Different helium source rocks exhibit varying characteristics, including differences in the content and occurrence states of precursor elements such as uranium (U) and thorium (Th). In sedimentary rocks, U and Th mainly exist in adsorbed and (or) complexed states of organic matter and clay minerals. The primary migration of helium generated in sediments is liable to occur due to the lack of mineral crystal restraint. Hence, source rocks and reservoir rocks in gas pools act as the primary effective helium source rocks in sediments. In contrast, other sedimentary rocks are less effective as helium sources due to the fact that high porosity results in prolonged helium saturation, thereby restraining the desolubilization and secondary migration of helium. In igneous rocks, isomorphous U and Th are mainly enriched in silicate and phosphate minerals. Temperature is the main controlling factor affecting their primary migration. Granite, characterized by low porosity and limited helium solubility, can experience large-scale release helium under conditions of tectonic uplift and abnormally high temperatures, acting as an effective helium source rock for helium-rich natural gases. Various forms of U and Th can exist in metamorphic rocks, which have higher porosity and higher soluble helium contents than granite, but this result in greater difficulty in helium release. Although the direct source rocks and reservoirs of natural gas reservoirs are effective helium source rocks, it is difficult to form He-rich natural gas due to the influence of hydrocarbon dilution. Sufficient He supply from basin basement or mantle-derived sources is a key condition for natural gas reservoirs to be rich in He.
{"title":"Characteristics of effective helium source rocks and releasing mechanism of helium","authors":"Xiaofeng Wang, Dong Zhao, Dongdong Zhang, Xiaofu Li, Keyu Chen, Wenhui Liu","doi":"10.1016/j.jnggs.2025.05.001","DOIUrl":"10.1016/j.jnggs.2025.05.001","url":null,"abstract":"<div><div>Different helium source rocks exhibit varying characteristics, including differences in the content and occurrence states of precursor elements such as uranium (U) and thorium (Th). In sedimentary rocks, U and Th mainly exist in adsorbed and (or) complexed states of organic matter and clay minerals. The primary migration of helium generated in sediments is liable to occur due to the lack of mineral crystal restraint. Hence, source rocks and reservoir rocks in gas pools act as the primary effective helium source rocks in sediments. In contrast, other sedimentary rocks are less effective as helium sources due to the fact that high porosity results in prolonged helium saturation, thereby restraining the desolubilization and secondary migration of helium. In igneous rocks, isomorphous U and Th are mainly enriched in silicate and phosphate minerals. Temperature is the main controlling factor affecting their primary migration. Granite, characterized by low porosity and limited helium solubility, can experience large-scale release helium under conditions of tectonic uplift and abnormally high temperatures, acting as an effective helium source rock for helium-rich natural gases. Various forms of U and Th can exist in metamorphic rocks, which have higher porosity and higher soluble helium contents than granite, but this result in greater difficulty in helium release. Although the direct source rocks and reservoirs of natural gas reservoirs are effective helium source rocks, it is difficult to form He-rich natural gas due to the influence of hydrocarbon dilution. Sufficient He supply from basin basement or mantle-derived sources is a key condition for natural gas reservoirs to be rich in He.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 137-144"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144563983","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-06-01Epub Date: 2025-06-12DOI: 10.1016/j.jnggs.2025.05.004
Liyong Fan , Jianshe Wei , Aiping Hu , Yuhong Li , Linze Xie , Tao Jiang , Yuxuan Zhang , Shangwei Ma
The Ordos Basin is the largest natural gas producing region in China. Recent discoveries of two helium-rich natural gas fields (Dongsheng and Qingyang) shows promising helium resource potential. Sulige Gas Field, the largest natural gas field in China, was analyzed to evaluate its helium resource potential. Comprehensive geochemical analyses were conducted, examining natural gas components, alkane gases, carbon isotopic signatures of carbon dioxide, helium concentrations, and helium isotopic ratios within the gas field. Preliminarily studies identified the geochemical characteristics of natural gas and helium in the Paleozoic strata of Sulige Gas Field, and explored the main controlling factors of helium reservoir formation. The results show that the composition of natural gas in the Upper Paleozoic is obviously different. Specifically, Upper Paleozoic natural gas exhibited typical wet gas at the mature stage and dry gas at the over-mature stage, while Lower Paleozoic natural gas is mainly dry gas with partial contribution of wet gas. The Upper Paleozoic is dominated by thermogenic natural gas, predominantly middle-late humic gas (coal-derived) originating from Carboniferous and Permian coal measure source rocks. In contrast, the Lower Paleozoic is dominated by late sapropelic dry gas and oil cracking gas. The helium concentrations in Paleozoic natural gas is higher than in conventional natural gas (0.03%), which belongs to middle helium gas, and the Upper Paleozoic is exceeding those of the Lower Paleozoic. The helium accumulation in the Sulige Gas Field is influenced by the ancient and modern structural location, the high helium generation intensity and relatively low hydrocarbon generation potential of helium source rocks (such as U–Th-rich basement granite and granite gneiss), the development of basement faults, and the complex gas–water relationship, which is favorable for the helium to dissolve out of the water and enter into the natural gas reservoirs.
{"title":"Geochemical characteristics, origin and main controlling factors of helium gas accumulation of helium-bearing natural gas in Sulige Gas Field, Ordos Basin, China","authors":"Liyong Fan , Jianshe Wei , Aiping Hu , Yuhong Li , Linze Xie , Tao Jiang , Yuxuan Zhang , Shangwei Ma","doi":"10.1016/j.jnggs.2025.05.004","DOIUrl":"10.1016/j.jnggs.2025.05.004","url":null,"abstract":"<div><div>The Ordos Basin is the largest natural gas producing region in China. Recent discoveries of two helium-rich natural gas fields (Dongsheng and Qingyang) shows promising helium resource potential. Sulige Gas Field, the largest natural gas field in China, was analyzed to evaluate its helium resource potential. Comprehensive geochemical analyses were conducted, examining natural gas components, alkane gases, carbon isotopic signatures of carbon dioxide, helium concentrations, and helium isotopic ratios within the gas field. Preliminarily studies identified the geochemical characteristics of natural gas and helium in the Paleozoic strata of Sulige Gas Field, and explored the main controlling factors of helium reservoir formation. The results show that the composition of natural gas in the Upper Paleozoic is obviously different. Specifically, Upper Paleozoic natural gas exhibited typical wet gas at the mature stage and dry gas at the over-mature stage, while Lower Paleozoic natural gas is mainly dry gas with partial contribution of wet gas. The Upper Paleozoic is dominated by thermogenic natural gas, predominantly middle-late humic gas (coal-derived) originating from Carboniferous and Permian coal measure source rocks. In contrast, the Lower Paleozoic is dominated by late sapropelic dry gas and oil cracking gas. The helium concentrations in Paleozoic natural gas is higher than in conventional natural gas (0.03%), which belongs to middle helium gas, and the Upper Paleozoic is exceeding those of the Lower Paleozoic. The helium accumulation in the Sulige Gas Field is influenced by the ancient and modern structural location, the high helium generation intensity and relatively low hydrocarbon generation potential of helium source rocks (such as U–Th-rich basement granite and granite gneiss), the development of basement faults, and the complex gas–water relationship, which is favorable for the helium to dissolve out of the water and enter into the natural gas reservoirs.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 145-157"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556883","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-06-01Epub Date: 2025-06-11DOI: 10.1016/j.jnggs.2025.05.002
Waseem Khan , Salman Ahmed Khattak , Saeed Anwar , Sarfraz Hussain Solangi , Licheng Wang , George Kontakiotis , S. Sahaya Jude Dhas
The primary method which has been traditionally used for assessing the hydrocarbon potential of reservoir rock involves analyzing petrophysical properties via well logs. Evaluating these properties is crucial for introducing new perspectives. This study offers a valuable case study for regional hydrocarbon evaluation, providing practical insights for exploration in the Lower Indus Basin, Pakistan. This study presents a comprehensive petrophysical evaluation of the Lower Goru Formation (LGF) located in the Sinjhoro Gas Field of Sindh, Pakistan. The characteristics of LGF reservoir are outlined, hydrocarbon potential is evaluated, and gas productivity is quantified through the analysis of density, gamma-ray, resistivity, and neutron logs, along with lateral correlation among different wells. Six significant sand masses exist that may be utilized for hydrocarbon extraction. The extensive sand area serves as the main contributor to current output from wells such as Hakeem Daho-01 and Resham-01, whereas the basal sand is the key source of production for the Well Chak-5. This study underscored the importance of leveraging these resources by showcasing the substantial hydrocarbon potential of the basal sand in Resham-01 and the extensive sand-01 in Hakeem Daho. The massive sand-01 exhibits a thickness of 10 m, with a hydrocarbon saturation of 72%, an average porosity of 11%, a shale volume of 18%, and a net thickness of 8 m. In contrast, the basal sand shows a hydrocarbon saturation of 62%, a porosity of 12%, and a net thickness of 8 m. Both are considered to possess significant reservoir potential. The data shown here has been correlated with its nearby stratigraphic equivalents dealing with the Bhuj Formation of the Kachchh Basin on India's western margin, which is important to understand and predict reservoir properties in other sandstone petroleum fields with similar properties. The conclusions of the study address issues related to reservoir characterization and facilitate the production and utilization of the significant hydrocarbon resources found in the Sinjhoro Gas Field.
{"title":"Petrophysical characterization and reservoir potential of the Lower Goru sandstone: A case study from the Sinjhoro Gas Field, Pakistan","authors":"Waseem Khan , Salman Ahmed Khattak , Saeed Anwar , Sarfraz Hussain Solangi , Licheng Wang , George Kontakiotis , S. Sahaya Jude Dhas","doi":"10.1016/j.jnggs.2025.05.002","DOIUrl":"10.1016/j.jnggs.2025.05.002","url":null,"abstract":"<div><div>The primary method which has been traditionally used for assessing the hydrocarbon potential of reservoir rock involves analyzing petrophysical properties via well logs. Evaluating these properties is crucial for introducing new perspectives. This study offers a valuable case study for regional hydrocarbon evaluation, providing practical insights for exploration in the Lower Indus Basin, Pakistan. This study presents a comprehensive petrophysical evaluation of the Lower Goru Formation (LGF) located in the Sinjhoro Gas Field of Sindh, Pakistan. The characteristics of LGF reservoir are outlined, hydrocarbon potential is evaluated, and gas productivity is quantified through the analysis of density, gamma-ray, resistivity, and neutron logs, along with lateral correlation among different wells. Six significant sand masses exist that may be utilized for hydrocarbon extraction. The extensive sand area serves as the main contributor to current output from wells such as Hakeem Daho-01 and Resham-01, whereas the basal sand is the key source of production for the Well Chak-5. This study underscored the importance of leveraging these resources by showcasing the substantial hydrocarbon potential of the basal sand in Resham-01 and the extensive sand-01 in Hakeem Daho. The massive sand-01 exhibits a thickness of 10 m, with a hydrocarbon saturation of 72%, an average porosity of 11%, a shale volume of 18%, and a net thickness of 8 m. In contrast, the basal sand shows a hydrocarbon saturation of 62%, a porosity of 12%, and a net thickness of 8 m. Both are considered to possess significant reservoir potential. The data shown here has been correlated with its nearby stratigraphic equivalents dealing with the Bhuj Formation of the Kachchh Basin on India's western margin, which is important to understand and predict reservoir properties in other sandstone petroleum fields with similar properties. The conclusions of the study address issues related to reservoir characterization and facilitate the production and utilization of the significant hydrocarbon resources found in the Sinjhoro Gas Field.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 179-197"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556885","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
To elucidate the mechanism of supercritical CO2 (ScCO2) on the microporous structure of shale, this study focuses on the Chang 73 submember of the Yanchang Formation in the Ordos Basin. Utilizing a combination of organic geochemical and mineral composition analyses, low-temperature gas (CO2 and N2) adsorption experiments and nuclear magnetic resonance (NMR) scanning methods are employed—combined with multiscale fractal theory—the research comprehensively analyze the changes in shale microporous structure and its fractal characteristics under ScCO2 treatment. The results show that after ScCO2 treatment, the total organic carbon (TOC) content of the shale samples decreases, the quartz content increases, while the contents of clay minerals and feldspar decrease. Notably, TOC and mineral components are more sensitive to pressure changes compared to temperature variations. Additionally, shale pores are mainly distributed in the micropore (0–2 nm) and mesopore (2–50 nm) ranges, contributing significantly to the specific surface area, while macropores (>50 nm), though fewer, considerably contribute to the total pore volume. Following ScCO2 treatment, the total specific surface area of shale samples decreases, whereas total pore volume, average pore diameter, and effective porosity increase. Specifically, total specific surface area and average pore diameter are more sensitive to temperature, while total pore volume and effective porosity are more influenced by pressure. The shale pores exhibit multi-scale fractal characteristics, with micropores displaying higher fractal dimensions than meso- and macropores. After ScCO2 treatment, fractal dimensions at all scales decline, indicating an improvement in the complexity of the shale pore structure. A significant positive correlation exists between the fractal dimension of micropores and TOC content, whereas meso- and macropore fractal dimensions have a stronger correlation with quartz and clay mineral content. These findings indicate that changes in shale mineral characteristics are intrinsic factors affecting microporous structure, while ScCO2 treatment conditions are important external factors. The interaction of both determines the evolution of shale pore structures, providing a valuable scientific basis and practical guidance for the optimal selection of carbon capture, utilization, and storage (CCUS) target layers.
{"title":"Research on the micro-pore structure and multiscale fractal characteristics of shale under supercritical CO2 action: A case study of the Chang 73 submember in the Ordos Basin, China","authors":"Lili Jiang , Leng Tian , Zhangxing Chen , Zechuan Wang , Wenkui Huang , Xiaolong Chai","doi":"10.1016/j.jnggs.2025.05.003","DOIUrl":"10.1016/j.jnggs.2025.05.003","url":null,"abstract":"<div><div>To elucidate the mechanism of supercritical CO<sub>2</sub> (ScCO<sub>2</sub>) on the microporous structure of shale, this study focuses on the Chang 7<sub>3</sub> submember of the Yanchang Formation in the Ordos Basin. Utilizing a combination of organic geochemical and mineral composition analyses, low-temperature gas (CO<sub>2</sub> and N<sub>2</sub>) adsorption experiments and nuclear magnetic resonance (NMR) scanning methods are employed—combined with multiscale fractal theory—the research comprehensively analyze the changes in shale microporous structure and its fractal characteristics under ScCO<sub>2</sub> treatment. The results show that after ScCO<sub>2</sub> treatment, the total organic carbon (TOC) content of the shale samples decreases, the quartz content increases, while the contents of clay minerals and feldspar decrease. Notably, TOC and mineral components are more sensitive to pressure changes compared to temperature variations. Additionally, shale pores are mainly distributed in the micropore (0–2 nm) and mesopore (2–50 nm) ranges, contributing significantly to the specific surface area, while macropores (>50 nm), though fewer, considerably contribute to the total pore volume. Following ScCO<sub>2</sub> treatment, the total specific surface area of shale samples decreases, whereas total pore volume, average pore diameter, and effective porosity increase. Specifically, total specific surface area and average pore diameter are more sensitive to temperature, while total pore volume and effective porosity are more influenced by pressure. The shale pores exhibit multi-scale fractal characteristics, with micropores displaying higher fractal dimensions than meso- and macropores. After ScCO<sub>2</sub> treatment, fractal dimensions at all scales decline, indicating an improvement in the complexity of the shale pore structure. A significant positive correlation exists between the fractal dimension of micropores and TOC content, whereas meso- and macropore fractal dimensions have a stronger correlation with quartz and clay mineral content. These findings indicate that changes in shale mineral characteristics are intrinsic factors affecting microporous structure, while ScCO<sub>2</sub> treatment conditions are important external factors. The interaction of both determines the evolution of shale pore structures, providing a valuable scientific basis and practical guidance for the optimal selection of carbon capture, utilization, and storage (CCUS) target layers.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 159-178"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556884","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-06-01Epub Date: 2025-06-11DOI: 10.1016/j.jnggs.2025.04.001
Dennis Chinamo, Xiaoqiang Bian
Gas condensate reservoirs present significant challenges in reservoir engineering due to their complex phase behavior, which is influenced by continuous compositional changes. In particular, nanopore confinement and adsorption significantly alter the thermodynamic properties of hydrocarbons, affecting phase transitions such as dew point pressure and condensate accumulation. This study investigates these effects within the Marcellus Shale formation by developing a compositional fluid model that integrates critical property shifts induced by pore confinement and adsorption. The model is compared with experimental measurements to ensure accuracy. To evaluate the impact of confinement, six fluid models were constructed using the Peng–Robinson equation of state, representing different pore sizes (1 nm, 2 nm, 5 nm, 10 nm, and 50 nm) alongside an unconfined reference case. The results demonstrate that smaller nanopores lead to significant shifts in critical pressure and temperature, ultimately delaying the onset of liquid condensation. Additionally, adsorption effects enhance reservoir pressure maintenance by storing hydrocarbons in the adsorbed phase, which desorbs as pressure declines, supplementing gas production. By incorporating confinement-induced phase behavior modifications, this research provides key insights into optimizing gas condensate production. The findings highlight the necessity of considering nanoscale confinement and adsorption effects in reservoir simulations to improve forecasting accuracy and develop more effective reservoir management strategies.
{"title":"Impact of pore confinement and adsorption on gas condensate critical properties confined in Marcellus Shale","authors":"Dennis Chinamo, Xiaoqiang Bian","doi":"10.1016/j.jnggs.2025.04.001","DOIUrl":"10.1016/j.jnggs.2025.04.001","url":null,"abstract":"<div><div>Gas condensate reservoirs present significant challenges in reservoir engineering due to their complex phase behavior, which is influenced by continuous compositional changes. In particular, nanopore confinement and adsorption significantly alter the thermodynamic properties of hydrocarbons, affecting phase transitions such as dew point pressure and condensate accumulation. This study investigates these effects within the Marcellus Shale formation by developing a compositional fluid model that integrates critical property shifts induced by pore confinement and adsorption. The model is compared with experimental measurements to ensure accuracy. To evaluate the impact of confinement, six fluid models were constructed using the Peng–Robinson equation of state, representing different pore sizes (1 nm, 2 nm, 5 nm, 10 nm, and 50 nm) alongside an unconfined reference case. The results demonstrate that smaller nanopores lead to significant shifts in critical pressure and temperature, ultimately delaying the onset of liquid condensation. Additionally, adsorption effects enhance reservoir pressure maintenance by storing hydrocarbons in the adsorbed phase, which desorbs as pressure declines, supplementing gas production. By incorporating confinement-induced phase behavior modifications, this research provides key insights into optimizing gas condensate production. The findings highlight the necessity of considering nanoscale confinement and adsorption effects in reservoir simulations to improve forecasting accuracy and develop more effective reservoir management strategies.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 199-218"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144556881","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-04-01Epub Date: 2025-03-27DOI: 10.1016/j.jnggs.2025.03.002
Deyu Gong , Yan Han , Tanguang Fan , Xinning Li , Chuanmin Zhou , Shoqing Wang , Ruiju Wang , Wei'an Wu , Yihao Miao
A billion-ton mega shale oil field has been discovered in the Jimsar Sag, located in the Eastern Uplift of Junggar Basin, which reveals the good hydrocarbon-generating potential of the source rocks in the Middle Permian Lucaogou Formation. This paper systematically evaluates the hydrocarbon-generating potential and formation environment of the Lucaogou source rocks in the Gucheng Sag, which is adjacent to the Jimsar Sag, and draws the distribution range of the source kitchen, and compares them with those of the Lucaogou source rocks in the Jimsar Sag. The results show that the kerogen type of Lucaogou source rocks in the Gucheng Sag is mainly of type II/III–III, dominated by good–excellent source rocks, and the type and abundance are slightly inferior to those in the Jimusar Sag. In the Middle and Late Jurassic, the Lucaogou source rocks in the Gucheng Sag entered the hydrocarbon-generating threshold, and now, the area entering the main oil-generating window reaches 212 km2. Although both of them are lacustrine deposits, the Lucaogou source rocks in the Gucheng Sag have slightly higher Pr/Ph, Ts/(Ts + Tm), C19/C21 tricyclic terpane, C24 tetracyclic terpane/C26 tricyclic terpane ratios, and somewhat lower C28 regular sterane content than the Jimsar Sag, suggesting that Lucaogou source rocks were deposited in an oxidizing–reducing transitional environment of a specific salinity in the Gucheng Sag. There was a certain amount of terrestrial higher plant input in addition to the contribution of algal and microbial biota in the Lucaogou source rocks in the Gucheng Sag. The Lucaogou source rocks have developed four centers with a thickness greater than 160 m in the Gucheng Sag, covering a total area of about 420 km2. In the southern part of the sag, three hydrocarbon-generating centers with an oil-generating intensity greater than 2000 × 103 t/km2 have developed, covering a total area of 130 km2. The research results further strengthen the resource base of the Middle Permian petroleum system in the Junggar Basin and lay the foundation for the next step of petroleum exploration in the Gucheng Sag.
{"title":"Hydrocarbon-generating potential of the Middle Permian Lucaogou source rocks in the Gucheng Sag, Junggar Basin, China","authors":"Deyu Gong , Yan Han , Tanguang Fan , Xinning Li , Chuanmin Zhou , Shoqing Wang , Ruiju Wang , Wei'an Wu , Yihao Miao","doi":"10.1016/j.jnggs.2025.03.002","DOIUrl":"10.1016/j.jnggs.2025.03.002","url":null,"abstract":"<div><div>A billion-ton mega shale oil field has been discovered in the Jimsar Sag, located in the Eastern Uplift of Junggar Basin, which reveals the good hydrocarbon-generating potential of the source rocks in the Middle Permian Lucaogou Formation. This paper systematically evaluates the hydrocarbon-generating potential and formation environment of the Lucaogou source rocks in the Gucheng Sag, which is adjacent to the Jimsar Sag, and draws the distribution range of the source kitchen, and compares them with those of the Lucaogou source rocks in the Jimsar Sag. The results show that the kerogen type of Lucaogou source rocks in the Gucheng Sag is mainly of type II/III–III, dominated by good–excellent source rocks, and the type and abundance are slightly inferior to those in the Jimusar Sag. In the Middle and Late Jurassic, the Lucaogou source rocks in the Gucheng Sag entered the hydrocarbon-generating threshold, and now, the area entering the main oil-generating window reaches 212 km<sup>2</sup>. Although both of them are lacustrine deposits, the Lucaogou source rocks in the Gucheng Sag have slightly higher Pr/Ph, Ts/(Ts + Tm), C<sub>19</sub>/C<sub>21</sub> tricyclic terpane, C<sub>24</sub> tetracyclic terpane/C<sub>26</sub> tricyclic terpane ratios, and somewhat lower C<sub>28</sub> regular sterane content than the Jimsar Sag, suggesting that Lucaogou source rocks were deposited in an oxidizing–reducing transitional environment of a specific salinity in the Gucheng Sag. There was a certain amount of terrestrial higher plant input in addition to the contribution of algal and microbial biota in the Lucaogou source rocks in the Gucheng Sag<sup>.</sup> The Lucaogou source rocks have developed four centers with a thickness greater than 160 m in the Gucheng Sag, covering a total area of about 420 km<sup>2</sup>. In the southern part of the sag, three hydrocarbon-generating centers with an oil-generating intensity greater than 2000 × 10<sup>3</sup> t/km<sup>2</sup> have developed, covering a total area of 130 km<sup>2</sup>. The research results further strengthen the resource base of the Middle Permian petroleum system in the Junggar Basin and lay the foundation for the next step of petroleum exploration in the Gucheng Sag.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 2","pages":"Pages 87-100"},"PeriodicalIF":0.0,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143869153","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 : 2025-04-01Epub Date: 2025-03-15DOI: 10.1016/j.jnggs.2025.02.001
Yunyan Ni , Jinchuan Zhang , Limiao Yao , Guoliang Dong , Yuan Wang , Li Wang , Jianping Chen
Different types of natural gas exhibit distinct carbon and hydrogen isotopic compositions, making these isotopic compositions crucial indicators for identifying gas origins. With ongoing advancements in natural gas exploration technology and the increasing volume of exploration data, our understanding of natural gas origins and sources continues to deepen, and how to update and verify the existing data to ensure the applicability of gas genetic diagrams has become crucial. This study comprehensively analyzes the stable carbon and hydrogen isotope characteristics of different genetic types of natural gases in Sichuan, Tarim, Ordos, Turpan-Hami, Songliao, Northern Jiangsu, Sanshui, Qaidam, and Bohai Bay basins in China, together with abiotic gases from the Lost City of the Middle Atlantic Ridge, and the genetic diagrams related to commonly used carbon and hydrogen isotopes are evaluated. The study yields the following four conclusions: (1) The carbon isotopic values of methane (δ13C1), ethane (δ13C2), propane (δ13C3) and butane (δ13C4) of natural gases from China are from −89.4‰ to −11.4‰ (average of −36.6‰), −66.0‰ to −17.5‰ (average of −29.4‰), −49.5‰ to −13.2‰ (average of −27.3‰), −38.5‰ to −16.0‰ (average of −25.6‰), respectively. (2) The hydrogen isotopic values of methane (δD1), ethane (δD2) and propane (δD3) of natural gases from China range from −287‰ to −111‰ (average of −177‰), −249‰ to −94‰ (average of −158‰), and −237‰ to −75‰ (average of −146‰), respectively. (3) The carbon and hydrogen isotopic distribution patterns among methane and its homologues of natural gases in China are mainly in positive order (δ13C1<δ13C2<δ13C3<δ13C4, δD1<δD2<δD3). In most natural gas samples, the fractionation amplitude between methane and ethane is greater than that between ethane and propane (Δ(δ13C2−δ13C1) > Δ(δ13C3−δ13C2), Δ(δD2−δD1) > Δ(δD3−δD2)). (4) The δ13C1–δ13C2–δ13C3, the δ13C1–δD1, δ13C1–C1/C2+3, Δ(δ13C2−δ13C1)–Δ(δ13C3−δ13C2) and Δ(δD2−δD1)–Δ(δD3−δD2) diagrams, can be used to identify the gas origin in many different cases, and the combined application between different charts can enhance the identification effect.
{"title":"Application of carbon and hydrogen isotopes in the study of natural gas origins","authors":"Yunyan Ni , Jinchuan Zhang , Limiao Yao , Guoliang Dong , Yuan Wang , Li Wang , Jianping Chen","doi":"10.1016/j.jnggs.2025.02.001","DOIUrl":"10.1016/j.jnggs.2025.02.001","url":null,"abstract":"<div><div>Different types of natural gas exhibit distinct carbon and hydrogen isotopic compositions, making these isotopic compositions crucial indicators for identifying gas origins. With ongoing advancements in natural gas exploration technology and the increasing volume of exploration data, our understanding of natural gas origins and sources continues to deepen, and how to update and verify the existing data to ensure the applicability of gas genetic diagrams has become crucial. This study comprehensively analyzes the stable carbon and hydrogen isotope characteristics of different genetic types of natural gases in Sichuan, Tarim, Ordos, Turpan-Hami, Songliao, Northern Jiangsu, Sanshui, Qaidam, and Bohai Bay basins in China, together with abiotic gases from the Lost City of the Middle Atlantic Ridge, and the genetic diagrams related to commonly used carbon and hydrogen isotopes are evaluated. The study yields the following four conclusions: (1) The carbon isotopic values of methane (δ<sup>13</sup>C<sub>1</sub>), ethane (δ<sup>13</sup>C<sub>2</sub>), propane (δ<sup>13</sup>C<sub>3</sub>) and butane (δ<sup>13</sup>C<sub>4</sub>) of natural gases from China are from −89.4‰ to −11.4‰ (average of −36.6‰), −66.0‰ to −17.5‰ (average of −29.4‰), −49.5‰ to −13.2‰ (average of −27.3‰), −38.5‰ to −16.0‰ (average of −25.6‰), respectively. (2) The hydrogen isotopic values of methane (δD<sub>1</sub>), ethane (δD<sub>2</sub>) and propane (δD<sub>3</sub>) of natural gases from China range from −287‰ to −111‰ (average of −177‰), −249‰ to −94‰ (average of −158‰), and −237‰ to −75‰ (average of −146‰), respectively. (3) The carbon and hydrogen isotopic distribution patterns among methane and its homologues of natural gases in China are mainly in positive order (δ<sup>13</sup>C<sub>1</sub><δ<sup>13</sup>C<sub>2</sub><δ<sup>13</sup>C<sub>3</sub><δ<sup>13</sup>C<sub>4</sub>, δD<sub>1</sub><δD<sub>2</sub><δD<sub>3</sub>). In most natural gas samples, the fractionation amplitude between methane and ethane is greater than that between ethane and propane (Δ(δ<sup>13</sup>C<sub>2</sub>−δ<sup>13</sup>C<sub>1</sub>) > Δ(δ<sup>13</sup>C<sub>3</sub>−δ<sup>13</sup>C<sub>2</sub>), Δ(δD<sub>2</sub>−δD<sub>1</sub>) > Δ(δD<sub>3</sub>−δD<sub>2</sub>)). (4) The δ<sup>13</sup>C<sub>1</sub>–δ<sup>13</sup>C<sub>2</sub>–δ<sup>13</sup>C<sub>3</sub>, the δ<sup>13</sup>C<sub>1</sub>–δD<sub>1</sub>, δ<sup>13</sup>C<sub>1</sub>–C<sub>1</sub>/C<sub>2+3</sub>, Δ(δ<sup>13</sup>C<sub>2</sub>−δ<sup>13</sup>C<sub>1</sub>)–Δ(δ<sup>13</sup>C<sub>3</sub>−δ<sup>13</sup>C<sub>2</sub>) and Δ(δD<sub>2</sub>−δD<sub>1</sub>)–Δ(δD<sub>3</sub>−δD<sub>2</sub>) diagrams, can be used to identify the gas origin in many different cases, and the combined application between different charts can enhance the identification effect.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 2","pages":"Pages 75-85"},"PeriodicalIF":0.0,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143869152","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 : 2025-04-01Epub Date: 2025-03-15DOI: 10.1016/j.jnggs.2025.03.001
Tao Zhang , Xiaofeng Wang , Kai Lu , Yiran Wang , Xiaoyan Chen , Wen Zhang , Xiaohui Jin , Qingqiang Meng , Juan Zhang
The geochemical characteristics of the Paleozoic natural gas in the southern part of the Ordos Basin shows significant differences from those in the northern part. These differences lead to the increase in dryness coefficient and a heavier carbon isotope composition of methane attributed to the increase in organic matter maturity of the source rocks. Additionally, the Upper Paleozoic natural gas in the southern basin contains a higher carbon dioxide (CO2) gas content, and exhibits a common phenomenon of methane and ethane carbon isotope composition inversions. This paper employs gas geochemistry as the principal analytical method to systematically compare the north-south differences in the Paleozoic natural gas composition and to explore its origin and source. The findings indicate that the Upper Paleozoic natural gas in the southern basin mainly composed of highly over-mature coal-type gas. However, certain gas geochemical indicators suggest the presence of lower paleomarine hydrocarbon sources in specific areas. The observed inversion of methane and ethane carbon isotope composition in the Upper Paleozoic natural gas in the southern basin is attributed to the mixing of different types of natural gas. Specifically, the varying degrees of mixing with the Lower Paleozoic oil-type gas—characterized by a higher ethane content and lighter ethane carbon isotope values—are identified as the primary cause of the inversion of carbon isotopes. Furthermore, geochemical indicators of natural gas in the lower Paleozoic in the southern basin strongly reflect typical marine hydrocarbon source characteristics. While these gases predominantly originate from marine source rocks, a minor contribution from the Upper Paleozoic coal-type gas cannot be entirely ruled out.
{"title":"Geochemical characteristics and genesis of the Paleozoic natural gas in the southern Ordos Basin, China","authors":"Tao Zhang , Xiaofeng Wang , Kai Lu , Yiran Wang , Xiaoyan Chen , Wen Zhang , Xiaohui Jin , Qingqiang Meng , Juan Zhang","doi":"10.1016/j.jnggs.2025.03.001","DOIUrl":"10.1016/j.jnggs.2025.03.001","url":null,"abstract":"<div><div>The geochemical characteristics of the Paleozoic natural gas in the southern part of the Ordos Basin shows significant differences from those in the northern part. These differences lead to the increase in dryness coefficient and a heavier carbon isotope composition of methane attributed to the increase in organic matter maturity of the source rocks. Additionally, the Upper Paleozoic natural gas in the southern basin contains a higher carbon dioxide (CO<sub>2</sub>) gas content, and exhibits a common phenomenon of methane and ethane carbon isotope composition inversions. This paper employs gas geochemistry as the principal analytical method to systematically compare the north-south differences in the Paleozoic natural gas composition and to explore its origin and source. The findings indicate that the Upper Paleozoic natural gas in the southern basin mainly composed of highly over-mature coal-type gas. However, certain gas geochemical indicators suggest the presence of lower paleomarine hydrocarbon sources in specific areas. The observed inversion of methane and ethane carbon isotope composition in the Upper Paleozoic natural gas in the southern basin is attributed to the mixing of different types of natural gas. Specifically, the varying degrees of mixing with the Lower Paleozoic oil-type gas—characterized by a higher ethane content and lighter ethane carbon isotope values—are identified as the primary cause of the inversion of carbon isotopes. Furthermore, geochemical indicators of natural gas in the lower Paleozoic in the southern basin strongly reflect typical marine hydrocarbon source characteristics. While these gases predominantly originate from marine source rocks, a minor contribution from the Upper Paleozoic coal-type gas cannot be entirely ruled out.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 2","pages":"Pages 101-109"},"PeriodicalIF":0.0,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143869093","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 : 2025-04-01Epub Date: 2025-04-10DOI: 10.1016/j.jnggs.2025.03.003
Jun Zhao , Chao Zheng , Jianxiang Pei , Di Tang , Jiang Jia
The Chinese offshore area holds vast reserves of deepwater and shallow gas hydrates. However, due to the geological looseness of deepwater and shallow layers, the absence of tight sealing layers, and the high heterogeneity of gas hydrate reservoirs, identifying the occurrence state of gas hydrates remains challenging, greatly impeding the accurate prediction of gas hydrate saturation. Based on the acoustic-electric response characteristics of deepwater and shallow gas hydrates, this study employs the intersection method of resistivity and longitudinal wave velocity diagrams to identify the occurrence state of gas hydrates. The pore volume of gas hydrate reservoirs is calculated using a density formula corrected for mud content. Gas hydrate saturation in the YL target area of the Qiongdongnan (QDN) Basin is predicted using three methods: the mud-corrected resistivity method, the equivalent medium method, and the joint inversion method, finding the minimum combined error of acoustic and electric data. The results indicate that the predicted values using the joint inversion method in the YL target area of the QDN Basin are closest to the measured values obtained from the chloride ion concentration method, with prediction errors ranging from 0.09 % to 14.89 % and an average error of 6.85 %. These findings suggest that selecting an appropriate acoustic-electric joint inversion saturation calculation model, based on the determination of hydrate occurrence states, can significantly improve the accuracy of hydrate saturation prediction. This approach provides a realiable method for calculating hydrate saturation in the deepwater and shallow sediments.
{"title":"Hydrate occurrence identification of shallow loose sediments in deep water and its saturation calculation","authors":"Jun Zhao , Chao Zheng , Jianxiang Pei , Di Tang , Jiang Jia","doi":"10.1016/j.jnggs.2025.03.003","DOIUrl":"10.1016/j.jnggs.2025.03.003","url":null,"abstract":"<div><div>The Chinese offshore area holds vast reserves of deepwater and shallow gas hydrates. However, due to the geological looseness of deepwater and shallow layers, the absence of tight sealing layers, and the high heterogeneity of gas hydrate reservoirs, identifying the occurrence state of gas hydrates remains challenging, greatly impeding the accurate prediction of gas hydrate saturation. Based on the acoustic-electric response characteristics of deepwater and shallow gas hydrates, this study employs the intersection method of resistivity and longitudinal wave velocity diagrams to identify the occurrence state of gas hydrates. The pore volume of gas hydrate reservoirs is calculated using a density formula corrected for mud content. Gas hydrate saturation in the YL target area of the Qiongdongnan (QDN) Basin is predicted using three methods: the mud-corrected resistivity method, the equivalent medium method, and the joint inversion method, finding the minimum combined error of acoustic and electric data. The results indicate that the predicted values using the joint inversion method in the YL target area of the QDN Basin are closest to the measured values obtained from the chloride ion concentration method, with prediction errors ranging from 0.09 % to 14.89 % and an average error of 6.85 %. These findings suggest that selecting an appropriate acoustic-electric joint inversion saturation calculation model, based on the determination of hydrate occurrence states, can significantly improve the accuracy of hydrate saturation prediction. This approach provides a realiable method for calculating hydrate saturation in the deepwater and shallow sediments.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 2","pages":"Pages 125-135"},"PeriodicalIF":0.0,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143869761","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 : 2025-04-01Epub Date: 2025-03-21DOI: 10.1016/j.jnggs.2025.02.002
Syed Oubee Khadri , Ahmed Hamza , Ibnelwaleed A. Hussein , Hamad Alsaad Alkuwari , Fadhil Sadooni
Shale gas is considered one of the promising unconventional gas reservoirs that would help meet the current demand for natural gas as a clean energy resource. Qatar has several shale gas reservoirs from diverse epochs, including the Eocene Midra Shale. Outcrop samples of Midra Shale were collected from the Umm Bab and Dukhan areas, and multiple measuring and geochemical analysis techniques were utilized to characterize the mineralogy, microstructure, and pores type. X-ray diffraction (XRD) mineralogy analysis and X-ray Fluorescence (XRF) indicated that palygorskite is the dominant clay in Midra Shale. The mineralogy of Midra Shale includes other minor minerals such as calcite, quartz, and halite, as well as low content of other clays, including sepiolite, smectite, and illite. Although the Midra Shale contains many elements, such as shark teeth and large foraminifera that support deposition under marine conditions, the existence horizons of laminated shale designate mixed marine continental depositional settings. Scanning electron microscope (SEM) images revealed various types of pores in Midra Shale, such as intragranular, intergranular, and organic pores. The geochemical analysis revealed that the Dukhan section is poor in organic matter and has low potential as a source rock for oil or gas. In contrast, the Umm Bab Section has a relatively high amount of organic carbon, making it a potential source rock.
{"title":"Geochemical and petrophysical characterization of the Midra Shale, Qatar","authors":"Syed Oubee Khadri , Ahmed Hamza , Ibnelwaleed A. Hussein , Hamad Alsaad Alkuwari , Fadhil Sadooni","doi":"10.1016/j.jnggs.2025.02.002","DOIUrl":"10.1016/j.jnggs.2025.02.002","url":null,"abstract":"<div><div>Shale gas is considered one of the promising unconventional gas reservoirs that would help meet the current demand for natural gas as a clean energy resource. Qatar has several shale gas reservoirs from diverse epochs, including the Eocene Midra Shale. Outcrop samples of Midra Shale were collected from the Umm Bab and Dukhan areas, and multiple measuring and geochemical analysis techniques were utilized to characterize the mineralogy, microstructure, and pores type. X-ray diffraction (XRD) mineralogy analysis and X-ray Fluorescence (XRF) indicated that palygorskite is the dominant clay in Midra Shale. The mineralogy of Midra Shale includes other minor minerals such as calcite, quartz, and halite, as well as low content of other clays, including sepiolite, smectite, and illite. Although the Midra Shale contains many elements, such as shark teeth and large foraminifera that support deposition under marine conditions, the existence horizons of laminated shale designate mixed marine continental depositional settings. Scanning electron microscope (SEM) images revealed various types of pores in Midra Shale, such as intragranular, intergranular, and organic pores. The geochemical analysis revealed that the Dukhan section is poor in organic matter and has low potential as a source rock for oil or gas. In contrast, the Umm Bab Section has a relatively high amount of organic carbon, making it a potential source rock.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 2","pages":"Pages 111-124"},"PeriodicalIF":0.0,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143869094","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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