Pub Date : 2025-12-01DOI: 10.1016/j.jnggs.2025.09.004
Ming Zhang, Xin Zhang, Jing Liang, Lideng Gan, Xiaowei Yu
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.
{"title":"Application of multicomponent seismic in tight reservoir prediction of the first member of Jurassic Shaximiao Formation, Sichuan Basin, China","authors":"Ming Zhang, Xin Zhang, Jing Liang, Lideng Gan, 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}
Pub Date : 2025-12-01DOI: 10.1016/j.jnggs.2025.11.002
Lijun You, Rui Qian, Yili Kang, Yijie Wu
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.
{"title":"Genesis of high-salinity formation water and salinity sensitivity of deep coal-rock gas reservoirs in the Ordos Basin, China","authors":"Lijun You, Rui Qian, Yili Kang, 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 CaCl<sub>2</sub> 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 Ca<sup>2+</sup> and Mg<sup>2+</sup> 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}
Pub Date : 2025-12-01DOI: 10.1016/j.jnggs.2025.11.001
Donggang Wang , Yu Ma , Yanyun Ma , Wenzhong Wu , Kun Yu
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 (RO), 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.
{"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 , Yu Ma , Yanyun Ma , Wenzhong Wu , 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><sub>O</sub>), 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 II<sub>1</sub> and II<sub>2</sub> 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}
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.
{"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 , A.S.M. Woobaidullah , Delwar Hossain , 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}
Pub Date : 2025-12-01DOI: 10.1016/j.jnggs.2025.10.001
Xingcheng Zhu , Jungang Lu , Yong Li , Qingbo He , Shuxing Li , Zhenglu Xiao , Qijun Jiang , Ruijie Chen , Wenxin Shi
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 TOC 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.
{"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 , Jungang Lu , Yong Li , Qingbo He , Shuxing Li , Zhenglu Xiao , Qijun Jiang , Ruijie Chen , 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 Shan<sub>2</sub><sup>3</sup> 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), N<sub>2</sub> and CO<sub>2</sub> 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}
Pub Date : 2025-10-01DOI: 10.1016/j.jnggs.2025.09.003
Yuman Wang , Yubing Ji , Feng Liang , Ziying Wang , Xinchun Jiang , Weimin Li , Rubiao Chen
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) T2 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.
{"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 , Yubing Ji , Feng Liang , Ziying Wang , Xinchun Jiang , Weimin Li , 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><sub>2</sub> 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}
Pub Date : 2025-10-01DOI: 10.1016/j.jnggs.2025.09.001
Zechuan Wang , Leng Tian , Jinbu Li , Peng Li , Xiaolong Chai , Xiaojiao Deng , Lili Jiang
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 > increasing fracture half-length > improving fracture conductivity > 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.
{"title":"Reserve utilization evaluation model for tight gas well based on low-velocity non-Darcy seepage","authors":"Zechuan Wang , Leng Tian , Jinbu Li , Peng Li , Xiaolong Chai , Xiaojiao Deng , 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 > increasing fracture half-length > improving fracture conductivity > 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}
Pub Date : 2025-10-01DOI: 10.1016/j.jnggs.2025.07.005
Jian Yang, Guowei Zhan, Yong Zhao, Di Wang, Liuyang Xiang
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.
{"title":"Inter-well interference and well spacing optimization in Weirong shale gas field in Sichuan Basin, China","authors":"Jian Yang, Guowei Zhan, Yong Zhao, Di Wang, 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}
Pub Date : 2025-10-01DOI: 10.1016/j.jnggs.2025.09.002
B.P. Parida, R. Sinharay
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.
{"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, 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}
Pub Date : 2025-10-01DOI: 10.1016/j.jnggs.2025.08.001
Yajie Tian , Guoqi Wei , Wei Yang , Hui Jin , Guoxiao Zhou
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.
{"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 , Guoqi Wei , Wei Yang , Hui Jin , 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}
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