Energy Geoscience最新文献

{"title":"Mechanical responses of deep salt caverns under synchronous and asynchronous operation strategies","authors":"Zhenxing Ji ,&nbsp;Jianfeng Liu ,&nbsp;Ken Qin ,&nbsp;Jinbing Wei ,&nbsp;Bingbing Liu ,&nbsp;Jianxiong Yang ,&nbsp;Yang Wu","doi":"10.1016/j.engeos.2026.100521","DOIUrl":"10.1016/j.engeos.2026.100521","url":null,"abstract":"<div><div>In China, gas storage in deep salt caverns faces challenges due to high in situ stresses, elevated geothermal temperatures, and the presence of interbedded salt-mudstone formations. These factors lead to heterogeneous deformation and stress concentration, which adversely affect the stability and sealing capacity of salt caverns. To address these issues, this study systematically investigates the differences in the mechanical responses of a dual-cavern system located in a representative deep salt district under synchronous and asynchronous injection-production processes. The impacts of key operating parameters on the long-term deformation evolution of salt caverns under thermo-mechanical coupling are examined, and the effectiveness of the asynchronous operation strategy in optimizing the cavern stability is quantitatively evaluated. The results demonstrate that asynchronous operation significantly enhances the stability of the inter-cavern pillar. Specifically, this strategy disrupts the connection between zones with high stress-to-strength ratios, thereby reducing the risk of coupled failure between the two salt caverns. Furthermore, this strategy improves the distribution of the dilatancy safety factor of the surrounding rocks. Asynchronous operation also performs well in mitigating long-term deformation of the salt caverns, resulting in a lower risk of unilateral pillar instability, reduced cavern roof subsidence, and diminished volume shrinkage. Notably, asynchronous operation can effectively suppress cavern deformation under high-frequency injection-production cycles. Increasing the operating rate and decreasing the minimum pressure result in decelerating and accelerating deformation trends, respectively. Sensitivity analysis identifies the minimum pressure as the primary factor directly controlling cavern deformation, while operating frequency benefits most from the adoption of an asynchronous operation strategy. Overall, the findings of this study are expected to advance the construction and operational optimization of deep salt caverns for gas storage in China.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 2","pages":"Article 100521"},"PeriodicalIF":3.6,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146090474","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":"Porosity and permeability prediction from petrographic point-counting data using machine learning: Applications to Rotliegendes and Buntsandstein reservoirs","authors":"Sahar Sadrikhanloo,&nbsp;Benjamin Busch,&nbsp;Christoph Hilgers","doi":"10.1016/j.engeos.2026.100537","DOIUrl":"10.1016/j.engeos.2026.100537","url":null,"abstract":"<div><div>Machine learning approaches are widely used in geosciences. However, one widely available dataset in reservoir geology remains underrepresented in published works: petrographic data from classical point-counting analyses. Such data are widely available for reservoir lithology characterization, often in combination with routine core analysis data (porosity and permeability). Since porosity and permeability in siliciclastic rocks are controlled by the detrital and authigenic composition and samples record effects of compaction during diagenesis, these datasets are often linked to assess reservoir quality controls.</div><div>Datasets from six wells, covering four regions and two large reservoir lithologies in central Europe, the Permian Rotliegendes and Triassic Buntsandstein, were used to apply machine learning to the petrographic and reservoir quality data to predict porosity and permeability. Predictions are based on point-counting data including detrital and authigenic phases, optical porosity, grain-to-IGV (GTI) and grain-to-grain (GTG) coating coverages, and granulometry. For both regression tasks, a Random Forest and a Support Vector Regression machine learning model were implemented, with performance compared and the best model selected based on coefficient of determination (<em>R</em>²) and error metrics. Porosity predictions using a Random Forest algorithm yielded an <em>R</em>² of 0.92, a mean average error (<em>MAE</em>) of 1.25%, and a root mean square error (<em>RMSE</em>) of 1.56%. Permeability predictions of real-scale permeability using Support Vector Regression gave an <em>R</em>² of 0.85, <em>MAE</em> of 29.4 mD, <em>RMSE</em> of 68.3 mD, and a range-based normalized <em>RMSE</em> of 8.76% (real-scale). Log-transformation of measured and predicted permeability resulted in a more representative <em>R</em>² of 0.83, <em>MAE</em> of 0.21, and <em>RMSE</em> of 0.24, reflecting its log-normal distribution. Predictions are acceptable despite the limited dataset, which reduces operator bias by using curated data. This machine learning approach may simultaneously unlock another understanding of reservoir quality controls based on SHapley Additive exPlanations (SHAP) value plots.</div><div>Further training of such models on cored reservoir sections can improve understanding of which detrital and authigenic mineral phases influence reservoir properties. Trained models could also potentially evaluate reservoir properties from cuttings, which, like well logs, are more continuous than cores while allowing diagenetic interpretation based on petrographic analysis.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 2","pages":"Article 100537"},"PeriodicalIF":3.6,"publicationDate":"2026-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146188834","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 role of organofacies in governing kerogen kinetics: A case study of the Permian Gondwana coals from India","authors":"Monalisa Mallick ,&nbsp;Runcie Paul Mathews ,&nbsp;Nihar Ranjan Kar ,&nbsp;Barnita Banerjee ,&nbsp;Subhasmit Dash ,&nbsp;E.V.S.S.K. Babu ,&nbsp;Srinivas Bikkina ,&nbsp;Vikram Partap Singh ,&nbsp;Satendra Kumar Gupta ,&nbsp;Vireswar Samanta","doi":"10.1016/j.engeos.2025.100503","DOIUrl":"10.1016/j.engeos.2025.100503","url":null,"abstract":"<div><div>This study investigates four Late Permian Gondwana coals from the Raniganj sub-basin, Damodar Valley and three Early Permian Gondwana coals from the Talcher sub-basin, Mahanadi Valley. The study aims to characterize the kerogen type, hydrocarbon generation potential, thermal maturity, and organic matter composition, as well as to explore the impact of organic matter characteristics on kerogen kinetic parameters, utilizing multi proxy approach. The study further investigates the influence of the mineral matrix on kerogen decomposition kinetics. Based on the Rock-Eval parameters, Fourier transform infrared spectroscopy (FTIR) parameters, and vitrinite reflectance (<em>R</em>_o), the kerogen is primarily classified as immature/early mature Type Ⅲ kerogen derived from terrestrial land plants, with minor contribution from Type Ⅱ kerogen having mainly gas generating potential. The source of the organic matter, as determined by stable carbon isotopic composition (δ¹³C_org) values and C/N ratios indicates a primary input from C₃ terrestrial plants. The presence of enriched collotelinites and liptinites, such as sporinite and resinite, provides evidence for the input of terrestrial higher plants, including both herbaceous and arborescent species. Various indices derived from maceral abundances, including the gelification index (<em>GI</em>), tissue preservation index (<em>TPI</em>), and vegetation index (<em>VI</em>), collectively indicate diverse depositional conditions which range from wet forest swamps to shallow water-covered wet forest swamps and even dry forest swamps. The variation in vitrinite macerals influenced the kerogen type and consequently impacted the kinetic parameters, viz. the distribution of activation energies (<em>E</em>_a), kerogen transformation ratio (<em>KTR</em>), and hydrocarbon generation rate (<em>HGR</em>). Among the Talcher coals, shaly coals exhibit different kerogen type and kerogen transformation. This dissimilarity can be attributed to variable maceral compositions. Unlike the Talcher samples, all Raniganj samples show consistent kinetic behaviour despite their sample type (coal/shaly coal) or kerogen type (Type Ⅲ/mixed Type Ⅱ/Ⅲ) owing to comparable liptinite/vitrinite maceral composition. This study reveals that whilst the presence of mineral matrix shifts the apparent <em>E</em>_a of kerogen through interactions like adsorption and catalysis, it does not significantly affect the kerogen type, <em>HGR</em>, or <em>KTR</em> of the studied coals.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100503"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145571787","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":"A reservoir rock wettability modifier for ultra-high temperature and high salinity environment","authors":"Ling Lin ,&nbsp;Yulong Bai ,&nbsp;Yue Feng ,&nbsp;Yuanzhi Qu ,&nbsp;Taigang Zhou","doi":"10.1016/j.engeos.2025.100506","DOIUrl":"10.1016/j.engeos.2025.100506","url":null,"abstract":"<div><div>During drilling process, the water phase in drilling fluids infiltrates rock fractures through capillary action. The surface wettability of dolomite is governed by multiple factors, resulting in an unstable wetting state. Studies have shown that altering the surface wettability of reservoir rocks to an intermediate wetting state can effectively reduce the damage of drilling fluids to oil and gas reservoirs and improve oil and gas recovery. Therefore, it is necessary to develop a reservoir protectant to prevent the water phase in the drilling fluid from intruding into the oil and gas reservoirs. Given this, a modified polysiloxane was synthesized to alter the surface wettability of dolomite. Tetramethylcyclotetrasiloxane (D^H₄) and octamethylcyclotetrasiloxane (D₄) were ring-opened copolymerized to obtain the hydrogen-containing polysiloxane, which in turn reacted with unsaturated hydrocarbons to obtain the modified polysiloxane. The ability of reservoir protectants to regulate the surface wettability of dolomite under high-temperature and high-salinity conditions was tested. The experimental results show that the reservoir protectant is able to alter the wettability of the dolomite surface to an intermediate wetting state by adsorption on the rock surface even after 16 h of aging at 240 °C and 15% salt concentration.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100506"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145618284","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":"Assessment of carbon dioxide storage in the Gulf of Gabes, Tunisia: Analytical and numerical modeling","authors":"Kais Ben Abdallah ,&nbsp;Kassabi Nadhem ,&nbsp;Mohamed Hamoud ,&nbsp;Essaieb Hamdi ,&nbsp;Qinhong Hu","doi":"10.1016/j.engeos.2025.100449","DOIUrl":"10.1016/j.engeos.2025.100449","url":null,"abstract":"<div><div>Significant hydrocarbon accumulations in the offshore Gulf of Gabes, Tunisia, remain largely undeveloped due to elevated concentrations of carbon dioxide (CO₂), nitrogen (N₂), and hydrogen sulfide (H₂S), which compromise commercial viability and have delayed field development. Addressing these constraints requires the deployment of technically robust and environmentally sustainable CO₂ management strategies. Carbon capture, utilization, and storage (CCUS) offers a comprehensive solution by enabling the redirection of captured CO₂ for enhanced oil recovery (EOR), industrial reuse, or permanent geological sequestration, supporting both resource recovery and long-term emissions mitigation. Building upon earlier pre-screening assessments, this study re-evaluates the CO₂ storage potential of selected sites in the Gulf of Gabes, with a focus on informing integrated utilization and storage frameworks. Based on geological, logistical, and socioeconomic criteria, the Fd1 Field within the Hasdrubal development area was selected as a prime candidate. A multi-scale assessment approach was applied to characterize the geological context, reservoir properties, containment integrity, and injection feasibility. The Eocene El Garia Formation within Fd1 Field, composed of thick-bedded nummulitic limestones, was identified as the most suitable reservoir for sequestration. It offers favorable characteristics in terms of porosity (10 %–26 %), permeability (40–100 mD), adequate structural thickness, and effective sealing by the overlying caprock. A key contribution of this study lies in the integration of regional geological screening with advanced 3D coupled flow-geomechanical simulations, the first of its kind in Tunisia's offshore domain. The simulation workflow evaluated pressure evolution, CO₂ plume migration, mechanical stability, and long-term seal integrity over a 30-year injection period. Results indicate that up to 16.5 million metric tonnes of CO₂ can be safely injected at a daily rate of 1.174 Mm³, with pressure buildup remaining within acceptable thresholds and no caprock failure observed. Overall, the findings demonstrate the technical feasibility and containment reliability of CO₂ storage in the El Garia Formation. The study establishes Fd1 Field as a strategic CCUS site and provides a transferable methodology for evaluating CO₂ storage potential in fractured carbonate reservoirs across North Africa and comparable offshore settings.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100449"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146173083","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":"Comparative study of the geological characteristics of sedimentary basins in Ghana: Implications for hydrocarbon generation potential","authors":"Alidu Rashid ,&nbsp;Mahamuda Abu ,&nbsp;Abdul Halim Abdul Latiff ,&nbsp;Md. Mahmodul Islam ,&nbsp;Ebo Nyarko ,&nbsp;Daniel Affum","doi":"10.1016/j.engeos.2025.100508","DOIUrl":"10.1016/j.engeos.2025.100508","url":null,"abstract":"<div><div>Ghana has four sedimentary basins, but attention has mostly been concentrated on the Tano Basin. This preference among potential investors is largely due to the fact that it has been extensively studied and also its established oil and gas reserves, which have facilitated the discovery and development of major fields such as the Jubilee Field. In contrast, the Saltpond, Keta, and Voltaian basins have not undergone the same level of exploration and research, thereby making them less attractive to investors. A comparative analysis of the research conducted on the Tano Basin and the other basins is necessary to identify research opportunities that could enhance understanding of these less-explored basins and increase investor interests. The findings indicate that the Tano Basin requires minimal further exploration, while studies on the Saltpond, Keta, and Voltaian basins have primarily focused on sedimentological and geochemical analyses, offering valuable but limited insights into their petroleum systems and hydrocarbon potential. Unlocking Ghana's hydrocarbon potential demands tailored studies for each basin. In the Tano Basin, the key to sustaining and optimizing production lies in advanced seismic reprocessing, pre-stack depth migration, 4D reservoir monitoring, and machine-learning-assisted reservoir characterization to address deepwater complexity and compartmentalization. Revitalizing the Saltpond Basin demands updated petroleum system evaluation through modern geochemical techniques, reprocessed 2D/3D seismic data, and comprehensive 1D–3D basin modeling to clarify trap integrity and overlooked plays. In the underexplored Accra–Keta Basin, high-resolution seismic imaging, sequence stratigraphic mapping, and full petroleum system modeling are essential to define reservoir intervals and assess charge potential. For the Voltaian Basin, a deep seismic profiling, integrated geological mapping, source-rock evaluation, and analog-based reservoir/seal studies are required to evaluate its hydrocarbon potential. These targeted efforts are key to de-risking and advancing exploration. An integrated approach is vital for gaining a deeper understanding of the petroleum system elements in these basins. This will not only expand scientific knowledge and inform decision-making at the highest levels but also provide a strong foundation for future exploration, development, and efficient exploitation of hydrocarbon resources.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100508"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145684347","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":"Differential accumulation mechanism of shale gas in superimposed basins: Insights from dynamic evolution of shale gas content and occurrence state","authors":"Min Li ,&nbsp;Xiongqi Pang ,&nbsp;Zhen Zhao ,&nbsp;Xin Ye ,&nbsp;Di Chen ,&nbsp;Pengwei Wang ,&nbsp;Chengxiang Wan ,&nbsp;Guanping Wang ,&nbsp;Xiaotong Ge","doi":"10.1016/j.engeos.2025.100505","DOIUrl":"10.1016/j.engeos.2025.100505","url":null,"abstract":"<div><div>By investigating the evolution of shale gas generation, storage, adjustment and accumulation under different structural settings in superimposed basins, this study elucidates the differential accumulation mechanisms of shale gas. An improved evaluation method of shale gas content evolution in superimposed basins is proposed. This method incorporates the coupling effect of key geological factors such as temperature, pressure, organic matter abundance, maturity, and pore characteristics on the content and occurrence state of shale gas, as well as the configuration relationship between shale gas generation and storage throughout geological history. Using this approach, the gas evolution histories of the Longmaxi Formation shales in wells N201 and PY1 are reconstructed under varying geological conditions. The Longmaxi Formation shales in these wells are dominated by type I kerogen, with original total organic carbon (<em>TOC</em>_o) contents of 6.20 wt% and 4.92 wt%, respectively, indicating differences in the initial material basis for gas generation. At the maximum burial depth of approximately 5000 m, the Longmaxi Formation shale in well N201 exhibits a formation pressure coefficient of 2.05, an organic matter maturity of 2.2%, and organic pores accounting for 68% of the total porosity. The gas generation quantity (<em>Q</em>_g) reaches 19.24 m³/t, while the gas storage capacity (<em>Q</em>_s) is 4.30 m³/t. The actual total gas content (<em>Q</em>_a), constrained by <em>Q</em>_s, is 4.30 m³/t, with free gas comprising 94%. Following relatively moderate tectonic uplift, the <em>Q</em>_a in well N201 decreases to 4.03 m³/t, with free gas accounting for 63%. In contrast, the Longmaxi Formation shale in well PY1 reached a maximum burial depth of 6300 m, associated with a formation pressure coefficient of 1.62, organic matter maturity of 2.5%, and organic pore proportion of 67%. Here, <em>Q</em>_g is 16.87 m³/t, and both <em>Q</em>_s and <em>Q</em>_a are 3.65 m³/t, with free gas accounting for 98%. After intense tectonic uplift, <em>Q</em>_a declines to 2.72 m³/t, and the proportion of free gas drops to 51%. Finally, a four-stage differential accumulation model of shale gas is established: Slow gas generation and only adsorbed gas occur in stage Ⅰ, which is primarily controlled by <em>TOC</em> content; both adsorbed gas and free gas present in stage Ⅱ, with free gas becoming dominant; rapid gas generation and free gas predominance are controlled by temperature and porosity in stage Ⅲ; and gas adjustment and accumulation are primarily controlled by temperature and pressure in stage Ⅳ.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100505"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145618283","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":"A rock physics model-based approach to delineate deep and tight sand reservoir heterogeneity in the Bohai Bay Basin, China","authors":"Donghong Zhou ,&nbsp;Qifeng Dou ,&nbsp;Jiaqi Jiang ,&nbsp;Yihao Deng ,&nbsp;Xiaodong Wei ,&nbsp;Xingrui Dou ,&nbsp;Yuhui Zhao ,&nbsp;Fengyang Dong","doi":"10.1016/j.engeos.2025.100477","DOIUrl":"10.1016/j.engeos.2025.100477","url":null,"abstract":"<div><div>Delineating sweet spots is critical for the exploration and production of oil and gas in deep and tight sand reservoirs. The lack of advanced and reliable methods makes this a challenge for geologists and geophysicists. This study introduces, for the first time, an integrated workflow that combines pre-stack seismic inversion with rock physics modeling to predict reservoir porosity and shale volume (V-shale) for sweet spot identification in tight sand reservoirs. A new elastic parameter, the density calculation index (<em>DCI</em>), is introduced which links acoustic and shear impedance for seismic density inversion, thereby addressing the long-standing problem of poor density inversion accuracy. A novel combined Sun–Walsh rock physics model, developed as part of this study, significantly improves V-shale evaluation from seismic data. The proposed three-step seismic inversion approach includes: (1) deriving acoustic and shear impedance from angle-stack seismic data using model-based inversion; (2) calculating density using shear impedance constrained by <em>DCI</em>, followed by porosity estimation from the density–porosity relation; and (3) evaluating V-shale using the α-parameter derived from the Sun–Walsh model and pre-stack inversion results. This integrated workflow provides an effective tool for building accurate 3D reservoir models, and is especially applicable to deep, low-porosity, tight sand reservoirs worldwide.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100477"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145618281","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":"Diagenetic controls on reservoir quality in deep ultra-thick sandstones: a case study from the Huagang Formation, Xihu Depression, East China Sea","authors":"Daowu Huang ,&nbsp;Yixiu Zhu ,&nbsp;Zhaoliang Yan ,&nbsp;Xianke He ,&nbsp;Chengshan Li ,&nbsp;Chuangxin Liu ,&nbsp;Binbin Liu","doi":"10.1016/j.engeos.2025.100474","DOIUrl":"10.1016/j.engeos.2025.100474","url":null,"abstract":"<div><div>Tight sandstone reservoirs represent a pivotal unconventional oil and gas production target. The upper section of the deeply buried Huagang Formation in the Xihu Depression is abundant in hydrocarbons and forms a tight reservoir. It exhibits substantial diagenetic variability and strong heterogeneity in sand bodies, which is reflected in variations in physical properties and grain size. Through integrated geological analysis, including rock thin sections, scanning electron microscopy, X-ray diffraction, well logging and production test data, we investigated the diagenesis, reservoir formation mechanisms, and controlling factors of high-quality reservoirs within the superposed sandstone bodies exceeding 100 m thick in the deeper Huagang Formation. We also studied the formation characteristics of these ultra-thick sandstones, clarifying that diagenesis and post-depositional modification are crucial for developing high-quality reservoirs in this formation. Our findings indicate that the sandstone underwent compaction, cementation (by chlorite, calcite and quartz), dissolution (of K-feldspar and carbonate cement), and authigenic clay mineral cementation (such as illite, chlorite, kaolinite). Multiple dissolution zones are present within the thick sandstone units. The distribution of these dissolution zones is mainly controlled by temperature and sandstone composition. With increasing temperature, acidic fluids derived from coal-bearing strata and early hydrocarbon source rocks promoted feldspar dissolution. The thick sandstone units in different intervals of varying depths are at various diagenetic stages. The petrophysical zoning of the reservoir is collectively controlled by diagenetic facies dominated by sedimentation, compaction, and dissolution processes. These findings provide valuable guidance and reference for oil and gas exploration and development in this area, particularly within the ultra-thick sandstone layers.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100474"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146172624","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":"Multi-source and multi-attribute collaborative fracture network modeling of a sandstone reservoir in Ordos Basin","authors":"Yinbang Zhou","doi":"10.1016/j.engeos.2025.100462","DOIUrl":"10.1016/j.engeos.2025.100462","url":null,"abstract":"<div><div>The effective channeling of fluid flow by fractures is a liability for enhanced oil recovery (EOR) methods like CO₂ flooding or CO₂ storage. Developing a distributed fracture model to understand the heterogeneity of the fracture network is essential in characterizing tight and low-permeability reservoirs. In the Ordos Basin, the Chang 8-1-2 layer of the Yanchang Formation is a typical tight and low permeability reservoir in the JH17 wellblock. The strong heterogeneity of distributed fractures, differing fracture scales and fracture types make it difficult to effectively characterize the fracture distribution within the Chang 8-1-2 layer. In this paper, multi-source and multi-attribute methods are used to integrate data into a neural network at different scales, and fuzzy logic control is used to judge the correlation of various attributes. The results suggest that attribute correlation between coherence and fracture indication is the best, followed by correlations with fault distance, north–south slope, and north–south curvature. Advantageous attributes from the target area are used to train the neural network, and the fracture density model and discrete fracture network (DFN) model are built at different scales. This method can be used to effectively predict the distribution characteristics of fractures in the study area. And any learning done by the neural network from this case study can be applied to fracture network modeling for reservoirs of the same type.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"7 1","pages":"Article 100462"},"PeriodicalIF":3.6,"publicationDate":"2026-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146172623","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}