Journal of Natural Gas Geoscience最新文献

{"title":"Investigating curve smoothing techniques for enhanced shale gas production data analysis","authors":"Taha Yehia ,&nbsp;Sondos Mostafa ,&nbsp;Moamen Gasser ,&nbsp;Mostafa M. Abdelhafiz ,&nbsp;Nathan Meehan ,&nbsp;Omar Mahmoud","doi":"10.1016/j.jnggs.2024.10.004","DOIUrl":"10.1016/j.jnggs.2024.10.004","url":null,"abstract":"<div><div>Evaluating shale gas reservoir economic viability remains challenging due to different factors such as long transient flow period and liquid loading resulting in successful shut-ins. Such factors cause fluctuations in production data, with inherent noise impacting analysis methods like decline curve analysis (DCA). In this research, we investigated data smoothing techniques as an alternative to noise removal methods. By applying these techniques, the essential characteristics of the periodic events and signals are retained while reducing the influence of noise making identifying and analyzing patterns easier. Applying seven smoothing techniques to three shale gas datasets with different noise levels to investigate their performance, then, utilizing the cluster-based local outlier factor (CBLOF) algorithm to remove noise from the production data, then, applying seven different DCA models to the original, smoothed, and processed data with CBLOF, the study found that smoothing the data facilitated the extraction of the well's signals. Different smoothing techniques exhibited varying spike levels. The goodness of fit was superior using LOWESS and Fast Fourier Transform (FFT) methods compared to Binomial Smoothing. Moreover, each smoothing technique yielded variations in prediction using the same DCA model. Applying the DCA models that commonly underestimate the reserve to the smoothed data led to further underestimations; however, the DCA models that commonly reserve overestimating reserves also leaned towards underestimations. The Duong's DCA model achieved the highest correlation coefficient (<em>R</em>²), whereas the Wang's DCA model recorded the lowest. In conclusion, this research highlights the benefits of smoothing shale gas production data for better analysis.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 6","pages":"Pages 431-458"},"PeriodicalIF":0.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143158158","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}

{"title":"Differential controlling on the deep tight sandstone reservoirs: Insight from the second member of lower Triassic Xujiahe Formation in Xinchang area, western Sichuan basin, China","authors":"Pengwei Li,&nbsp;Zongquan Hu,&nbsp;Zhongqun Liu,&nbsp;Shilin Xu,&nbsp;Zhenfeng Liu,&nbsp;Ai Wang,&nbsp;Junlong Liu,&nbsp;Wujun Jin,&nbsp;Yanqing Huang","doi":"10.1016/j.jnggs.2024.10.003","DOIUrl":"10.1016/j.jnggs.2024.10.003","url":null,"abstract":"<div><div>With advancements in deep exploration, the deep tight sandstone gas reservoir has become a significant exploration field. However, it remains challenging to develop on a large scale due to the unclear distribution of relatively high-quality reservoirs. In this paper, the petrology, reservoir properties, diagenesis, and structural fracturing of deep tight sandstone reservoirs are systematically studied, focusing on the second member of the Upper Triassic Xujiahe Formation (T₃<em>x</em>²) in the Xinchang area, and the types of relatively high-quality reservoirs and their differential controlling are further clarified. According to the matching relationship between pores and fractures, tight sandstone reservoirs can be classified into four types: extremely tight, fractured, porous, and pore-fractured types. Among these, the porous and pore-fractured types are considered effective reservoirs. The formation of tight sandstone reservoirs is closely related to sedimentary microfacies, grain size, diagenesis and tectonic fracturing, with distinct controlling differences across reservoir types. Overall, sedimentary microfacies provide the foundation, while differential diagenesis and tectonic fracturing are the key factors influencing reservoir quality. Among them, the extremely tight sandstone reservoirs can form in various sedimentary microfacies, particularly in medium to fine, lithic-rich sandstones, where strong compaction and cementation are the main factors for the underdevelopment of reservoir space. In contrast, fractured reservoirs mainly form based on porous reservoirs through the superimposition of tectonic fracturing. The porous reservoirs are typically found in relatively high-energy environments such as distributary channels and mouth bars, with medium to coarse feldspar-rich sandstone. Dissolution and chlorite-liner cementation are the key factors for their pore formation. Similarly, pore-fractured reservoirs originate from porous reservoirs that have been further altered by superimposing tectonic fracturing.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 6","pages":"Pages 387-399"},"PeriodicalIF":0.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143158157","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}

{"title":"Sources and exploration potential of Ordovician subsalt natural gas in Ordos Basin, China","authors":"Qingfen Kong ,&nbsp;Linyin Kong ,&nbsp;Jingli Yao ,&nbsp;Junfeng Ren ,&nbsp;Kai Wu ,&nbsp;Taiping Zhao","doi":"10.1016/j.jnggs.2024.11.001","DOIUrl":"10.1016/j.jnggs.2024.11.001","url":null,"abstract":"<div><div>With the continuous increase in exploration efforts in new zones and new strata, significant breakthroughs have been made in the natural gas exploration of the O₁<em>m</em>₅⁶ to O₁<em>m</em>₄ formations in the Ordos Basin. Thus, the origin and exploration potential of subsalt natural gas have attracted much attention and urgently need to be addressed. On the basis of certain geochemical characteristics, genetic types, and sources of natural gas, a comprehensive study on the sedimentary environment, organic geochemical characteristics, and spatial distribution scale of source rocks are conducted in this paper by using geological and geochemical methods. The study shows that: (1) The Ordovician subsalt natural gas is mainly “pyrolysis dry gas,” among which the δ¹³C₁ of Ordovician subsalt low sulfur (sulfur-free) natural gas is lighter, with an average value of −39.6‰; the δ¹³C₂ ranges more largely from −35.6‰ to −25.8‰. In contrast, both δ¹³C₁ and δ¹³C₂ values are heavier in high-sulfur natural gas, revealing that different Thermochemical Sulfate Reduction (TSR) reaction stages have different degrees of influence on natural gas components and carbon isotope composition. (2) Subsalt natural gas is classified as “oil-type gas,” which is self-generated and self-accumulated, whose source rocks are mainly Ordovician subsalt marine deposits. (3) Three types of marine source rocks are developed in Ordovician subsalt, including black argillaceous rock, dark argillaceous dolomite (dolomitic mudstone), and dark micrite (bioclastic) limestone. In addition to micrite limestone, these rocks were mainly formed in a confined lagoon sedimentary environment with high salinity and anoxia. Sedimentary water was significantly stratified and the environment was highly reduced. The organic matter content of the source rocks is relatively high, with an average <em>TOC</em> value of 0.45%. The hydrocarbon-generating parent materials are mainly composed of bacteria and algae, and the organic matter evolution reaches high-over maturity stage. The total gas generation amount of the marine source rocks in Ordovician subsalt is approximately 43.8 × 10¹² m³, which can provide hydrocarbons and accumulate for the subsalt favorable reservoir facies located far from Upper Paleozoic gas sources.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 6","pages":"Pages 401-416"},"PeriodicalIF":0.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143158154","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}

{"title":"Main controlling factors of shale gas migration in the Longmaxi Formation, Changning area of the Sichuan Basin, China","authors":"Guozhen Wang ,&nbsp;Zhenxue Jiang ,&nbsp;Yuanhao Zhang ,&nbsp;Ruihua Chen ,&nbsp;Houjian Gong ,&nbsp;Shijie He","doi":"10.1016/j.jnggs.2024.10.002","DOIUrl":"10.1016/j.jnggs.2024.10.002","url":null,"abstract":"<div><div>Shale gas migration is a critical geological process in the enrichment of shale gas deposits. Computational fluid dynamics (CFD) methods were employed to investigate this migration process. Utilizing CFD principles, an abstract physical model incorporating stratum dip angles and physical properties was developed. The control variable method was utilized to ascertain the impact of these factors on gas migration. By employing a typical shale gas reservoir profile from the Changning area as the case study, mathematical equations were formulated to describe the evolution of ancient pressures and gas contents under real geological conditions. These equations served as initial conditions for simulating the macroscopic dynamic evolution of the shale gas reservoir through fluid dynamics techniques. The findings indicate that the stratum dip angle dictates the normal stress on bedding planes and the gas pressure gradient along these planes. A larger dip angle corresponds to lesser compaction on the stratum surface, resulting in a steeper pressure gradient and improved gas migration efficiency. Gas predominantly migrates through channels with superior physical properties, and the larger the disparity between these channels and the surrounding rock, the more pronounced the influence on hydrocarbon migration. In the Changning anticline, shale gas migration is predominantly governed by strata uplift, which reduces vertical diffusion and encourages lateral migration from lower to higher regions within the reservoir. In Tiangongtang, on the other hand, early-phase normal fault activity during the last tectonic stage led to significant seepage losses. Although subsequent reverse faulting mitigated these losses, the overall gas content in the reservoir remains relatively low.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 6","pages":"Pages 373-385"},"PeriodicalIF":0.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143158156","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}

{"title":"Fractures development characteristics and distribution prediction of carbonate buried hills in Nanpu Sag, Bohai Bay Basin, China","authors":"Lei Gong ,&nbsp;Xinnan Qin ,&nbsp;Jun Lu ,&nbsp;Yang Gao ,&nbsp;Lingjian Meng ,&nbsp;Hongqi Yuan ,&nbsp;Qi Lu ,&nbsp;Xiaoxi Yin","doi":"10.1016/j.jnggs.2024.10.001","DOIUrl":"10.1016/j.jnggs.2024.10.001","url":null,"abstract":"<div><div>The natural fracture system plays a key role in the formation of hydrocarbon reservoirs in the carbonate buried hill of the Nanpu Sag in the Bohai Bay Basin, affecting the distribution of high-quality reservoirs and the migration and accumulation of hydrocarbons. Using data from outcrops, cores, thin sections, and image logs, a quantitative analysis was conducted on the development patterns of fractures both in vertical and horizontal directions, and the main controlling factors for fracture development were identified. On this basis, numerical simulation techniques were applied to quantitatively predict the development patterns of fractures in the carbonate reservoirs of the ancient buried hills in Nanpu Sag. Four types of fractures were identified in the study area: structural fractures, diagenetic fractures, weathering fractures, and dissolution fractures, with structural fractures being the most predominant. The fractures show a low degree of filling, with 59% being effective, indicating good fracture effectiveness. The linear density of structural fractures ranges from 3 to 10 m⁻¹, with an average of 5.6 m⁻¹. The height of structural fractures is generally less than 30 cm, mainly distributed between 5 and 20 cm. The microscopic fracture areal density ranges from 25 to 50 cm/cm², with an average of 32.3 cm/cm², and the porosity of micro-fractures ranges from 0.24% to 0.69%, averaging at 0.55%. These micro-fractures provide essential storage space in tight reservoirs and enhance pore connectivity, facilitating hydrocarbon migration and accumulation. Three primary fracture groups were identified in the study area: nearly E–W trending fractures, NE–SW trending fractures, and NW–SE trending fractures, with the first two groups being the most developed. The degree of fracture development in the study area is mainly affected by lithology, rock mechanical layers, and faults. Fractures are most abundant in dolomite and dolomitic limestone, but less developed in mudstone. Different rock mechanical interfaces affect the geometry, scale, and intensity of fracture development. Stratigraphy-bound fractures are generally vertical and terminate at rock mechanical interfaces, while throughgoing fractures usually span multiple mechanical layers and are controlled by more extensive mechanical interfaces. Faults are important factor in fracture heterogeneity, with fracture intensity being highest near fault cores, especially at fault tips, overlaps, intersections, and the hinges of fault-associated folds. The number of fractures decreases as the distance from the fault zone increases.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"9 6","pages":"Pages 417-430"},"PeriodicalIF":0.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143158159","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}

{"title":"Helium resources accumulation regulations and their development prospects in China","authors":"Jian Li ,&nbsp;Xiaobo Wang ,&nbsp;Zhusong Xu ,&nbsp;Huiying Cui ,&nbsp;Xiaomei Wang ,&nbsp;Bin Zhang ,&nbsp;Jianying Guo ,&nbsp;Shizhen Tao ,&nbsp;Jianfa Chen ,&nbsp;Zengye Xie ,&nbsp;Jixian Tian ,&nbsp;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}

{"title":"Diagenetic features recorded in sedimentary rocks within a gas chimney: A case study from the Makassar Strait, offshore Indonesia","authors":"Syahreza S. Angkasa ,&nbsp;Harya D. Nugraha ,&nbsp;Dian Yesy Fatimah ,&nbsp;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}

{"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 ,&nbsp;Shang Deng ,&nbsp;Jibiao Zhang ,&nbsp;Cheng Huang ,&nbsp;Huabiao Qiu ,&nbsp;Yingtao Li ,&nbsp;Yuqing Liu ,&nbsp;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}

{"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 ,&nbsp;Zhenyu Zhao ,&nbsp;Ai Yue ,&nbsp;Hua Jiang ,&nbsp;Xingwang Tian ,&nbsp;Qingchun Jiang ,&nbsp;Debo Ma ,&nbsp;Wei Song ,&nbsp;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 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.</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}

{"title":"Natural gas accumulation conditions and exploration directions of Carboniferous clastic rocks in the northeastern margin of Junggar Basin, China","authors":"Yanzhao Wei ,&nbsp;Abulimiti Yiming ,&nbsp;Weian Wu ,&nbsp;Aicheng Wu ,&nbsp;Fan Yang ,&nbsp;Chaowei Liu ,&nbsp;Zesheng Wang ,&nbsp;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}