Journal of Natural Gas Geoscience最新文献

{"title":"Characteristics and controlling factors of pore structure of shale in the 7th member of Yanchang Formation in Huachi area, Ordos Basin, China","authors":"Weikai Huang ,&nbsp;Xiaofeng Ma ,&nbsp;Xinping Zhou ,&nbsp;Jiangyan Liu ,&nbsp;Tongtong He ,&nbsp;Huifei Tao ,&nbsp;Shutong Li ,&nbsp;Lewei Hao","doi":"10.1016/j.jnggs.2023.09.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.09.001","url":null,"abstract":"<div><p>To clarify the influence of organic matter and mineral composition on the pore structure of shale reservoirs in the 7th member of the Yanchang Formation (Chang 7 Member) in the Ordos Basin, we characterized the pore structure of Chang 7 shale reservoirs using argon ion polishing-field emission scanning electron microscopy (FE-SEM) and low-pressure nitrogen adsorption (LP-N₂A). This characterization was combined with whole-rock mineral composition and organic geochemical experiments to analyze the main controlling factors of the pore structure of Chang 7 Member shale. The results reveal the presence of various pore types in shale, including organic matter pores, intergranular pores, intercrystalline pores, dissolved pores, and micro-cracks. The LP-N₂A isotherms of shale consistently exhibit type Ⅱ isotherms with H₃ and H₄ hysteresis loop characteristics, indicating the relatively developed nature of mesopores and a pore morphology characterized by parallel lamellar and “ink bottle” shapes. The primary determinants of shale pore structure are identified as organic matter, clay minerals, quartz, feldspar, and pyrite. Among these factors, clay mineral phase transformation generates a substantial number of micropores and mesopores within the mineral crystal layers, serving as the main source of shale pores in the study area. Additionally, liquid hydrocarbons generated, solid bitumen, and euhedral pyrite fill inorganic mineral pores, thereby reducing the pore space of Chang 7 shale to a certain extent. These results provide a new cognition into understanding the pore structure characteristics and controlling factors of Chang 7 shale.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49891258","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":"Effect of marine incursion on the formation of lacustrine source rocks: A case study of mudstones from the third member of the Shahejie Formation in the southwestern Bozhong Sag, Bohai Bay Basin, China","authors":"Qian Huang ,&nbsp;Yaohui Xu ,&nbsp;Feilong Wang ,&nbsp;Haifeng Yang ,&nbsp;Ning Wang ,&nbsp;Jiaohao He","doi":"10.1016/j.jnggs.2023.08.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.08.001","url":null,"abstract":"<div><p>Bozhong Sag, the largest hydrocarbon generation sag in the Bohai Bay Basin, is characterized by presence of the third member of the Shahejie Formation (E₂<em>s</em>³), which serves as a significant source rock. While previous studies have provided insights into the source material, sedimentary environment, and thermal maturity of the E₂<em>s</em>³ source rocks, further investigation is required to deepen our understanding of sedimentary events and biological sources. In this research, nine mudstone core samples from the southwestern Bozhong Sag were thoroughly analyzed using organic-inorganic geochemistry and organic petrology. The results reveal the following key findings: (1) The middle and lower sections of the third member of the Shahejie Formation are characterized by high-quality source rocks, with the lower section exhibiting superior quality. The increase in water salinity during warm and humid climates, and the detection of 24-n-propylcholestane compounds reflected the occurrence of transgression events in the E₂<em>s</em>³. These transgressions gradually increased from the lower sections to the middle sections of the E₂<em>s</em>³. (2) The studied samples exhibit abundant presence of 4α-methyl-24-ethylcholestanes, 24-n-propylcholestanes, 2α-methylhopanes, oleananeabundant algainite, and a small amount of vitrinite. This diversity of hydrocarbon-forming organisms in the E₂<em>s</em>³ source rocks is evident. (3) The moderate marine incursion in the lower part of the E₂<em>s</em>³ results in nutrient elements that promote the flourishing of bacteria and algae, providing an abundant material basis for the formation of high-quality source rocks. However, the large-scale marine incursion in the middle of the E₂<em>s</em>³ weakens water eutrophication, resulting in a decrease in the quality of source rocks compared to the lower part of the E₂<em>s</em>³.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50193325","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":"Evaluating the lacustrine Shahejie Formation source rock potential in the Bohai Bay Basin using a simplified regional basin model","authors":"Jonathan C. Evenick","doi":"10.1016/j.jnggs.2023.07.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.07.001","url":null,"abstract":"<div><p>Often petroleum system modelers tend to build complex and time-consuming basin models to understand detailed aspects of hydrocarbon generation and migration within a sedimentary basin. This study built a simple basin model focused on the middle part of the organic-rich, Eocene-Oligocene Shahejie Formation which is the predominant lacustrine source rock in the Bohai Bay Basin. This map-based basin model was created using published regional cross sections, subsurface maps, geochemical data, geothermal gradient data, and structural elements. The integration of these datasets allowed for basin-wide, average TOC and thermal maturity maps to be modeled much more quickly than a geocellular model. These maps show that the majority of the known hydrocarbon fields are found above the Shahejie source rock kitchens. Some fields, however, are found slightly outside of the source rock kitchens indicating either contribution from deeper known source rocks intervals (e.g., the Kongdian Formation) or lateral migration from the middle Shahejie Formation.</p><p>The Bohai Bay Basin is a structurally complex rift basin with several strike-slip fault systems being present in the basin with the Tanlu fault system being the most prominent. Using potential field data, published cross sections, isopach maps, hydrocarbon fields, and the presence of Eocene evaporites, structural elements (lineaments) were interpreted. These structural elements influence depositional trends at various stratigraphic levels and the regional thermal maturity trends. Many of these structural elements likely represent thick-skinned faults and subtly influence the TOC trends within the Eocene. Within the middle Shahejie Formation, the average TOC is higher within the depocenters, which may show that lacustrine source rocks are driven more by accommodation space because of the inherent restricted nature associated with lacustrine depositional environments.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50193852","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":"Paleogeomorphology and shale distribution of Late Ordovician-Early Silurian Yangtze platform, South China: Implication for shale mineralogy and TOC content","authors":"Zhensheng Shi ,&nbsp;Yuan Yuan ,&nbsp;Qun Zhao ,&nbsp;Shasha Sun ,&nbsp;Tianqi Zhou ,&nbsp;Feng Cheng","doi":"10.1016/j.jnggs.2023.06.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.06.001","url":null,"abstract":"<div><p>The distribution and mineral composition of the Wufeng-Longmaxi shale on the Yangtze platform are directly influenced by the geomorphology of the Late Ordovician-Early Silurian period. This research aimed to clarify the geomorphology of the Yangtze platform during this time period and its implication on the Wufeng-Longmaxi shale. Geophysical interpretation, chronostratigraphic division, and correlation, isometric map compilation, and mineral composition analysis were utilized to achieve this objective. The results of the study showed the following findings: (1) The Wufeng-Longmaxi shale was deposited on the southeastern slope of the Leshan-Longnüsi paleo-uplift on the Yangtze platform; (2) The southeastern slope exhibited three significant slope breaks, which allowed for the division of the slope into four geomorphology units: subaqueous high, subaqueous slope, subaqueous plain, and subaqueous sag; (3) The overlying Wufeng–Longmaxi shale was fully developed in the subaqueous plain and subaqueous sag, but lacked graptolite zones LM1-4 in the subaqueous high and subaqueous slope, with the shale onlapping the southeastern slope from southeast to northwest; (4) The southeastern slope significantly affects the grain size, mineral composition, and TOC content of the overlying shale. Specifically, as the slope transitioned from the subaqueous high to the subaqueous sag, the grain size becomes finer, the contents of TOC and silica increased, and the contents of carbonate and clay minerals decreased.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50193327","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":"Pore structure characteristics and impact factors of laminated shale oil reservoir in Chang 73 sub-member of Ordos Basin, China","authors":"Qiliang Mei ,&nbsp;Ruiliang Guo ,&nbsp;Xinping Zhou ,&nbsp;Guofeng Cheng ,&nbsp;Shixiang Li ,&nbsp;Yubin Bai ,&nbsp;Jiangyan Liu ,&nbsp;Weitao Wu ,&nbsp;Jingzhou Zhao","doi":"10.1016/j.jnggs.2023.07.003","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.07.003","url":null,"abstract":"<div><p>This research paper focuses on the laminated shale oil reservoir in the third sub-member of the seventh member of Yanchang Formation (Chang 7₃ sub-member) in the Ordos Basin. The study aims to comprehensively analyze the lithofacies type, micro qualitative and quantitative pore structure parameters, and the main controlling factors of the pore structure in laminated shale. The analysis involves various techniques, including a comprehensive analysis of TOC, rock-eval, X-ray diffraction, polarized light and fluorescence microscope observation, field emission scanning electron microscope observation, and low-pressure N₂ adsorption analysis. Based on the sedimentation characteristics, geochemistry, and mineral composition differences, the Chang 7₃ laminated shale can be classified into three lithofacies types: tuffaceous-organic matter binary laminated shale, clayey-organic matter binary laminated shale, and felsic-clayey binary laminated shale. The pore network consists primarily of organic hydrocarbon generation pressurization fractures, clay mineral felsic intergranular composite pores, and felsic plasmid intergranular pore fracture systems. Mesopores are the most developed pore type. The pore volume and specific surface area increase in the order of “tuffaceous-organic matter”, “clayey-organic matter”, and “felsic-clay”, while the heterogeneity of the pore network gradually weakens, and the roughness of the pore surface enhances. The overall development of organic matter pores is limited, with organic matter-pyrite-clay mineral composite pores being the main components of micropores. The primary intergranular pore system, associated with rigid quartz particles, dominates the mesopores and macropores, and acts as the main framework of the entire pore network. The development of feldspar dissolution pores is limited and contributes minimally to the pore network.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50193326","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":"Main reservoir controlling factors and diagenetic evolution of the Xiao'erbulak Formation of Tarim Basin, NW China: A case study of Well KPN1 in Kalpin area","authors":"Lihong Liu ,&nbsp;Miao Han ,&nbsp;Yongjin Gao ,&nbsp;Yuanyin Zhang ,&nbsp;Chengxin Liu ,&nbsp;Ye Duan ,&nbsp;Youxing Yang ,&nbsp;Kunpeng Jiang","doi":"10.1016/j.jnggs.2023.07.002","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.07.002","url":null,"abstract":"<div><p>The Cambrian subsalt dolomite in the Kalpin area of the Tarim Basin is an important reserve growth point and strategic replacement area. However, there is a lack of clear understanding regarding the formation mechanism of high-quality reservoirs in this region, which has hindered oil and gas exploration. This study aims to address this knowledge gap by providing a comprehensive description of the rock types and characteristics of the Xiao'erbulak Formation. Microscope observations, geochemical analyses, and interpretations of well logging data from Well KPN1 were used in this analysis. The Xiao'erbulak Formation can be divided into four members, arranged from bottom to top. The relatively high manganese (Mn) content (87–137.7 ppm), oxygen isotope composition (δ¹⁸O) with an average value of −6.37‰, and strontium isotope ratio (⁸⁷Sr/⁸⁶Sr) with an average value of 0.7109 indicate that dolomitization of the Xiao'erbulak Formation likely occurred during the penecontemporaneous-shallow burial period. The early formation of dolomite contributed to increased reservoir porosity and resistance to compaction during deep burial, which laid the foundation for reservoir formation. The carbon isotope composition (δ¹³C) of the Xiao 1 and Xiao 2 members exhibit frequent zigzag curves, indicating recurring progression/regression processes. The subsequent development of granular beach facies played a crucial role in reservoir formation in the Xiao 2 Member. Tectonic fractures and penecontemporaneous karstification controlled the reservoir characteristics of the Xiao 3 Member. Furthermore, this study provides an analysis of the diagenetic evolution model of Well KPN1 and examines the impact of diagenetic transformations on reservoir quality. The systematic analysis of downhole data from Well KPN1 serves as a foundational reference for comparative studies with other drilling sites in the area. It also offers valuable guidance for future exploration and deployment strategies in the northwest Tarim Basin.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50193851","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":"Enrichment characteristics of deep shale gas in tectonically complex regions of the southeastern sichuan basin, China","authors":"Kaiming Wang","doi":"10.1016/j.jnggs.2023.04.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.04.001","url":null,"abstract":"<div><p>In recent years, breakthroughs have been made in deep shale gas exploration in the Wufeng-Longmaxi formations in the complex tectonic region of the Sichuan Basin and southeastern margin, indicating promising prospects for exploration and development. This study focuses on the Nanchuan area of the complex tectonic region of the southeastern Sichuan Basin margin, using data from drilling wells and experimental analysis tests to investigate deep shale gas enrichment characteristics, particularly the effects of changes in the formation environment such as formation temperature and pressure on deep shale gas enrichment. The study concludes that: (1) The dominant sedimentary phase zone is the basis for hydrocarbon formation in shale gas reservoirs, with the Wufeng Formation–the first member of Longmaxi Formation in the study area—formed in a deep-water shelf sedimentary environment with high-quality shale development, which provides favorable material conditions for the formation of shale gas reservoirs. (2) Organic carbon content controls the degree of development of nanoscale organic matter pores, and the high-pressure-ultra-high-pressure environment helps maintain pores and improve the physical properties of deep shale. (3) Deep shale gas exhibits typical geological characteristics of high temperature, high ground stress, and exceptionally low permeability. The study finds the influence of temperature on the adsorption capacity of shale is more significant than that of pressure, and deep shale gas is primarily free gas. High pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (4) Gas diffusion is complex, with high temperature increasing the diffusion of gas, aggravating the migration and escape of gas, while high pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (5) The burial depth and pressure coefficient show a positive correlation, and the burial depth has a more significant effect on the pressure coefficient of syncline shale gas, indicating that preservation conditions of deep syncline shale gas reservoirs are becoming better. Residual syncline core with larger depths, inner-sag uplift, and slopes with reverse faults can be favorable targets for shale gas exploration in complex tectonic zones.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49871426","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":"Reservoir characteristics of marine–continental transitional shale and gas-bearing mechanism:Understanding based on comparison with marine shale reservoir","authors":"Taotao Cao ,&nbsp;Mo Deng ,&nbsp;Juanyi Xiao ,&nbsp;Hu Liu ,&nbsp;Anyang Pan ,&nbsp;Qinggu Cao","doi":"10.1016/j.jnggs.2023.03.004","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.03.004","url":null,"abstract":"<div><p>Transitional shale gas layers are widely distributed in China, but no significant exploration breakthrough has been made so far. This paper investigates and analyzes the characteristics and gas-bearing mechanisms of transitional shale gas reservoirs in detail, aiming to clarify the shale gas accumulation mechanism of transitional shale and provide theoretical support for the selection of favorable intervals. The transitional shale gas layer is characterized by a thin single-layer thickness, rapid lithological change, low brittle mineral content, and poor kerogen type. The lack of organic matter (OM) sponge pore development process from the oil-generation stage results in limited numbers of OM nanometer-scale pores. Shale pore space is dominated by pores and fractures related to clay minerals. The measured gas content is well consistent with the theoretically calculated gas content for marine organic-rich shales. However, the actual measured gas content is far lower than the theoretically calculated gas content for the transitional shale gas reservoir. The main mechanisms are summarized to be (1) the high hydrocarbon expulsion efficiency of the “sandwich” space structure of the sandstone–shale–coal association, which gives rise to most natural gas migrating into nearby sandstone, and (2) high water saturation resulting in insufficient storage space for free gas in the shale reservoir. Unlike marine shale gas, natural gas in the transitional shale reservoir is primarily dominated by adsorbed gas in kerogen, and free gas is relatively low. The favorable lithofacies types are organic-rich siliceous/calcareous shales. Multiple layers of siderite-bearing shales/siderites are developed vertically and continuously distributed horizontally in transitional strata, particularly in flat-lagoon facies. It is easy to form a “micro-trap” to store gas in siderite-bearing shale, and siderite-bearing shale has strong sealing properties due to low porosity, low permeability and high breakthrough pressure. This property can form overpressure and trap shale gas inside the shale, providing a new research perspective for the optimization of vertical favorable intervals, as well as exploration breakthrough in transitional shale gas. Further research should strengthen the systematic sedimentological study of transitional facies, reveal shale gas occurrence state and dynamic transformation, and optimize favorable interval evaluation systems to clarify the feasibility of coal-measure gas commingled production.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49871427","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":"An integrated study on the reservoir potential of upper Cretaceous succession of the Anambra Basin (Nigeria) using the seismic-structural, petrophysical, and sedimentological approach","authors":"Oladotun Oluwajana ,&nbsp;Olubusayo Olatunji ,&nbsp;Olutayo Lawal ,&nbsp;Yinka Olayinka ,&nbsp;Olugbenga Ehinola","doi":"10.1016/j.jnggs.2023.04.002","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.04.002","url":null,"abstract":"<div><p>The Anambra Basin has a relatively high hydrocarbon production base compared with other Cretaceous basins in Nigeria. Structural deformation, overpressures, and faulting in the Cretaceous sequence of the Anambra Basin have resulted in significant uncertainties regarding reservoir parameters, necessitating accurate reservoir characterization. This study uses several subsurface data, including 2D seismic data, a report of core descriptions, and well log data from an exploration well drilled in the Anambra Basin to identify reservoirs and assess the petrophysical parameters of Cretaceous Formations for hydrocarbon accumulations. Three reservoirs were identified in the interpreted seismic section of the Cretaceous strata, and the structural framework was described as a system of synthetic faults dipping north-south that controlled the thickness and lateral extension of the deposited sediments. The shale volume, total and effective porosity, permeability, water, and hydrocarbon saturation were estimated using standard equations. The low shale volume, good-to-very good porosity values, fair-to-moderate permeability values, and low-to-moderate hydrocarbon saturation of the identified Cretaceous reservoirs suggest that the reservoir sands have the capacity to produce hydrocarbons. The density-neutron cross-plots of the identified reservoirs show a dual mineral system and also indicate the effect of gas in the Cretaceous reservoirs. This study found that the Anambra Basin has gas potential. However, the identified gas reservoirs should be further evaluated using reservoir pressure data, if available, to aid in accurate hydrocarbon fluid typing. The reservoirs should be developed and optimized in such a way as to keep production risk to its minimum.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49870705","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":"Development characteristics and genesis of deep tight conglomerate reservoirs of Mahu area in Junggar Basin, China","authors":"Jing Sun,&nbsp;Xincai You,&nbsp;Quan Zhang,&nbsp;Jingjing Xue,&nbsp;Qiusheng Chang","doi":"10.1016/j.jnggs.2023.05.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.05.001","url":null,"abstract":"<div><p>To clarify the development rules and main origins of deep tight conglomerate reservoirs in the Mahu area of Junggar Basin, various materials and data from deep wells were systematically researched to determine the reservoir's basic characteristics and effective origins. The results indicate that the reservoir mainly comprises a fine and medium-fine conglomerate, which belongs to the fan delta distributary channel conglomerate. Additionally, it is a typical deep tight conglomerate reservoir with low to ultra-low porosity and permeability, and the gravel primarily consists of volcanic rock composed of tuff and intermediate acid volcanic lava. The cement is mainly composed of laumontite and calcite, and the reservoir has undergone three types of diagenesis: compaction, cementation, and dissolution. The first two types have dual effects of destruction and construction, while the result of dissolution is the widespread development of secondary pore enrichment zones composed of intergranular solution pores formed by the dissolution of zeolite, carbonate cement, and argillaceous matrix, as well as intragranular solution pores formed by the dissolution of feldspar and dark minerals. Unlike the middle and shallow layers, the reservoir space mainly composed of secondary pores and fractures. The effective reservoir is mainly caused by rock composition, dissolution, fracture system, and abnormal high pressure. The rock composition provides a sufficient material basis and is the internal cause, while the dissolution, fracture system, and abnormal high pressure are the external causes. The dissolution forms a secondary pore enrichment zone, the fracture system improves the seepage capacity of the reservoir, and abnormal high pressure can effectively maintain and increase the pores. Four factors control the formation and distribution of relatively high-quality deep tight conglomerate reservoirs.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49870706","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}