Energy Geoscience最新文献

{"title":"Organic pore heterogeneity and its impact on absorption capacity in shale reservoirs in the Wufeng and Longmaxi formations, South China","authors":"Yuying Zhang ,&nbsp;Zhiliang He ,&nbsp;Shuangfang Lu ,&nbsp;Dianshi Xiao ,&nbsp;Yifei Li ,&nbsp;Yang Liu","doi":"10.1016/j.engeos.2025.100427","DOIUrl":"10.1016/j.engeos.2025.100427","url":null,"abstract":"<div><div>This study aims to determine the variation and controlling factors of shale gas adsorption capacity in reservoirs in the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation (also referred to as the WF-LMX formations), South China. Based on data obtained using scanning helium ion microscopy (HIM) and nitrogen (N₂) and methane (CH₄) adsorption experiments, this study analyzed the organic pore heterogeneity of shales in the WF-LMX formations in well A and its effect on shale gas adsorption. Using the Frenkel-Halsey-Hill (FHH) model, data from N₂ adsorption experiments were converted into fractal dimensions, which can reflect the complexity and heterogeneity of organic pores while also serving as a novel indicator for quantitatively assessing the pore structure complexity. The results indicate that shales in the WF-LMX formations in well A can be divided into two sections: (Ⅰ) the Wufeng Formation and the lower Longmaxi Formation (depths: ca. 2871.0–2898.6 m), and (Ⅱ) the upper Longmaxi Formation (depths: &lt; 2871.0 m). Organic pores in Section Ⅰ typically exhibit complex internal structures, coarse surfaces, and interconnectivity, whereas those in Section Ⅱ are simple, smooth, and isolated. Moreover, the former possesses larger specific surface areas (SSAs) than the latter. A fractal analysis reveals that organic pores in the shale sequence can be classified into micropores (&lt;2 nm), mesopores (2–10 nm), and macropores (&gt;10 nm). The calculated fractal dimensions show greater heterogeneity of organic pores, especially macropores, in Section Ⅰ compared to Section Ⅱ. The results also reveal that organic macropores are the primary pores controlling the SSAs of organic pores in shale reservoirs in the WF-LMX formations. Organic pores in Section Ⅰ manifest a superior shale gas adsorption capacity compared to Section Ⅱ. The heterogeneity of organic pores might affect the adsorption capacity of shales in the formations. Generally, organic macropores in Section Ⅰ of the shale sequence exhibit more complex structures and larger SSAs, leading to a stronger absorption capacity of shale reservoirs in Section Ⅰ compared to Section Ⅱ.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100427"},"PeriodicalIF":0.0,"publicationDate":"2025-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144480802","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":"Enhanced understanding of carbonate-rich shale heterogeneity through multifractal characterization based on N2 adsorption data: A case study of the Permian Wujiaping Formation in the Sichuan Basin","authors":"Bao Zhang ,&nbsp;Li Liu ,&nbsp;Aiwei Zheng ,&nbsp;Detian Yan ,&nbsp;Xiaoming Wang ,&nbsp;Jikang Wang ,&nbsp;Kai Li ,&nbsp;Yuhao Yi","doi":"10.1016/j.engeos.2025.100426","DOIUrl":"10.1016/j.engeos.2025.100426","url":null,"abstract":"<div><div>The carbonate-rich shale of the Permian Wujiaping Formation in Sichuan Basin exhibits significant heterogeneity in its lithology and pore structure, which directly influence its potential for shale gas extraction. This study assesses the factors that govern pore heterogeneity by analyzing the mineral composition of the shale, as well as its pore types and their multifractal characteristics. Three primary shale facies—siliceous, mixed, and calcareous—are identified based on mineralogy, and their multifractal characteristics reveal strongly heterogeneous pore structures. The brittleness of siliceous shale, rich in quartz and pyrite, is favorable for hydraulic fracturing; while calcareous shale, with higher levels of calcite, exhibits reduced brittleness. Multifractal analysis, using nitrogen adsorption isotherms, reveals complex pore structures across different shale facies, with siliceous shale showing better pore connectivity and uniformity. The types of pores in shales include organic matter pores, interparticle pores, and intraparticle pores, among which organic matter pores are the most abundant. Pore size distribution and connectivity are notably higher in siliceous shale compared to calcareous shale, which exhibit a predominance of micropores and more isolated pore structures. Pore heterogeneity of the carbonate-rich shale in the Wujiaping Formation is primarily governed by its intrinsic mineral composition, carbonate diagenesis, mechanical compaction, and its subsequent thermal maturation with the micro-migration of organic matter. This study highlights the importance of mineral composition, especially the presence of dolomite and calcite, in shaping pore heterogeneity. These findings emphasize the critical role of shale lithofacies and pore structure in optimizing shale gas extraction methods.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100426"},"PeriodicalIF":0.0,"publicationDate":"2025-05-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144321495","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":"Cambrian-Devonian paleogeographic evolution of the western and central segments of North Africa","authors":"Yilin Li ,&nbsp;Zhiqiang Feng ,&nbsp;Naixi Zheng ,&nbsp;Lei Li ,&nbsp;Zongfeng Li ,&nbsp;Hancheng Ji ,&nbsp;Zhidong Bao","doi":"10.1016/j.engeos.2025.100417","DOIUrl":"10.1016/j.engeos.2025.100417","url":null,"abstract":"<div><div>This study reconstructs the lithofacies and paleogeographic evolution of North Africa during the Cambrian to Devonian periods, emphasizing the influence of tectonic events, sea-level fluctuations, and climatic changes on the region's depositional systems and basin development. Integrating seismic, well log, and core data, we identify key depositional patterns and their implications for hydrocarbon exploration. During sedimentation of diverse stages, the source-to-sink systems underwent significant transitions under provenance variation. During the Cambrian–Ordovician periods, intracratonic sag basins dominated, with braided river systems transitioning into glacial deposits in response to climatic cooling and glaciation. Under the control of the source-to-sink system, Silurian witnessed the opening of the Paleo-Tethys Ocean, leading to extensive marine transgressions and the deposition of organic-rich shales of the Lower Silurian, a primary hydrocarbon source rock. Regression during the Late Silurian introduced deltaic and fluvial systems, influenced by tectonic uplifting. During the Devonian period, the Hercynian Orogeny significantly impacted basin architecture, facilitating the development of passive margin basins. Braided and meandering river systems transitioned into deltaic and shallow marine environments, with Late Devonian anoxic conditions fostering the formation of additional hydrocarbon source rocks. This research highlights the interplay of tectonics, climate, and sea-level changes in shaping North Africa's sedimentary history. The findings provide critical insights into the distribution of hydrocarbon source and reservoir rocks, offering valuable guidance for exploration and development in the region.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100417"},"PeriodicalIF":0.0,"publicationDate":"2025-05-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144123979","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":"2025-05-16","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":"Transient well-test model of a slanted well in a heterogeneous multi-zonal reservoir","authors":"Renshi Nie ,&nbsp;Letian Zhang ,&nbsp;Yu Xiong ,&nbsp;Changjian Gan ,&nbsp;Tao Zhang ,&nbsp;Shanshan Lu ,&nbsp;Yangyang Chen ,&nbsp;Jie Zhan","doi":"10.1016/j.engeos.2025.100415","DOIUrl":"10.1016/j.engeos.2025.100415","url":null,"abstract":"<div><div>To enhance the comprehension of flow characteristics and enrich the well-test theory of slanted wells, this study established a well-test model for a slanted well in a heterogeneous multi-zonal reservoir. The model considered closed boundaries at both the top and bottom, as well as an external boundary with infinite, closed, or constant pressure on the horizontal plane. We took the bi-zonal composite model as an example to carry out concrete analysis. Various contemporary mathematical techniques, including Laplace integral transformation, separation of variables, and eigenfunction methods, were employed to solve the model. The pressure solution in real space was obtained through Duhamel's principle and Stehfest numerical inversion, then analytical curves created, and flow stages were defined for a slanted well in a bi-zonal composite reservoir. In addition, we performed a sensitivity analysis on some parameters affecting the curves. For a tri-zonal composite model, we also plotted the well-test curves and categorized them. Finally, we validated the model through the interpretation of an example well. The results show that the fluid flow of a slanted well in a bi-zonal composite reservoir can be divided into seven main stages, including wellbore storage effect (WSE) stage, skin effect (SE) stage, linear flow (LF) stage, radial flow (RF) stage of the 1st zone, transitional flow (TF) stage from the 1st to the 2nd zone, RF stage of the 2nd zone, and the external boundary response stage. The position of the pressure curve at the SE stage and LF stage decreases as the length and inclination angle increase. Correspondingly, the pressure curve at the RF stage of the 2nd zone and external boundary response stage decreases with increasing mobility ratio. Furthermore, as the radius of the 1st zone increases, the pressure curve at the RF stage of the 1st zone and the TF stage shifts towards the right. The established model and plotted curves provide a theoretical basis for further studies on the flow behavior of slanted wells in composite reservoirs.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100415"},"PeriodicalIF":0.0,"publicationDate":"2025-05-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144195609","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 technologies for increasing production based on the best practices of major shale oil and gas basins","authors":"Jon Jincai Zhang,&nbsp;Zhihui Fan","doi":"10.1016/j.engeos.2025.100414","DOIUrl":"10.1016/j.engeos.2025.100414","url":null,"abstract":"<div><div>Key technologies that make productivity increase are revealed through analyzing the best practices and production data in major shale basins of North America. Trends of the key technologies and optimization designs for shale oil and gas development are summarized and analyzed based on drilling and completion operations and well data. These technologies mainly include: (1) Optimizing well design and hydraulic fracturing design, including reducing cluster spacing, increasing proppant and fracturing fluid volumes, optimizing horizontal well lateral length and fracture stage length. The most effective method is to reduce cluster spacing to an optimized length. The second most effective method is to optimally increase proppant volumes. (2) Placing horizontal wells in the sweet spots and drilling the wells parallel or close to the minimum horizontal stress direction. (3) Using cube development with optimized well spacing to maximize resource recovery and reduce well interferences. Plus, in-situ stress impacts on hydraulic fracture propagation and hydrocarbon production are addressed. Determination of formation breakdown pressure is studied by considering the impacts of in-situ stresses, drilling and perforation directions. Whether or not the hydraulic fracturing can generate orthogonal fracture networks is also discussed. The key technologies and optimization design parameters proposed in this paper can be applied to guide new well placement, drilling and completion designs, and hydraulic fracture operations to increase productivity.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100414"},"PeriodicalIF":0.0,"publicationDate":"2025-05-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144170234","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 characteristics and potential of liptinite-rich coal in China","authors":"Yuting Yin ,&nbsp;Dongdong Wang ,&nbsp;Lei Lan ,&nbsp;Youchuan Li ,&nbsp;Haiyan Liu ,&nbsp;Zengxue Li ,&nbsp;Yan Liu","doi":"10.1016/j.engeos.2025.100413","DOIUrl":"10.1016/j.engeos.2025.100413","url":null,"abstract":"<div><div>Coal-measure source rocks may play an important role in hydrocarbon generation in petroliferous basins where coal seams are well developed. Hydrocarbon generation characteristics and potential of coal-measure source rocks have been well documented for continental petroliferous basins, while the understanding of coal-measure source rocks in offshore basins is yet to be delved into. Significant oil exploration breakthroughs have been made in the well-developed coal measures of Turpan–Hami Basin (THB), a typical continental petroliferous basin in northwestern China. In this study, a comparative analysis is conducted on the Paleogene coal seams in the Zhu I Depression (ZID), located in the northern part of the South China Sea, and the Jurassic coal seams in the THB in terms of genetic conditions, mineral composition, and hydrocarbon generation potential. The geological understandings are obtained as follows. Both the coal-forming periods during the deposition of the ZID and THB were of a warm and wet climate type. The Paleogene coal-forming environments during the deposition of the ZID mainly include peat swamp in the upper plain and interdistributary bays in the lower plain of the braided river delta, along with littoral shallow lakes. As a whole, the coal seams are characterized by multiple layers, thin single layer thickness and poor stability, while those in the upper plain peat swamp of the braided river delta have relatively larger single layer thickness but relatively fewer number of layers. The Jurassic coal-forming environments in the THB include peat swamp in the upper delta plain, lower delta plain, and inter-delta bay. The coal seams formed in the lower delta plain are the most stable, while those in the inter-delta bay are the thickest. The ZID coal has a higher vitrinite content (averaging 76.11 %) and liptinite content (averaging 10.77 %) compared to its THB counterpart, which has an average vitrinite content of 68.28 % and average liptinite content of 7.61 %. The kerogen of the ZID coal is mainly of type II₁, while that of the THB coal mainly of type II₂, followed by type Ⅲ. Both the ZID and THB coals have entered the oil-generation window, as indicated by their maximum vitrinite reflectance values (<em>R</em>_{o, max}, %), reflecting good oil generation capacity. However, the hydrocarbon generation potential of the ZID coal is higher than that of the THB.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100413"},"PeriodicalIF":0.0,"publicationDate":"2025-04-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143943332","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 data-driven PCA-RF-VIM method to identify key factors driving post-fracturing gas production of tight reservoirs","authors":"Yifan Zhao ,&nbsp;Xiaofan Li ,&nbsp;Lei Zuo ,&nbsp;Zhongtai Hu ,&nbsp;Liangbin Dou ,&nbsp;Huagui Yu ,&nbsp;Tiantai Li ,&nbsp;Jun Lu","doi":"10.1016/j.engeos.2025.100411","DOIUrl":"10.1016/j.engeos.2025.100411","url":null,"abstract":"<div><div>Hydraulic fracturing technology has achieved remarkable results in improving the production of tight gas reservoirs, but its effectiveness is under the joint action of multiple factors of complexity. Traditional analysis methods have limitations in dealing with these complex and interrelated factors, and it is difficult to fully reveal the actual contribution of each factor to the production. Machine learning-based methods explore the complex mapping relationships between large amounts of data to provide data-driven insights into the key factors driving production. In this study, a data-driven PCA-RF-VIM (Principal Component Analysis-Random Forest-Variable Importance Measures) approach of analyzing the importance of features is proposed to identify the key factors driving post-fracturing production. Four types of parameters, including log parameters, geological and reservoir physical parameters, hydraulic fracturing design parameters, and reservoir stimulation parameters, were inputted into the PCA-RF-VIM model. The model was trained using 6-fold cross-validation and grid search, and the relative importance ranking of each factor was finally obtained. In order to verify the validity of the PCA-RF-VIM model, a consolidation model that uses three other independent data-driven methods (Pearson correlation coefficient, RF feature significance analysis method, and XGboost feature significance analysis method) are applied to compare with the PCA-RF-VIM model. A comparison the two models shows that they contain almost the same parameters in the top ten, with only minor differences in one parameter. In combination with the reservoir characteristics, the reasonableness of the PCA-RF-VIM model is verified, and the importance ranking of the parameters by this method is more consistent with the reservoir characteristics of the study area. Ultimately, the ten parameters are selected as the controlling factors that have the potential to influence post-fracturing gas production, as the combined importance of these top ten parameters is 91.95 % on driving natural gas production. Analyzing and obtaining these ten controlling factors provides engineers with a new insight into the reservoir selection for fracturing stimulation and fracturing parameter optimization to improve fracturing efficiency and productivity.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 2","pages":"Article 100411"},"PeriodicalIF":0.0,"publicationDate":"2025-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143868279","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"An intelligent log-seismic integrated stratigraphic correlation method based on wavelet frequency-division transform and dynamic time warping: A case study from the Lasaxing oilfield","authors":"Mian Lu ,&nbsp;Dongmei Cai ,&nbsp;Xiandi Fu ,&nbsp;Shunguo Cheng ,&nbsp;Yu Sun ,&nbsp;Pengkun Liu ,&nbsp;Yanli Jiao","doi":"10.1016/j.engeos.2025.100412","DOIUrl":"10.1016/j.engeos.2025.100412","url":null,"abstract":"<div><div>Stratigraphic correlations are essential for the fine-scale characterization of reservoirs. However, conventional data-driven methods that rely solely on log data struggle to construct isochronous stratigraphic frameworks for complex sedimentary environments and multi-source geological settings. In response, this study proposed an intelligent, automatic, log-seismic integrated stratigraphic correlation method that incorporates wavelet frequency-division transform (WFT) and dynamic time warping (DTW) (also referred to as the WFT-DTW method). This approach integrates seismic data as constraints into stratigraphic correlations, enabling accurate tracking of the seismic marker horizons through WFT. Under the constraints of framework construction, a DTW algorithm was introduced to correlate sublayer boundaries automatically. The effectiveness of the proposed method was verified through a stratigraphic correlation experiment on the SA0 Formation of the Xingshugang block in the Lasaxing oilfield, the Songliao Basin, China. In this block, the target layer exhibits sublayer thicknesses ranging from 5 m to 8 m, an average sandstone thickness of 2.1 m, and pronounced heterogeneity. The verification using 1760 layers in 160 post-test wells indicates that the WFT-DTW method intelligently compared sublayers in zones with underdeveloped faults and distinct marker horizons. As a result, the posterior correlation of 1682 layers was performed, with a coincidence rate of up to 95.6 %. The proposed method can complement manual correlation efforts while also providing valuable technical support for the lithologic and sand body characterization of reservoirs.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100412"},"PeriodicalIF":0.0,"publicationDate":"2025-04-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143923795","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":"GIS-based multi-criteria predictive modelling for geothermal energy exploration","authors":"Andongma Wanduku Tende ,&nbsp;Mamidak Miner Iiiya ,&nbsp;Serah Habu ,&nbsp;Jiriko Nzeghi Gajere ,&nbsp;Shekwonyadu Iyakwari ,&nbsp;Mohammed Dahiru Aminu","doi":"10.1016/j.engeos.2025.100409","DOIUrl":"10.1016/j.engeos.2025.100409","url":null,"abstract":"<div><div>Renewable energy resources, including geothermal, are crucial for sustainable environmental management and climate change mitigation, offering clean, reliable, and low-emission alternatives to fossil fuels that reduce greenhouse gases and support ecological balance. In this study, geographic information system (GIS) predictive analysis was employed to explore geothermal prospects, promoting environmental sustainability by reducing the dependence on fossil energy resources. Spatial and statistical analysis including the attribute correlation analysis was used to evaluate the relationship between exploration data and geothermal energy resources represented by hot springs. The weighted sum model was then used to develop geothermal predictive maps while the accuracy of prediction was determined using the receiver operating characteristic/area under curve (ROC/AUC) analysis. Based on the attribute correlation analysis, exploration data relating to geological structures, host rock (Asu River Group) and sedimentary contacts were the most critical parameters for mapping geothermal resources. These parameters were characterized by a statistical association of 0.52, 0.48, and 0.46 with the known geothermal occurrences. Spatial data integration reveals the central part of the study location as the most prospective zone for geothermal occurrences. This zone occupies 14.76 % of the study location. Accuracy assessment using the ROC/AUC analysis suggests an efficiency of 81.5 % for the weight sum model. GIS-based multi-criteria analysis improves the identification and evaluation of geothermal resources, leading to better decision-making.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 2","pages":"Article 100409"},"PeriodicalIF":0.0,"publicationDate":"2025-04-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143839332","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}