Journal of Natural Gas Geoscience最新文献

{"title":"Evolution of hydrocarbon accumulation in Upper Cambrian carbonate rocks of the Yingdong structural belt, eastern Tarim Basin, China: Insights from fluid inclusion analysis of Well Yingdong-1","authors":"Weihong Liu ,&nbsp;Hao Li ,&nbsp;Yong Peng ,&nbsp;Honggang Cheng ,&nbsp;He Wang","doi":"10.1016/j.jnggs.2026.01.001","DOIUrl":"10.1016/j.jnggs.2026.01.001","url":null,"abstract":"<div><div>The Cambrian strata in the eastern Tarim Basin (Tadong area) possess favorable geological conditions for hydrocarbon accumulation; however, the exploration degree remains low, and no major breakthroughs have been achieved for an extended period. The limitation lies in an insufficient hydrocarbon accumulation and evolution processes, which leads to ambiguous exploration directions. To address this issue, this study integrates data from drilling, core samples, and fluid inclusion thin section analyses, combined with burial history reconstruction, hydrocarbon generation evolution, and structural evolution analyses. The characteristics of fluid inclusions in the Paleozoic reservoirs from Well Yingdong-1 in the Yingdong structural belt of the Tadong area were systematically investigated. The homogenization temperature and salinity of the inclusions were determined, and a burial-thermal evolution simulation was conducted. The results indicate that the fluid inclusions can be divided into two distinct periods: Period I inclusions formed in the middle stage of the Late Ordovician, which corresponds to the initial oil generation stage of the source rocks; Period II inclusions formed from the Late Permian to the Early Triassic and represent the destruction and adjustment phase of the oil and gas reservoirs. Combined with the structural evolution history of the Yingdong structural belt, the results suggest that oil reservoirs were primarily formed toward the end of the Ordovician, while the main gas generation phase occurred during the Silurian to Devonian. By the end of the Devonian, the oil reservoirs had largely cracked into gas reservoirs. Subsequently, by the end of the Triassic, the Yingdong-1 oil and gas reservoir experienced significant destruction and adjustment as a result of the Indosinian tectonic movement. Based on these findings, it is recommended that the future exploration targets focus on areas where ancient carbonate rocks have not been breached by faulting or on traps that have undergone structural adjustments and preservation.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 1","pages":"Pages 31-41"},"PeriodicalIF":0.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147420494","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Construction and geological application of comprehensive evaluation indices for biomarker characteristics: A case study of the Yanchang Formation in the Ordos Basin, China","authors":"Kaiming Su ,&nbsp;Jingyi Li ,&nbsp;You Zhou ,&nbsp;Wanglin Xu ,&nbsp;Yaohui Xu ,&nbsp;Yang Li ,&nbsp;Gang Yan ,&nbsp;Taohua He","doi":"10.1016/j.jnggs.2026.02.001","DOIUrl":"10.1016/j.jnggs.2026.02.001","url":null,"abstract":"<div><div>In response to the issue of numerous, redundant, and complexly interpreted biomarker parameters in molecular geochemistry, this paper proposes a novel comprehensive index evaluation method. Focusing on the Yanchang Formation in the Ordos Basin, factor analysis is employed to screen biomarker parameters that are most closely related to organic matter maturity, parent material type, and water salinity. Based on the selected parameters, three comprehensive indices—the Maturity Index (MI), Parent Material Index (PMI), and Water Salinity Index (WSI)—are constructed through linear combinations. Applications of these indices to different stratigraphic layers and structural blocks of the Yanchang Formation demonstrate their ability to represent the geochemical characteristics of organic matter more concisely and clearly, with higher accuracy and reliability than single biomarker parameters. Research findings based on these indices reveal that the maturity of organic matter in the Yanchang Formation gradually increases with burial depth, that the Chang 7 oil group exhibits a significant contribution from aquatic organic matter, and that deeper oil groups, such as Chang 9 and Chang 10, are associated with relatively higher water salinity. Additionally, the planar distribution patterns of maturity, parent material type, and water salinity across different blocks are complex, reflecting the heterogeneity of geological conditions. Overall, the comprehensive index evaluation method proposed in this paper provides a new analytical framework for molecular geochemistry research and has important implications for oil and gas exploration under complex geological settings.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 1","pages":"Pages 43-56"},"PeriodicalIF":0.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147420493","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Microscopic coupling mechanisms between helium and carrier gas molecules and their influence on accumulation and retention behavior","authors":"Wentao Zhang ,&nbsp;Yifei Liu ,&nbsp;Ping Li ,&nbsp;Chunhui Zhao ,&nbsp;Zhe Ding ,&nbsp;Huifei Tao ,&nbsp;Jianjun Liang ,&nbsp;Zhuanhong Lu ,&nbsp;Dongqi Wang ,&nbsp;Qiaohui Fan","doi":"10.1016/j.jnggs.2026.01.002","DOIUrl":"10.1016/j.jnggs.2026.01.002","url":null,"abstract":"<div><div>Helium (He) is an indispensable strategic resource for global high-technology industries, and its migration and preservation during accumulation are strongly governed by synergistic interactions with fluid carrier gases such as methane (CH₄), carbon dioxide (CO₂), and nitrogen (N₂). To elucidate the microscopic coupling mechanisms between He and carrier gas molecules, as well as their environmental dependence, this study employs quantum chemical calculations combined with molecular configuration screening to systematically evaluate coupling energies and the stability of He-carrier coupled structures under anhydrous and hydrous conditions. The results show that, under anhydrous environments, the coupling affinity between He and carrier molecules follows the order CO₂&gt;CH₄&gt;N₂&gt;He. In contrast, under hydrous conditions, the interactions of He with CO₂ and CH₄ are weakened, whereas the coupling stability with N₂ is significantly enhanced, accompanied by a spatial reorganization of coupling sites. Solvation effects induced by water molecules strengthen He–N₂ interactions, indicating that pore water within mineral matrices facilitates the co-existence of He and N₂. In multi-molecular systems, He–H₂O complexes exhibit the highest stability, followed by He–CO₂, He–CH₄, and He–N₂. Moreover, owing to their relatively large molecular sizes and their propensity to form molecular clusters, carrier gas molecules can physically block caprock pore throats, thereby enhancing sealing efficiency and reducing He leakage. Based on these findings, three key microscopic contributions of carrier gases to He accumulation are identified, namely aggregation in water, cooperative transport through fractures, and effective retention by caprocks. From a molecular-scale perspective, this study reveals the cooperative role of the He-carrier system in helium accumulation and provides a theoretical basis for elucidating accumulation mechanisms and predicting He-rich sweet spots.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 1","pages":"Pages 57-66"},"PeriodicalIF":0.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147420492","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Accumulation characteristics and models of low-rank multi-source coal-rock gas in the Jurassic of Junggar Basin, China","authors":"Honglin Liu ,&nbsp;Huaichang Wang ,&nbsp;Ze Deng ,&nbsp;Daojun Huang","doi":"10.1016/j.jnggs.2025.12.001","DOIUrl":"10.1016/j.jnggs.2025.12.001","url":null,"abstract":"<div><div>The Junggar Basin is a large Jurassic low-rank coal-bearing basin in western China, mainly comprising the Xishanyao Formation and the Badaowan Formation, which are characterized by substantial coal measure thickness and stable spatial distribution. The coal-rock gas resources in the whole basin exceed 3 × 10¹² m³, and with a maximum daily gas production of 57 × 10³ m³. However, the accumulation characteristics and enrichment laws of coal-rock gas remain insufficiently understood. Subsequent to this development, this paper comprehensively analyzes coal quality, reservoir characteristics, and gas-bearing properties of coal seams, and concludes that: (1) The southeastern margin of the Junggar Basin has superior conditions for coal-rock gas accumulation, characterized by wide distribution of Jurassic coal seams with large thickness, good coal quality, moderate to poor reservoir physical and adsorption properties, and rich coal-rock gas resources. (2) Reservoir formation is jointly controlled by multiple factors, including gas source conditions, structural conditions, and preservation conditions. The identified reservoir types include exogenous fault-occlusion type, exogenous anticlinal type, endogenous pore type, formation pinch-out type, and exogenous fracture type. (3) The enrichment of coal-rock gas shows distinct characteristics of plane distribution, being more favorable in the south than in the north and better in the west than in the east. The main controlling factors include coal quality, thermal evolution degree, coal seam roof and floor sealing and hydrogeological conditions. (4) Using the volumetric method, coal-rock gas resources in the weathered zone shallower than 5000 m across the basin were estimated. In the Urumquqi to Fukang area at depths shallower than 2000 m, the estimated resource volume is 1623.82 × 10⁹ m³, while resources at depths between 2000 and 5000 m amount to 1316.36 × 10⁹ m³. Based on an optimal selection index system of advantageous areas, Urumqi–Dahuangshan and Baijiahai are identified as advantageous exploration targets, covering a total area of 2630 km² with a predicted resource volume of 320 × 10⁹ m³, indicating abundant resources and favorable reservoir-forming conditions.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 1","pages":"Pages 15-30"},"PeriodicalIF":0.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147420429","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Hydrocarbon accumulation differences and exploration directions among sub-sags of the Taibei Sag, Tuha Basin, China","authors":"Jianzhong Li ,&nbsp;Fan Yang ,&nbsp;Dongsheng Xiao ,&nbsp;Xuan Chen ,&nbsp;Chao Wu ,&nbsp;Hua Zhang ,&nbsp;Haiyue Yu ,&nbsp;Xueli Jia ,&nbsp;Gang Chen","doi":"10.1016/j.jnggs.2025.12.002","DOIUrl":"10.1016/j.jnggs.2025.12.002","url":null,"abstract":"<div><div>The Taibei Sag of the Tuha Basin contains three major hydrocarbon-generating sub-sags—Shengbei, Qiudong, and Xiaocaohu—in the Shuixigou Group. Although these sub-sags share similar tectonic–sequence–sedimentary evolutionary backgrounds, they exhibit distinct petroleum geological characteristics and hydrocarbon accumulation patterns as a result of differential uplift between the southern and northern orogenic belts. Based on a comprehensive analysis of structural evolution, source rocks, sedimentary reservoirs, and accumulation condition differences among the three sub-sags are identified mainly in four aspects. (1) During the Early to Middle Jurassic, the Taibei Sag maintained a relatively unified tectonic–sedimentary framework, internally segmented by local uplifts, with the Xiaocaohu sub-sag in the east serving as the primary depocenter. By the Late Jurassic, eastern uplift shifted the depositional focus to the Shengbei sub-sag. (2) During the main hydrocarbon accumulation stage of the Xiaocaohu sub-sag, source rocks had already reached a highly mature stage. Subsequently, as the Shengbei sub-sag deepened, both sags reached a mature to highly mature stage. Overall, the source rocks of the Shuixigou Group in the Taibei Sag are generally characterized by mature to highly mature hydrocarbon evolutionary stage. (3) The Shengbei sub-sag developed three provenance systems, among which the northwestern long-axis provenance system transported well-sorted sediments over long distances. In contrast, the Qiudong and Xiaocaohu sub-sags are dominated by bidirectional NS braided river delta systems. The southern provenance systems across all three sub-sags contain rigid clasts with strong compressive resistance, which is favorable for high-quality reservoir formation. (4) The Shuixigou Group experienced at least three stages of hydrocarbon accumulation. The Shengbei and Xiaocaohu sub-sags underwent slightly earlier hydrocarbon charging compared to the Qiudong sub-sag. Favorable exploration areas were assessed on the basis of accumulation patterns in the three sub-sags. Three key exploration frontiers are identified: tight sandstone reservoirs in sub-sags, lithologic–stratigraphic reservoirs in slope zones in the south, and structural reservoirs in piedmont buried zones in the north. These areas represent prioritized directions for near-term hydrocarbon exploration in the Taibei Sag.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"11 1","pages":"Pages 1-14"},"PeriodicalIF":0.0,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147420431","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of multicomponent seismic in tight reservoir prediction of the first member of Jurassic Shaximiao Formation, Sichuan Basin, China","authors":"Ming Zhang,&nbsp;Xin Zhang,&nbsp;Jing Liang,&nbsp;Lideng Gan,&nbsp;Xiaowei Yu","doi":"10.1016/j.jnggs.2025.09.004","DOIUrl":"10.1016/j.jnggs.2025.09.004","url":null,"abstract":"<div><div>As the most powerful tool for tight gas prediction and exploration in the second member of the Shaximiao Formation (Sha 2 Member) in the Sichuan Basin, the technique of bright spot fails to deliver satisfactory results in the Sha 1 Member. To address the challenge posed by non-bright spot reservoirs, a multicomponent seismic survey was performed. Seismic responses of tight gas reservoirs in the Sha 1 and Sha 2 members were identified through the analysis of log responses and forward modeling. PP-PS registration was accomplished in the time domain, followed by joint PP-PS prediction of channel sands and gas accumulation in the Sha 1 Member. The results show that: (1) Reservoir porosity in the Sha 1 Member is smaller than in the Sha 2 Member, while bright spots generally correspond to high-porosity sands. Consequently, bright spot reflections are relatively scarce in the Sha 1 Member. (2) Sands in the Sha 1 Member that exhibit weak PP reflections and medium to strong PS reflections can be clearly delineated using PS data, which has led to the discovery of extensive reservoirs in the study area. This research has facilitated multicomponent seismic acquisition and application on a larger scale in the northwestern Sichuan Basin. Newly deployed wells have achieved a ratio of 90% for reservoir penetration, offering an effective support for reserve estimating in the Sha 1 Member.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 6","pages":"Pages 361-370"},"PeriodicalIF":0.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145802006","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Genesis of high-salinity formation water and salinity sensitivity of deep coal-rock gas reservoirs in the Ordos Basin, China","authors":"Lijun You,&nbsp;Rui Qian,&nbsp;Yili Kang,&nbsp;Yijie Wu","doi":"10.1016/j.jnggs.2025.11.002","DOIUrl":"10.1016/j.jnggs.2025.11.002","url":null,"abstract":"<div><div>Deep coal-rock gas reservoirs in the Ordos Basin are characterized by high-salinity formation water, low water saturation, and high gas saturation. During hydraulic fracturing, injected fluid can easily permeate the coalbed, which restricts the development of coal-rock gas to further increase production. The No.8 deep coal of Benxi Formation in the Ordos Basin was selected, and the salinity sensitivity experiment was done via the pressure decay method, soluble substance immersion experiment, and thermal evolution-hydrogeological analysis. We analyzed the genesis of high-salinity CaCl₂ type formation water and quantitatively evaluated the permeability damage of different salt fractions in the coal rock. The study shows that: the high-salinity formation water in deep coal rock of the Ordos Basin mainly originates from the synergistic effect of the thermally evolved hydrocarbon drainage-driven primary water and the deep formation water extrusion from the karst layer. The proportion of Ca²⁺ and Mg²⁺ in the cationic fraction of formation water is as high as 16%–66%. The coal rock salinity sensitivity damage is significantly enhanced with the increase in salinity (up to 61.93%). The damage rate of divalent calcium and magnesium was much higher than that of monovalent sodium and potassium, which were 72.15%–85.92% and 36.82%–45.40%, respectively. The brine with salinity lower than 20000 mg/L can enhance permeability, but the intrusion of high-salinity fluid can easily trigger irreversible salinity sensitivity damage. Deionized water can dissolve a small amount of soluble salts and trace organic matter in coal rock. Based on this study, the countermeasures of using clear water fracturing fluid and flowback fluid softening are proposed to provide theoretical basis for reservoir protection and efficient development of deep coal rock gas reservoirs.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 6","pages":"Pages 371-381"},"PeriodicalIF":0.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145802007","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reservoir characteristics and effect on methane adsorption capacity in marine–continental transitional shale: The Carboniferous Yanghugou Formation in the Weiningbeishan area (eastern North Qilian orogenic belt), China","authors":"Donggang Wang ,&nbsp;Yu Ma ,&nbsp;Yanyun Ma ,&nbsp;Wenzhong Wu ,&nbsp;Kun Yu","doi":"10.1016/j.jnggs.2025.11.001","DOIUrl":"10.1016/j.jnggs.2025.11.001","url":null,"abstract":"<div><div>Marine–continental transitional (MCT) shale from the Yanghugou Formation in the Weiningbeishan area represents a promising yet underexplored target for shale gas development. This study systematically investigates the reservoir properties and methane adsorption behavior of MCT shale samples from the Well ZK03 through integrated analyses, including total organic carbon (TOC), Rock-Eval pyrolysis, maceral composition, vitrinite reflectance (<em>R</em>_O), X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), low-pressure nitrogen adsorption, and high-pressure methane adsorption. The results reveal that the shale is rich in type II₁ and II₂ organic matter with high TOC content and has entered the dry gas generation window. A key finding is the predominance of well-developed clay mineral-hosted pores, in contrast to the scarcity of organic matter-hosted pores—a distinctive feature compared to typical marine shales. The complex pore structure is dominated by meso–macropores in terms of volume, whereas micropores contribute most significantly to the specific surface area. Methane adsorption capacity shows positive correlations with both TOC and clay content, underscoring the synergistic role of organic and clay components in controlling gas adsorption. By clarifying the specific mechanisms governing methane adsorption in MCT shales of the Yanghugou Formation, this work provides novel insights into the unique gas enrichment patterns of transitional shales, addressing a critical gap in the current understanding of their reservoir characteristics.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 6","pages":"Pages 399-413"},"PeriodicalIF":0.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145802058","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Shelf edge progradation: An example from Early Cretaceous to Recent based on a seismic sequence stratigraphic framework in the Bengal Basin","authors":"Rabeya Basri ,&nbsp;A.S.M. Woobaidullah ,&nbsp;Delwar Hossain ,&nbsp;Md. Anwar Hossain Bhuiyan","doi":"10.1016/j.jnggs.2025.10.002","DOIUrl":"10.1016/j.jnggs.2025.10.002","url":null,"abstract":"<div><div>This study reconstructs the stratigraphic and tectonostratigraphic frameworks of the Bengal Basin by integrating outcrop geological observations, 2D seismic profiles, well logs, core samples, sedimentological, geochemical, and radiometric dating data that are tied to global eustatic sea-level variations. Sequence stratigraphic analysis of the basin allowed the identification of three megasequences, seven seismic sequences, and twelve regional stratigraphic markers spanning from the Late Cretaceous to Holocene. The shelf-edge progradation analysis from Early Cretaceous to Recent reveals the Bengal Basin’s evolution from Gondwana rifting to foredeep subsidence and deltaic progradation. Controlled by tectonics, eustasy, and sediment supply, the Ganges-Brahmaputra Delta and the Bengal Fan established a complex stratigraphic framework with significant petroleum potential. Petroleum prospectivity is concentrated in Paleocene to Pliocene sandstones having intraformational shales as seals. Structural trapping configurations include horst-graben fault blocks and fold-belt closures, and stratigraphic trapping configurations such as stratigraphic pinchouts and channelized deposits. Seismic attribute analysis combined with well and core data emphasizes on the potential of underexplored Miocene-Pliocene slope-fan and canyon-fill turbidites as emerging frontier targets. Comparative evaluation of the Bengal Basin with the Krishna-Godavari Basin highlights greater structural complexity, thicker sedimentary pile, and diverse play types, suggesting it’s higher hydrocarbon potential. However, exploration continues to face significant challenges, as this study is based only on qualitative analysis constrained by limited seismic coverage and the low resolution of older datasets. Overall, the Bengal Basin represents a tectonically dynamic and sedimentologically complex petroleum province, whose stratigraphic framework and depositional history are crucial for guiding future exploration strategies.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 6","pages":"Pages 415-477"},"PeriodicalIF":0.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145802056","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Full-scale pore structure characterization and main controlling factors of marine–continental transitional shale and coal reservoirs in the Shanxi Formation, Ordos Basin, China","authors":"Xingcheng Zhu ,&nbsp;Jungang Lu ,&nbsp;Yong Li ,&nbsp;Qingbo He ,&nbsp;Shuxing Li ,&nbsp;Zhenglu Xiao ,&nbsp;Qijun Jiang ,&nbsp;Ruijie Chen ,&nbsp;Wenxin Shi","doi":"10.1016/j.jnggs.2025.10.001","DOIUrl":"10.1016/j.jnggs.2025.10.001","url":null,"abstract":"<div><div>Pore structure heterogeneity between marine–continental transitional shale and coal reservoirs plays a crucial role in exploration and development of unconventional oil and gas resources. This study uses the Shan₂³ sub-member in the Danning–Jixian area of the Ordos Basin as a case study, systematically characterizing and comparing the full-scale pore structures of shale and coal reservoirs. Using field emission scanning electron microscopy (FE-SEM), mercury intrusion porosimetry (MIP), N₂ and CO₂ adsorption experiments, along with total organic carbon (TOC) and x-ray diffraction (XRD) analyses, the study investigates the influence of organic matter and inorganic minerals on pore structures at different scales. The results show that the average TOC value of the shale is 4.69% and exhibit well-developed organic matter pores, inorganic pores, and microfractures, with organic matter pores being the most abundant and often densely and clustered. In contrast, the coal has a significantly higher average TOC value of 74.22%, with organic matter pores being the dominant pore type. The pore diameter in coal is also significantly larger than that in marine–continental transitional shale and marine shale. For shale, micropores, mesopores, and macropores all contribute to the total pore volume, with organic matter serving as the primary material foundation for micropore development. Meanwhile, clay mineral diagenesis plays an important role in promoting mesopore and macropore development. For coal, micropores and macropores are the main types, with organic matter being the most significant factor influencing pore development; A higher <span>TOC</span> content supports the formation of larger organic pores. Overall, this study provides a comprehensive look at the similarities and differences in the pore structures of marine–continental transitional shale and coal reservoirs at the micro scale, providing a scientific basis for the precise evaluation and development of unconventional oil and gas resources.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 6","pages":"Pages 383-397"},"PeriodicalIF":0.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145802057","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}