Journal of Natural Gas Geoscience最新文献

{"title":"Fracture pore characterization of the first member of Maokou Formation of Middle Permian in Sichuan Basin: A case study of Da’an block, western Chongqing area, China","authors":"Yuman Wang ,&nbsp;Yubing Ji ,&nbsp;Feng Liang ,&nbsp;Ziying Wang ,&nbsp;Xinchun Jiang ,&nbsp;Weimin Li ,&nbsp;Rubiao Chen","doi":"10.1016/j.jnggs.2025.09.003","DOIUrl":"10.1016/j.jnggs.2025.09.003","url":null,"abstract":"<div><div>The first member of the Maokou Formation of the Middle Permian (Mao 1 Member) in the Da’an Block is a key area for exploration of tight limestone gas in the Sichuan Basin. Through the identification and quantitative evaluation of fracture pores from two evaluation wells in the Da’an Block, this paper explores and reveals the development characteristics, distribution patterns, and main controlling factors of fractures in the Mao 1 Member in southern Sichuan Basin. The study reveals that: (1) In the structurally high zones, low-angle bedding fractures, high-angle en echelon fractures, and reticulated fractures are widely developed. The fractures are densely distributed, primarily filled with calcite, and range in width from 1 to 25 mm; some are locally filled with asphalt. In the low zones of the structure, fractures are poorly developed or locally developed. (2) The pore system is complex and diverse, comprising intercrystalline pores of clay minerals, calcite, dolomite, quartz, pyrite, and other mineral grains (crystals), intragranular dissolution pores, organic pores, and fractures. The nuclear magnetic resonance (NMR) <em>T</em>₂ spectrum generally exhibits multi-peak or double-peak characteristics. The volume of reservoir space is mainly composed of brittle mineral pores and fractures, with an average proportion of 47.6%–71.6% and 11.5%–40.3% of the total volume, respectively, whereas organic pores contribute only 16.5%–26.8%. The average porosity of fractures is 0.23%–1.00%, with significant regional variation—higher in the structurally elevated thrust zones but relatively lower in synclinal or structurally low areas. (3) The thickness of fractured favorable reservoirs is 2–24 m, and varies greatly in the region. High value zones are located in the elevated parts of fold belts or anticline cores, where they are distributed in strip-like distribution patterns extending from northeast to southwest. Meanwhile, low value zones are concentrated in the lower parts of fold belts or broad syncline zones. (4) The highly brittle argillaceous limestone enriched in siliceous and dolomitic components, combined with three stages compressional folding and detachment during the Indosinian, Yanshan, and Himalayan orogenic periods, are the key controlling factors for the development of large-scale fracture zones in the area. The middle to late stages of the Yanshan movement represent the peak stages of fracture development.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 5","pages":"Pages 291-305"},"PeriodicalIF":0.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145374566","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":"Reserve utilization evaluation model for tight gas well based on low-velocity non-Darcy seepage","authors":"Zechuan Wang ,&nbsp;Leng Tian ,&nbsp;Jinbu Li ,&nbsp;Peng Li ,&nbsp;Xiaolong Chai ,&nbsp;Xiaojiao Deng ,&nbsp;Lili Jiang","doi":"10.1016/j.jnggs.2025.09.001","DOIUrl":"10.1016/j.jnggs.2025.09.001","url":null,"abstract":"<div><div>In the depletion production process of tight gas wells, the decline in formation pressure leads to a gradual reduction in the production pressure gradient from the near-well region to the far-well region. At the same time, the impact of low-velocity non-Darcy seepage on production intensifies. These phenomena pose challenges to accurately assessing reserve utilization. In this study, laboratory experiments were conducted to investigate the phenomenon of low-velocity non-Darcy seepage of gas under varying pore pressures in tight, water-bearing rocks. Using fractured horizontal wells as a case study, an evaluation model of reserve utilization founded on dual-media seepage characterization was developed. The variation in reserve utilization and recovery percentage within the production range during depletion are quantitatively depicted, and the impact of different stimulation measures is probed. The results indicate that: (1) Incorporating low-velocity non-Darcy seepage into the motion equation allows for a more precise description of the nonlinear variation characteristics in gas flow relative to pressure differences. Consequently, the established numerical simulation model can assess dynamic reserve utilization with higher accuracy. (2) During the progression of single-well depletion production, the scope of exploited reserves expands; however, this expansion may cause inadequate reserve control. The recovery percentage within the producing range initially exhibits an upward trend and subsequently decreases. At the point where gas-well mining attains its maximum recovery factor, the recovery percentage within the producing range decreases by more than 6%. (3) From the perspective of enhancing the recovery factor of reserve utilization, the significance of stimulation measures can be ranked in the following order: reducing fracture spacing &gt; increasing fracture half-length &gt; improving fracture conductivity &gt; raising bottom-hole flowing pressure. While lowering the bottom-hole flowing pressure and extending the abandonment production condition can increase reserve utilization and cumulative production, they simultaneously decrease the recovery percentage of reserves. Artificial fracturing enhances both the producing geological reserves and the recovery factor of a single well, making it the primary approach for improving the production efficiency of tight gas wells.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 5","pages":"Pages 331-341"},"PeriodicalIF":0.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145374569","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":"Inter-well interference and well spacing optimization in Weirong shale gas field in Sichuan Basin, China","authors":"Jian Yang,&nbsp;Guowei Zhan,&nbsp;Yong Zhao,&nbsp;Di Wang,&nbsp;Liuyang Xiang","doi":"10.1016/j.jnggs.2025.07.005","DOIUrl":"10.1016/j.jnggs.2025.07.005","url":null,"abstract":"<div><div>Optimal well spacing is crucial for maximizing single-well productivity and efficiently utilizing reserves, making it a core indicator for evaluating development effectiveness. Due to the influence of natural fractures and the production sequence, the annual well opening pressure and inter-well interference in the Weirong Gas Field have led to an intensifying year-on-year decline, which have seriously affected both production and construction outcomes. To reduce inter well interference and improve productivity and construction efficiency, this study analyzes the interference mechanisms between wells. The results show that the main causes of interference are natural fractures and older well energy depletion. Based on these insights, a numerical simulation method was used to quantitatively evaluate the impact of varying well spacing, degrees of fracture hit and cumulative gas production from older wells on the Estimated Ultimate Recovery (EUR) of new wells. Consequently, a targeted and differentiated well spacing optimization design method was developed. The results show that: (1) The smaller the well spacing and the higher the degree of fracture hit, the greater the decrease on the EUR of new wells, with impact degrees of 7.1%–15.1%; (2) The smaller the well spacing and the higher the cumulative gas production from older wells, the greater the negative impact on the EUR of new wells, ranging from 8.1% to 28.3%; (3) In areas with well-developed natural fractures, a recommended well spacing of 350–450 m is suggested based on the fracture hit degree; (4) Near older wells, where energy depletion is prominent, a well spacing of 400–500 m is recommended. Following the application of well spacing optimization, the average well opening pressure increased by 9.3 MPa, and the EUR improved by 22.8%, demonstrating a favorable application effect and providing reference for well pattern arrangement in similar shale gas reservoirs.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 5","pages":"Pages 321-330"},"PeriodicalIF":0.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145374568","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":"Sweet spots in coal bed methane (CBM): Major controlling parameters identification through reservoir modeling, simulation, and uncertainty analysis to De-risk field development","authors":"B.P. Parida,&nbsp;R. Sinharay","doi":"10.1016/j.jnggs.2025.09.002","DOIUrl":"10.1016/j.jnggs.2025.09.002","url":null,"abstract":"<div><div>Sweet spots refer to specific areas within a reservoir where the parameters are optimal for achieving maximum production while minimizing the required footprint and investment. The high complexity of reservoirs, often compounded by absent or insufficient seismic data and the requirement of many wells, poses significant challenges. Hence, it is crucial to identify the sweet spot during the exploration stage for the optimized assessment of a coal bed methane (CBM) field. Identifying major controlling parameters that impact production is the first and foremost step toward demarcating the sweet spot. The present study uniquely presents an integrated workflow combining all aspects of subsurface processes i.e. reservoir characterization, modeling, and numerical simulation with sensitivity analysis. This workflow has been used along with both short- and long-term uncertainty analysis, which adds considerable value to the existing knowledge. The analysis shows that Gas content, Permeability, thickness, and gas saturation are the dominant parameters for sweet spot demarcation. However, other parameters like bottom-hole pressure constraint and relative permeabilities also impact production, especially during early production periods. It is interesting to note that the order of impacting parameters changes from long-term to short-term. In the long term, thickness and gas content, i.e., resources, play a more significant role than saturation, permeability, or relative permeability. However, in the short term, which is vital for the economic success of the field, permeability, saturation, and relative permeability play a more critical role. This practical insight helped identify sweet spots in this coal reservoir by shortlisting the areas where these dominant controlling parameters coexist and are well developed. Further, sweet spots were used to plan appraisal or pilot production test wells whose success ultimately led to field-scale development. The average production trends of producing wells in both sweet spot and moderate areas are used to validate these findings. This workflow can be applied in other reservoirs or basins, which will help CBM exploitation time and cost-effectiveness and optimize field development.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 5","pages":"Pages 343-359"},"PeriodicalIF":0.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145374570","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":"Provenance study of the Xujiahe Formation in northern Sichuan Basin and its implications for the source to sink systems during the Late Triassic, China","authors":"Yajie Tian ,&nbsp;Guoqi Wei ,&nbsp;Wei Yang ,&nbsp;Hui Jin ,&nbsp;Guoxiao Zhou","doi":"10.1016/j.jnggs.2025.08.001","DOIUrl":"10.1016/j.jnggs.2025.08.001","url":null,"abstract":"<div><div>Numerous studies have investigated the provenance of the Upper Triassic Xujiahe Formation, but there are still controversies concerning the provenance of this formation in the northern part of the Sichuan Basin. This research combines sandstone grain point-counting, heavy mineral assemblage analysis, and electron microprobe measurements of heavy mineral compositions to examine the provenance of the Xujiahe Formation in the Guangyuan, Wangcang, Nanjiang, and Tuhuang sections located in the northern part of the Sichuan Basin. The results show that the sandstone composition, unstable heavy mineral type and garnet composition are similar for samples from Guangyuan, Wangcang, Nanjiang sections, characterized by abundance of garnet and chromian spinel. Garnet types are predominantly almandine and pyrope, which are mainly derived from amphibolite-to granulite-facies metasedimentary rocks. In contrast, samples from the Tuhuang section are characterized by lack of chromian spinel and existence of pyroxene, with garnet of almandine type and derivation from intermediate-acidic magmatic rocks, and with pyroxene of augite and diopside types and derivation from alkaline-subalkaline volcanic arc basalt magma or subalkaline oceanic floor basalt magma. Comprehensive analysis shows that the provenance of the Guangyuan, Wangcang, and Nanjiang sections includes Triassic turbidites from the Songpan-Ganzi Fold Belt and west Qinling Orogen and Paleozoic strata in the Longmenshan thrust belt. The Tuhuang section, by contrast, receive sediment from the North China Block and Qinling Orogen. These findings, in combination with previous provenance and sedimentary studies, support the existence of two distinct source to sink systems in the northern part of the Sichuan Basin during the Late Triassic. The provenance study of the Xujiahe Formation also demonstrates the limitation of the detrital zircon U–Pb method and underscores the importance of the combination of multiple provenance analysis methods for the effective discrimination of complex source to sink systems.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 5","pages":"Pages 307-320"},"PeriodicalIF":0.0,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145374567","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":"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}