Journal of Natural Gas Geoscience最新文献

{"title":"Multi-stage karst characteristics and reservoir control of early diagenetic limestone in Taiyuan Formation, Ordos Basin, China","authors":"Xiaoxiong Yan ,&nbsp;Shoukang Zhong ,&nbsp;Wenchao Pei ,&nbsp;Jie Xu ,&nbsp;Xiucheng Tan","doi":"10.1016/j.jnggs.2025.06.001","DOIUrl":"10.1016/j.jnggs.2025.06.001","url":null,"abstract":"<div><div>Recently, several wells, such as YT1H and ZT1 in the Ordos Basin, have made new discoveries of natural gas in the Permian Taiyuan Formation limestone, revealing that the limestone of the Taiyuan Formation has good exploration potential. However, there are still problems such as unclear reservoir genesis mechanism and undefined key reservoir formation mode in the Taiyuan Formation limestone, which seriously restricts further gas exploration and deployment in this layer. Therefore, based on the abundant core, thin section and physical property data of Taiyuan Formation, this paper systematically studies the relationship between limestone reservoir development and early exposed karstification, establishing the karst reservoir control model in the early limestone diagenesis. The results show that: (1) Early diagenetic karstification primarily developed in granular limestone and mostly located in the middle and upper parts of the upward-shallowing sequence. Meanwhile, the identifiable karst features include fabric selective dissolution, solution fissures/solution gullies, dissolution speckle, karst breccia, and multi-phase exposed surfaces. (2) Karst strength within a single cycle gradually increases from the bottom to the top. The karst at the bottom of the cycle was weak, with locally developed chip moldic holes. The upward karst reconstruction scope expanded, the dominant channel and the dissolution mottling began to emerge, and the karst process developed moderately; the upper karst system of the cycle cleaved and dissociated the bedrock, developed karst breccia, and exhibiting overdeveloped karst processes. (3) Under the control of exposure time, both high- and low–frequency cycles are developed in the study area, and the exposed surfaces of high–frequency cycles are mostly found in limestone, which is an “episodic” cycle interface, and the inner karst intensity is manifested as karst non-development→selective degradation of bioclastic debris→dominant channels and dissolution spots. In contrast, low frequency cycle interfaces are observed only at the top of slope sections or Maergou Section of the limestone, where inner karst intensity is manifested as dominant channels→dissolution spots→karst breccia. (4) The high-quality limestone reservoirs are mainly developed in the middle and upper parts of the quaternary cycle, corresponding to regions of moderate karst reconstruction area. In comparison, reservoir quality of the lower part of the cycle and the top part of the cycle became significantly worse. It is believed that the multi-stage karst in the early diagenetic stage not only controls the development and distribution of limestone reservoirs in the study area, but also greatly improves the reservoir and seepage capacity, which is the key factor for the formation of limestone reservoirs in Taiyuan Formation.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 4","pages":"Pages 249-261"},"PeriodicalIF":0.0,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144911941","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":"Geological characteristics of Jurassic coal rock gas and evaluation of favorable zones in the northern structural belt of the Kuqa Depression, Tarim Basin, China","authors":"Zeqing Guo ,&nbsp;Caiyuan Dong ,&nbsp;Bin Wang ,&nbsp;Ling Li ,&nbsp;Zhenglian Pang ,&nbsp;Xiuyan Chen ,&nbsp;Debo Ma","doi":"10.1016/j.jnggs.2025.07.002","DOIUrl":"10.1016/j.jnggs.2025.07.002","url":null,"abstract":"<div><div>The Kuqa Depression in the Tarim Basin has developed two sets of coal-bearing strata: the Triassic and the Jurassic. The Jurassic coals are characterized by multiple layers, large cumulative thickness, and a wide distribution area, providing a strong material basis for the development of coal rock gas. This study presents a comprehensive evaluation of the Jurassic coal quality and reservoir characteristics in the northern structural belt of the Kuqa Depression. The evaluation is based on intensive core sampling, rock debris data, and the use of analytical techniques, including microscopic identification, industrial analysis, vitrinite reflectance measurement, scanning electron microscopy, conventional physical property analysis, nuclear magnetic resonance (NMR) detection, CT scanning, and nitrogen adsorption analysis. The results show that: (1) The microscopic components are mainly vitrinite, with an average content of 64.06%; coal has the characteristics of medium to high volatile matter content, ultra-low moisture, ultra-low ash content, and overall relatively low maturity. (2) Various matrix pores and fractures are developed, with large microcracks forming the main component of the pore network. These microcracks are interconnected and form stacked networks. The porosity of shallow samples ranges from 4% to 23%, with an average of 9.7%, and is characterized by a high proportion of mesopores and macropores. The porosity below 4000 m deep can reach up to 6.34%. Based on the critical burial depth observed in other basins and the correlation between coal maturity and burial depth, the top critical burial depth for effective coal rock gas accumulation in this area is determined to be at least 2500 m. On this basis, an accumulation model for coal rock gas reservoirs was established, and further, in low-to middling coal rank areas, the method for evaluating favorable coal rock gas zones were put forward. Applied the above methods, the coal rock gas favorable zones in the area were comprehensively evaluated. On the one hand, this study provides various indicator parameters for evaluating coal quality in this area, and the critical burial depth, reservoir formation model, and favorable zones offer significant guidance for the selection of target areas for coal rock gas exploration in the future. More importantly, the proposed comprehensive evaluation method serves as a technical reference for coal rock gas exploration in other basins.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 4","pages":"Pages 219-238"},"PeriodicalIF":0.0,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144911939","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":"Method and application for ultra-deep carbonate reservoir quality evaluation: A case study of the Well X area in the Fuman Oilfield, Tarim Basin, China","authors":"Ke Xu ,&nbsp;Hui Zhang ,&nbsp;Penglin Zheng ,&nbsp;Mingjin Cai ,&nbsp;Ziwei Qian ,&nbsp;Jianli Qiang ,&nbsp;Lei Liu","doi":"10.1016/j.jnggs.2025.07.001","DOIUrl":"10.1016/j.jnggs.2025.07.001","url":null,"abstract":"<div><div>The Ordovician ultra-deep carbonate reservoirs in the Tarim Basin are rich in oil and gas resources. However, due to the influence of multiple periods of tectonic activity, their distribution shows strong heterogeneity. In regions characterized by fault-controlled fractures and caves, traditional reservoir quality evaluation methods based on physical property parameters are subject to considerable uncertainty. In contrast, methods incorporating geomechanical parameters show notable advantages. In this study, geomechanical parameters—such as present-day in-situ stress, elastic modulus, and natural fracture density—were quantitatively characterized. A geological model of the carbonate fracture-cavity system was established, and a reservoir quality evaluation factor was defined and calculated to enable a quantitative evaluation of ultra-deep carbonate reservoir quality. The results indicate that: (1) In fault-controlled fracture-cavity ultra-deep carbonate reservoirs, the spatial distribution of geomechanical parameters has strong heterogeneity and significantly affected by fault structure. This distribution is segmented along the fault extension direction. Both the elastic modulus and natural fracture density indicate elevated values near fault zones, while present-day in-situ stresses are relatively lower in these areas. (2) Reservoir geomechanical parameters are strongly responsive to the structural and geological characteristics of fault-controlled fracture-cavity carbonate oil and gas reservoirs. The proposed evaluation methods are effective in evaluating reservoir quality and provide a valuable geological reference and support for the efficient exploration and profitable development of fault-controlled fracture-cavity ultra-deep carbonate reservoirs.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 4","pages":"Pages 239-247"},"PeriodicalIF":0.0,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144911940","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":"Differences and controlling factors of pores structure between coal and shale in Longtan Formation from western Guizhou Province, China","authors":"Mengjiang Zhang ,&nbsp;Zhaobiao Yang ,&nbsp;Wei Gao ,&nbsp;Jun Jin ,&nbsp;Xiwei Mu ,&nbsp;Dan Lu ,&nbsp;Hailong Li","doi":"10.1016/j.jnggs.2025.07.004","DOIUrl":"10.1016/j.jnggs.2025.07.004","url":null,"abstract":"<div><div>Transitional facies with high-frequency cycles of coal-shale-sandstone assemblages are widely developed in the Upper Permian Longtan Formation in western Guizhou Province, exhibiting significant contrasts in pore structures between coal and shale reservoirs. A comparative study was conducted on the differences in pore structure between coal and adjacent shale using coal rock samples from six typical coal bearing gas wells in Guizhou, employing analytical techniques such as geological analysis, scanning electron microscopy (SEM), and low-temperature liquid nitrogen adsorption. The research results show that the specific surface area of coal is 44.2–168 m²/g, with a total pore volume of 0.024–0.065 cm³/g. These pores are primarily semi-closed and slit-shaped. The volume and specific surface area of micropores (&lt;2 nm) have absolute advantages, and are positively correlated with the degree of thermal evolution, mainly micropores, as they are closely associated with the gas generation process. In contrast, macropores (&gt;2 nm) exhibit strong heterogeneity, which is linked to differences in microscopic components. The specific surface area of shale is 43.2–66.6 m²/g, and the total pore volume is 0.032–0.059 cm³/g, mainly composed of inkbottle-shaped pores. The distribution of micropores and mesopores is relatively uniform, and the pore size distribution curve shows a bimodal patterns with peaks at approximately 3 nm and 30 nm. Despite structural differences, pores of &lt;10 nm are the main contributors to the specific surface area in both coal and shale. The extractable asphalt has a significant impact on the pore space in coal, and pore volumes across all size ranges increase notably after extraction. The degree of thermal evolution and organic matter content of coal are the main influencing factors on pore structure, while the organic matter content and mineral type of shale are the main factors affecting pore structure, with thermal maturity playing a less significant role. These findings provide critical insights for the co-exploration of coalbed methane and shale gas in coal-measure systems in western Guizhou Province.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 4","pages":"Pages 263-273"},"PeriodicalIF":0.0,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144911942","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":"Geochemical properties of helium and its origin in the Indus Basin, Pakistan","authors":"Muhammad Aslam Khan ,&nbsp;Chenglin Liu ,&nbsp;Zhengang Ding ,&nbsp;Haidong Wang ,&nbsp;Anqi Tian","doi":"10.1016/j.jnggs.2025.07.003","DOIUrl":"10.1016/j.jnggs.2025.07.003","url":null,"abstract":"<div><div>The Indus Basin, one of Pakistan's most significant hydrocarbon provinces, is an underexplored region for helium resources. This study investigates the geochemical characteristics of helium in natural gas samples from the Middle and Lower Indus Basins, focusing on its concentration, isotopic composition, and relationships with other noble gases and hydrocarbons. The anomalous decrease in the helium concentration with increasing depth is attributed to the complex geochemical and geological factors influencing helium distribution, through helium migration along faults and fractures, dissolution into formation water, structural trapping in shallower reservoirs, and dilution by other gases. The results reveal a notable variation in helium concentrations, particularly in the Middle Indus Basin, where CO₂-N₂-rich gas samples exhibit higher helium levels. In contrast, helium concentrations in the Lower Indus Basin remain relatively uniform, regardless of depth. The isotopic analysis indicates a crustal origin for helium in the basin, with contributions from sedimentary sources and radiogenic decay within basement rocks. Isotopic ratios of ³He/⁴He range between 1.3 × 10⁻⁸ and 7.8 × 10⁻⁸, while ⁴He/²⁰Ne ratios further distinguish basement and sedimentary contributions. The absence of correlation between helium and hydrocarbons (CH₄, CO₂) underscores their distinct origins and migration pathways before converging into a shared reservoir. A moderate positive association with nitrogen (N₂) and lack of correlation with argon isotopes (⁴⁰Ar/³⁶Ar) highlight the complexity of noble gas accumulation dynamics.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 4","pages":"Pages 275-289"},"PeriodicalIF":0.0,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144911943","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":"Characteristics of effective helium source rocks and releasing mechanism of helium","authors":"Xiaofeng Wang,&nbsp;Dong Zhao,&nbsp;Dongdong Zhang,&nbsp;Xiaofu Li,&nbsp;Keyu Chen,&nbsp;Wenhui Liu","doi":"10.1016/j.jnggs.2025.05.001","DOIUrl":"10.1016/j.jnggs.2025.05.001","url":null,"abstract":"<div><div>Different helium source rocks exhibit varying characteristics, including differences in the content and occurrence states of precursor elements such as uranium (U) and thorium (Th). In sedimentary rocks, U and Th mainly exist in adsorbed and (or) complexed states of organic matter and clay minerals. The primary migration of helium generated in sediments is liable to occur due to the lack of mineral crystal restraint. Hence, source rocks and reservoir rocks in gas pools act as the primary effective helium source rocks in sediments. In contrast, other sedimentary rocks are less effective as helium sources due to the fact that high porosity results in prolonged helium saturation, thereby restraining the desolubilization and secondary migration of helium. In igneous rocks, isomorphous U and Th are mainly enriched in silicate and phosphate minerals. Temperature is the main controlling factor affecting their primary migration. Granite, characterized by low porosity and limited helium solubility, can experience large-scale release helium under conditions of tectonic uplift and abnormally high temperatures, acting as an effective helium source rock for helium-rich natural gases. Various forms of U and Th can exist in metamorphic rocks, which have higher porosity and higher soluble helium contents than granite, but this result in greater difficulty in helium release. Although the direct source rocks and reservoirs of natural gas reservoirs are effective helium source rocks, it is difficult to form He-rich natural gas due to the influence of hydrocarbon dilution. Sufficient He supply from basin basement or mantle-derived sources is a key condition for natural gas reservoirs to be rich in He.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 137-144"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144563983","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":"Geochemical characteristics, origin and main controlling factors of helium gas accumulation of helium-bearing natural gas in Sulige Gas Field, Ordos Basin, China","authors":"Liyong Fan ,&nbsp;Jianshe Wei ,&nbsp;Aiping Hu ,&nbsp;Yuhong Li ,&nbsp;Linze Xie ,&nbsp;Tao Jiang ,&nbsp;Yuxuan Zhang ,&nbsp;Shangwei Ma","doi":"10.1016/j.jnggs.2025.05.004","DOIUrl":"10.1016/j.jnggs.2025.05.004","url":null,"abstract":"<div><div>The Ordos Basin is the largest natural gas producing region in China. Recent discoveries of two helium-rich natural gas fields (Dongsheng and Qingyang) shows promising helium resource potential. Sulige Gas Field, the largest natural gas field in China, was analyzed to evaluate its helium resource potential. Comprehensive geochemical analyses were conducted, examining natural gas components, alkane gases, carbon isotopic signatures of carbon dioxide, helium concentrations, and helium isotopic ratios within the gas field. Preliminarily studies identified the geochemical characteristics of natural gas and helium in the Paleozoic strata of Sulige Gas Field, and explored the main controlling factors of helium reservoir formation. The results show that the composition of natural gas in the Upper Paleozoic is obviously different. Specifically, Upper Paleozoic natural gas exhibited typical wet gas at the mature stage and dry gas at the over-mature stage, while Lower Paleozoic natural gas is mainly dry gas with partial contribution of wet gas. The Upper Paleozoic is dominated by thermogenic natural gas, predominantly middle-late humic gas (coal-derived) originating from Carboniferous and Permian coal measure source rocks. In contrast, the Lower Paleozoic is dominated by late sapropelic dry gas and oil cracking gas. The helium concentrations in Paleozoic natural gas is higher than in conventional natural gas (0.03%), which belongs to middle helium gas, and the Upper Paleozoic is exceeding those of the Lower Paleozoic. The helium accumulation in the Sulige Gas Field is influenced by the ancient and modern structural location, the high helium generation intensity and relatively low hydrocarbon generation potential of helium source rocks (such as U–Th-rich basement granite and granite gneiss), the development of basement faults, and the complex gas–water relationship, which is favorable for the helium to dissolve out of the water and enter into the natural gas reservoirs.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 145-157"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556883","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":"Petrophysical characterization and reservoir potential of the Lower Goru sandstone: A case study from the Sinjhoro Gas Field, Pakistan","authors":"Waseem Khan ,&nbsp;Salman Ahmed Khattak ,&nbsp;Saeed Anwar ,&nbsp;Sarfraz Hussain Solangi ,&nbsp;Licheng Wang ,&nbsp;George Kontakiotis ,&nbsp;S. Sahaya Jude Dhas","doi":"10.1016/j.jnggs.2025.05.002","DOIUrl":"10.1016/j.jnggs.2025.05.002","url":null,"abstract":"<div><div>The primary method which has been traditionally used for assessing the hydrocarbon potential of reservoir rock involves analyzing petrophysical properties via well logs. Evaluating these properties is crucial for introducing new perspectives. This study offers a valuable case study for regional hydrocarbon evaluation, providing practical insights for exploration in the Lower Indus Basin, Pakistan. This study presents a comprehensive petrophysical evaluation of the Lower Goru Formation (LGF) located in the Sinjhoro Gas Field of Sindh, Pakistan. The characteristics of LGF reservoir are outlined, hydrocarbon potential is evaluated, and gas productivity is quantified through the analysis of density, gamma-ray, resistivity, and neutron logs, along with lateral correlation among different wells. Six significant sand masses exist that may be utilized for hydrocarbon extraction. The extensive sand area serves as the main contributor to current output from wells such as Hakeem Daho-01 and Resham-01, whereas the basal sand is the key source of production for the Well Chak-5. This study underscored the importance of leveraging these resources by showcasing the substantial hydrocarbon potential of the basal sand in Resham-01 and the extensive sand-01 in Hakeem Daho. The massive sand-01 exhibits a thickness of 10 m, with a hydrocarbon saturation of 72%, an average porosity of 11%, a shale volume of 18%, and a net thickness of 8 m. In contrast, the basal sand shows a hydrocarbon saturation of 62%, a porosity of 12%, and a net thickness of 8 m. Both are considered to possess significant reservoir potential. The data shown here has been correlated with its nearby stratigraphic equivalents dealing with the Bhuj Formation of the Kachchh Basin on India's western margin, which is important to understand and predict reservoir properties in other sandstone petroleum fields with similar properties. The conclusions of the study address issues related to reservoir characterization and facilitate the production and utilization of the significant hydrocarbon resources found in the Sinjhoro Gas Field.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 179-197"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556885","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":"Research on the micro-pore structure and multiscale fractal characteristics of shale under supercritical CO2 action: A case study of the Chang 73 submember in the Ordos Basin, China","authors":"Lili Jiang ,&nbsp;Leng Tian ,&nbsp;Zhangxing Chen ,&nbsp;Zechuan Wang ,&nbsp;Wenkui Huang ,&nbsp;Xiaolong Chai","doi":"10.1016/j.jnggs.2025.05.003","DOIUrl":"10.1016/j.jnggs.2025.05.003","url":null,"abstract":"<div><div>To elucidate the mechanism of supercritical CO₂ (ScCO₂) on the microporous structure of shale, this study focuses on the Chang 7₃ submember of the Yanchang Formation in the Ordos Basin. Utilizing a combination of organic geochemical and mineral composition analyses, low-temperature gas (CO₂ and N₂) adsorption experiments and nuclear magnetic resonance (NMR) scanning methods are employed—combined with multiscale fractal theory—the research comprehensively analyze the changes in shale microporous structure and its fractal characteristics under ScCO₂ treatment. The results show that after ScCO₂ treatment, the total organic carbon (TOC) content of the shale samples decreases, the quartz content increases, while the contents of clay minerals and feldspar decrease. Notably, TOC and mineral components are more sensitive to pressure changes compared to temperature variations. Additionally, shale pores are mainly distributed in the micropore (0–2 nm) and mesopore (2–50 nm) ranges, contributing significantly to the specific surface area, while macropores (&gt;50 nm), though fewer, considerably contribute to the total pore volume. Following ScCO₂ treatment, the total specific surface area of shale samples decreases, whereas total pore volume, average pore diameter, and effective porosity increase. Specifically, total specific surface area and average pore diameter are more sensitive to temperature, while total pore volume and effective porosity are more influenced by pressure. The shale pores exhibit multi-scale fractal characteristics, with micropores displaying higher fractal dimensions than meso- and macropores. After ScCO₂ treatment, fractal dimensions at all scales decline, indicating an improvement in the complexity of the shale pore structure. A significant positive correlation exists between the fractal dimension of micropores and TOC content, whereas meso- and macropore fractal dimensions have a stronger correlation with quartz and clay mineral content. These findings indicate that changes in shale mineral characteristics are intrinsic factors affecting microporous structure, while ScCO₂ treatment conditions are important external factors. The interaction of both determines the evolution of shale pore structures, providing a valuable scientific basis and practical guidance for the optimal selection of carbon capture, utilization, and storage (CCUS) target layers.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 159-178"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556884","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":"Impact of pore confinement and adsorption on gas condensate critical properties confined in Marcellus Shale","authors":"Dennis Chinamo,&nbsp;Xiaoqiang Bian","doi":"10.1016/j.jnggs.2025.04.001","DOIUrl":"10.1016/j.jnggs.2025.04.001","url":null,"abstract":"<div><div>Gas condensate reservoirs present significant challenges in reservoir engineering due to their complex phase behavior, which is influenced by continuous compositional changes. In particular, nanopore confinement and adsorption significantly alter the thermodynamic properties of hydrocarbons, affecting phase transitions such as dew point pressure and condensate accumulation. This study investigates these effects within the Marcellus Shale formation by developing a compositional fluid model that integrates critical property shifts induced by pore confinement and adsorption. The model is compared with experimental measurements to ensure accuracy. To evaluate the impact of confinement, six fluid models were constructed using the Peng–Robinson equation of state, representing different pore sizes (1 nm, 2 nm, 5 nm, 10 nm, and 50 nm) alongside an unconfined reference case. The results demonstrate that smaller nanopores lead to significant shifts in critical pressure and temperature, ultimately delaying the onset of liquid condensation. Additionally, adsorption effects enhance reservoir pressure maintenance by storing hydrocarbons in the adsorbed phase, which desorbs as pressure declines, supplementing gas production. By incorporating confinement-induced phase behavior modifications, this research provides key insights into optimizing gas condensate production. The findings highlight the necessity of considering nanoscale confinement and adsorption effects in reservoir simulations to improve forecasting accuracy and develop more effective reservoir management strategies.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 199-218"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556881","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}