Energy Geoscience最新文献

{"title":"Spatiotemporal distribution patterns and exploration implications of multi-type coal-measure gases in the Daniudi gas field, Ordos Basin, China","authors":"Zhenrui Bai ,&nbsp;Fengcun Xing ,&nbsp;Zengqin Liu","doi":"10.1016/j.engeos.2025.100431","DOIUrl":"10.1016/j.engeos.2025.100431","url":null,"abstract":"<div><div>Coal-measure gas is a primary target with significant potential for the exploration of unconventional hydrocarbon resources. However, the spatiotemporal distribution and combination patterns of multi-type coal-measure gases are yet to be clarified, directly impeding the sweet spot evaluation and exploration deployment of coal-measure gas. This study discussed the characteristics and distribution patterns of coal-measure gases in the Daniudi gas field in northeastern Ordos Basin, China, with abundant drilling data. The results indicate that the coal seams variably thin upward and are mainly seen in the first and second members of the Taiyuan Formation (also referred to as the Tai 1 and Tai 2 members, respectively) and the first member of the Shanxi Formation (Shan 1 Member). Nos. 8, 5 and 3 coal seams are laterally continuous, and significantly thicker in its southern part compared to the northern part. Moreover, carbonaceous mudstones and shales are better developed in the southern part, where limestones are only observed in the Tai 1 Member. Based on the main lithological types, we identified three lithologic roofs of coal seams, that is, limestone, mudstone, and sandstone, which determine the spatiotemporal distribution of coal-measure gases. Besides bauxite gas in the Benxi Formation, the coal-measure gases include tight-sand gas, coalbed methane (CBM), coal-measure shale gas, and tight-limestone gas, with CBM typically associated with coal-measure shale gas. The combinations of different types of coal-measure gas vary across different layers and regions. Tight-sand gas is well-developed in areas where tight sandstones are in contact with coal-measures. From the Taiyuan to the Shanxi formations, CBM gradually transitions into a combination of CBM and coal-measure shale gas, and coal-measure shale gas. Nos.8 and 5 coal seams in low-lying areas exhibit favorable gas-bearing properties due to their large thickness and favorable roof lithologies, serving as prospective play fairways. Mudstone and limestone roofs are more conducive to achieving good gas-bearing properties. The direct contact between sandstones and coal seams tends to result in the formation of tight-sand gas and a reduced gas content of CBM. While focusing on single types of gas reservoirs such as CBM and tight-sand gas, it is essential to consider the concurrent exploration of various coal-measure gas combinations to discover more additional gas resources and guide exploration deployment.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100431"},"PeriodicalIF":0.0,"publicationDate":"2025-06-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144338541","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":"Characteristics of pore-throat structures in volatile oil reservoirs and strategies for optimal development","authors":"Ying Tang ,&nbsp;Zhao Li ,&nbsp;Shuai Yin ,&nbsp;Ruifei Wang ,&nbsp;Kai Feng ,&nbsp;Tao Jiang","doi":"10.1016/j.engeos.2025.100430","DOIUrl":"10.1016/j.engeos.2025.100430","url":null,"abstract":"<div><div>The third member of Shahejie Formation (also referred to as Sha 3 Member) in Dongpu Depression, China, a volatile, low-permeability oil reservoir with complex fluid compositions, is subjected to high temperature and high pressure (HPHT), which poses significant challenges to conventional water injection. To elucidate flow mechanisms and optimize development strategies, this study integrates constant-rate mercury injection (CRMI), nuclear magnetic resonance (NMR), and HPHT three-phase oil/gas/water relative permeability experiments to analyze pore-throat structures, movable fluid characteristics, and relative permeability. The CRMI results indicate that the reservoir exhibits low porosity and low permeability, with dominant throat radius ranging from 0.6 to 5.0 μm, and mean pore-throat radius ratio ranging from 40.303 to 278.320, demonstrating significant microscopic heterogeneity. The NMR results reveal that water-alternating-gas (WAG) injection enhances oil recovery by 16.28 % (Sample W1) and 13.52 % (Sample W2) compared to conventional water injection, primarily due to the gas phase's low viscosity and high mobility, enabling access to micropores unreachable by water phases. The HPHT three-phase relative permeability tests demonstrate positive correlations between saturation and relative permeability, with oil permeability significantly influenced by three-phase saturation and rock wettability. These findings establish a microscopic seepage model for optimizing enhanced oil recovery (EOR) strategies in volatile reservoirs.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100430"},"PeriodicalIF":0.0,"publicationDate":"2025-06-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144321637","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 investigation of the heat extraction performance of an enhanced geothermal system using H2, CO2, and H2O as working fluids","authors":"Dandan Wang ,&nbsp;Xiong Wu ,&nbsp;Pu Zhao ,&nbsp;Huiming Fang ,&nbsp;Zhiwei Dang ,&nbsp;Zhewei Shi ,&nbsp;Chao Huo","doi":"10.1016/j.engeos.2025.100429","DOIUrl":"10.1016/j.engeos.2025.100429","url":null,"abstract":"<div><div>The optimization of working fluids in single-well coaxial geothermal systems presents a critical pathway for advancing the use of enhanced geothermal systems (EGS) in renewable energy applications. This study evaluates the thermo-hydraulic performance of three working fluids (H₂O, CO₂, and H₂) in a single-well coaxial geothermal system, focusing on the effects of their injection temperatures. Using a 3D finite element model in COMSOL Multiphysics, simulations were conducted at three injection temperatures (17 °C, 27 °C, 40 °C) under constant mass flow rates. The results reveal that hydrogen significantly outperforms water and carbon dioxide, achieving a 297.77 % and 5453.76 % higher thermal output, respectively. Notably, the heat transfer efficiency is significantly improved when the injected working fluids are at 40 °C, compared to 27 °C; this demonstrates a positive correlation between injection temperature and thermal recovery. Though water systems exhibit better geological compatibility, the superior thermal properties of hydrogen position it as a promising alternative—despite potential subsurface challenges. This study provides critical insights for advancing the application of high-efficiency geothermal systems as well as the development of non-aqueous working fluids, thus contributing to the sustainable utilization of geothermal energy.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100429"},"PeriodicalIF":0.0,"publicationDate":"2025-06-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144308026","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":"Facies and NMR-based petrophysical analyses of the Apollonia unconventional gas reservoir: A case study from the BED 9 field, Abu Gharadig Basin, North Western Desert, Egypt","authors":"Reem Roshdy ,&nbsp;Mohsen Abdelfattah ,&nbsp;Ilius Mondal ,&nbsp;Abdelrahman Abdelsamad ,&nbsp;Patricia Pinheiro Beck Eichler ,&nbsp;Mohamed Elkammar ,&nbsp;Rania Abu-Ali","doi":"10.1016/j.engeos.2025.100428","DOIUrl":"10.1016/j.engeos.2025.100428","url":null,"abstract":"<div><div>The Early Paleocene to Middle Eocene Apollonia Formation in the BED<strong>‒</strong>9 field has been particularly interesting for unconventional hydrocarbon exploration since its discovery in 2006. However, the multiscale compositional and diagenetic inconsistencies present challenges for its characterization. This study aims to evaluate the petrophysical properties of the Apollonia Formation to locate the sweet-spot intervals. Moreover, it seeks to investigate reservoir rock types (RRTs), depositional settings, and the impact of diagenesis on reservoir quality. The findings of this study are as follows. 1) The Apollonia A5 and C1 units are identified as \"sweet-spot\" intervals. Their effective porosity ranges from 18 % to 35 %, average permeability varies from 0.1 to 2.0 mD, and water saturation falls between 40 % and 50 %, indicating good reservoir quality. 2) High-order eustatic sea-level changes and repetitive climatic change cycles significantly influence the alternating carbonate productivity and dilution cycles. Five distinct RRTs are classified, denoting a gradational facies change from clean, argillaceous, and carbonaceous chalky limestone to marl and interbedded shale intervals. 3) Interpreting the electro-facies responses, collated with microfacies variations and faunal content, deepens our understanding of the depositional environment, which extends from the inner-to outer-shelf setting. 4) The diagenetic processes have a dual impact that enhances and diminishes the reservoir quality. Finally, the gap in evaluating the petrophysical characteristics of all the Apollonia members has been addressed based on integrating the petrophysical and facies analysis for A, B, and C members. The Apollonia Formation has unique characteristics as an unconventional hydrocarbon resource.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100428"},"PeriodicalIF":0.0,"publicationDate":"2025-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144365249","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":"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}