Energy Geoscience最新文献

{"title":"Impact of salt dome morphology on geological storage volumetric estimations: Implications for prospect-scale assessment","authors":"C. Nur Schuba ,&nbsp;Lorena G. Moscardelli ,&nbsp;Jonathan P. Schuba","doi":"10.1016/j.engeos.2025.100443","DOIUrl":"10.1016/j.engeos.2025.100443","url":null,"abstract":"<div><div>Geological storage in salt caverns plays a critical role in managing energy resources, yet regional assessments often fall short in accounting for specific salt dome morphological variations that can significantly influence cavern engineering and storage capacity. To address this gap, we developed a refined approach to modeling salt domes, incorporating primary axis tilt, ellipticity, and conic taper. These geometric modifications are applied to a cylindrical baseline salt dome model to assess the effects on total salt volume, workable salt volume, and cavern storage potential. Case studies of four salt domes from the East Texas Salt Basin—Mount Sylvan, Boggy Creek, Steen, and Hainesville—validate the observed trends from the models. Our findings reveal that positive cone taper and primary axis tilt configurations enhance storage potential, leading to significant increases in potential cavern volume, while ellipticity and negative cone taper result in reduced storage capacities. The study underscores the importance of refining volumetric assessments by accounting for detailed morphologic variations, providing a more accurate framework for site-specific geological storage evaluations. Additionally, we discuss challenges related to intra-salt heterogeneities, including intra-salt deformation and mineralogical impurities, highlighting the need for improved site characterization to optimize the safety and efficiency of subsurface storage systems. This work contributes to the development of scalable and reliable geological storage infrastructure, essential for meeting future energy demands.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100443"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144721918","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":"Mitigating clay swelling and permeability loss in thermal EOR with a quaternary ammonium clay stabilizer under high-temperature low-salinity conditions","authors":"Aisha Labak,&nbsp;Peyman Pourafshary","doi":"10.1016/j.engeos.2025.100444","DOIUrl":"10.1016/j.engeos.2025.100444","url":null,"abstract":"<div><div>Clay swelling and fines migration pose significant challenges to thermally enhanced oil recovery (EOR) operations, particularly in clay-rich formations. This study systematically investigates clay swelling behavior and permeability impairment under high-temperature, low-salinity (HTLS) conditions and evaluates various inhibition methods to mitigate formation damage. To ensure realistic analysis, data and materials from a field with similar issues in Kazakhstan were used. Static/dynamic swelling tests demonstrated that a quaternary ammonium-based inhibitor consistently provided superior clay stabilization through effective ion exchange and surface charge modification mechanisms. In distilled water at 100 °C, inhibitor-treated samples maintained 48.89 % of their original permeability, while untreated samples exhibited severe damage, retaining only 17.05 %. Additionally, this chemical inhibitor significantly lowered the critical salt concentration (CSC), effectively stabilizing clay at 4920 ppm salinity compared to 7380 ppm required without treatment. Scanning electron microscopy (SEM) imaging corroborated these results, revealing that inhibitor-treated clay maintains a compact and coherent structure, in stark contrast to the pronounced swelling, delamination, and structural deterioration observed in untreated clay samples. Nevertheless, this quaternary ammonium-based clay stabilizer presents a robust and promising solution for reducing clay swelling-induced damage, sustaining reservoir permeability, and improving thermal EOR performance in swelling-prone formations.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100444"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144738431","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":"Exploring the geochemical, petrographic, and palynological signatures: An analysis of the Mungaroo Formation source rock potential in the Exmouth Plateau, Northern Carnarvon Basin, Australia","authors":"Ummi Fayyadhah Binti Haji Talipudin ,&nbsp;Mohamed Ragab Shalaby ,&nbsp;Amajida Roslim ,&nbsp;Md Aminul Islam","doi":"10.1016/j.engeos.2025.100446","DOIUrl":"10.1016/j.engeos.2025.100446","url":null,"abstract":"<div><div>The Late Triassic Mungaroo Formation of the Exmouth Plateau was investigated through an integrated, stratigraphically and geographically extensive study to characterize its source rock potential and depositional controls. Geochemical, petrographic, and palynological analyses reveal highly variable organic richness across the formation, with total organic carbon (<em>TOC</em>) content values ranging from very low in sand-dominated intervals to notably high in coal-bearing mudstones. The Mungaroo Formation exhibits diverse organic composition, with <em>TOC</em> content ranging from 0.63 % to 54.18 %, demonstrating that while certain intervals contain significant organic richness, others are notably lean in organic content. Petrographic analyses reveal the presence of dinoflagellates, liptodetrinite, sporinite, and cutinite, suggesting transitional settings with varying marine influence. Thermal maturity assessments indicate a range of maturity levels, with vitrinite reflectance (<em>R</em>_o) values ranging from 0.45 % to 1.39 %, reflecting thermal maturity of immature to post-mature stage. Rock-Eval pyrolysis parameters support these observations, highlighting varying stages of hydrocarbon generation. Biomarker characteristics further confirm the mixed organic origin and complex paleo-depositional environments within the Mungaroo Formation. The presence of both marine and terrigenous biomarkers underscores the depositional history of the region, with Pristane/Phytane ratios (Pr/Ph) indicating oxidizing environments typically associated with terrigenous plants’ input. Palynological data indicates strong terrigenous influence within both the wells Mercury-1 and Jupiter-1, characterized by proximal delta-plain environments.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100446"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144826388","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":"Regional sedimentary responses to syndepositional faulting and reservoir potential of Upper Cretaceous limestones in the B Oilfield, Mesopotamian Basin","authors":"Dancheng Zhu ,&nbsp;Jianhua Qu ,&nbsp;En Xie ,&nbsp;Benbing Ren ,&nbsp;Yuyuan Li ,&nbsp;Ke Zhang ,&nbsp;Jinla Huang","doi":"10.1016/j.engeos.2025.100470","DOIUrl":"10.1016/j.engeos.2025.100470","url":null,"abstract":"<div><div>Upper Cretaceous limestones represent the primary reservoirs in the B Oilfield, central Mesopotamian Basin. While syndepositional faults have clear influences on the thickness of these strata, their controls on sedimentation across different reservoir intervals remain poorly understood. This study examines the sedimentary responses to syndepositional faulting during the Late Cretaceous through integrating analysis of fault growth rates and facies distribution across fault blocks. Estimated growth rates for two major faults (F1 and F2) range from 0 to 30 m/Ma, with thickness differences of up to 60 m observed between hanging wall and footwall sites. Fault activity varied over time and was more intense during the deposition of the Lower Hartha and Tanuma formations. This enhanced activity resulted in significant thickness variations and promoted the accumulation of foraminifera and bioclastic packstone facies (MF3/MF2) inside tilted fault-blocks, which are associated with favorable reservoir properties. By influencing facies distribution, syndepositional faulting might also contribute to the development of thicker reservoirs within fault zones. In contrast, fault activity diminished during the deposition of the Upper Hartha and Khasib formations, where more uniform stratigraphic thickness and facies distributions are observed. These findings highlight the critical role of syndepositional faulting in creating accommodation space and enhancing reservoir development conditions in the study area, offering valuable implications for petroleum exploration and reservoir modeling in structurally analogous settings.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100470"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145219366","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":"Investigation on full-scale pore characterization and its implications for gas storage and development potential of deep coal seam in the Jiaxian block, NE Ordos Basin, China","authors":"Cong Li ,&nbsp;Ze Wang ,&nbsp;Peijie Li ,&nbsp;Yongchao Zhang ,&nbsp;Shulei Duan ,&nbsp;Limin Ma ,&nbsp;Peng Cong ,&nbsp;Zefan Wang ,&nbsp;Xiaoxiao Sun ,&nbsp;Hui Wang","doi":"10.1016/j.engeos.2025.100471","DOIUrl":"10.1016/j.engeos.2025.100471","url":null,"abstract":"<div><div>Deep coal reservoirs (buried depth &gt; 2000 m) represent a significant yet underexploited resource for coalbed methane (CBM) production. In these reservoirs, CBM primarily exists in adsorbed and free phase, with the pore structure playing a critical role in gas storage and migration. The Jiaxian block in the northeastern Ordos Basin, has emerged as a key area for deep CBM exploration due to its promising resource potential. However, the pore structure characteristics of the No. 8 coal seam in Jiaxian block and their implications for gas storage and production remain poorly understood. A comprehensive characterization of the No. 8 coal seam's pore structure is conducted in the study using multiple methods including high-pressure mercury injection, N₂/CO₂ adsorption experiments, and integration of measured core gas content data and production history. The study results reveal that the pores can be mainly classified as vesicles and cellular pores, and the fractures are mainly static pressure fractures. Micropores (pore diameter &lt; 10 nm) dominate the pore system (accounting for more than 99 % of the total specific surface area), providing important adsorption sites for gas storage. Although mesopores (pore diameter of 100–1000 nm) and macropores (pore diameter &gt; 1000 nm) account for a small proportion, they feature effective storage spaces and interconnectivity, resulting in a high proportion of free gas. Therefore, the reservoirs shows great development potential after stimulation (such as hydraulic fracturing). These findings emphasize the feasibility of large-scale and long-term development of CBM in the Jiaxian block in terms of reservoir space, gas content and production characteristics. This study serves to lay a scientific basis for its efficient exploitation.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100471"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145219367","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":"Implications of the geochemical characteristics of post-fracturing flowback fluids for shale gas exploration and exploitation","authors":"Zhipeng Ou ,&nbsp;Cheng Chang ,&nbsp;Weiyang Xie ,&nbsp;Haoqian Zhang ,&nbsp;Haoran Hu ,&nbsp;Ruiqi Gao ,&nbsp;Mengting Gao ,&nbsp;Shengwang Lin ,&nbsp;Chunhai Ji ,&nbsp;Ziqiang Xia","doi":"10.1016/j.engeos.2025.100416","DOIUrl":"10.1016/j.engeos.2025.100416","url":null,"abstract":"<div><div>Previous studies on post-fracturing flowback fluids focus primarily on their cleaning and discharge, high salinity sources, and damage to gas reservoirs. An analysis of the geochemical characteristics of these fluids helps develop an improved understanding of the preservation condition and fracturing performance of shale gas reservoirs. This study analyzed the ion, total dissolved solids (TDS) concentration, and stable isotope characteristics of post-fracturing flowback fluids from five horizontal shale gas wells in the Luzhou area. Among these wells, two were subjected to hydraulic fracturing using fresh water, and three using reused flowback fluids. The results indicate that with increasing flowback time, the post-fracturing flowback fluids from wells subjected to hydraulic fracturing using fresh water showed increased TDS concentration, heavier stable isotopes, and the presence of new ion components. These results indicate the mixing of a large volume of formation water into the fluids. In contrast, post-fracturing flowback fluids from wells subjected to hydraulic fracturing using reused flowback fluids exhibited a slow increase in the TDS concentration and stable isotopes. As the flowback time increased, the trends in TDS concentration and stable isotope ratios of post-fracturing flowback fluids from shale gas wells subjected to fracturing using fresh water evolved toward those of post-fracturing flowback fluids from shale gas wells undergoing fracturing using reused flowback fluids. Measurements show that post-fracturing flowback fluids from both well types exhibited roughly the same properties after one year of shale gas production. This result suggests that post-fracturing flowback fluids from wells using reused flowback fluids progressively took on the formation water properties. In particular, post-fracturing flowback fluids from well Lu 211—a well subjected to hydraulic fracturing using fresh water—showed a low sodium-chloride coefficient, a low coefficient of variation, high TDS concentration, heavy stable isotopes, and a high nitrate ion concentration. This indicates a formation water source of the fluids and the poor sealing of the formation water, which hinders shale gas enrichment. The quantification of the fracturing fluid and formation water contents in the post-fracturing flowback fluids reveals that higher TDS concentration and heavier stable isotopes in the fluids appear to correspond to higher formation water content and lower fracturing fluid content, as well as higher fracturing performance. A systematic analysis of the geochemical characteristics and flowback pattern of fracturing fluids indirectly provides insights into the flow path of formation water, water body mixing, rock-water interactions, and fluid sources. Besides, the analysis offers a new perspective for understanding the preservation conditions and fracturing performance of shale gas reservoirs.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100416"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145158001","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 characterization and well production proxy analyses on drill cuttings: Case study from the Flysch play in the Vienna Basin (NE Austria)","authors":"Jasemin A. Ölmez ,&nbsp;Benjamin Busch ,&nbsp;Rolf Möbius ,&nbsp;Kanchan Dasgupta ,&nbsp;Albert L. Gauer ,&nbsp;Filippo Tosoratti ,&nbsp;Christoph Hilgers","doi":"10.1016/j.engeos.2025.100461","DOIUrl":"10.1016/j.engeos.2025.100461","url":null,"abstract":"<div><div>Drill cuttings, though rarely used, are crucial subsurface samples to understand petrographic properties affecting reservoir quality. Unlike core material, cuttings are continuously available along the wellbore and can be used during drilling to monitor progress. Therefore, cuttings may allow a semi-quantitative, statistical calibration of rock properties from the subsurface, but they are often underutilized. Although fracture and vein orientations cannot be reconstructed from drill cuttings, the presence of veins and their internal textures (open, partially sealed or sealed) in specific formation sections and depths can be identified and analyzed using e.g., transmitted light microscopy and cathodoluminescence to supplement characterization at the well site and subsequently assess production behavior. Borehole gamma ray logs in combination with handheld portable X-ray fluorescence (pXRF) analyses on cleaned and dried drill cuttings can be used to further improve the depth accuracy of the cutting samples and to geochemically fingerprint the samples, based on the Si/Al ratio, as a proxy for sandstone-rich and mudrock-rich sections of the well. In this study, eighty-three sandstone cutting samples from two wells, covering ∼400 m of stratigraphy targeting the Paleocene-Eocene Greifenstein Fm. equivalent (Glauconite Sandstone, GLS) in the Vienna Basin (Austria), were studied. They also cover parts of three different reservoir sections (1. to 3. GLS). The Flysch play in the Vienna Basin hosts several sandstone-mudrock interbeds and is composed of several nappes, forming complex reservoir compartments. The glauconite contents vary between different sections of the GLS, where the highest is observed in the 3. GLS. The sandstones are predominantly cemented by ferroan calcite, resulting in low optical porosity (&lt;5 %) in both wells, with only individually elevated porosity, related to partially dissolved K-feldspar grains. A paragenetic sequence solely based on cuttings further highlights that reservoir quality in the studied section is independent of sandstone compaction, but is related to lower optical porosity in finer-grained sandstones and higher carbonate vein cement contents. Furthermore, productive intervals are related to lower Fe + Mg contents. The understanding of reservoir properties, diagenesis, and their influence on fluid flow is crucial for successful exploration and reduction of uncertainty in reservoir production and development. The diagenetic variations from cuttings and the geochemical fingerprint by pXRF are linked to reservoir quality and production performance of individual well perforations. This approach can provide additional information on reservoir quality where core material is unavailable.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100461"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144890360","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":"Origin of bedding-parallel fibrous calcite veins in the Permian carbonate, central Thailand: Constraint on hydrocarbon generation","authors":"Tindikorn Kanta ,&nbsp;Piyaphong Chenrai ,&nbsp;Stijn Glorie ,&nbsp;Ian Cartwright ,&nbsp;Pengfei Ma","doi":"10.1016/j.engeos.2025.100473","DOIUrl":"10.1016/j.engeos.2025.100473","url":null,"abstract":"<div><div>Bedding-parallel fibrous calcite veins (BPCVs) are found extensively in sedimentary basins and usually developed in petroleum source rock; however, their origin remains debated. This study investigates the formation of BPCVs in the Permian carbonate rocks of the Khao Khwang Formation, central Thailand, through petrographic, geochemical, and isotopic analyses, along with total organic carbon (<em>TOC</em>) content assessment. Five samples, including 9 veins and 5 host rocks, were analyzed. The petrographic observations show that the BPCVs exhibit cone-in-cone structure and beef vein and are classified as unitaxial veins. The geochemical analyses and stable isotope compositions suggest local fluid sources originated from inorganic carbonates and diagenetic formation fluids within the microbial methanogenic zone. The BPCVs have an average δ¹³C_VPDB value of 3.04‰ ± 0.30‰ and an average δ¹⁸O_VPDB value of −10.75‰ ± 0.62‰, while the host rocks have an average δ¹³C_VPDB value of 1.88‰ ± 1.10‰ and an average δ¹⁸O_VPDB value of −10.77‰ ± 0.39‰. The mineral compositions and element contents of the host rock and fibrous calcite veins are similar, with a strong negative relationship between calcium and other elements. The rare earth element (REE) distribution patterns from the calcite veins are similar to the host rocks, with positive Ce anomalies and small positive Eu anomalies. Oxygen isotope data suggest vein formation at temperatures between 62 °C and 75 °C, corresponding to the onset of the oil window. The in-situ U-Pb dating indicates that fibrous calcite veins formed between the Early to Middle Permian period [(260.1 ± 4.5) to (288.9 ± 4.8) Ma)]. Microstructural and geochemical evidence suggests that vein initiation resulted from fluid overpressure of a supersaturation of pore fluids within semi-consolidated sediments, with continuous vein dilatation driven by crystallization forces. This study illustrates that the BPCVs of the Khao Khwang Formation highlight significant potential in accurately assessing the evolution of hydrocarbon generation.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100473"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145219368","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":"Quantifying fracture evolution characteristics of gravelly sandstones based on fractal theory","authors":"Kai Feng ,&nbsp;Zhenlin Wang ,&nbsp;Guanfang Li ,&nbsp;Peilin Zhang ,&nbsp;Zhichao Wang ,&nbsp;Yujia Wang ,&nbsp;Kouqi Liu","doi":"10.1016/j.engeos.2025.100463","DOIUrl":"10.1016/j.engeos.2025.100463","url":null,"abstract":"<div><div>With the advancement of unconventional oil and gas exploration and development, tight gravelly sandstone reservoirs have garnered increasing attention. In this study, triaxial compression experiments are conducted on gravelly sandstone cores, and correlation analysis is employed to establish the relationships between fractal dimensions of the fractures and rock mechanics parameters. For cores of gravelly sandstone, a positive correlation exists between the fractal dimension and the brittleness index. The prediction model reveals that the error between the predicted and actual values for well 3 is relatively large, which can be attributed to the presence of pure sandstone cores in well 3. Under high confining pressure in the deep strata, rocks exhibit a decreasing trend in fractal dimensions, a phenomenon due to the stress-memory effect. In addition, numerical simulation is further employed to study the effect of the factors that could affect the complexity of the fractures, and the results show that the fractal dimension of gravelly sandstone declines with increasing confining pressure, peak compressive strength, and rock elastic modulus as the loading process intensifies.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100463"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144913044","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":"Quantitative kinetic modeling of methane generation and δ13C signals for multiple samples in closed-system pyrolysis","authors":"Zixuan Guan ,&nbsp;Wenhui Liu ,&nbsp;Ping Guan ,&nbsp;Houyong Luo","doi":"10.1016/j.engeos.2025.100472","DOIUrl":"10.1016/j.engeos.2025.100472","url":null,"abstract":"<div><div>Hydrocarbon generation kinetics are influenced by complex factors, including temperature, reaction time, pressure, and molecular structure, which render simple modeling approaches inadequate for accurately simulating methane generation. The closed-system pyrolysis experiment, a common method to study hydrocarbon generation, poses challenges for kinetic parameter regression due to limited data points. This limitation necessitates the application of sophisticated data analysis techniques to extract meaningful insights from sparse experimental data. This paper establishes a quantitative relationship between methane production and the thermal process through closed system pyrolysis experiments. A nonlinear regression model using multiple algorithms is established based on this quantitative relationship. Accordingly, a method that can quantitatively invert the methane generation kinetic parameters corresponding to the samples based on the experimental data is provided. Based on this theoretical model, a computer program capable of processing experimental data is designed and implemented. Practical analyses are performed using the method above for three samples: a coal sample from the Yulong, Guizhou; a solid bitumen sample from Guangyuan, Sichuan; and a marlstone sample containing type I kerogen from Luquan, Yunnan. The results obtained agree with the qualitative estimates based on hydrocarbon generation kinetic theory using the previous method. Thus, the validity of the new data processing method, the new mathematical model, and the data processing procedures are verified.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100472"},"PeriodicalIF":3.6,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145324108","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}