Journal of Natural Gas Geoscience最新文献

{"title":"Effects of temperature on seepage capacity for a multi-type ultra-deep carbonate gas reservoir","authors":"Yuxiang Zhang ,&nbsp;Haijun Yan ,&nbsp;Shenglai Yang ,&nbsp;Hui Deng ,&nbsp;Xian Peng ,&nbsp;Zhangxing Chen","doi":"10.1016/j.jnggs.2023.03.003","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.03.003","url":null,"abstract":"<div><p>Ultra-deep carbonate gas reservoirs are buried at great depths and have high temperatures, and the impact of high temperature on the seepage capacity of multi-type reservoirs is still unclear. The study selected cores from the fourth member of Dengying Formation in the Gaoshiti-Moxi area to measure the gas single-phase permeability of rock samples during the heating and cooling process, as well as the gas-water interfacial tension and gas-water two-phase relative permeability at different temperatures. This allowed researchers to obtain the effect of temperature on the seepage capacity of multi-type ultra-deep carbonate gas reservoir. The research results show that within the range of 20–120 °C, with the change of temperature, the gas single-phase seepage capacity of different types of reservoir rock samples changes as a power function. The decrease in gas-phase permeability during the heating process is jointly affected by the increase in gas viscosity, the expansion of dolomite crystals, and the migration of rock particles after embrittlement. After one heating and cooling process, fractured-cavity type rock samples had the highest irreversible degree of permeability at 82.52%, due to the development of micro-fractures, followed by 27.63% for pore type due to the development of small pores and throats, and the lowest was 9.46% for pore-cavity type. Fractured-cavity rock samples are temperature-sensitive, while pore-type and pore-cavity-type rock samples are temperature-resistant. The upper-temperature limit of the target multi-type gas reservoir is concentrated around 46–50 °C. The temperature increase mainly improves the gas-displacing water efficiency and gas-water two-phase seepage capacity by reducing the water-gas viscosity ratio, which is about 1/3 of the normal temperature at the formation temperature. The gas-water phase permeability curves of multi-type reservoirs under high-temperature conditions can better represent the two-phase seepage characteristics of actual formations. The effect of temperature on the seepage capacity of multi-type ultra-deep carbonate gas reservoirs can provide a theoretical basis for the efficient development of such gas reservoirs.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49865701","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":"Geochemical characteristics of source rocks and gas exploration direction in Shawan Sag, Junggar Basin, China","authors":"Yong Li ,&nbsp;Jungang Lu ,&nbsp;Xiangjun Liu ,&nbsp;Jian Wang ,&nbsp;Shijia Chen ,&nbsp;Qingbo He","doi":"10.1016/j.jnggs.2023.02.003","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.02.003","url":null,"abstract":"<div><p>In recent years, significant advancements have been achieved in the exploration of natural gas around Shawan Sag in the Junggar Basin. However, the geochemical characteristics and distribution of source rocks in the center of the sag have yet to be thoroughly researched, and there is a lack of understanding regarding the evolution history of hydrocarbon generation and the characteristics of each set of source rocks. This has posed limitations on future exploration and development initiatives in the area. The study focused on source rock samples from the uplift zone and conducted a comprehensive evaluation through seismic and hydrocarbon generation thermal simulation experiments. This allowed for clarification of the product characteristics of source rocks in different strata and pointing out the direction for future natural gas exploration. The results showed the presence of four sets of well-developed source rocks in Shawan Sag, characterized by their extensive thickness, wide distribution, and deep burial, laying a material foundation for oil and gas accumulation in peripheral structures. The Carboniferous and Jiamuhe Formation source rocks have high organic matter abundance, but the quality is poor and the potential for generating hydrocarbons is low, leading mainly to the generation of dry gas. On the other hand, the Fengcheng Formation and Lower Wuerhe Formation source rocks have high organic matter abundance and good quality, and are highly mature, resulting in high potential for generating hydrocarbons. The δ¹³C₁-<em>R</em>_O regression equation of natural gas in Shawan Sag was established, and the carbon isotope distribution patterns of ethane generated from source rocks in different layers were identified, providing a foundation for determining the maturity of natural gas and correlating the sources of gas in surrounding structures. The west slope of Shawan Sag has favorable preservation conditions and is located on a hydrocarbon migration pathway, similar to the slope of Mahu Sag. This area also has favorable geological conditions for the formation of large lithologic reservoirs, making it a key field for gas exploration in the study area moving forward.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49865724","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":"Geochemical investigation of oil seepages and Paleozoic sediments for determining probable source rock in the Bandar Abbas Hinterland","authors":"Rameh Farokhvand ,&nbsp;Mohammad Hossein Saberi ,&nbsp;Bahman ZareNezhad","doi":"10.1016/j.jnggs.2023.02.004","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.02.004","url":null,"abstract":"<div><p>A remarkable characteristic of the Bandar Abbas Hinterland is the frequent presence of oil seepages that can serve as an indicator of probable oilfields in the region. The Seeps A and B are located in the main Zagros Suture Zone, 150 km to the northeast of Bandar Abbas and 30 km to the west of the same city, respectively. The presence of well-known Paleozoic source rocks (<em>e.g.</em>, Seyahou, Sarchahan, and Gurpi formations) in the vicinity of the mentioned oil seepages shows that the seeping oil is coming from an oil source. The present research is aimed investigating the petroleum system and determining the source of the mentioned oil seepages. Results of the Rock-Eval analyses showed that the samples of the Seyahou Formation are thermally overmatured, making them exhibit inadequate oil generation potential. These samples contain Type-III kerogen and were found to be in the metagenesis stage. However, compared to other formations, Sarchahan and Gurpi exhibited good hydrocarbon generation potentials. On the other hand, based on the PI – T_max diagram, the Sarchahan Formation was found to be in the early oil and condensate production window (i.e., catagenesis stage) while the Gurpi Formation was seen to be immature. Biomarker analysis results showed that the samples were deposited in a mixed marine environment and contained Type-II and Type II/III kerogen. The reason behind the occurrence of the oil seepages in an oxidative environment could be the sever impact of the biological degradation. The stable carbon isotope composition of the crude samples supported the biomarker data in general. Therefore, it can be concluded that the studied oil seepages were probably sourced from the Sarchahan Formation.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49865699","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":"Dynamic evaluation method of water-sealed gas for ultra-deep buried fractured tight gas reservoir in Kuqa Depression, Tarim Basin, China","authors":"Zhikai Lü ,&nbsp;Haifa Tang ,&nbsp;Qunming Liu ,&nbsp;Yongliang Tang ,&nbsp;Qifeng Wang ,&nbsp;Baohua Chang ,&nbsp;Yanbo Nie","doi":"10.1016/j.jnggs.2023.03.002","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.03.002","url":null,"abstract":"<div><p>The ultra-deep-buried fractured tight gas reservoir in the Kuqa Depression of the Tarim Basin has developed edge and bottom water. Faults and fractures have become “highways” for water invasion, resulting in the “water sealed gas” effect and reducing gas reservoir recovery. At present, there is a lack of effective evaluation methods. Therefore, based on an analysis of water invasion characteristics of the gas reservoir, a dynamic evaluation method for water-sealed gas in a fractured gas reservoir is established. This method considers two factors: fracture development scale and peripheral water body strength. It is then applied to three developed blocks in the Kuqa ultra-deep layer. The effectiveness of the evaluation results is verified by static and dynamic combination, and countermeasures to improve gas reservoir recovery are proposed. The results indicate that: (1) The non-uniform water invasion of fractures is jointly controlled by structural position, fracture development degree, and fracture network combination, which can be divided into three modes: edge water channeling along the large fracture in the core, edge and bottom water invading along the fracture in the wing, and rapid, violent water flooding of the bottom water along the fracture/small fault in the low part. (2) The replacement coefficient of water invasion in the three typical blocks is 0.2–0.3, indicating that they are sub active water-gas reservoirs. However, the severity of water-sealed gas varies greatly. The more severe the water-sealed gas is, the lower the recovery factor of the gas reservoir. (3) For directionally penetrating large fracture gas reservoirs, water shutoff should be carried out. For fracture network gas reservoirs with high fracture density, mild exploitation can control water, and early drainage can reduce the impact of water invasion, improving gas reservoir recovery. It is concluded that the new method of water-sealed gas dynamic evaluation can provide a reliable basis for evaluating fracture non-uniform water invasion dynamics of the ultra-deep gas reservoir and enhancing oil recovery of the gas reservoir in the Kuqa Depression. This method also supports the formulation of water control policies and the economic and efficient development of ultra-deep gas reservoirs in the Kuqa Depression.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49865700","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":"Detection and potential geochemical significance of methyltrimethyltridecylchromans in mature crude oils","authors":"Youjun Tang ,&nbsp;Yurong Jing ,&nbsp;Tianwu Xu ,&nbsp;Chengfu Zhang ,&nbsp;Lishuang Lü ,&nbsp;Xiaoyong Yang ,&nbsp;Bingbing Pei","doi":"10.1016/j.jnggs.2023.03.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.03.001","url":null,"abstract":"<div><p>Methyltrimethyltridecylchromans (MTTCs) are biomarkers that are commonly used to identify immature-low mature source rocks or crude oil. MTTCs are abundant in the mature crude oils found in the Machang area of the southern Dongpu Depression in the Bohai Bay Basin. To explore the mechanism behind the enrichment of MTTCs in mature crude oils, a detailed study was conducted to investigate their distribution characteristics in crude oil samples. The study integrated tectonic evolution history, distribution characteristics, and thermal history of source rocks, molecular fingerprints characteristics of crude oils, and catalytic characteristics and combination features of clay minerals in the wall rock of crude oils. Based on this analysis, two enrichment models were proposed: (1) The first model suggests that crude oils were mixed with a small amount of immature-low mature soluble bitumen containing MTTCs; (2) The second model proposes that the evolutionary mechanism of clay minerals in the reservoir could reduce the decomposition rate and degree of MTTCs, resulting in their relative enrichment. Therefore, this study provides insights into the enrichment mechanism of MTTCs in mature crude oils and highlights the importance of considering various factors, such as tectonic evolution history, source rock characteristics, and catalytic properties of clay minerals, to understand the distribution and enrichment of biomarkers in crude oils.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49865698","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 controlling factors and genetic mechanism for the development of high-quality reservoirs in the mound-shoal complexes on the platform margin of the intra-cratonic rift: A case study of the fourth member of the Dengying Formation in the eastern limb of Deyang-Anyue intra-cratonic rift, Sichuan Basin, China","authors":"Wei Yang ,&nbsp;Guoqi Wei ,&nbsp;Wuren Xie ,&nbsp;Nan Su ,&nbsp;Fuying Zen ,&nbsp;Cuiguo Hao ,&nbsp;Zhuangzhuang Bai ,&nbsp;Rong Li ,&nbsp;Xueqiong Wu ,&nbsp;Yiqing Su","doi":"10.1016/j.jnggs.2023.02.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.02.001","url":null,"abstract":"<div><p>Reservoirs of large platform margin mound-shoal complexes of the fourth member of Dengying Formation (Deng 4 Member) are developed in the margin of the Deyang-Anyue intra-cratonic rift in the Sichuan Basin and it is the main pay horizon of the Anyue gas field. A clear understanding of the reservoir genetic mechanism of the mound-shoal complexes is the key to predicting the distribution of high-quality reservoirs and guiding the deployment of exploration. Based on the data of drilling, seismic, outcrop, and analytical data, this paper analyzes the reservoir characteristics and genetic mechanism of the mound-shoal complexes at the margin of the Deng 4 Member and obtains three new understandings: (1) Platform margin mound-shoal reservoirs are developed on the margin of Deyang-Anyue intra-cratonic rift in Sichuan Basin. The mound-shoal complexes are mainly composed of algal mounds and bioclastic shoals in multiple stages. The reservoir space is mainly dissolution pores, caverns, and fractures, with low porosity and low permeability in general. (2) The reservoir can be divided into three types, i.e., the fracture-dissolution pore type, the dissolution pore type, and the matrix pore type, and the reservoirs of fracture-dissolution pore type are high-quality reservoirs; the development of reservoirs is mainly controlled by the platform margin mound-shoal complexes, the penecontemporaneous interstratal karst, and two-stage weathering crust karstification as well as multi-stage disruptive actions; the upper part of the reservoir in the same stage is good, and the reservoir at the top of Deng 4 Member is good. (3) Before the Himalayan movement, the reservoir forming and the environments of the two platform margin mound-shoal complexes were the same, and the characteristics of the formation of the reservoir were similar. The Himalayan movement led to a great difference in the current buried depth of the reservoir, resulting in a host of fractures and retaining a host of dissolution pores and caverns. The whole platform margin mound-shoal complexes have large-scale reservoirs developed and have a good exploration prospect. The results enrich the theory of ancient and deep carbonate reservoir forming and its genetic mechanism and provide the geological basis for the deployment of exploration.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49904854","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":"Hydrocarbon generation and potential of marine source rocks in supercritical water","authors":"Yanhong Liu ,&nbsp;Junli Qiu ,&nbsp;Yanqing Xia ,&nbsp;Xilong Zhang ,&nbsp;Wenqiang Gao ,&nbsp;Xiangxian Ma ,&nbsp;Wang Xu ,&nbsp;Yingqin Wu","doi":"10.1016/j.jnggs.2022.12.003","DOIUrl":"https://doi.org/10.1016/j.jnggs.2022.12.003","url":null,"abstract":"<div><p>Water, in ultra-deep layers of the earth and in layers receiving abnormally high heat, can exist in a supercritical state. Supercritical water (SCW) can participate in the transformations of organic compounds not only as a solvent but also as a reactant, influencing petroleum formation and the evolution of sedimentary organic matter. Here, we carried out hydrous pyrolysis experiments in both SCW and water vapor (WV) using two organic-rich marine rocks under closed conditions, to quantitatively evaluate the generation potential of hydrocarbons in a supercritical state and to clarify the effect of water phase on hydrous pyrolysis experiments. The results showed that SCW promoted gaseous and liquid hydrocarbon generation and facilitated the cracking of aliphatic hydrocarbons. For gaseous hydrocarbons, the action of SCW became stronger as the temperature increased. For liquid hydrocarbons, the peak yields of bitumen were enhanced by the SCW, and the temperature corresponding to peak yield in SCW was lower than that in WV. These results were attributed to the supply of hydrogen and oxygen from SCW for the petroleum formation and cracking. The δ¹³C and δD values of gases were also influenced by SCW. However, these values obtained in SCW did not always become positive as their yields increased. Generally, methane (CH₄) was enriched in ¹²C and ¹H. The influence of SCW on the isotopic fractionation of ethane (C₂H₆) and propane (C₃H₈) was more complex. The water phase is an important factor affecting the experimental results of hydrous pyrolysis. From these findings, it can be concluded that SCW allowed for increased conversion of sedimentary organic matter to gaseous and liquid hydrocarbons in ultra-deep layers and layers affected by volcanic-hydrothermal activity.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49904850","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":"Formation conditions and the main controlling factors for the enrichment of shale gas of Shanxi Formation in the southeast of Ordos Basin, China","authors":"Ke Wang ,&nbsp;Yuanyuan Wang ,&nbsp;Fengqin Wang ,&nbsp;Licheng Xie","doi":"10.1016/j.jnggs.2023.02.002","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.02.002","url":null,"abstract":"<div><p>Based on the dissection of the geological characteristics of typical shale gas wells, the relationship between reservoir-forming factors and shale gas enrichment is deeply analyzed, and the controlling factors of shale gas enrichment are summarized. An analysis of data from drilling, logging, testing, and shale sample has revealed that the factors contributing to the formation of shale gas reservoirs in marine–continental transitional facies of Shanxi Formation in the southeast of Ordos Basin are highly heterogeneous. This is mainly reflected in the rapid spatial change of shale organic matter, physical properties, and other parameters of the shale in this area. The shale found in the Shanxi Formation has a high content of organic carbon (TOC), with an average of 2.24%. The kerogen type is mainly type Ⅲ, and the average value of <em>R</em>_O is 2.48%, indicating that it is in the high mature-overmature stage and is a high-quality source rock. The rock composition is rich in clay (40.5%–88.5%), mainly composed of illite-mongolian mixed layer and kaolinite, and its relatively high specific surface area is beneficial for improving the gas adsorption capacity of the shale. Thin sandstone interbeds, measuring less than 3 m are widely distributed in the Shanxi Formation and have good physical conditions. With an average porosity 3.37% and an average permeability of 0.1 mD. The natural gas generated by the shale can be transported to these sandstone interlayers (laminae) in a short distance, which is beneficial for improving the gas-bearing property of the shale. The gas-bearing property of the Shanxi Formation in the study area is affected by different lithologic assemblages. The gas-bearing property of the thick mudstone-coal assemblage of the second member of the Shanxi Formation is the best, with more than 80% of the samples having a gas content of over 1 m³/t. This study suggests that the high thermal evolution degree of shale, special marine–continental transitional facies reservoir conditions, and good preservation conditions are the main factors affecting the enrichment of shale gas in the study area. This makes the shale gas of the Shanxi Formation in the southeast of the Ordos Basin have certain potential for exploration and development, and delineates the enrichment targets of shale gas in the Zichang-Yan'an-Fuxian and Yichuan areas.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49904858","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":"Molecular dynamics and energy distribution of methane gas adsorption in shales","authors":"Abdullah Musa Ali,&nbsp;Mohammed Yerima Kwaya,&nbsp;Abubakar Mijinyawa,&nbsp;Ahmed Alhassan Aminu,&nbsp;Zainab Musa Usman","doi":"10.1016/j.jnggs.2022.12.004","DOIUrl":"https://doi.org/10.1016/j.jnggs.2022.12.004","url":null,"abstract":"<div><p>This study uses simulations to explore the energy distributions involved in the adsorption of methane gas in shales. Molecular mechanics calculations were carried out using the Forcite module in BIOVIA material studio software. The critical challenge in molecular-scale simulations remains the need to improve the description of the gas adsorption prior to up-scaling to a realistic scenario. Resolving this challenge requires the implementation of multi-scale techniques that employ atomistic/molecular-level results as input. Thus, it is pertinent that the appropriate molecular data on CH₄ gas interaction with shale is obtained. This study provides empirical data on CH₄ sorption/adsorption in shale at the molecular level to confirm the CH₄ storage potential of shales. The effect of pressure on the CH₄ sorption/adsorption was also investigated. A vital aspect of this study is elucidating the energy distribution and dominant energy that controls CH₄ sorption/adsorption to serve as a basis for the exploitation of CH₄ in productive shales. Following the intensive simulation exercise, the average total energy of CH₄ sorption varied from approximately −30 to −120 kcal/mol with increase in pressure from 500 to 2500 psi, suggesting increasing thermodynamic stability. The results indicated that van der Waals energy is the major sorption energy with values ranging from 60 to −250 kcal/mol as the sorption pressure increased, while electrostatic energy recorded the least contribution. The total adsorption energy increased from −5 to −16 kcal/mol for reservoir pressure range of 1–15 MPa. This energy distribution data confirmed the possibility of CH₄ adsorption on shale under reservoir pressure conditions.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49904853","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":"Outcrop analogy with the subsurface geology and hydrocarbon prospectivity of Jaintiapur and adjacent areas in North-East Bangladesh","authors":"Rabeya Basri ,&nbsp;A.S.M. Woobaidullah ,&nbsp;Delwar Hossain ,&nbsp;Md. Anwar Hossain Bhuiyan","doi":"10.1016/j.jnggs.2023.01.001","DOIUrl":"https://doi.org/10.1016/j.jnggs.2023.01.001","url":null,"abstract":"<div><p>The availability of hydrocarbons in the eastern part of Bangladesh indicates the presence of active petroleum systems in the Bengal basin. Although extensive research has been conducted in the Surma basin, the correlation between structural configuration, tectonostratigraphic framework, and hydrocarbon potentiality in the basin including Jaintiapur area has not yet been established. In this study, the hydrocarbon prospectivity of Jaintiapur and the adjoining Dupigaon area has been characterized through outcrop analogy with the subsurface interpretation of seismic data along L13-01, PK-SY-5, and L13-03 lines. The main three megasequences have been recognized based on sequence stratigraphy in the Sylhet region utilizing outcrop, seismic, and well-log data. The exposed Tertiary and Quaternary formations of Jaintiapur and adjoining areas can be classified into eleven litho-stratigraphic units. Detailed facies analyses indicate that these rock units were deposited in fluvial, deltaic, and shallow marine environments. The subsurface lithology of the study area has been inferred from the petrophysical data obtained from Sylhet-7, Kailashtila-4, and Jalalabad-1 wells. Jaintiapur area lies in a tectonically complex province and is controlled by the Dauki Fault System. Folding and faulting represent intense tectonic deformation in the area. Detailed analyses of surface and subsurface geology indicate that faults pass along the rivers and transverse faults segment the reservoirs. A total of seven horizons have been interpreted using Petrel software. The seismic attribute analysis identifies leads and prospects based on transverse faults and amplitude anomalies with distinct bright spots at the PK-SY-5 line. From seismic interpretation, attribute analysis, and lithofacies distribution of Sylhet-7 well and its surround area in the Dupigaon, it seems that same gas bearing sand. Gas sands of the Sylhet-7 well indicate the possibility of gas/oil in the equivalent sedimentary sequence in the Dupigaon structure as this area is located close to and more down-dip towards the kitchen area.</p></div>","PeriodicalId":100808,"journal":{"name":"Journal of Natural Gas Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49904856","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}