Journal of Natural Gas Geoscience最新文献

{"title":"Reservoir characteristics and geological implications of marine sandstone on the periphery of Awati Sag, Tarim Basin, China: Case study of Upper Ordovician-Lower Silurian Kepingtage Formation","authors":"Ronghu Zhang ,&nbsp;Chaofeng Yu ,&nbsp;Zhao Yang ,&nbsp;Ran Xiong ,&nbsp;Fengqin Zhi","doi":"10.1016/j.jnggs.2024.12.001","DOIUrl":"10.1016/j.jnggs.2024.12.001","url":null,"abstract":"<div><div>The marine-origin source rocks on the periphery of the Awati Sag in the western Tarim Basin hold significant potential for hydrocarbon resources. However, the developmental level of marine sandstone reservoirs remains a key factor limiting the hydrocarbon exploration across the Keping thrust nappe belt along the western margin of the Awati Sag. This study focuses on the Upper Ordovician-Lower Silurian Kepingtage Formation sandstone through a multi-factor comprehensive approach, integrating data from outcrops, drilling, seismic surveys, and experimental analyses. Is the study clarifies that the Kepingtage Formation in the western margin of the Awati Sag is predominantly characterized by an early tide-dominated sedimentary system transitioning into late littoral deposition, resulting in tight sandstone reservoirs of sufficient thickness. The Kepingtage Formation sandstone is mainly composed of lithic sandstone, followed by lithic quartz sandstone. It exhibits low compositional maturity but high textural maturity, with well-developed intergranular pores and structural fractures. Porosity generally generally ranges from 6% to 10%. Class-IV reservoirs dominate, followed by Class-III and a few Class-II reservoirs. Reservoir quality is mainly controlled by sedimentary microfacies and structural compression. The reservoir rocks of sufficient scales of the delta and foreshore sandstone are more developed in the backward-breaking zone of the thrust nappe belt and the western margin slope of the Awati Sag. In contrast, the northwestern margin slope of the Awati Sag tends to develop fault-block oil and gas reservoirs as well as updip pinch-out sandstone oil and gas reservoirs. The favorable play spans an area of approximately 4320 km², with the predicted oil and gas resources of 78.17 × 10⁶ t and 707.6 × 10⁹ m³, respectively. The deep to ultra-deep low-structural-compression zone at the front of the Keping thrust nappe structure are identified as strategic favorable field of exploration for structural-lithological oil and gas reservoirs.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 1","pages":"Pages 1-11"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143529792","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":"The Early Jurassic sedimentary records characteristics and geological significance in the northern margin of the Qaidam Basin, NW China: A study of Well Lengke-1","authors":"Dingshu Cheng ,&nbsp;Fei Zhou ,&nbsp;Chen Cheng ,&nbsp;Zhengwen Jiang ,&nbsp;Yushan Shen","doi":"10.1016/j.jnggs.2025.01.001","DOIUrl":"10.1016/j.jnggs.2025.01.001","url":null,"abstract":"<div><div>The Qaidam Basin began to accumulate continental deposits during the Early Jurassic period, when it was located at a geographical position of 8.8 °N latitude. The paleoclimate was characterized by a warm and humid climate zone, conducive to the formation of lakes and marshes. This ancient continental lake deposit record provides a robust indication of key paleoenvironmental and paleoclimatic information. According to the descriptions of rock debris in the basic geological research and oil &amp; gas exploration, the drilling coring and electrical measurement data confirm that Well Lengke 1 is drilled through the Early Jurassic Huxishan Formation, and the location of Well Lengke 1 is the center of the lake basin, which can well reflect the Early Jurassic sedimentary characteristics and paleoenvironment restoration in Qaidam Basin. This study utilizes rock dating, thin section identification, biomarker compounds, and spore-pollen analysis to investigate the Early Jurassic sediments of the cold lake in the Qaidam Basin. The results confirm: (1) The sedimentary environment was identified as the origin of the sediments from 400 to 450 Ma and 250 to 300 Ma, and the development of algal bodies, algal wall keratinites, sporophytes and other organisms was found in thin section identification. (2) Biomarker analysis confirmed various compounds indicating that the second member of the Early Jurassic Huxishan Formation was rich in terrestrial higher plants, followed by aquatic lower organisms, freshwater lakes developed, and the depositional environment was partial oxidation; The first member of Huxishan Formation indicates low biological bacteria and algae (<em>n</em>C₁₄), terrigenous organic matter (<em>n</em>C₂₁-₂₉), and mixed organic matter. Gamma-cerane and paleosalinity analysis of sedimentary water suggest that black shale was formed in freshwater environment. (3) The palaeoclimate was humid, hot and rainy, the terrain was flat, the plants were flourishing along the marshes and shallow lakes, the plant group was flourishing gymnosperms, the sporogenous assemblage was Coniferae with cysts - piceites - spines, and the fern types were relatively simple. (4) The deep strata in this area have the characteristics of Paleozoic strata, and brachiopods, foraminifera, grid bryozoa, echinodermata and other marine fossils are found in the rock debris.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 1","pages":"Pages 27-39"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143529718","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 facies of the Fengcheng Formation tight reservoir in the alkaline lake sedimentary environment, the southern margin of Mahu Sag, Junggar Basin, China","authors":"Zongbin Zhang ,&nbsp;Jun Qin ,&nbsp;Zhongchen Ba ,&nbsp;Wenbiao Huang ,&nbsp;Mengyun Han ,&nbsp;Yuhui Gao ,&nbsp;Dong Wu","doi":"10.1016/j.jnggs.2025.01.003","DOIUrl":"10.1016/j.jnggs.2025.01.003","url":null,"abstract":"<div><div>With the aim of exploring the diagenetic characteristics, influence mechanisms, and distribution of dominant diagenetic facies in the Fengcheng Formation, at the southern margin of Mahu Sag in the Junggar Basin, this paper quantitatively characterized the reservoir transformation intensity of compaction, cementation, and dissolution on the basis of the analysis of petrological characteristics, pore types, diagenesis, and diagenetic environment evolution, and established a diagenetic facies division scheme. Based on single-well core interval evaluations, the diagenetic facies distribution was described, and the mechanisms influencing their distribution were explained. The results show that the reservoir space in the Fengcheng Formation is characterized by a dual medium of “matrix-pores dominated and micro-fractures supplemented”, with intra- and intergranular dissolved pores being predominant types in matrix pores. The Fengcheng Formation underwent an evolution through an alkaline sedimentary environment and an alkali-acid-alkaline diagenetic sequence. During the alkaline sedimentary and early alkaline diagenetic stages, significant intergranular pore loss occurred due to cementation, while volcanic material hydrolysis and plagioclase albitization facilitated the formation of solution pores. The reaming in the acidic diagenetic environment in the middle stage caused additional dissolution pore become the main reservoir space, and mitigating the densification to some extent. In the late alkaline diagenetic environment, the concentration of alkaline mineral ions increased, leading to precipitation in the remaining intergranular pores, solution pores, and other reservoir spaces, and the reservoir densification degree is further improved. In the study area, the cementation and dissolution of fan delta plain and front junction were weak, resulting in more compact phases developed, with an average porosity of about 4.9%. Moving from the inner front of the fan delta to the junction of the outer front, dissolution became more dominant than cementation, leading to development of cementation-dissolution phases, with an average porosity of about 6.6%. The dissolution phases near the central and southern faults prevailed, with an average porosity of 9%. The outer front of the fan delta is mostly associated with solution-cementation facies, resulting in an average porosity of the reservoir of about 3.1%. In general, alkaline diagenesis in the alkaline lake sedimentary setting has a dual effect on reservoir reconstruction. The cementation-dissolution and dissolution phases, under the control of acid/alkaline dissolution process, are favorable sites for tight oil accumulation in this area, and are also the key factors for the high productivity in this area.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 1","pages":"Pages 41-57"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143529719","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":"Experimental and molecular dynamics evaluation of the effect of a sulfate surfactant on the shale’s methane sorption","authors":"Hamid Sharifigaliuk ,&nbsp;Vahid Khosravi ,&nbsp;Mansoor Zoveidavianpoor ,&nbsp;Syed Mohammad Mahmood","doi":"10.1016/j.jnggs.2024.11.002","DOIUrl":"10.1016/j.jnggs.2024.11.002","url":null,"abstract":"<div><div>Shale gas has shown a great potential for exploration and development via advanced horizontal drilling and multistage hydraulic fracturing. Slickwater is a major type of fracking fluid, containing various chemical additives, water, and sand. In this matter, surfactant additives play a significant role in regulating the optimal performance of slickwater. The implication of the change in gas adsorption/desorption behavior of shale rocks and their individual minerals has rarely been experimentally investigated. In this study, the effect of a sulfate surfactant on methane adsorption capacity of a Marcellus shale was evaluated. Molecular dynamics simulation was also applied for gas adsorption assessment on major minerals in shales. Accordingly, the significant alteration of the adsorption energy of illite, quartz, and calcite minerals treated by a surfactant was investigated. Conclusively, the methane sorption capacity of the treated shale sample was reduced and correspondingly, the gas diffusion coefficient increased. Experimentally, the methane sorption analysis showed that the diffusion of the surfactant resulted in significant methane desorption. Besides, the major mineral constituents of shale behaved differently as unveiled by molecular simulation. The methane adsorption energy of calcite was reduced more significantly than quartz and illite when treated with surfactant. And, at the molecular level, the number of adsorbed methane molecules on illite reduced by half after a sulfate surfactant treatment.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 1","pages":"Pages 59-74"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143529720","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":"Geological characteristics of biogenic gas formation and direction of favorable zones in the Quaternary mudstone of the Qaidam Basin, China","authors":"Jixian Tian ,&nbsp;Zeyu Shao ,&nbsp;Jian Li ,&nbsp;Dekang Song ,&nbsp;Zhou Fei ,&nbsp;Ya'nan Li ,&nbsp;Wei Sha ,&nbsp;Hao Zhang ,&nbsp;Lili Hou ,&nbsp;Xiaoqiu Zhang ,&nbsp;Haining Zhang ,&nbsp;Yixuan Yang","doi":"10.1016/j.jnggs.2025.01.002","DOIUrl":"10.1016/j.jnggs.2025.01.002","url":null,"abstract":"<div><div>Quaternary biogas is the main natural gas resource in the Qaidam Basin, where sandstone reservoirs have traditionally been the primary producers. However, reserve growth in these reservoirs has become increasingly difficult in recent years. Mudstone gas, representing a new exploration field, has a low exploration level, and its formation, reservoir characteristics, and potential remain unknown. In this study, we utilize core data from the mudstone sections of two newly drilled wells in the study area as the object, and carry out a comprehensive study of the formation and reservoir characteristics of mudstone biogas through systematic experimental analysis, on the basis of which, favourable exploration areas for mudstone biogas are identified. The results of the study show that: (1) The Quaternary mudstone is mainly composed of dark grey mudstone in shallow and semi-deep lake, and influenced by the anoxic environment of brackish water and semi-brine water, exhibiting blocky, striped, and laminar structures. The mudstone layers frequently feature interbeds of sand and carbonate rocks. in which the mudstone is mainly concentrated in the Ⅲ, Ⅵ, and Ⅷ layer groups, characterized by large thickness and good continuity. (2) The low abundance of organic matter in the Quaternary mudstone, but a substantial proportion of organic matter suitable for microbial modification, and the large amount of different types of organic matter, such as hydrocarbons and algae, improve the biogas gas production capacity of the Quaternary system. (3) The Quaternary mudstone exhibits various pore types, including primary intergranular pores, dissolution pores, cracks, and a small number of organic pores. It is characterized by high porosity and permeability, although the pore radii of macropores, mesopores, and micropores are relatively small. (4) On-site analysis shows that mudstone layers are generally gas-bearing, with free gas being the main gas. Gas accumulation is prominent in brittle mineral developmental zones and tectonic high points within gas-bearing sections. (5) The loose Quaternary mudstone, with its high porosity and permeability, is controlled by various factors such as water content, overburden pressure, and mudstone thickness, and has the ability of self-containment and self-sealing properties. It is concluded that the Quaternary mudstone gas reservoir follows a formation model characterized by “integrated source and storage, brittle mineral content-controlled accumulation, mudstone thickness and pore sealing, and tectonic direction control”. Favorable areas for mudstone gas accumulation include the three major fields and the northern slope of the study area.</div></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":"10 1","pages":"Pages 13-25"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143529717","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":"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":"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":"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":"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}