Journal of Natural Gas Geoscience最新文献

{"title":"","authors":"","doi":"","DOIUrl":"","url":null,"abstract":"","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 4","pages":"Pages 219-238"},"PeriodicalIF":0.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146750107","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"","authors":"","doi":"","DOIUrl":"","url":null,"abstract":"","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 2","pages":"Pages 75-85"},"PeriodicalIF":0.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146380317","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"","authors":"","doi":"","DOIUrl":"","url":null,"abstract":"","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 5","pages":"Pages 343-359"},"PeriodicalIF":0.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147012113","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"","authors":"","doi":"","DOIUrl":"","url":null,"abstract":"","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 5","pages":"Pages i-ii"},"PeriodicalIF":0.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147012114","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"","authors":"","doi":"","DOIUrl":"","url":null,"abstract":"","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 6","pages":"Pages 383-397"},"PeriodicalIF":0.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147062160","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"","authors":"","doi":"","DOIUrl":"","url":null,"abstract":"","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 3","pages":"Pages 145-157"},"PeriodicalIF":0.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147182621","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"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}