Pub Date : 2024-10-01DOI: 10.1016/j.jnggs.2024.09.003
Jian Li , Xiaobo Wang , Zhusong Xu , Huiying Cui , Xiaomei Wang , Bin Zhang , Jianying Guo , Shizhen Tao , Jianfa Chen , Zengye Xie , Jixian Tian , Yifeng Wang
Helium is a globally scarce strategic resource that is relevant to national economies and the development of high-tech industries, and China primarily depends on imported helium for its industrial applications. Therefore, there is an urgent demand for clarifying helium formation and enrichment patterns, searching for helium-rich fields, and realizing China's helium resource inventory and development potential. This article analyzes the reservoir characteristics and accumulation conditions of typical helium-rich fields in China, and clarifying the origin and source of helium as well as the main controlling factors of helium enrichment. It was recognized that helium in natural gas in China mainly comes from crustal sources. Relatively shallow buried ancient U–Th-rich granite basement or intrusion, large and stable ancient uplift or submarine formed in the early period, good overburden of huge thick paste-salt rock or mudstone cover, and channels connecting the basement and reservoir, were the main controlling factors of helium enrichment. Four types of helium-rich gas reservoirs, namely helium-rich conventional gas, helium-rich shale gas, helium-rich non-hydrocarbon gas, and helium-rich water-soluble gas, have been modeled and predicted to be helium-rich favorable exploration areas. Based on this analysis, the prospect of helium resource development in China has been analyzed. It was proposed that the exploration of helium-rich fields and the comprehensive development and utilization of medium- and low-abundance helium resources are important ways to increase the domestic helium production in China in the future.
{"title":"Helium resources accumulation regulations and their development prospects in China","authors":"Jian Li , Xiaobo Wang , Zhusong Xu , Huiying Cui , Xiaomei Wang , Bin Zhang , Jianying Guo , Shizhen Tao , Jianfa Chen , Zengye Xie , Jixian Tian , Yifeng Wang","doi":"10.1016/j.jnggs.2024.09.003","DOIUrl":"10.1016/j.jnggs.2024.09.003","url":null,"abstract":"<div><div>Helium is a globally scarce strategic resource that is relevant to national economies and the development of high-tech industries, and China primarily depends on imported helium for its industrial applications. Therefore, there is an urgent demand for clarifying helium formation and enrichment patterns, searching for helium-rich fields, and realizing China's helium resource inventory and development potential. This article analyzes the reservoir characteristics and accumulation conditions of typical helium-rich fields in China, and clarifying the origin and source of helium as well as the main controlling factors of helium enrichment. It was recognized that helium in natural gas in China mainly comes from crustal sources. Relatively shallow buried ancient U–Th-rich granite basement or intrusion, large and stable ancient uplift or submarine formed in the early period, good overburden of huge thick paste-salt rock or mudstone cover, and channels connecting the basement and reservoir, were the main controlling factors of helium enrichment. Four types of helium-rich gas reservoirs, namely helium-rich conventional gas, helium-rich shale gas, helium-rich non-hydrocarbon gas, and helium-rich water-soluble gas, have been modeled and predicted to be helium-rich favorable exploration areas. Based on this analysis, the prospect of helium resource development in China has been analyzed. It was proposed that the exploration of helium-rich fields and the comprehensive development and utilization of medium- and low-abundance helium resources are important ways to increase the domestic helium production in China in the future.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 5","pages":"Pages 303-319"},"PeriodicalIF":0.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142535016","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.jnggs.2024.07.003
Syahreza S. Angkasa , Harya D. Nugraha , Dian Yesy Fatimah , Ananda Bagus Krisna Pratama
Methane seeps, prevalent in ocean basins globally, indicate upward methane migration from the subsurface, often evident as gas chimneys in seismic reflection data. The footprint of this methane migration is often indicated by methane-derived authigenic carbonate (MDAC), a product of anaerobic oxidation of methane (AOM). Despite extensive research on MDAC from present-day seafloors and outcrops, understanding methane migration footprints from subsurface rock samples remains limited. Therefore, this study aims to investigate methane migration footprints from subsurface rock samples taken from a proven area of gas migration. This study utilized cutting samples from well XS-01 located in the Makassar Strait, offshore Indonesia. The well was drilled through a gas chimney into Oligocene carbonate reservoirs hosting a substantial methane column (102 m). Analysis of 44 cutting samples involved petrographic examination, Scanning Electron Microscope (SEM) imaging, and X-ray Diffraction (XRD) analysis to discern mineralogical content and diagenetic features signaling the presence of gas. A diagenetic texture called clotted peloidal micrite (CPM) was discovered within foraminifera fossils and around fractures based on petrographic analysis. CPM is a type of MDAC and predominantly occurs in fine-grained, siliciclastic rocks, indicating gas migration. This migration is interpreted to occur: (i) during the early burial stages originating from microbial activity since the Oligocene (biogenic gas); (ii) following matured source rock that reached its peak maturity from the Middle Eocene to the Pliocene (thermogenic gas); or (iii) interference of these two processes. The migration route persists until present day as evidenced by gas chimney and seabed pockmarks identified in seismic reflection data. This study emphasizes the importance of subsurface rock samples, such as cuttings, in uncovering gas migration footprints. Especially, where seismic data is unavailable or could not image fluid flow features. In addition, this study also provides a new perspective on diagenesis along methane migration route, complementing most of the research that is primarily focused on reservoir diagenesis.
{"title":"Diagenetic features recorded in sedimentary rocks within a gas chimney: A case study from the Makassar Strait, offshore Indonesia","authors":"Syahreza S. Angkasa , Harya D. Nugraha , Dian Yesy Fatimah , Ananda Bagus Krisna Pratama","doi":"10.1016/j.jnggs.2024.07.003","DOIUrl":"10.1016/j.jnggs.2024.07.003","url":null,"abstract":"<div><div>Methane seeps, prevalent in ocean basins globally, indicate upward methane migration from the subsurface, often evident as gas chimneys in seismic reflection data. The footprint of this methane migration is often indicated by methane-derived authigenic carbonate (MDAC), a product of anaerobic oxidation of methane (AOM). Despite extensive research on MDAC from present-day seafloors and outcrops, understanding methane migration footprints from subsurface rock samples remains limited. Therefore, this study aims to investigate methane migration footprints from subsurface rock samples taken from a proven area of gas migration. This study utilized cutting samples from well XS-01 located in the Makassar Strait, offshore Indonesia. The well was drilled through a gas chimney into Oligocene carbonate reservoirs hosting a substantial methane column (102 m). Analysis of 44 cutting samples involved petrographic examination, Scanning Electron Microscope (SEM) imaging, and X-ray Diffraction (XRD) analysis to discern mineralogical content and diagenetic features signaling the presence of gas. A diagenetic texture called clotted peloidal micrite (CPM) was discovered within foraminifera fossils and around fractures based on petrographic analysis. CPM is a type of MDAC and predominantly occurs in fine-grained, siliciclastic rocks, indicating gas migration. This migration is interpreted to occur: (i) during the early burial stages originating from microbial activity since the Oligocene (biogenic gas); (ii) following matured source rock that reached its peak maturity from the Middle Eocene to the Pliocene (thermogenic gas); or (iii) interference of these two processes. The migration route persists until present day as evidenced by gas chimney and seabed pockmarks identified in seismic reflection data. This study emphasizes the importance of subsurface rock samples, such as cuttings, in uncovering gas migration footprints. Especially, where seismic data is unavailable or could not image fluid flow features. In addition, this study also provides a new perspective on diagenesis along methane migration route, complementing most of the research that is primarily focused on reservoir diagenesis.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 5","pages":"Pages 361-371"},"PeriodicalIF":0.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142534914","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.jnggs.2024.09.002
Weilong Peng , Shang Deng , Jibiao Zhang , Cheng Huang , Huabiao Qiu , Yingtao Li , Yuqing Liu , Dawei Liu
Typical condensate reservoirs have been developed in the No.4 fault zone of the Shunbei area in the Tarim Basin. However, exploration expansion is restricted due to the unclear genetic mechanisms and main controlling factors of condensate accumulation. Through a comprehensive analysis of organic geochemical characteristics and the regional geological background, the genetic mechanisms and main controlling factors of condensate accumulation in the No.4 fault zone of the Shunbei area have been identified, and the following understandings are mainly obtained: (1) the condensate oil and gas reservoirs in the No.4 fault zone of the Shunbei area are mainly primary condensate reservoirs, and their formation is mainly affected by differential maturation of organic matter, multi-phase accumulation, and secondary alteration; (2) the overall secondary effects on the condensate oil and gas reservoirs in the Shunbei No.4 fault zone are relatively weak, however, the secondary effect experienced by the middle and southern sections is relatively stronger compared to the northern section; these secondary processes include oil cracking, gas invasion, and thermochemical sulfate reduction (TSR); and (3) the enrichment degree of condensate oil and gas reservoirs in the northern section of the Shunbei No.4 fault zone is significantly higher than in the middle and southern sections; the enrichment and high production of condensate oil and gas are mainly controlled by transport conditions and reservoir scale. Stronger fault activity, better transport conditions, larger reservoir size, and thinner gypsum-salt rock layers facilitate the upward migration of oil and gas along strike-slip faults, leading to higher production and enrichment of condensate.
{"title":"Genetic mechanism and main controlling factors of deep marine condensate reservoirs: A case study of the Shunbei No.4 fault zone in Tarim Basin, NW China","authors":"Weilong Peng , Shang Deng , Jibiao Zhang , Cheng Huang , Huabiao Qiu , Yingtao Li , Yuqing Liu , Dawei Liu","doi":"10.1016/j.jnggs.2024.09.002","DOIUrl":"10.1016/j.jnggs.2024.09.002","url":null,"abstract":"<div><div>Typical condensate reservoirs have been developed in the No.4 fault zone of the Shunbei area in the Tarim Basin. However, exploration expansion is restricted due to the unclear genetic mechanisms and main controlling factors of condensate accumulation. Through a comprehensive analysis of organic geochemical characteristics and the regional geological background, the genetic mechanisms and main controlling factors of condensate accumulation in the No.4 fault zone of the Shunbei area have been identified, and the following understandings are mainly obtained: (1) the condensate oil and gas reservoirs in the No.4 fault zone of the Shunbei area are mainly primary condensate reservoirs, and their formation is mainly affected by differential maturation of organic matter, multi-phase accumulation, and secondary alteration; (2) the overall secondary effects on the condensate oil and gas reservoirs in the Shunbei No.4 fault zone are relatively weak, however, the secondary effect experienced by the middle and southern sections is relatively stronger compared to the northern section; these secondary processes include oil cracking, gas invasion, and thermochemical sulfate reduction (TSR); and (3) the enrichment degree of condensate oil and gas reservoirs in the northern section of the Shunbei No.4 fault zone is significantly higher than in the middle and southern sections; the enrichment and high production of condensate oil and gas are mainly controlled by transport conditions and reservoir scale. Stronger fault activity, better transport conditions, larger reservoir size, and thinner gypsum-salt rock layers facilitate the upward migration of oil and gas along strike-slip faults, leading to higher production and enrichment of condensate.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 5","pages":"Pages 347-359"},"PeriodicalIF":0.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142534913","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.jnggs.2024.09.001
Shipeng Huang , Zhenyu Zhao , Ai Yue , Hua Jiang , Xingwang Tian , Qingchun Jiang , Debo Ma , Wei Song , Haijing Song
Through the analysis of natural gas composition, carbon and hydrogen isotopes of alkane gases, reservoir bitumen, source rock conditions, and source–reservoir combinations, this study clarifies the differences in gas sources and the origins of natural gas in the Permian Changxing Formation–Triassic Feixianguan Formation on both sides of the Kaijiang–Liangping Trough. Additionally, it identifies favorable exploration directions for coal-formed gas generated by the Longtan Formation in the Sichuan Basin. The following understanding was obtained: (1) The natural gas in the Changxing–Feixianguan formations mainly composed of alkane gas, typical of dry gas. (2) The carbon isotope values of methane and ethane in the Changxing–Feixianguan formations on the east side of the trough are lower than those on the west side. Specifically, the ethane carbon isotope value in the Longgang Gas Field on the west side is higher than that in the Yuanba Gas Field, while the methane hydrogen isotope value is lower in the Longgang Gas Field compared to the Yuanba Gas Field. (3) The natural gas in the Dongyuezhai, Puguang, and Yuanba gas fields predominantly originates from sapropelic organic matter of the Wujiaping Formation, with kerogen types II1–I; in contrast, the Longgang Gas Field contains a mixture of coal-formed gas and oil-type gas, with a slightly higher content of coal-formed gas, originating from mixed organic matter of the Wujiaping Formation, with kerogen type II1–II2. (4) Multiple types of gas, such as coal rock gas, tight sandstone gas, and shale gas, can be formed within the Longtan Formation. The Suining–Luzhou and Langzhong–Guang'an–Fuling areas are identified as favorable zones for the exploration of coal rock gas and marine–continental transitional shale gas, respectively. Additionally, the reef and shoal development areas of the Changxing Formation in the Suining–Hechuan and Guang'an–Nanchong regions are also favorable exploration areas for coal-formed gas.
{"title":"Differences in gas sources of the Changxing–Feixianguan formations around the Kaijiang-Liangping Trough and favorable exploration directions for coal-formed gas generated by the Upper Permian Longtan Formation, Sichuan Basin, China","authors":"Shipeng Huang , Zhenyu Zhao , Ai Yue , Hua Jiang , Xingwang Tian , Qingchun Jiang , Debo Ma , Wei Song , Haijing Song","doi":"10.1016/j.jnggs.2024.09.001","DOIUrl":"10.1016/j.jnggs.2024.09.001","url":null,"abstract":"<div><div>Through the analysis of natural gas composition, carbon and hydrogen isotopes of alkane gases, reservoir bitumen, source rock conditions, and source–reservoir combinations, this study clarifies the differences in gas sources and the origins of natural gas in the Permian Changxing Formation–Triassic Feixianguan Formation on both sides of the Kaijiang–Liangping Trough. Additionally, it identifies favorable exploration directions for coal-formed gas generated by the Longtan Formation in the Sichuan Basin. The following understanding was obtained: (1) The natural gas in the Changxing–Feixianguan formations mainly composed of alkane gas, typical of dry gas. (2) The carbon isotope values of methane and ethane in the Changxing–Feixianguan formations on the east side of the trough are lower than those on the west side. Specifically, the ethane carbon isotope value in the Longgang Gas Field on the west side is higher than that in the Yuanba Gas Field, while the methane hydrogen isotope value is lower in the Longgang Gas Field compared to the Yuanba Gas Field. (3) The natural gas in the Dongyuezhai, Puguang, and Yuanba gas fields predominantly originates from sapropelic organic matter of the Wujiaping Formation, with kerogen types II<sub>1</sub>–I; in contrast, the Longgang Gas Field contains a mixture of coal-formed gas and oil-type gas, with a slightly higher content of coal-formed gas, originating from mixed organic matter of the Wujiaping Formation, with kerogen type II<sub>1</sub>–II<sub>2</sub>. (4) Multiple types of gas, such as coal rock gas, tight sandstone gas, and shale gas, can be formed within the Longtan Formation. The Suining–Luzhou and Langzhong–Guang'an–Fuling areas are identified as favorable zones for the exploration of coal rock gas and marine–continental transitional shale gas, respectively. Additionally, the reef and shoal development areas of the Changxing Formation in the Suining–Hechuan and Guang'an–Nanchong regions are also favorable exploration areas for coal-formed gas.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 5","pages":"Pages 321-331"},"PeriodicalIF":0.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142534911","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.jnggs.2024.09.004
Yanzhao Wei , Abulimiti Yiming , Weian Wu , Aicheng Wu , Fan Yang , Chaowei Liu , Zesheng Wang , Boyu Zhou
The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan–Dishuiquan Sag, the Wucaiwan Sag–Dajing area, and the Dongdao Haizi Sag–Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900–4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions.
{"title":"Natural gas accumulation conditions and exploration directions of Carboniferous clastic rocks in the northeastern margin of Junggar Basin, China","authors":"Yanzhao Wei , Abulimiti Yiming , Weian Wu , Aicheng Wu , Fan Yang , Chaowei Liu , Zesheng Wang , Boyu Zhou","doi":"10.1016/j.jnggs.2024.09.004","DOIUrl":"10.1016/j.jnggs.2024.09.004","url":null,"abstract":"<div><div>The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan–Dishuiquan Sag, the Wucaiwan Sag–Dajing area, and the Dongdao Haizi Sag–Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900–4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 5","pages":"Pages 333-346"},"PeriodicalIF":0.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142534912","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.jnggs.2024.08.002
Shizhen Tao, Yue Chen, Yiqing Yang
The classification system, effective reservoir control elements, and major enrichment and exploration modes of helium resources in China are analyzed based on the source of helium, carrier, geological background, and anatomy of typical helium-rich fields. Firstly, based on the special characteristics of helium and the correlation analysis of natural gas accumulation and reservoir formation, we analyzed and sorted out the helium resource and play type classification scheme and classification system in China from nine aspects, namely, the source of helium parental sources, helium type diversities, the storage and carrier types, the technically and economically recoverable characteristics of carrier gases, the carrier gas genesis, the main components of carrier gases, the matching combination of helium sources and reservoirs, background of prototype basin structure, and helium content, to lay the foundation for the subsequent targeted and detailed studies and evaluation programs in different categories. Secondly, the analysis points out the characteristics of helium resource types in the east, middle, and west of China in terms of longitudinal and transverse distribution, tectonic dynamics, geological and geochemical characteristics, and key conditions for the formation of helium deposits. Thirdly, from the perspective of the helium “generation-migration-accumulation” system and the controlling elements and effectiveness of helium-rich reservoir formation, we analyze the effective controlling elements of helium accumulation and the related problems that deserve attention in geological evaluation and point out the misunderstandings in helium reservoir formation and exploration evaluation. Last but not least, from the perspective of basin tectonic background, helium enrichment controlling mechanism and exploration direction, the exploration and evaluation direction and classification scheme for the four element combination zones of “original basin–structure–lithology–carrier gas” helium accumulation in China have been proposed, based on which, four types of basins and eight types of helium-rich zones in China have been sorted out. In these eight types of helium-rich zones, eight typical helium-rich field enrichment and exploration patterns, including the ancient uplift type of China's craton, fracture-fold variant of the craton margin, fracture-rise type of depression basin, slope bulge and uplift type of foreland basin, fracture-convex type of fracture basin, and U/Th-rich basement type of basin were analyzed, and the main controlling factors of the formation of different types of helium-rich deposits were analyzed, which will provide a reference for the subsequent exploration and discovery of similar helium-rich areas and exploration target evaluation.
{"title":"Helium resource and play classification systems, effective reservoir control elements, and enrichment patterns in China","authors":"Shizhen Tao, Yue Chen, Yiqing Yang","doi":"10.1016/j.jnggs.2024.08.002","DOIUrl":"10.1016/j.jnggs.2024.08.002","url":null,"abstract":"<div><p>The classification system, effective reservoir control elements, and major enrichment and exploration modes of helium resources in China are analyzed based on the source of helium, carrier, geological background, and anatomy of typical helium-rich fields. Firstly, based on the special characteristics of helium and the correlation analysis of natural gas accumulation and reservoir formation, we analyzed and sorted out the helium resource and play type classification scheme and classification system in China from nine aspects, namely, the source of helium parental sources, helium type diversities, the storage and carrier types, the technically and economically recoverable characteristics of carrier gases, the carrier gas genesis, the main components of carrier gases, the matching combination of helium sources and reservoirs, background of prototype basin structure, and helium content, to lay the foundation for the subsequent targeted and detailed studies and evaluation programs in different categories. Secondly, the analysis points out the characteristics of helium resource types in the east, middle, and west of China in terms of longitudinal and transverse distribution, tectonic dynamics, geological and geochemical characteristics, and key conditions for the formation of helium deposits. Thirdly, from the perspective of the helium “generation-migration-accumulation” system and the controlling elements and effectiveness of helium-rich reservoir formation, we analyze the effective controlling elements of helium accumulation and the related problems that deserve attention in geological evaluation and point out the misunderstandings in helium reservoir formation and exploration evaluation. Last but not least, from the perspective of basin tectonic background, helium enrichment controlling mechanism and exploration direction, the exploration and evaluation direction and classification scheme for the four element combination zones of “original basin–structure–lithology–carrier gas” helium accumulation in China have been proposed, based on which, four types of basins and eight types of helium-rich zones in China have been sorted out. In these eight types of helium-rich zones, eight typical helium-rich field enrichment and exploration patterns, including the ancient uplift type of China's craton, fracture-fold variant of the craton margin, fracture-rise type of depression basin, slope bulge and uplift type of foreland basin, fracture-convex type of fracture basin, and U/Th-rich basement type of basin were analyzed, and the main controlling factors of the formation of different types of helium-rich deposits were analyzed, which will provide a reference for the subsequent exploration and discovery of similar helium-rich areas and exploration target evaluation.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 4","pages":"Pages 219-241"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2468256X24000415/pdfft?md5=d62de0d054ebf4babbab6e813ae8ab8c&pid=1-s2.0-S2468256X24000415-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142229659","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The crude oils of the Sarvak reservoir were studied by integrated geochemical, inorganic and isotopic analyses to evaluate the origin, depositional conditions, geological age, thermal maturity of the source rocks and possible facies from which these oils were sourced. This study provides new insights into the Middle-Jurassic age source rock in the Azar Oilfield. This is the first geochemical study in Azar Oilfield where non-biomarker parameters and biomarker parameters were utilized to achieve the objectives. The n-alkane distribution pattern along with their standard ratios, including CPI (0.83–1.03), TAR (0.18–0.29) and isoprenoids (Pr/Ph, 0.52–0.65) as well as pristane/n-C17 versus phytane/n-C18 cross-plot indicate a marine source of the organic matter deposited in an anoxic condition. The sterane parameters such as C27 and C29 are characterized by the predominance of C27ααα-20R steranes (41%–49%) and also depict the algal source of organic matter. The organic input and facies of the source units were also determined by terpanes C29/C30H, Ts/Tm, C35/C34-HH, and DBT/Phen. The relatively high ratio of C29/C30H along with the ratios of Ts/Tm (<0.5) and C35/C34 (>0.8) reflect the carbonate marine facies of the source rocks. Furthermore, the higher values of the homohopane index (>0.1) along with the low ratio of the gammacerane/C30-H (0.06–0.22) as well as the high ratio of V/Ni (>1) further indicate anoxic environments. The dibenzothiophene/phenanthrene ratios of the oil samples (from 2.43 to 3.25) indicate the marine carbonates/marl zone. This genetic classification is also supported by stable carbon isotopic compositions (δ1³C). Most of the maturity-related biomarkers and non-biomarker parameters such as CPI, steranes-C29S/(S + R), ββ/(αα+ββ), moretane to hopane (M29/C30H), pentacyclic terpanes C27Ts/(Ts + Tm), C32-S/(S + R) hopanes, and methyl phenanthrene index agree that the analyzed oils have originated from mature source rocks. Ultimately, this study has demonstrated that analyses of biomarkers and their stable isotope compositions (δ13C and δ34S) complemented with trace element data provide an excellent novel tool for better understanding the basic concepts in petroleum basins and for solving a wide range of problems during petroleum exploration.
{"title":"Geochemical evaluation of Sarvak oil reservoir using biomarkers, carbon isotope and trace element: A case study from Southwest Iran","authors":"Soheila Bagheri, Maryam Pourbagher, Mohsen Shourab","doi":"10.1016/j.jnggs.2024.06.001","DOIUrl":"10.1016/j.jnggs.2024.06.001","url":null,"abstract":"<div><p>The crude oils of the Sarvak reservoir were studied by integrated geochemical, inorganic and isotopic analyses to evaluate the origin, depositional conditions, geological age, thermal maturity of the source rocks and possible facies from which these oils were sourced. This study provides new insights into the Middle-Jurassic age source rock in the Azar Oilfield. This is the first geochemical study in Azar Oilfield where non-biomarker parameters and biomarker parameters were utilized to achieve the objectives. The <em>n</em>-alkane distribution pattern along with their standard ratios, including CPI (0.83–1.03), TAR (0.18–0.29) and isoprenoids (Pr/Ph, 0.52–0.65) as well as pristane/<em>n</em>-C<sub>17</sub> versus phytane/<em>n</em>-C<sub>18</sub> cross-plot indicate a marine source of the organic matter deposited in an anoxic condition. The sterane parameters such as C<sub>27</sub> and C<sub>29</sub> are characterized by the predominance of C<sub>27</sub>ααα-20R steranes (41%–49%) and also depict the algal source of organic matter. The organic input and facies of the source units were also determined by terpanes C<sub>29</sub>/C<sub>30</sub>H, Ts/Tm, C<sub>35</sub>/C<sub>34</sub>-HH, and DBT/Phen. The relatively high ratio of C<sub>29</sub>/C<sub>30</sub>H along with the ratios of Ts/Tm (<0.5) and C<sub>35</sub>/C<sub>34</sub> (>0.8) reflect the carbonate marine facies of the source rocks. Furthermore, the higher values of the homohopane index (>0.1) along with the low ratio of the gammacerane/C<sub>30</sub>-H (0.06–0.22) as well as the high ratio of V/Ni (>1) further indicate anoxic environments. The dibenzothiophene/phenanthrene ratios of the oil samples (from 2.43 to 3.25) indicate the marine carbonates/marl zone. This genetic classification is also supported by stable carbon isotopic compositions (<em>δ</em><sup>1</sup>³C). Most of the maturity-related biomarkers and non-biomarker parameters such as CPI, steranes-C<sub>29</sub>S/(S + R), ββ/(αα+ββ), moretane to hopane (M<sub>29</sub>/C<sub>30</sub>H), pentacyclic terpanes C<sub>27</sub>Ts/(Ts + Tm), C<sub>32</sub>-S/(S + R) hopanes, and methyl phenanthrene index agree that the analyzed oils have originated from mature source rocks. Ultimately, this study has demonstrated that analyses of biomarkers and their stable isotope compositions (<em>δ</em><sup>13</sup>C and <em>δ</em><sup>34</sup>S) complemented with trace element data provide an excellent novel tool for better understanding the basic concepts in petroleum basins and for solving a wide range of problems during petroleum exploration.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 4","pages":"Pages 281-302"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2468256X24000373/pdfft?md5=ffe12e8fa53b19e9d993b8fb2eecb97e&pid=1-s2.0-S2468256X24000373-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142229662","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.jnggs.2024.07.001
Shengfei Qin , Zizhuo Zhao , Wei Wu , Guoxiao Zhou , Gang Tao , Jiyuan Li
Aiming to address whether coal-bed methane and shale gas can form helium-rich gas reservoirs, this paper employs geochemical research methods to analyze the content of uranium (U) and thorium (Th) in coal and shale, as well as the helium content in coal-bed and shale gas reservoirs. An objective evaluation of the helium-generating potential and helium-bearing properties of coal and shale is provided. It is observed that although the content of U and Th in coal and shale is significantly higher than in other rocks, resulting in relatively more helium production from radioactive decay, the large amount of natural gas generated by coal and shale exerts a serious dilution effect on helium, making it difficult for coal beds and shale to enrich helium. The organic carbon content of coal is much higher than that of shale, leading to a greater generation of natural gas from coal beds compared to shale. Consequently, the helium content of coal-bed gas is much lower than that of shale gas. The helium rich shale gas and coal bed gas found in a few areas are attributed to the helium supply from other rocks in the gas reservoir, which is mostly distributed on or near the old granite masses, or in the tectonic active zones. In addition to capturing some of the helium produced by the coal beds and shales themselves, helium from other rocks, particularly from ancient basement rocks, is also captured, though this is not common.
{"title":"Helium content and helium enrichment conditions of coalbed methane and shale gas","authors":"Shengfei Qin , Zizhuo Zhao , Wei Wu , Guoxiao Zhou , Gang Tao , Jiyuan Li","doi":"10.1016/j.jnggs.2024.07.001","DOIUrl":"10.1016/j.jnggs.2024.07.001","url":null,"abstract":"<div><p>Aiming to address whether coal-bed methane and shale gas can form helium-rich gas reservoirs, this paper employs geochemical research methods to analyze the content of uranium (U) and thorium (Th) in coal and shale, as well as the helium content in coal-bed and shale gas reservoirs. An objective evaluation of the helium-generating potential and helium-bearing properties of coal and shale is provided. It is observed that although the content of U and Th in coal and shale is significantly higher than in other rocks, resulting in relatively more helium production from radioactive decay, the large amount of natural gas generated by coal and shale exerts a serious dilution effect on helium, making it difficult for coal beds and shale to enrich helium. The organic carbon content of coal is much higher than that of shale, leading to a greater generation of natural gas from coal beds compared to shale. Consequently, the helium content of coal-bed gas is much lower than that of shale gas. The helium rich shale gas and coal bed gas found in a few areas are attributed to the helium supply from other rocks in the gas reservoir, which is mostly distributed on or near the old granite masses, or in the tectonic active zones. In addition to capturing some of the helium produced by the coal beds and shales themselves, helium from other rocks, particularly from ancient basement rocks, is also captured, though this is not common.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 4","pages":"Pages 243-254"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2468256X24000385/pdfft?md5=10fa77746203abcdb6340bddbeea2106&pid=1-s2.0-S2468256X24000385-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141851880","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.jnggs.2024.07.002
Deyu Gong , Yihao Miao , Xuan Chen , Hongguang Gou , Tong Lin , Di Li , Runze Yang , Yan Han
The Middle Permian Lucaogou Formation is the most significant source rock in the eastern Junggar Basin. Previous studies have confirmed its excellent hydrocarbon-generating potential in the Jimsar Sag. However, its potential in other areas of the eastern Junggar Basin remains uncertain. Based on total organic carbon and pyrolysis, organic petrology, hydrocarbon simulation experiments, basin simulation, and combined well-seismic coupling interpretation, this study systematically compares the hydrocarbon-generating potential of the Lucaogou source rock in the Jimsar Sag with other areas of the eastern Junggar Basin. It discusses the sedimentary environment of high-quality source rocks and depicts the distribution of practical source kitchens. The Lucaogou source rocks in the eastern Junggar Basin are oil-prone, dominated by type I–II kerogen, and generally classified as good to excellent source rocks. Nowadays, the area of the Lucaogou source rocks that have entered the main oil-generating window is approximately 11 × 103 km2. Except for the bulge area, the Lucaogou source rocks in the eastern Junggar Basin successively entered the hydrocarbon-generating threshold during the Jurassic and the main oil-generating window in the Cretaceous. The Lucaogou source rocks in the Jimsar Sag and other parts of the eastern Junggar Basin share similar biomarker fingerprints, characterized by relatively low ratios of Pr/Ph, Pr/n-C17, Tm/C30 hopane, C19/C20 tricyclic terpene, and C24 tetracyclic terpene/C26 tricyclic terpene, and high β-carotene content, gammacerane index, and Ts/Tm ratios. These characteristics reflect deposition in a strongly reducing brackish lacustrine environment with parental sources dominated by lower organisms such as algae and bacteria. Generally, the Lucaogou source rocks in the eastern Junggar Basin have an oil-generating intensity of more than 3 × 106 t/km2. Several oil-generating centers with an intensity of more than 5 × 106 t/km2 have developed in the front of the Bogda Mountain, Jimsar Sag, Dongdaohaizi Sag, Wucaiwan Sag, and Shazhang Fault Zone, covering a total area of approximately 12,500 km2. These characteristics of the Lucaogou source rocks promise favorable potential for forming large and medium oil fields. The results further consolidated the oil and gas resources in the eastern Junggar Basin and provided valuable references for exploring future oil and gas fields.
{"title":"Hydrocarbon-generating potential of the Middle Permian Lucaogou source rock in the eastern Junggar Basin, China","authors":"Deyu Gong , Yihao Miao , Xuan Chen , Hongguang Gou , Tong Lin , Di Li , Runze Yang , Yan Han","doi":"10.1016/j.jnggs.2024.07.002","DOIUrl":"10.1016/j.jnggs.2024.07.002","url":null,"abstract":"<div><p>The Middle Permian Lucaogou Formation is the most significant source rock in the eastern Junggar Basin. Previous studies have confirmed its excellent hydrocarbon-generating potential in the Jimsar Sag. However, its potential in other areas of the eastern Junggar Basin remains uncertain. Based on total organic carbon and pyrolysis, organic petrology, hydrocarbon simulation experiments, basin simulation, and combined well-seismic coupling interpretation, this study systematically compares the hydrocarbon-generating potential of the Lucaogou source rock in the Jimsar Sag with other areas of the eastern Junggar Basin. It discusses the sedimentary environment of high-quality source rocks and depicts the distribution of practical source kitchens. The Lucaogou source rocks in the eastern Junggar Basin are oil-prone, dominated by type I–II kerogen, and generally classified as good to excellent source rocks. Nowadays, the area of the Lucaogou source rocks that have entered the main oil-generating window is approximately 11 × 10<sup>3</sup> km<sup>2</sup>. Except for the bulge area, the Lucaogou source rocks in the eastern Junggar Basin successively entered the hydrocarbon-generating threshold during the Jurassic and the main oil-generating window in the Cretaceous. The Lucaogou source rocks in the Jimsar Sag and other parts of the eastern Junggar Basin share similar biomarker fingerprints, characterized by relatively low ratios of Pr/Ph, Pr/<em>n</em>-C<sub>17</sub>, Tm/C<sub>30</sub> hopane, C<sub>19</sub>/C<sub>20</sub> tricyclic terpene, and C<sub>24</sub> tetracyclic terpene/C<sub>26</sub> tricyclic terpene, and high <em>β</em>-carotene content, gammacerane index, and Ts/Tm ratios. These characteristics reflect deposition in a strongly reducing brackish lacustrine environment with parental sources dominated by lower organisms such as algae and bacteria. Generally, the Lucaogou source rocks in the eastern Junggar Basin have an oil-generating intensity of more than 3 × 10<sup>6</sup> t/km<sup>2</sup>. Several oil-generating centers with an intensity of more than 5 × 10<sup>6</sup> t/km<sup>2</sup> have developed in the front of the Bogda Mountain, Jimsar Sag, Dongdaohaizi Sag, Wucaiwan Sag, and Shazhang Fault Zone, covering a total area of approximately 12,500 km<sup>2</sup>. These characteristics of the Lucaogou source rocks promise favorable potential for forming large and medium oil fields. The results further consolidated the oil and gas resources in the eastern Junggar Basin and provided valuable references for exploring future oil and gas fields.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 4","pages":"Pages 265-279"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2468256X24000397/pdfft?md5=d1fa767756b2d70a542e66bba8976214&pid=1-s2.0-S2468256X24000397-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141841757","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Understanding the key timings related to petroleum evolution is crucial for optimizing exploration targets and assessing oil/gas resources, attract petroleum geologists’ attention worldwide. Recently, hydrocarbon (oil and bitumen) Re–Os isotope dating has been innovatively applied to constrain the timing related to oil/gas generation, however, the resulting Re–Os isochron ages can be complex and challenging to interpret. This study utilizes various geochemical and geochronological data from Sinian to Cambrian natural gas reservoirs in the Sichuan Basin to reconstruct the hydrocarbon evolution process and discuss the significance of different bitumen Re–Os dating results. The gas accumulation in the Sinian-Cambrian reservoirs experienced four stages of evolution: (1) initial oil generation during the Ordovician to Silurian periods, (2) secondary oil generation during the Triassic period, (3) gas generation through thermal cracking of liquid oil from the Jurassic to Cretaceous periods, and (4) gas reservoir redistribution since the late Cretaceous. The Re–Os dates (ca. 485 Ma) of low maturity and biodegraded bitumen from the western Sichuan Basin record the oil generation during the Ordovician before the Caledonian tectonic event. The Re–Os dates (ca.184–128 Ma) of highly mature bitumen associated with MVT Pb–Zn deposits in northern Sichuan Basin provide insights into both liquid oil-cracking and thermochemical sulfate reduction (TSR) processes. The complex Re–Os dates (ca.414 Ma, ca.154 Ma) of highly mature bitumen from the central Sichuan Basin may represent different periods related to either oil or gas generation. Future studies should explore the genetic type, maturity, thermal cracking, or TSR degrees of bitumen to better understand the significance of Re–Os dates.
{"title":"Solid bitumen Rhenium-Osmium (Re–Os) isotope geochronology and existing problems: Sampled of Sinian-Cambrian gas reservoir in Sichuan Basin, China","authors":"Xiang Ge , Shisheng Xu , Guangyou Zhu , Xinyu Chen , Yaxian Gao , Chuanbo Shen","doi":"10.1016/j.jnggs.2024.08.001","DOIUrl":"10.1016/j.jnggs.2024.08.001","url":null,"abstract":"<div><p>Understanding the key timings related to petroleum evolution is crucial for optimizing exploration targets and assessing oil/gas resources, attract petroleum geologists’ attention worldwide. Recently, hydrocarbon (oil and bitumen) Re–Os isotope dating has been innovatively applied to constrain the timing related to oil/gas generation, however, the resulting Re–Os isochron ages can be complex and challenging to interpret. This study utilizes various geochemical and geochronological data from Sinian to Cambrian natural gas reservoirs in the Sichuan Basin to reconstruct the hydrocarbon evolution process and discuss the significance of different bitumen Re–Os dating results. The gas accumulation in the Sinian-Cambrian reservoirs experienced four stages of evolution: (1) initial oil generation during the Ordovician to Silurian periods, (2) secondary oil generation during the Triassic period, (3) gas generation through thermal cracking of liquid oil from the Jurassic to Cretaceous periods, and (4) gas reservoir redistribution since the late Cretaceous. The Re–Os dates (ca. 485 Ma) of low maturity and biodegraded bitumen from the western Sichuan Basin record the oil generation during the Ordovician before the Caledonian tectonic event. The Re–Os dates (ca.184–128 Ma) of highly mature bitumen associated with MVT Pb–Zn deposits in northern Sichuan Basin provide insights into both liquid oil-cracking and thermochemical sulfate reduction (TSR) processes. The complex Re–Os dates (ca.414 Ma, ca.154 Ma) of highly mature bitumen from the central Sichuan Basin may represent different periods related to either oil or gas generation. Future studies should explore the genetic type, maturity, thermal cracking, or TSR degrees of bitumen to better understand the significance of Re–Os dates.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 4","pages":"Pages 255-264"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2468256X24000403/pdfft?md5=5dc94d7dc97533fb5efa21bc167e730c&pid=1-s2.0-S2468256X24000403-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142229661","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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