case study of the second member of Jurassic Penglaizhen Formation in Western Sichuan Depression
TIAN Wenzhong, QIAO Lin, YUAN Jian, LI Xingwen, XIANG Lei, WANG Changcheng, LU Gang, LU Xihe
2026, Vol.38(1): 78–88
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doi: https://doi.org/10.12108/yxyqc.20260107
By integrating seismic and logging interpretation data， a three-in-one characterization technology system for thin sandstone reservoir of “multi-scale seismic sedimentology analysis-logging constrained wave impe-dance inversion-sand body thickness verification” was established. And through seismic attribute analysis， frequency division RGB fusion， and waveform clustering analysis， the sedimentary microfacies and distribution of channel sand bodies of the second member of Jurassic Penglaizhen Formation in Western Sichuan Depression were cha-racterized. The results show that：（1） The reservoir of the second member of Jurassic Penglaizhen Formation in Western Sichuan Depression is mainly composed of underwater distributary channel sand bodies， with logging response feature of “low gamma box curve”， and seismic response feature of “a strong peak and corresponding strong valley reflection”. The establishment of an isochronous stratigraphic framework and isochronous comparisons of well-seismic consistency can improve the accuracy of stratigraphic interpretation. （2） The sedimentary microfacies of the second member of Penglaizhen Formation in the study area are mainly underwater distributary channels and distributary channel bays. JP33-1 sublayer is compopsed of underwater distributary channel deposits， with two channels developed： a northeast-southwest trending one and an east-west trending one. And the northeast-southwest trending channel is wider in development and greater in thickness， making it a key area for further exploration and development. （3） The underwater distributary channel sand bodies of the second member of Penglaizhen Formation in the study area exhibit the geophysical response characteristic of “medium-low impe-dance”.The integrated characterization technology system for thin sandstone reservoir of “multi-scale seismic sedimentology analysis-logging constrained wave impedance inversion-sand body thickness verification”can improve the accuracy of predicting sand body thickness， with correlation coefficient of 0.886 5 between inversion prediction thickness and logging interpretation thickness. The main channel sand body thickness is large， ranging from 10 to 20 m， and the distributary channel sand body thickness is small， ranging from 5 to 10 m.
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Origin and accumulation mechanism of hydrocarbon of Oligocene Lingshui Formation in the southern slope of Baodao Sag, Qiongdongnan Basin
LIU Haiyu, LI Shanshan, GUO Xiaoxiao, LUO Wei, LIANG Gang, WANG Biwei
2026, Vol.38(1): 89–99
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doi: https://doi.org/10.12108/yxyqc.20260108
First dual breakthrough in oil and gas exploration have been achieved in Oligocene Lingshui Formation of the southern slope of Baodao Sag in Qiongdongnan Basin, demonstrating significant exploration potential. Based on the analysis and laboratory data of Y10-F structural oil-gas and source rock samples, combined with regional geological understanding, the geochemical characteristics, hydrocarbon sources, and reservoir formation characteristics of Oligocene Lingshui Formation of the southern slope of Baodao Sag in Qiongdongnan Basin were analyzed by using oil and gas geochemistry, fluid inclusion method, and basin simulation method. The results show that: （1） The crude oil from the southern slope of Baodao Sag exhibits characteristics of a partially reduced marine crude oil with low terrestrial input of higher plants and high input of marine algal, manifested as low Pr/Ph ratios (0.98-1.34), high sterane/hopane ratios(0.42-0.72), and heavier kerogen carbon isotope values (-26.04‰ to -24.47‰). Symbiotic natural gas exhibits typical condensate gas characteristics, with more contribution from sapropelic organic matter in its hydrocarbon parent material,which has low drying coefficient (0.85-0.92) and lighter ethane carbon isotope values (-29.56‰ to -28.18‰). （2） The crude oil in the study area is a product of the mature stage of hydrocarbon source rocks, while the associated natural gas is a product of the high mature stage. Both oil and natural gas originate from marine mixed hydrocarbon source rock formed by Oligocene reducing environment in Baodao Sag, and such source rock possesses oil and gas co-generation capacity. （3） Lingshui Formation oil and gas reservoir in the study area has the characteristic of two-stage of “early oil and late gas” filling and accumulation, and the late natural gas has the effect of evaporation and fractionation modification on the early crude oil. Controlled by differences in the distance between hydrocarbon source rocks of the sag and the development of conductors, different zones experience varying degrees of “evaporation and fractionation”. The northern block of Y10-F structure underwent strong evaporative fractionation, predominantly generating gas. The southern block was less affected by evaporative fractionation, and retained its primary reservoir capacity, forming the present-day distribution pattern of “oil in the south, gas in the north”.
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Coal measure shale reservoir characteristics and exploration potential of Permian Leping Formation in Pingle Depression of Lower Yangtze region
XIAO Fuqiang, XIAO Weidong, JIANG Zhidong, GAO Lei, ZHAO Zhengwei, PAN Xiaofei, CHEN Fugui, ZOU Yongjun
2026, Vol.38(1): 100–114
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doi: https://doi.org/10.12108/yxyqc.20260109
Upper Permian Leping Formation of Pingle Depression is an important coal measure strata in south China， with favorable conditions for the formation of coal measure shale gas reservoirs. Mineral composition， organic geochemical characteristics， pore types， pore structure， and influencing factors of pore development of Leping Formation coal measure shale reservoir in the west section of Pingle Depression were studied through testing methods， such as thin section identification， X-ray diffraction， organic geochemical analysis， scanning electron microscopy， high-pressure mercury intrusion， low-temperature N2 and CO2 adsorption， and exploration prospects of shale gas were explored. The results show that： （1） The coal measure shale of Permian Leping Formation in Pingle Depression of Lower Yangtze region is mainly composed of detrital grain， mud and charcoal， with high content of brittle minerals and good fracability. TOC content of coal measures shale is relatively high， kerogen types are Ⅱ1 and Ⅲ， and thermal evolution reaches high maturity to over maturity stage. （2） The porosity of shale is mostly 3.75%-4.67%， and the permeability is 0.006 2-0.009 1 mD， with low-porosity and low-permeability characteristics. The pore types are mainly intergranular pores， intragranular pores and microcracks， with fewer organic pores. （3） Average pore volume of shale is 0.020 2 cm3/g， average specific surface area is 15.02 m2/g. Mesopores contribute the most to the total pore volume， while micropores contribute the most to the total specific surface area. The pore size is characterized by “multi-peak” distribution. （4） Quartz and carbonate minerals can promote the development of mesopore and inhibit the development of micropores. The increase of quartz content reduces pore heterogeneity， and the increase of carbonate minerals improves pore heterogeneity. Clay minerals and organic matter can promote micropores development and inhibit mesopore development. Clay minerals increase pore heterogeneity， while organic matter strengthens pore homogeneity. （5） The coal measure shale in the study area exhibit good fracability， hydrocarbon generation potential， reservoir capacity， and with good preservation conditions. Yang-qiao， Fengcheng， Fujiaxu， and Taiyangxu are selected as favorable areas for coal measures shale gas exploration， with Fengcheng area being the primary target for further exploration.
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Reverse-time migration in TI media based on optical flow vector
FENG Yancang, LIU Wenqing, ZHANG Huixing, WU Jie, LI Dongsheng
2026, Vol.38(1): 115–125
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doi: https://doi.org/10.12108/yxyqc.20260110
When dealing with complex geological structures， the cross-correlation of back-propagated reflected waves with normally propagating wavefield in elastic reverse-time migration （RTM） generates strong-amplitude low-frequency noise. To address the issues of computational instability and insufficient accuracy of conventional Poynting vector-based traveling wave separation RTM algorithm， TI （transversely isotropic） media RTM method based on optical flow vector was proposed. By integrating optical flow theory with anisotropic elastic wave dynamics， through iterative computations， the proposed mothod obtains a more accurate vector that closely approximates the true wavefield propagation direction， effectively suppressing migration noise. The results show that：（1） The optical flow vector derived from the constant-wavefield assumption over adjacent time steps and the spatial smoothness assumption of wavefields in TI media eliminates the instability inherent in Poynting vectors， and accurately indicates the P-wave and S-wave propagation direction in TI media. （2） The traveling wave separation method based on optical flow vector can accurately decompose wavefields into up-， down-， left-， and right-traveling wave. （3） The optical flow vector-based TI media RTM algorithm effectively avoids cross-correlation imaging of wavefields along identical paths， and can suppress migration noise.
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A method for assessing fault lateral sealing based on high-resolution geological modeling: A case study of Archean buried hill reservoir in Xinglongtai structural belt of Liaohe Depression
LI Bin, MIN Zhongshun, MENG Lingna, ZHANG Yuanli, YIN Jianfeng, ZHOU Peijie
2026, Vol.38(1): 126–135
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doi: https://doi.org/10.12108/yxyqc.20260111
Allan diagram analysis is of great significance for the study of fault sealing. Taking Archean buried hill hydrocarbon reservoir in Xinglongtai structural belt of Liaohe Depression as an example, an improved Allan diagram method based on high-resolution geological modeling technology was proposed to analyze fault sealing by integrating well logging, 3D seismic, and experimental analysis and testing data. The results show that: （1） The high-resolution geological model established based on the well-seismic integration can address the issue of missing well-location data. Based on a detailed analysis of lithology development and fracture-forming capability in various regions of the metamorphic buried hill, the high-resolution geological model can accurately depict the stratigraphic contact relationship and lithology distribution pattern on both sides of the fault. After manual inspection and adjustment, the final improved Allan diagram can be formed. （2） There are six lithology docking patterns on the fault plane in the study area. The docking patterns with good sealing properties include breccia-mudstone, migmatite-mudstone, migmatite-gneiss, migmatite-breccia, and breccia-breccia. The peripheral faults F3 and F5 in the area are completely sealed, and the altitude of the leakage point in the area is -4 390 m. （3） Cross-verification was carried out by combining the fuzzy mathematics method and the on-site fluid distribution. The analysis results of each region were highly consistent with the lateral fault sealing analyzed by the improved Allan diagram method, indicating that the method shows excellent applicability and accuracy in metamorphic buried hills and has high application value.
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Characterization of fracture-cavity carbonate karst system and main controlling factors for hydrocarbon enrichment： A case study of Ordovician in Lungu Oilfield, Tabei area
GUAN Baozhu, WANG Aiping, YANG Xinying, PEI Mingli, WAN Chaofan, NI Xianglong, ZHANG Qiang, YANG Wei
2026, Vol.38(1): 136–145
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doi: https://doi.org/10.12108/yxyqc.20260112
Ordovician fracture-cavity carbonate reservoirs in Lungu Oilfield of Tabei area represent a significant target for ultra-deep hydrocarbon exploration in China. Based on high-density seismic data, well logging, and dynamic production data, a multi-field coupling reservoir prediction theoretical framework integrating structure, karst, and fluid was established for Ordovician fracture-cavity carbonate reservoirs in Lungu Oilfield of Tabei area. Through quantitative characterization technology of fracture-cavity systems, the reservoir development patterns and main controlling factors of hydrocarbon enrichment were systematically revealed. The results show that: (1) Ordovician reservoir in Lungu Oilfield exhibits strong heterogeneity, and the reservoir space can be classified into four types: intercrystalline pores mainly develop in grain dolomite, with pore sizes ranging from 5 to 20 μm. Intergranular dissolution pores are mainly formed by selective dissolution of granular limestone, such as oolitic limestone, with pore sizes ranging from 50 to 200 μm, which are the main seepage channels of the reservoir. Microfracture widths are mostly less than 10 μm. Biogenic pores mainly develop in bioclastic limestone, commonly found in biological framework pores, such as crinoid stems, with pore sizes ranging from 100 to 500 μm. (2) Epikarst reservoirs are distributed in sheets over paleo-geomorphic highlands, subterranean river karst reservoirs exhibit bead-like distribution along paleo-water systems, and fault-controlled karst reservoirs are bead-string distributed along fault zones. Multi-attribute fusion and 3D geological modeling technologies can achieve holistic 3D spatial characterization of karst reservoirs. (3) The degree of hydrocarbon enrichment is controlled by karst facies-faults-reservoir scale. Class Ⅰ high-enrichment areas are concentrated in NE/NEE-oriented fault zones, with residual hill thickness greater than 90 m, effective porosity greater than 8%, and effective thickness greater than 550 m, forming a hydrocarbon accumulation model characterized by fault and fracture-cavity dual transport and multi-stage composite charging. Differentiated development strategies of “lateral tracking of epikarst reservoirs, 3D evaluation of subterranean river areas, and directional transportation of fault-controlled areas” can increase production capacity by 15%-30%, and add reserves of more than 200×104 t.
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Paleogeomorphologic characteristics and sand control mechanisms of Cretaceous Shahezi Formation in Lishu fault depression, southern Songliao Basin
XIAO Meng, ZHOU Yong, WANG Ke, YAN Jingchi, ZHANG Yuejie
2026, Vol.38(1): 146–161
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doi: https://doi.org/10.12108/yxyqc.20260113
By comprehensively utilizing well logging and seismic interpretation data, activity characteristics of Cretaceous Shahezi Formation synsedimentary faults in Lishu fault depression of southern Songliao Basin were analyzed. The paleogeomorphology was reconstructed based on the impression method, and the controlling role of paleogeomorphology on sedimentary systems were explored. The results show that: （1） The fault activity rate during the deposition of Member 2 of Cretaceous Shahezi Formation in Lishu fault depression was generally higher than that during the deposition of Member 1, showing a trend of first increasing and then decreasing towards the north. （2） During the depositional period of Shahezi Formation, the steep slope zone of Lishu fault depression primarily developed nearshore subaqueous fan and deep-lacustrine sedimentary systems, while the gentle slope zone mainly developed fan delta and shallow-lacustrine sedimentary systems. （3） The paleogeomorphology of the study area controls the distribution of sedimentary facies and sand bodies. Four paleogeomorphic types,such as valleys,transverse uplifts (subaqueous uplifts), strike slopes, and structural slope-break zones,have been identified,all of them exert significant control on sand bodies distribution. Valleys can serve as sand transport pathways, controlling the progression of sand bodies from source areas to depositional areas, and also acting as depositional unloading units. Transverse uplifts developed along the edges of steep slope scarps promote the fan-shaped dispersal of sand bodies into the basin. Strike slopes control the lateral extension of sand bodies, and activity at the terminations of synsedimentary faults governs the pathways of sand diffusion from source areas into the basin. Structural slope-break zones control the transport, migration, and enrichment locations of sand bodies within the basin, which are favorable zones for exploring sandstone oil and gas reservoirs. （4） The depositional period of Shahezi Formation in the study area exhibited a paleogeomorphy sand control model of“multi-source supply—fault-controlled channels—paleogeomorphic sand accumulation”.
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Seismic prediction technology for coal rock gas reservoir of Carboniferous Benxi Formation in northern Mizhi area, Ordos Basin
ZHANG Mengbo, PENG Jiankang, CUI Xiaojie, ZHANG Dong, NI Na, LONG Shengfang, WEI Penghui
2026, Vol.38(1): 162–171
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doi: https://doi.org/10.12108/yxyqc.20260114
Through well-to-seismic calibration, establishment of different surrounding rock lithology-coal rock models, and wave equation forward modeling, the lithologies, coal rock thickness, and seismic response characteristics of Carboniferous Benxi Formation surrounding rock in northern Mizhi area of Ordos Basin were analyzed. Three thickness prediction methods of coal rock gas reservoir, such as amplitude fitting method, impe-dance inversion method, and reflection coefficient inversion method, were contrasted and evaluated. The results show that: （1） The geological conditions of Carboniferous Benxi Formation coal rock gas reservoir in Mizhi area are complex. The overlying lithology are mainly sandstone, limestone, and mudstone. Physical properties of coal rock and surrounding rock strata are significant different, coal rock are with characteristics of low natural gamma, low density, high neutron, high acoustic time difference, and high resistivity. Different surrounding rocks have a significant impact on seismic response characteristics of coal rock layers, and the planar distribution of surrounding rocks can affect the accuracy of coal seam thickness prediction. （2） During wave equation forward modeling for different lithological combinations, when the coal rock thickness is less than the tuned thickness of 12.5 m, the amplitude value increases with the increase of coal rock thickness.When the thickness of coal rock reaches 12.5 m, the amplitude value reaches its peak.When the thickness of coal rock is greater than 12.5 m, the amplitude value begins to slowly decrease as the thickness of coal rock increases. （3） The reflection coefficient inversion method is suitable for the evaluation and development stages of coal rock gas reservoirs. The coal rock top and bottom re-interpretation technology is less affected by amplitude,and the predicted thickness of coal rock gas reservoir in the study area shows the highest consistency with the actual thickness, reaching 88.9%.
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Numerical simulation on the coupling of flow and geomechanics during CO2 huff and puff in shale oil reservoirs
ZHANG Qingfu, ZHANG Shiming, CAO Xiaopeng, LYU Qi, LI Zongyang, YU Jinbiao, WANG Yong
2026, Vol.38(1): 172–179
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doi: https://doi.org/10.12108/yxyqc.20260115
A component model was used to describe fluid flow and phase changes, and an embedded discrete fracture model was constructed to characterize hydraulic fractures. The constitutive relationship of matrix and fracturing fracture proppant was established, and the influence of stress field under different mechanical and development parameters on the diversion capacity and field development effect of hydraulic fractures was studied. The results show that: (1) The development of shale oil reservoir through CO2 huff and puff is a complex process of multi-component and multi-field coupling, accompanied by repeated changes in the formation pressure field and stress field during shale oil development. Under the influence of fluid-solid coupling effect, proppants will deform and embed into the fracture boundary layer, resulting in variation of the hydraulic fracture aperture, conductivity coefficient, porosity and permeability of shale oil reservoirs, which has a significant impact on the development effect of shale oil reservoir. (2) A higher elastic modulus of proppant reduces deformation during the development, leading to smaller fracture closure. Larger proppant diameter is more conducive to maintaining the fracture aperture. (3) A higher elastic modulus of the matrix reduces proppant embedment, leading to smaller fracture closure and better maintaince of fracture conductivity.
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Research progress on retention effects of pre-CO2 fracturing fluid of shale oil reservoirs
ZHANG Yanjun, LIU Zhengjun, XU Hao, HE Wenjie, LIU Yaru, XING Liang, ZHOU Desheng, WANG Zhen
2026, Vol.38(1): 180–190
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doi: https://doi.org/10.12108/yxyqc.20260116
The pre-CO2 fracturing technology has obvious advantages in developing shale oil reservoirs, which can reduce reservoir damage, improve fracture network complexity and oil-gas utilization degree. Through extensive information investigation and systematic review, retention mechanism and resulting changes in reservoir physical-chemical properties of pre-CO2 fracturing fluid were summarized, and the stages of pre-CO2 fracturing fluid retention effect and the applicability of fracturing technology were discussed. The results show that: （1） Retention mechanisms of pre-CO2 fracturing fluid in shale oil reservoirs mainly include multi-level fracture network retention, near fracture surface matrix imbibition retention, and physical-chemical interaction retention. Gravity dominates the retention in main fractures, and the “locking” effect of branches and micro-fractures is significant.（2） Physical-chemical property changes of reservoir caused by liquid retention include: promoting the formation of fracture networks, weakening water phase trapping, and increasing the pressure of matrix pores. CO2 affects the retention of matrix liquid near the fracture surface by influencing surface tension. Its strong diffusion effect and dissolution on rocks facilitate the formation of complex fracture networks, thereby altering the permeability of rocks. （3） The retention effect of pre-CO2 fracturing fluid varies significantly in the four stages of fracture propagation, well shut-in, flowback and production. In the future, it is necessary to enhance the iterative upgrade of pre-CO2 fracturing technology, leverage the synergistic advantages of CO2 flooding and storage, develop intelligent regulation and optimization strategies for multi-media coordinated injection in reservoirs, and achieve the common development of oil and gas production increase and carbon neutrality.
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A new method for splitting the production of fractured horizontal wells in strong heterogeneous gas reservoirs:Taking Permian He1 member gas reservoir in Dongsheng Gasfield of Ordos Basin as an example
XUN Xiaoquan, LI Hongtao, LI Changping, YANG Fan, LIU Xiong
2026, Vol.38(1): 191–200
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doi: https://doi.org/10.12108/yxyqc.20260117
In order to quantitatively evaluate the initial gas production contribution rate of each fracturing section of the fractured horizontal well in a strong heterogeneous gas reservoir, taking Permian He1 member gas reservoir in Xinzhao block of Dongsheng Gasfield in Ordos Basin as an example, based on reservoir geological engineering parameters, fracture characteristics, and gas production profile testing analysis, a new method for segmented production splitting of“fracture-controlled reserves”that integrated geological engineering factors was proposed. The results show that:（1）The characteristics of hydraulic fractures in Permian He1 member gas reservoir in Xinzhao block of Dongsheng Gasfield are controlled by geology and engineering. With the same construction parameters, better physical properties correspond to shorter hydraulic fractures half-length. Under the same geological conditions, larger construction displacement and greater net liquid inflow into the ground lead to longer fracture half-length, and more perforation clusters lead to shorter the fracture half-length. The ratio of half length to width of hydraulic fracture in different types of reservoirs in the same area is consistent.（2）The output of each horizontal fracturing section is significantly affected by geological engineering factors,and sections with good physical properties, good gas-bearing, and large-scale fracturing construction achieve greater post fracturing production capacity.（3）Taking into account geological engineering factors, it was clarified that the transformed “fracture-controlled reserves” have a linear relationship with the initial production capacity of each fracturing section of the horizontal well in the strong heterogeneous gas reservoir, with a correlation coefficient of 0.997, indicating that the larger fracture-controlled reserves lead to high proportion of production capacity in each fracturing section. By comparing the splitting method of “fracture-controlled reserves” with the gas production profile testing results, it was found that the relative error of splitting gas production in each section of ClassⅠand ClassⅡreservoirs is within 12.00%.