Energy Geoscience最新文献

{"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":"2025-09-24","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":"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":"2025-09-22","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":"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":"2025-09-21","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":"Influence of mineral evolution on pore development in marine shales based on thermal simulation experiments","authors":"Jinghui Yang,&nbsp;Bao Jia,&nbsp;Xu Chen,&nbsp;Qiang Wang,&nbsp;Shixi Wang","doi":"10.1016/j.engeos.2025.100469","DOIUrl":"10.1016/j.engeos.2025.100469","url":null,"abstract":"<div><div>High-temperature thermal simulation experiments (500–1000 °C) were conducted with samples from the Lower Cambrian Niutitang Formation shale to investigate its mineral evolution and pore development. Integrated analyses, including total organic carbon (<em>TOC</em>) content determination, X-ray diffraction (XRD), Scanning Electron Microscopy (SEM), and pore structure characterization, reveal that clay minerals progressively decompose and transform into quartz during heating, with a new mineral phase mullite produced at a temperature above 800 °C. Concurrently, organic matter undergoes thermal evolution and shrinkage, creating distinctive shrinkage-induced fractures that enhance pore development. Clay mineral decomposition produces a more complex internal pore structure and fragmented reservoir matrix, generating pores at various scales. This process increases the number and size of micropores, mesopores, and macropores, creating intricate pore networks favorable for shale reservoir development. The study illuminates the intrinsic relationship between mineral transformation and pore development in highly mature marine shales exposed to elevated temperatures.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100469"},"PeriodicalIF":3.6,"publicationDate":"2025-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145157948","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":"Delineation of depth to basement and subsurface structures beneath the Gerad Graben, western Sirt Basin, Libya, from gravity and aeromagnetic data","authors":"Abdelhakim Eshanibli ,&nbsp;Nur Azwin Ismail ,&nbsp;Hussin B. Ghanush ,&nbsp;Abdullatif Dugdug ,&nbsp;Osagie Abel Uyimwen ,&nbsp;Nabil Khalifa ,&nbsp;Abed Alrauf M. Aushah ,&nbsp;Khiri A. Khalf","doi":"10.1016/j.engeos.2025.100468","DOIUrl":"10.1016/j.engeos.2025.100468","url":null,"abstract":"<div><div>This study integrates gravity and aeromagnetic datasets to delineate basement depth and characterise the subsurface structural framework of the Gerad Graben in the western Sirt Basin, Libya. Techniques including high-pass filtering, Centre for Exploration Targeting (CET) edge detection, Source Parameter Imaging (SPI), and Euler Deconvolution (ED) were applied to residual gravity and residual reduced-to-pole (RTP) magnetic data to enhance fault mapping and basement morphology. Tests of various cutoff wavelengths show that 10 km for gravity and 15 km for magnetic data provide optimal resolution of shallow structures while preserving deeper trends. Forward 2D GM-SYS modelling and Werner Deconvolution further constrained the geometry and depth of intrusive bodies and fault systems. Results reveal a structurally complex graben with NE-SW, NW-SE, ENE-WSW, and N-S trending faults, indicating multiphase tectonic deformation. Graben-bounding faults show displacement values of 600–4290 m, and basement depths in the central depocenter reach 4275–4300 m, validated by well NTF-50. Magnetic anomalies indicate intrusive igneous bodies, including NW-SE-trending sills and dikes, associated with the Tibesti and Al Haruj volcanic provinces. These intrusions likely caused localised heating, uplift, and fault reactivation. The integrated interpretation supports a tectono-magmatic evolution involving successive rifting phases from the Paleozoic to Cenozoic, influenced by inherited Precambrian structures. These features, coupled with substantial sediment infill and magmatic activity, enhance the hydrocarbon potential of the Gerad Graben, suggesting the presence of structural and stratigraphic traps within the broader of Sirt Basin petroleum system.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100468"},"PeriodicalIF":3.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145120943","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":"Fault sealing effect on hydrocarbon accumulation in the Yuquan area of the Xihu Sag, East China Sea Basin","authors":"Zhongcai Zhang ,&nbsp;Jingdong Liu ,&nbsp;Jianjun Huang ,&nbsp;Shaohua Wang ,&nbsp;Jianjian Zhuang ,&nbsp;Qihang Zhang ,&nbsp;Hai Yang","doi":"10.1016/j.engeos.2025.100466","DOIUrl":"10.1016/j.engeos.2025.100466","url":null,"abstract":"<div><div>This study examines the effect of fault sealing on hydrocarbon accumulation in the Xihu Sag where NE- and NNE-striking faults within the sag prevent the escape of trapped oil and gas. Analyses like the shale gouge ratio (<em>SGR</em>), shale smear factor (<em>SSF</em>), and fault lateral sealing coefficient (<em>F</em>_h) are used for a quantitative evaluation of the lateral sealing capacity of faults in the Yuquan area of the Xihu Sag. Paleo-structural sections reconstructed using cross-section balancing techniques are used to analyze the evolutionary characteristics of fault sealing. The results indicate that the lateral sealing capacity of faults is mainly controlled by fault throw, clay content, and sand–shale distribution characteristics; in the Yuquan area, fault segments exhibit good lateral sealing when the <em>SGR</em> exceeds 0.5, the <em>SSF</em> is less than 2.5, and the <em>F</em>_h is greater than 10.5. The methodology for evaluating fault sealing evolution, established using structural reconstructions during key geological periods, shows that fault sealing capacity increased gradually over time; in the Xihu Sag, effective sealing of the main hydrocarbon-bearing intervals began during the Liulang period. Evaluating fault sealing capacity is also crucial for estimating the rate of hydrocarbon accumulation, and typically shows a positive correlation with gas (oil) column height. In the Yuquan area, the volume of hydrocarbons sealed by the faults increased progressively over time, with a relatively high overall fault sealing capacity during the second hydrocarbon accumulation period. This study provides valuable insights into the evaluation of fault sealing capacity as well as an investigation of the relationship between faults and hydrocarbon migration–accumulation in the Xihu Sag and analogous geological settings.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100466"},"PeriodicalIF":3.6,"publicationDate":"2025-09-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145048442","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":"2025-08-20","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":"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":"2025-08-15","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":"Key geological and engineering technologies and research directions for shale gas exploration and development in western Hubei Province, China","authors":"Guangyou Zhu,&nbsp;Jineng Jin,&nbsp;Qilin Xiao,&nbsp;Lei Wang,&nbsp;Guanglong Sheng,&nbsp;Jun Tang,&nbsp;Jianghui Meng,&nbsp;Zhiyuan Lu,&nbsp;Can Chen","doi":"10.1016/j.engeos.2025.100460","DOIUrl":"10.1016/j.engeos.2025.100460","url":null,"abstract":"<div><div>Multiple sets of marine shale sequences occur in western Hubei Province and its adjacent areas within the Middle-Upper Yangtze region, offering substantial resource potential. However, their shale gas preservation conditions differ significantly due to the heterogeneous porosity and fracture system resulting from multistage tectonic reworking. This necessitates developing region-specific evaluation systems and exploitation techniques. Drawing on previous application cases and guided by the research paradigm of geology-engineering integration, this study presents key technologies potentially applicable to shales in western Hubei Province, spanning from reservoir and sweet spot evaluation to fracturing scheme design and fracturing performance monitoring. Several insights are gained accordingly. In terms of pore evaluation, the pore heterogeneity caused by compaction and rebound can be quantified using ideal shape coefficients and fractal dimensions, both of which are influenced by structural deformations, thereby guiding reservoir classification. For seismic data interpretation, pre-stack elastic inversion and azimuthal anisotropy inversion can be employed as core techniques, overcoming the limitation of individual post-stack attributes in typically detecting only major faults. Furthermore, the inversion boundaries are constrained using log-seismic joint quality control and geomechanical simulation, contributing to enhanced reliability of sweet spot evaluation and efficient exploration in areas with complex structures. For fracturing scheme design, scientifically formulated well shut-in strategies, tailored to regional geological characteristics, are essential to activate the fracture-matrix imbibition effect. Parameters with vastly different scales used in the design, such as meter-scale fracture half-length and millidarcy-scale fracture conductivity, can be co-optimized using artificial intelligence (AI) algorithms such as the genetic algorithm (GA) and the simultaneous perturbation stochastic approximation (SPSA) algorithm. Dynamic monitoring of fracturing performance can be achieved using trace chemical tracer technology, thereby reducing target ambiguity caused by structural complexity. Research on shale gas in the structurally complex areas of western Hubei faces multiple challenges, spanning from basic geological understanding to development engineering. These challenges create an urgent need for deep interdisciplinary collaboration. Therefore, this study highlights research into geology-engineering integration, aiming to enhance the efficiency of shale gas exploration and development in western Hubei.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100460"},"PeriodicalIF":3.6,"publicationDate":"2025-08-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144879014","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":"Microscopic pore combination type identification of tight sandstone reservoir based on improved swin transformer architecture","authors":"Zhenyu Pang ,&nbsp;Zhicong Chen ,&nbsp;Sijie Lu ,&nbsp;Zhenbo Cai ,&nbsp;Yuqing Lu ,&nbsp;Mengting Peng","doi":"10.1016/j.engeos.2025.100450","DOIUrl":"10.1016/j.engeos.2025.100450","url":null,"abstract":"<div><div>Tight sandstone reservoirs differ fundamentally from conventional medium to high permeability reservoirs due to their complex and heterogeneous microscopic pore structures. This complexity poses significant challenges for accurate reservoir characterization and often results in suboptimal development performance. The specific configuration of microporosity combinations plays a decisive role in determining the storage and seepage capacities of tight sandstone reservoirs. Therefore, the precise identification of microporosity combination types is essential for improving both reservoir evaluation accuracy and development effectiveness. However, traditional computer vision models exhibit limitations in capturing fine-grained textures and spatial relationships among microscopic pores with complex morphologies, leading to inadequate generalization capabilities. To address these issues, this study proposes an enhanced Swin Transformer-based neural network architecture, termed SwinLSC (Swin Transformer with Linformer and Self-Adaptive Channel Attention). The model incorporates a global-local attention mechanism and is trained on image datasets of cast thin sections from tight sandstone reservoirs in the Yanchang Oilfield. To evaluate model performance, <em>Top-1 Accuracy</em>, <em>Loss</em>, and <em>Recall</em> metrics were employed, and the SwinLSC model was benchmarked against three mainstream architectures: Swin Transformer, Vision Transformer (ViT), and ResNet. Experimental results demonstrate that SwinLSC achieves a prediction accuracy of 93.3 %, significantly outperforming the comparative models. These findings indicate that the SwinLSC model effectively addresses the generalization deficiencies of conventional approaches in recognizing microstructural features in cast thin section imagery. Consequently, it offers a robust and accurate solution for microporosity type identification, thereby providing reliable technical support for the efficient exploration and development of tight sandstone reservoirs.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100450"},"PeriodicalIF":3.6,"publicationDate":"2025-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144830216","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}