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2025 Vol. 47, No. 4

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2025, 47(4): .
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Geological characteristics and exploration suggestions for shale in Paleogene Hetaoyuan Formation of Biyang and Nanyang sags, Nanxiang Basin
WANG Yong, LI Yanran, ZHU Yan, ZHANG Yuheng, NIU Mingwei, XIONG Jian, LI Hengquan, WANG Qi
2025, 47(4): 705-719. doi: 10.11781/sysydz2025040705
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The shale layers in the Paleogene Hetaoyuan Formation of the Biyang and Nanyang sags in the Nanxiang Basin show significant geological differences from the shale strata in the eastern rift basins where breakthroughs have been achieved. The limited understanding of the formation mechanism of shale oil and its geological characteristics in this area constrains its exploration and development. Through core analysis, X-ray diffraction (XRD), thin-section observation, scanning electron microscopy (SEM), and confocal laser scanning microscopy (CLSM), the geological differences of the shale in the Hetaoyuan Formation across various sags in the Nanxiang Basin were systematically studied, and suggestions for future exploration were proposed. The Hetaoyuan Formation in the Nanxiang Basin mainly develops laminated mixed shale. Particularly, the Biyang Sag mainly develops laminated dolomitic and felsic mixed shale and is abundant in matrix-type shale oil. The Nanyang Sag mainly develops laminated felsic and argillaceous mixed shale with well-developed sandstone interlayers, primarily containing sandwich-type shale oil. The shale in the Biyang Sag exhibits normal pressure, medium to low evolution degree, and medium to high organic matter abundance, with medium to good reservoir property, good oil-bearing capacity, good compressibility, and medium mobility. The shale in the Nanyang Sag exhibits normal pressure, medium evolution degree, and medium to low organic matter abundance, with medium reservoir property, medium to good oil-bearing capacity, and medium compressibility and mobility. Comparative analysis revealed that boundary faults and paleo-water depth controlled the types of lake basins in different sags. Lake basin types and the paleo-depositional environment collectively affected shale lithofacies types. The organic matter components and hydrocarbon-generating organism types controlled the abundance of organic matter in shale. The sandwich-type shale oil with medium to low organic matter abundance in the freshwater lake basin of the Nanyang Sag and the matrix-type shale oil under normal pressure in the salt lake basin of the Biyang Sag possess favorable reservoir-forming conditions. For the shale layers in the Biyang Sag, which have good oil-bearing properties and relatively concentrated sweet spots, it is recommended to strengthen research on low-cost engineering technologies and explore efficient development models for sandwich-type shale oil through vertical and deviated wells. For the shale layers in the Nanyang Sag, which feature large vertical spans and complex faults, highly deviated wells are recommended for large-scale, multi-layer vertical fracturing.
Enrichment mechanism and evaluation indicators of normal pressure shale gas in the complex structural area of southeastern Chongqing
FANG Dazhi
2025, 47(4): 720-730. doi: 10.11781/sysydz2025040720
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Normal pressure shale gas is widely distributed in the complex structural area of southeastern Chongqing, with good prospects for resource exploration. Normal pressure shale gas has gradually become a hot topic in shale gas exploration and development. Due to the influence of multiple stages of structural evolution, there are significant differences in the preservation conditions of shale gas in the complex structural area of southeastern Chongqing. Shale reservoirs and gas geochemical characteristics are distributed differently under different pressure systems. The overall trend of alkane isotopes in shale gas in the study area shows a gradual increase in weight from the basin margin toward the basin exterior, while the dryness coefficient gradually decreases, indicating differences in gas preservation and dissipation in different structural zones. Lighter alkane carbon isotopic values and a higher dryness coefficient indicate better shale gas preservation conditions. A comprehensive comparison of shale gas evaluation indicators from the Lower Silurian Longmaxi Formation in the complex structural area of southeastern Chongqing reveals that static geological parameters including porosity, face porosity, deformation index, and gas content exhibit strong heterogeneity within synclinal structures, with significant variations among shale samples from individual wells. Meanwhile, dynamic geological parameters such as alkane carbon isotopes, dryness coefficient, and gas production rate show marked differences across various structural zones. An integrated evaluation of shale reservoir properties and gas geochemical characteristics demonstrates that the Pingqiao and Dongsheng anticline zones exhibited favorable gas preservation conditions, representing optimal shale reservoirs and sweet spots for shale gas enrichment.
Lithofacies paleogeography of Middle Triassic Leikoupo Formation in the southern Sichuan Basin and its implications for conventional and unconventional dual-domain exploration
SONG Xiaobo, CHEN Anqing, SU Chengpeng, LIU Yong, SUN Na, WANG Zeyu, LI Wen, WANG Xianfeng, HUANG Guanghui, SUN Shi
2025, 47(4): 731-741. doi: 10.11781/sysydz2025040731
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The Leikoupo Formation of the Middle Triassic is one of the earliest strata for oil and gas exploration in the Sichuan Basin, but its exploration has long been limited to scattered small gas fields. Recent studies reveal that the Leikoupo Formation holds dual prospects for marine conventional and unconventional oil and gas reservoirs, but the existing paleogeographic pattern is inadequate for the new exploration needs. This study focused on the Leikoupo Formation in the southern Sichuan Basin. Based on the detailed analysis of sedimentary facies in outcrops and drill cores, the lithofacies paleogeography was reconstructed and the sediment and reservoir development patterns were studied. The sedimentary environment types in the Middle Triassic Leikoupo Formation of the southern Sichuan Basin included platform tidal flats, tidal shoals, shelf bays, and saline lagoons. During the transgression period (members 1 and 3 of the Leikoupo Formation), relatively high-energy marine conditions favored the development of high-energy shoal facies and organic-rich mudstone or marl. During the regressive period (members 2 and 4 of the Leikoupo Formation), the energy was relatively lower, favoring the development of dolomite and evaporite successions. The development of conventional carbonate rock reservoirs in the Leikoupo Formation of the southern Sichuan Basin was primarily controlled by the paleogeomorphic pattern. The combined effects of wave and tidal actions led to the extensive distribution of thin shoal-facies dolomite reservoirs. The transgression during the depositional period of member 3 of the Leikoupo Formation played a significant role in the formation of unconventional reservoirs of organic-rich mudstone or marl. It not only altered the original paleogeomorphic pattern but also transported organic-rich clastic materials from the Badong Formation into the interior of the Upper Yangtze Craton. Under intense evaporation during the later stages, intersalt hydrocarbon reservoirs with a "salt rock and marl" cycle were formed. The paleogeographic reconstruction in both conventional and unconventional domains of the Leikoupo Formation in the southern Sichuan Basin not only reveals a new exploration area for marine intersalt unconventional resources, but also confirms the favorable conditions for the development of high-quality source rocks within the formation.
Quantitative evaluation of brittleness of deep shale gas reservoirs of Wufeng- Longmaxi formations in Lintanchang area, southeastern Sichuan Basin
FENG Shaoke, XIONG Liang, YIN Shuai, DONG Xiaoxia, WEI Limin
2025, 47(4): 742-753. doi: 10.11781/sysydz2025040742
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With the increase in rock plasticity of deep shale gas reservoirs, their brittleness characteristics become difficult to be accurately characterized using traditional evaluation methods. Taking the deep shale gas reservoirs from the upper Ordovician Wufeng Formation to the first member of Lower Silurian Longmaxi Formation in the Lintanchang area of the southeastern Sichuan Basin as a case study, triaxial rock mechanics and fracture toughness experiments on shale samples were conducted. Based on the experimental results, a comprehensive quantitative evaluation of reservoir brittleness was carried out using deep learning. The experimental results showed that with the increasing temperature and pressure, the Young's modulus, Poisson's ratio, and compressive strength of the shale samples all increased. The brittleness of shale samples from layer ① was significantly lower than that of samples from layer ③. Shale samples with better brittleness exhibited obvious fluctuations in the stress-strain curves, showed nonlinear deformation characteristics, and had relatively small residual strain values. The fracture toughness of shale samples was closely related to the content of brittle minerals, and the fracture toughness values of type Ⅰ and type Ⅱ samples with laminations perpendicular to bedding planes were relatively lower. Based on the shale characteristics of mineral composition, triaxial rock mechanics, and fracture toughness, a deep learning weight analysis model was developed using brittleness indices Bel and Bmine3 and fracture toughness index IKIC as data inputs.The cumulative risk value was less than 5, indicating the high reliability of the model.A comprehensive brittleness index B was established based on the model, and its correlation with the measured brittleness index BS of core samples was significantly improved (R=0.852 7). The quantitative brittleness evaluation results truly reflect the vertical profile of brittleness characteristics in deep shale reservoirs. The reservoirs at layer ③ bottom and layer ② in the Wufeng-Longmaxi formations of the study area exhibit relatively better brittleness and lower fracture toughness index, making them preferred target layers for future exploration and development.
Differential diagenetic evolution of Sinian Dengying Formation reservoirs in Anyue gas field, Central Sichuan Uplift, Sichuan Basin
YANG Chengyu, YU Bo, ZHANG Jianfeng, WANG Tieguan, LI Meijun, NI Zhiyong
2025, 47(4): 754-766. doi: 10.11781/sysydz2025040754
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Large in-situ pyrolysis gas reservoirs have developed in the dolomites of the Sinian Dengying Formation in the Central Sichuan Uplift, Sichuan Basin. Investigating the effects of sedimentation and diagenesis on these reservoirs provides important insights for evaluating and predicting ancient deep carbonate reservoirs. Through hand specimen observation, thin-section identification, cathodoluminescence, and scanning electron microscopy (SEM) of core samples, the study systematically analyzed the lithological variations, diagenetic types, diagenetic sequences, and the constraints imposed by different lithologies on diagenetic processes in the dolomite reservoirs of the fourth member of the Dengying Formation. The results showed that the main lithologies of the Dengying Formation reservoirs in the Central Sichuan Uplift were algal stromatolite dolomite with a skeleton-filling structure, granular dolomite, and mud-fine crystalline dolomite mainly composed of fine-grained dolomite accumulations. The main types of diagenesis followed the sequence of compaction, dissolution, and cementation during the syngenetic-penecontemporaneous and supergene stages, sparry cementation at the burial stage, and late-stage hydrothermal activity. Hydrocarbon charging occurred after sparry cementation, while hydrocarbon pyrolysis coincided with hydrothermal activity. The dolomite reservoirs in the fourth member of the Dengying Formation were algal mound platform deposits formed by typical T-type carbonate factories. The algal stromatolite dolomite and granular dolomite experienced weak compaction but stronger cementation and dissolution during the syngenetic-penecontemporaneous and supergene stages. Sparry cementation significantly reduced porosity, and residual intergranular pores were preserved until the hydrocarbon charging period. With the intrusion of late-stage hydrothermal fluids, these pores were further filled with hydrothermal minerals and pyrobitumen formed through pyrolysis. In contrast, the mud-fine crystalline dolomite underwent strong compaction and weaker cementation during the syngenetic-penecontemporaneous and supergene stages. Sparry cementation further reduced porosity, and residual pores were also preserved until liquid hydrocarbon charging. No obvious signs of hydrothermal intrusion were observed in mud-fine crystalline dolomite, but the high temperature of hydrothermal fluids still promoted liquid hydrocarbon pyrolysis, leading to pyrobitumen formation.
Petrofacies types and evolution characteristics of tight sandstone gas reservoirs of Jurassic Shaximiao Formation, Tianfu gas area, central Sichuan Basin
GUAN Xu, PANG Xiaoting, RAN Qi, YANG Changcheng, WANG Xiaojuan, ZHU Deyu, PAN Ke, LI Fei, XIAO Boyi, CAO Binfeng
2025, 47(4): 767-780. doi: 10.11781/sysydz2025040767
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The classification of rock types is important for characterizing the heterogeneity of tight sandstone reservoirs and revealing their differential evolution process. The Middle Jurassic Shaximiao Formation in the Tianfu gas area of the central Sichuan Basin was selected as the study object, and petrofacies types and diagenetic evolution process were investigated using thin-section observation, scanning electron microscopy (SEM), and stable carbon and oxygen isotope analysis. The gas-bearing reservoirs of the Shaximiao Formation in the Tianfu gas area exhibit strong heterogeneity in physical properties, pore types and distribution. Based on the differences in petrographic composition and texture, diagenetic patterns and processes, and pore structure characteristics, four types of petrofacies were classified: ductile-lean sandstone, ductile-rich sandstone, tightly calcite-cemented sandstone, and tightly laumontite-cemented sandstone. During the reservoir evolution process, ductile-lean sandstone experienced moderate compaction, active fluid-rock interactions, and strong dissolution, and generally underwent multiple stages of dissolution and cementation, resulting in effective reservoir petrofacies. Ductile-rich sandstone underwent strong mechanical compaction, became dense in the early diagenetic stage, and exhibited weak fluid activity and slight dissolution in the late stage. In tightly calcite- and laumontite-cemented sandstone, calcite and laumontite were interlocked, resulting in early-stage densification and late-stage weak fluid modification. The original composition and texture of sediments controlled the differences in the influencing patterns and degrees of diagenesis within reservoirs. The concept of petrofacies provides a systematic framework for identifying key petrographic parameters that influence reservoir porosity and permeability. In combination with well logging data, this approach can effectively guide reservoir property modeling.
Helium accumulation characteristics and main controlling factors of helium depletion in Daniudi Gas Field, Ordos Basin
WANG Jie, AN Chuan, MA Liangbang, JIANG Haijian, ZHANG Wei, TAO Cheng, WANG Fubin, DONG Qingwei
2025, 47(4): 781-790. doi: 10.11781/sysydz2025040781
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A certain amount of helium is found in the natural gas of both the Dongsheng and Daniudi gas fields in the Hangjinqi area of the Ordos Basin. However, the average helium content in the Daniudi Gas Field is only about one-fourth of that in the Dongsheng Gas Field. Given the similar basement geology and tectonic background of the basin, it is necessary to investigate the factors leading to this significant difference. A systematic analysis of the geochemical characteristics of associated helium in natural gas and the key factors controlling helium accumulation was conducted. The results revealed that the helium content in the Paleozoic natural gas of the Daniudi Gas Field ranged from 0.000 1% to 0.15%, classifying it as a low- to medium-helium gas field. Helium content in the Upper Paleozoic was relatively higher, and vertically, it gradually increased from the lower to the upper layers, showing relative enrichment in shallower layers. The helium in the Paleozoic source rocks of the Daniudi Gas Field was typical crust-source helium, mainly derived from the Archean-middle Paleoproterozoic metamorphic rock-granite series in the basin basement. The contribution of helium generated by potential helium source rocks in the Upper Paleozoic was minimal. By comparing the geological conditions and accumulation characteristics of the Upper Paleozoic between the Daniudi and Dongsheng gas fields, it was found that the basement helium source rocks in both gas fields were similar in rock type, mineral composition, thickness, and uranium (U) and thorium (Th) contents, suggesting that the differences in source rock were not responsible for the significant difference in helium content. In the Daniudi area, only one second-level deep fault was developed in the basement of the Daniudi area, and its activity during the Yanshanian-Himalayan period was relatively weak, resulting in limited activity of secondary faults. This led to a lack of effective channels for helium to migrate upward from the basement helium source rocks, as well as vertical transport and lateral adjustment. Due to the mismatch in spatiotemporal configuration of key accumulation factors for helium and conventional gas, helium entered the Paleozoic gas reservoirs in Daniudi only by diffusion, resulting in low helium content. Therefore, the main factors contributing to helium depletion in the Daniudi Gas Field are the underdevelopment and weak activity of deep faults and secondary faults in the basement, the mismatch between helium and conventional gas accumulation conditions, the lack of an effective transport system, and the reliance on concentration-driven diffusion for helium migration.
Characteristics and controlling factors of shale oil reservoirs in the seventh member of Triassic Yanchang Formation, western Mahuangshan area, Ordos Basin
QI Rong, ZHU Feng, HE Faqi, JIANG Longyan, YIN Chao, SHAO Longkan
2025, 47(4): 791-804. doi: 10.11781/sysydz2025040791
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The seventh member of the Triassic Yanchang Formation (Chang 7) in the Ordos Basin is abundant in shale oil resources. However, there are significant differences in reservoir characteristics between the basin margin and the basin center. Currently, research on shale oil reservoirs in the western Mahuangshan area at the basin margin remains insufficient, which has constrained shale oil exploration in this area. In this study, a detailed characterization of the shale oil reservoirs of Chang 7 member in this area was conducted using scanning electron microscopy (SEM), high-pressure mercury injection, low-field nuclear magnetic resonance (NMR), nitrogen adsorption, and micro-CT, combined with core observations and thin-section identification. Additionally, carbon and oxygen isotope and major and trace element analyses were conducted to investigate the development mechanism of high-quality reservoirs. The results showed that: (1) The shale oil reservoir in the Chang 7 member of the western Mahuangshan area is mainly composed of fine sandstone, siltstone, and mud shale. The mineral composition is characterized by high contents of felsic and clay minerals, with felsic minerals generally exceeding 50%. (2) The reservoir exhibits diverse space types, and the pore development differs among lithologies. In fine sandstone, intergranular pores and clay mineral intercrystalline pores are dominant, with pore sizes mainly distributed in the 1 to 2 μm range. In siltstone (mainly argillaceous siltstone), both inorganic pores and organic matter pores are developed, with dominant pore sizes near 3 nm and 500 nm. Mud shale is mainly composed of pores with organic-clay composites matter and microfractures, developed with pores below 10 nm and those in the range of tens of nanometers. (3) Analysis of reservoir physical properties and pore structure indicated that interbedded-type fine sandstone reservoirs represent the high-quality reservoir type. During compaction diagenesis, the porosity was reduced by approximately 26% to 33%. Hydrocarbon-generating fluids significantly modified the central parts of the sandstone bodies of reservoirs, and the current porosity generally exceeds 5%. In contrast, the edges of sandstone bodies and laminated-type reservoirs experienced substantial cement sedimentation, resulting in relatively poor physical properties.
Characteristics and genesis analysis of dolomite in Lower Ordovician Penglaiba Formation in Tahe area
XU Qinqi, PENG Jun, HE Chengqi, XIA Jingang, LIU Rui, HUANG Wei
2025, 47(4): 805-819. doi: 10.11781/sysydz2025040805
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The dolomite of the Lower Ordovician Penglaiba Formation is an important successor field for oil and gas exploration in the Tahe oilfield. Clarifying the sedimentary characteristics and genetic mechanisms of the dolomite is of great significance for oil and gas exploration and development in the Tahe oilfield. Based on this, the geological and geochemical characteristics and genetic mechanisms of the dolomite in the Lower Ordovician Penglaiba Formation of the Tahe Oilfield were systematically studied through core description, thin section identification, scanning electron microscopy, cathodoluminescence, and geochemical analyses. The results showed that: (1) The study area was dominated by crystalline dolomite, followed by residual granular dolomite. Mud-microcrystalline dolomite was mainly anhedral. Silty-medium crystalline dolomite was mostly subhedral to euhedral. Medium-coarse crystalline dolomite was predominantly xenomorphic. Residual granular dolomite was mainly composed of silty-fine crystalline dolomite, showing residual intraclastic texture. (2) Cathodoluminescence showed that the mud- microcrystalline dolomite emitted dull blue-purple or dark brown luminescence. Silty dolomite emitted dull purple-red luminescence. Fine-medium crystalline dolomite had a purple core with a bright orange-red rim-shaped band. Medium-coarse crystalline dolomite exhibited purple-red and a bright brown-red rim-shaped luminescent band. (3) Mud-microcrystalline dolomite was mainly enriched in heavy rare earth elements (REE), with large δ18O fluctuations and 87Sr/86Sr ratios close to those in the Early Ordovician seawater, indicating quasi-syngenetic dolomitization by high-salinity evaporative seawater. Residual granular dolomite was mainly characterized by residual intraclastic texture and its genetic mechanism was burial dolomitization. The REE distribution patterns of silty crystalline dolomite and fine-medium crystalline dolomite were similar to those of contemporaneous micrites, which were enriched in heavy REEs with large δ18O fluctuations. The 87Sr/86Sr values were partially higher compared with the strontium isotope values in contemporaneous seawater, indicating products of shallow-medium burial dolomitization superimposed with hydrothermal fluids. Medium-coarse crystalline dolomite was relatively enriched in light rare earth, with negative δ18O values and 87Sr/86Sr values higher than those in contemporaneous seawater, indicating formation by hydrothermal metasomatism related to clastic rock layers.
Crude oil type classification and source rock identification in Miaoxi area of Bohai Sea area based on stoichiometric method
TANG Youjun, FU Tianyi, YANG Haifeng, WANG Feilong, TANG Guomin, SUN Peng
2025, 47(4): 820-834. doi: 10.11781/sysydz2025040820
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The crude oil types in the Miaoxi area of the Bohai Sea area are highly complex, and the source rocks and genetic types remain unclear. Using multivariate statistical analysis, researchers can comprehensively examine the interrelationships among multiple correlated variables, which is particularly suitable for large-scale data mining and regional oil-oil and oil-source analysis. In this study, based on the biomarker parameter index system, hierarchical cluster analysis (HCA) and principal component analysis (PCA), common methods in multivariate statistical analysis, were applied for oil-oil and oil-source correlation of crude oil from multiple layers in the Miaoxi area. Three types of crude oil were detected. Type Ⅰ crude oil are characterized by a low C23TT/C30H ratio with relatively low maturity. It may be derived from a freshwater lacustrine reducing environment with abundant input of terrigenous organic matter. This type of crude oil shows a strong correlation with the source rocks in the first and second members of the Shahejie Formation in the eastern sag of the Huanghekou Depression. Type Ⅱ crude oil is at a mature stage and features lower C23TT/C30H and G/C30H ratios compared to Type Ⅰ, but with slightly higher Pr/Ph, sterane/hopane, and C19TT/C23TT ratios. These features also indicate a freshwater lacustrine environment with terrestrial organic matter input. It is inferred that Type Ⅱ oil is mainly sourced from the third member of the Shahejie Formation, with contributions from source rocks in both the eastern sag of the Huanghekou Depression and the southern sag of the Miaoxi Depression. Type Ⅲ crude oil is at a mature stage, exhibiting a wide distribution range in multiple biomarker parameters, including ETR[(C28TT+C29TT)/(C28TT+C29TT+ Ts)], G/C30H, C23TT/C21TT, Pr/Ph, C23TT/C30H C24Te/C26TT, C27/C29 regular sterane, and 4-methyl sterane/ C29 regular sterane. These variations reflect heterogeneity in the depositional environment of oil source rocks and organic matter types. It can be concluded that type Ⅲ crude oil is mixed-source oil, likely derived from the third and fourth members of the Shahejie Formation. Alternating least squares analysis results indicated that Type Ⅲ crude oil is mainly derived from the source rocks in the fourth member of the Shahejie Formation, with a contribution rate of 85% to 93%, while the contribution from the third member is only 7% to 15%.
Organic matter characteristics of Eocene source rocks with different lithologies in Baiyun Sag of Pearl River Mouth Basin and their geological significance
CHEN Yue, ZHU Xiaojun, ZHANG Lili, XIANG Xuhong, ZENG Xiang, ZHU Weilin
2025, 47(4): 835-846. doi: 10.11781/sysydz2025040835
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In the deep-water area of the Zhu Ⅱ Depression of the Pearl River Mouth Basin, the Baiyun Sag develops three types of source rocks: mudstone, carbonaceous mudstone, and coal. Existing studies lack experimental data support, making it difficult to accurately assess the differences in hydrocarbon generation potential among source rocks with different lithologies and from different regions. To clarify the lithologies and hydrocarbon generation potential of Eocene source rocks in the Baiyun Sag, comprehensive methods, including thin-section identification, X-ray diffraction analysis, palynofacies identification, and organic geochemical analysis, were used to systematically conduct lithological division, organic matter composition analysis, and hydrocarbon generation potential evaluation. The Eocene source rocks in the Baiyun Sag showed significant differences in mineral composition and organic matter content, with diverse sedimentary structures. Based on the total organic carbon content and mineral composition characteristics, the source rocks in the Baiyun Sag can be classified into sand-rich mudstone, sand-bearing mudstone, carbonaceous mudstone, and coal. The characteristics of these source rocks with different lithologies vary greatly. The sand-bearing mudstone has a massive structure with a relatively high organic matter abundance, mainly coaly organic matter, and contains some amorphous organic matter. Its source rocks are primarily sapropelic with relatively higher hydrocarbon generation potential and tend to generate oil. Sand-rich mudstone is primarily characterized by a clastic massive structure with a relatively low abundance of organic matter, mainly coaly and sporonic organic matter. The source rocks are mainly humic with relatively smaller hydrocarbon generation potential and tend to generate gas. Carbonaceous mudstone and coal are mainly characterized by discontinuous laminated structures and laminated structures, respectively, with high organic matter abundance, predominantly coaly, woody, and shell-type organic matter. Both are humic source rocks and tend to generate gas. The sand-rich mudstone is mainly distributed in the eastern and southern parts of the sag during the sedimentation periods of the Eocene Enping Formation and Wenchang Formation, the sand-bearing mudstone in the eastern part of the sag during the same periods, and the carbonaceous mudstone and coal in the southern part of the sag during the sedimentation periods of the Lower Wenchang Formation and Enping Formation.
Geochemical effects of intra-layer hydrocarbon micro-migration in shale layers: a case study of the No. 5 shale layer of the No. Ⅲ sand group in the upper submember of the third member of the Paleogene Hetaoyuan Formation in the deep sag area of Biyang Sag, Nanxiang Basin
ZHANG Dongmei, LI Shuifu, ZHANG Yanyan, SU Peng, ZHOU Changran
2025, 47(4): 847-856. doi: 10.11781/sysydz2025040847
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Hydrocarbon micro-migration within source rock layers is an important pathway for shale oil enrichment, and the resulting geochemical effects provide strong evidence for its occurrence. To verify the existence of hydrocarbon micro-migration in the deep sag area of the Biyang Sag of Nanxiang Basin and to investigate the enrichment mechanism of shale oil, the No. 5 shale layer of the No. Ⅲ sand group in the upper submember of the third member of the Paleogene Hetaoyuan Formation in wells BY1 and Cheng 2 was selected as the research object. By using geochemical analysis methods such as rock pyrolysis, extraction and chromatographic techniques, chromatography-mass spectrometry, and rock thin-section observation, the existence of hydrocarbon micro-migration within the shale layer in the study area and its resulting geochemical effects were revealed. The results indicated that, based on the relationship between pyrolytically desorbed hydrocarbon (S1) and total organic carbon (TOC), hydrocarbon micro-migration within the shale layer in the study area was divided into three types: weak hydrocarbon expulsion (type Ⅰ), strong hydrocarbon expulsion (type Ⅱ), and indigenous hydrocarbons (type Ⅲ), and their corresponding hydrocarbon expulsion intensities were quantitatively calculated. The geochemical characteristics of the three types of hydrocarbon micro-migration were as follows: type Ⅲ samples had the highest saturate/aromatic ratio, type Ⅱ samples had the lowest saturate/aromatic ratio, and type Ⅰ samples were in between. The ratio of n-alkane nC19 to methylphenanthrene (MP) showed a similar pattern. Additionally, rock thin-section observation further confirmed that type Ⅲ samples contained more reservoir space, allowing for indigenous hydrocarbon influx and storage. Type Ⅱ samples developed fractures, enabling smooth expulsion of oil and gas. Type Ⅰ samples had small pore and throat radii, low permeability, high capillary resistance, and undeveloped fractures, leading to poor expulsion capacity, which aligned with their resulting geochemical effects.
Geochemical and hydrocarbon generation evolution characteristics of marine-continental transitional facies shale: a case study of the Lower Permian Shanxi Formation in the Daning-Jixian area, eastern margin of Ordos Basin
ZHANG Yangyang, LI Yong, ZHANG Xueying, LUO Liyuan, HE Qingbo, LI Shuxin, LIU Xiangjun, LI Xiang, LI Xingtao, YANG Qiang, CHEN Shijia, LU Jungang, ZHANG Nan, LIU Zhe, YU Ruiyang, MA Haichuan
2025, 47(4): 857-871. doi: 10.11781/sysydz2025040857
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To clarify the geochemical and hydrocarbon evolution characteristics of marine-continental transitional facies shale, the shale in the Lower Permian Shanxi Formation of the Daning-Jixian area in the eastern margin of the Ordos Basin was taken as the research object. By analyzing and determining total organic carbon (TOC) content, rock pyrolysis, kerogen carbon isotopes, maceral composition, paleontology, vitrinite reflectance (Ro), and conducting hydrocarbon generation thermal simulations, the study investigated the mineral composition, hydrocarbon source, generation potential, generation kinetics, and cumulative gas production rate calculation models of the shale in the Shanxi Formation. The results showed that: (1) The mineral composition of the shale in the Shanxi Formation of the Daning-Jixian area was mainly composed of quartz and clay minerals, with an average TOC content of 4.06%. The organic macerals were mainly composed of humic amorphous bodies and vitrinites, with an average Ro value of 2.61%. Overall, the shale was characterized by high organic matter abundance, dominated by humic-type organic matter, and was at an overmature stage of evolution, demonstrating high gas generation potential. (2) In a closed system, the maximum yields of gaseous hydrocarbons C1 and C1-5 from the shale in the Shanxi Formation were 138.74 and 139.22 mg/g, respectively. In a semi-closed system, the maximum yields of C1 and C1-5 were 86.51 and 102.59 mg/g, respectively, which were significantly lower than the maximum yields under closed conditions. (3) The activation energy for the generation of gaseous hydrocarbon C1 and C1-5 from the shale in the Shanxi Formation exhibited two distinct peaks, representing kerogen degradation and secondary cracking of heavy hydrocarbons. For C1, the two peaks of activation energy were 56 kcal/mol (26.53%) and 61 kcal/mol (30.10%), with a frequency factor of 2.0×1011 S-1. For C1-5, the two peaks of activation energy were 56 kcal/mol (28.45%) and 61 kcal/mol (19.18%), with a frequency factor of 2.2×1011 S-1. (4) The variation trend between cumulative gas production rate and Ro for the marine-continental transitional facies shale in the Shanxi Formation followed the pattern of a logistic function described by y=1/(1+e-x). Cumulative gas production rate calculation models for both the closed and semi-closed systems were established. The research results provide important theoretical support for the calculation of shale gas resources in marine-continental transitional facies and offer insights into favorable zone prediction.
"NMR+" shale oil experimental technology system and application
SHI Yujiang, ZHANG Zhehao, ZHAO Jianbin, LUO Yanying, WAN Jinbin, HE Guofen, ZHANG Chenjun, HU Zuzhi
2025, 47(4): 872-881. doi: 10.11781/sysydz2025040872
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To accurately obtain the key reservoir evaluation parameters such as porosity, oil saturation, and movable oil saturation in shale oil, an experimental technology system "NMR+" was established based on core nuclear magnetic resonance (NMR), combined with helium gas method, heavy water inhibition method, and multi-temperature heating method. Through this set of experimental workflow, multiple petrophysical parameters were obtained. Total porosity was obtained via the "NMR + helium" method by measuring the content of retained and escaping fluids in the cores. The "NMR + heavy water inhibition" method determined the distribution and content of different fluids using 2D NMR spectra based on the principles of heavy water inhibition and capillary imbibition, thereby obtaining oil saturation. The "NMR + multi-temperature heating" method determined the initial temperature point at which heavy hydrocarbons began to move and the amount of escaped hydrocarbon, based on the differences in 2D NMR distributions before and after heating, thereby obtaining movable oil saturation. This technical system was applied to fresh organic-rich shale samples from the third submember of the seventh member of the Triassic Yanchang Formation (Chang 73) (2 285.26 m) of well X in the Longdong area, Ordos Basin. A total porosity of 5.5%, oil saturation of 53.66%, and movable oil saturation of 42.68% were determined. At the same time, based on the experimental results, a 4 ms T2 cut-off value for movable porosity was calculated for this reservoir submember using NMR logging. The establishment and application of the "NMR+" experimental technology system for shale oil have enriched the laboratory methods and approaches for obtaining core porosity and saturation.
Computed tomography and image processing based multi-scale fracture extraction method for core samples
WU Feng, CHEN Xuewu, ZHAO Hui, SHI Xiangchao, LIU Jianfeng
2025, 47(4): 882-894. doi: 10.11781/sysydz2025040882
Abstract(76) HTML (48) PDF-CN(18)
Abstract:
Fractures are widely present in various kinds of rocks and are critical for reservoir evaluation, deve-lopment, and geological disaster prediction. Existing image-based fracture extraction technologies have noticeable deficiencies in micro-fracture recognition, fracture detail extraction, and fracture and pore differentiation. A multiscale fracture filter kernel superimposition noise reduction method was proposed, which used multiple filter kernels in superimposition to filter and reduce noises in CT scanning images of rock cores, with the filtering results then superimposed. A multiscale information-enhanced fracture segmentation method was also proposed. It combined image segmentation methods such as threshold and top-hat segmentation with edge enhancement to better capture micro-fracture information, applying different strategies for fractures of varying scales. The relationships between morphological parameters such as length, width, surface area, volume, shape factor, flatness, and elongation of the segmented 3D volumes were analyzed. The results showed that the proposed noise reduction method significantly reduced noise interference in CT scanning images of rock cores, and accurately preserved detailed fracture characteristics. This method improves the accuracy and stability of multiscale fracture extraction. The fracture morphological parameter chart effectively eliminates non-fractures such as pores and special mineral boundaries that are similar to fractures, achieving precise extraction of multiscale fractures.
Influence of non-thermal maturity factors on laser Raman spectroscopy of highly to overmature shale: a case study of Lower Paleozoic marine shale in southern Sichuan Basin
ZHANG Hongfei, JIAO Kun, WANG Jiayu, XU Ning, MA Lijun, LIU Lanfeng, WU Yunjun, DENG Bin, WU Juan, YE Yuehao, GUAN Quanzhong, WANGZHOU Xiangxin, ZHANG Congke
2025, 47(4): 895-903. doi: 10.11781/sysydz2025040895
Abstract(53) HTML (22) PDF-CN(11)
Abstract:
Laser Raman spectroscopy has become increasingly prevalent in assessing the thermal maturity of ancient marine shale due to its advantages of simple sample preparation, easy operation, and non-destructive analysis. Current studies primarily focus on the response of Raman spectral parameters to thermal maturity variations, while research on the influence of non-thermal maturity factors, such as spectrum processing methods, sample pretreatment, and laser wavelength settings, on experimental accuracy remains relatively scarce and inconsistent. Using laser Raman spectroscopy, this study conducted a systematic comparative analysis of highly to overmature black shale samples from the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation and Lower Cambrian Qiongzhusi Formation in the Sichuan Basin, with a particular focus on the impact of non-thermal maturity factors on parameters such as Raman band separation (RBS), full width at half maximum (FWHM), and the intensity ratio of D peak to G peak (ID/IG). The findings are as follows: (1) Spectrum processing methods: Two-peak fitting demonstrated lower uncertainty and higher efficiency than five-peak fitting, making it more suitable for thermal maturity assessment of highly to overmature shale, especially for the processing of Raman spectra of shale in Qiongzhusi Formation. (2) Parameter selection: Positional parameters (WD, WG, and RBS) showed thermal maturity differences of less than 2% after peak fitting, indicating high stability. Conversely, among the peak shape parameters (ID/IG, FWHM-D, FWHM-G), ID/IG was less affected by peak fitting and demonstrated better sample discrimination. Therefore, RBS and ID/IG are recommended as priority parameters in thermal maturity correlation studies. (3) Sample pretreatment: Polishing treatment has an overall impact of less than 3% on the Raman parameters of highly to overmature black shale from the Wufeng Formation and Longmaxi Formation. However, to accurately locate the dispersed organic matter within the black shale, polishing prior to Raman analysis is recommended.
Super-resolution reconstruction technology for full-diameter core nuclear magnetic resonance scanning data: a global non-negative least squares-based approach
MA Yingying, PENG Zebo, CHEN Jingzhi, WU Fei, NIE Xin, LIAO Zhongshu, ZHANG Gong
2025, 47(4): 904-912. doi: 10.11781/sysydz2025040904
Abstract(36) HTML (26) PDF-CN(9)
Abstract:
Full-diameter core nuclear magnetic resonance (NMR) analysis is one of the key exploration and analysis techniques in unconventional oil and gas exploration. It provides continuous high-resolution information on rock core porosity, permeability, and fluid saturation. However, due to its large measurement sensitivity area, signals from different positions overlap, resulting in a significantly lower vertical resolution compared to instrument sampling. This limitation hinders its effectiveness in detecting thin interbedded reservoir. To improve the vertical resolution of the full-diameter core NMR measurements, the measured data were modeled as the convolution of the instrument's sensitivity area function and the core's real signal. High-resolution reconstruction of the original signal was achieved using global non-negative least squares, without changing the existing instrument structure or measurement mode. The feasibility of this method was validated through numerical simulations, physical experiments, and actual data analysis. Practical applications show that the high-resolution processed NMR porosity from well logging aligns more closely with gas-filled porosity. This method significantly improves the vertical resolution of full-diameter core NMR measurements, enhancing the detection capabilities for thin interbedded reservoirs.
Gas injection capacity of low permeability reservoirs considering microscopic characteristics
MA Yongxin, ZHANG Qiaoliang, ZHU Jinqi, MA Shuai, WANG Xin, ZHU Runhua
2025, 47(4): 913-920. doi: 10.11781/sysydz2025040913
Abstract(66) HTML (22) PDF-CN(14)
Abstract:
Gas injection is a crucial method for enhancing oil recovery in low permeability reservoirs, but current evaluation methods for gas injection capacity have not fully considered microscopic pore characteristics. Therefore, taking the low permeability reservoirs in the fourth member of the Oligocene Weizhou Formation in well block 3 in the middle block of the Weizhou B Oilfield, Beibuwan Basin as the research object, a gas-phase effective permeability evaluation model was established based on dynamic correction of static logging permeability, comprehensively considering microscopic pore-throat structural characteristics (such as fractal dimension, throat radius, and tortuosity) and the thickness of bound water film. At the same time, core multiple-cycle gas flooding experiments were used to verify the accuracy of the evaluation model, and the seepage patterns of gas injection under the influence of microscopic characteristics were analyzed. The results showed that the gas injection capacity in low permeability reservoirs undergoes three evolutionary stages: In the initial stage of gas injection (0 to 100 PV), gas preferentially displaces crude oil in larger pores, leading to a rapid reduction in bound water saturation and a sharp increase in gas-phase permeability, which significantly improves gas flooding efficiency. In the middle stage of gas injection (100 to 1 200 PV), the gas-phase effective permeability increases linearly, and the bound water enters a stable phase due to capillary force constraints in microscopic throats. In the later stage of gas injection (>1 200 PV), gas begins to break through the water film in microscopic pores, causing a slow decrease in bound water saturation. However, due to the hydrophilicity and heterogeneity of reservoirs, residual oil are trapped as an isolated phase, leading to the stabilization of gas-phase permeability and displacement efficiency (with a maximum of 52%), and limiting the development potential of reservoirs. Field verification in the Weizhou B Oilfield demonstrated that increasing injection pressure in the initial stage can effectively improve gas injectivity index, while in the later stage, it is necessary to control the gas injection amount to prevent oil phase isolation in heterogeneous reservoirs and rising water cut in production wells, thereby ensuring oil phase precipitation and improving the overall reservoir gas flooding efficiency.
Utilization strategies for deep coal-measure reservoirs with different stacking patterns in Linxing block, Ordos Basin
SUN Lichun, LIU Jia, LI Xinze, SUN Le, FANG Maojun, LI Na, FAN Weipeng
2025, 47(4): 921-929. doi: 10.11781/sysydz2025040921
Abstract(40) HTML (17) PDF-CN(9)
Abstract:
The Linxing block in the Ordos Basin has entered the stage of co-production of tight gas and coalbed methane (CBM), and the stacking patterns of tight sandstone and coal seams directly affect the production methods. By analyzing the stacking relationships and production dynamics using different development methods in the Linxing block, the utilization strategies for deep coal-measure reservoirs were investigated. Based on the sedimentary characteristics and relative spatial positions of tight sandstone and coal seams, the sand-coal stacking patterns in the Linxing block were mainly categorized into interbedded sand-coal type and upper sand-lower coal type. By comparing the development status under different stacking patterns, it was found that horizontal wells were preferred for the independent development of deep CBM, and wells co-producing CBM and tight gas had higher initial gas production capacity than vertical or directional wells producing CBM alone. An optimization chart of deep coal-measure reservoir utilization strategies under different stacking patterns was further established, with economic efficiency as the optimization objective. When CBM abundance is less than 1.1×108 m3/km2 and the tight gas reservoir is classified as a Class Ⅰ or Class Ⅱ, a co-production approach should be adopted. Under the condition that CBM abundance ranges from 1.1×108 to 1.5×108 m3/km2, if the tight gas reservoir is underdeveloped, horizontal wells should be used for the independent utilization of CBM; if the tight gas reservoir is classified as Class Ⅰ or Ⅱ, a co-production method should be adopted. Under the condition that CBM abundance exceeds 1.5×108 m3/km2, if the tight gas reservoir is underdeveloped or classified as Class Ⅱ or Ⅲ, horizontal wells should be used to develop the coal seams solely; if the tight gas reservoir is classified as Class Ⅰ, tight gas and CBM should be developed separately. The research provides technical support for the efficient co-production of deep CBM resources in the Linxing block and other similar blocks.
Influencing mechanisms of solid-phase asphaltene precipitation in crude oil of Yongjin Oil Field, Junggar Basin
YANG Yang, ZHANG Dongxiao, WANG Hao, LUN Zengmin, GAO Zhiwei, WANG Rui, HU Wei
2025, 47(4): 930-940. doi: 10.11781/sysydz2025040930
Abstract(47) HTML (19) PDF-CN(8)
Abstract:
Solid-phase asphaltene precipitation and deposition, commonly occurring during reservoir development, lead to reservoir damage and production well blockage, seriously affecting crude oil exploitation and reducing economic efficiency. Solid-phase asphaltene precipitation is affected by the properties of crude oil and temperature/pressure condition, and is a thermodynamic issue involving complex gas-liquid-solid three-phase behavior. This study aims to investigate the solid-state precipitation pattern and its influencing mechanisms of asphaltenes in crude oil from the Yongjin Oil Field, aiming to provide theoretical support for the rational prevention of asphaltene deposition during reservoir development. High-asphaltene-content crude oil from the Yongjin Oil Field was selected as the research object. Crude oil composition analysis, pressure-volume-temperature (PVT) high-pressure physical property analysis, gas injection, and solid-phase asphaltene precipitation experiments were conducted to reveal the precipitation pattern of asphaltenes under different conditions. Based on the cubic plus association (CPA) equation of state (EoS), a three-phase equilibrium calculation model for the oil-gas-asphaltene system was established. The model was fitted to experimental results and used to further simulate the precipitation pattern of asphaltenes under complex conditions, clarifying the effects and their influencing mechanisms of fluid composition, temperature, pressure, and production well operation strategies on solid-phase asphaltene precipitation. The results showed that fluid composition and temperature/pressure conditions were the intrinsic factors and external conditions, respectively, influencing asphaltene precipitation in the system, and the like-dissolves-like principle could fully explain the mechanism of complex phase behavior changes in asphaltenes. After gas injection, the fluid composition was altered, and its influence on crude oil and asphaltene phase behavior was primarily determined by the miscibility of injected gas with crude oil and the extraction and stripping of intermediate components. Production well operation strategies affected asphaltene precipitation by controlling temperature and pressure variations during crude oil flow, thereby determining the location of precipitation. Risk assessment of asphaltene deposition and blockage requires comprehensive analysis integrating reservoir conditions, wellbore structure, and production dynamics.

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