Energy Geoscience最新文献

{"title":"Evaluating poro-elastic production drive mechanisms: Quantifying the potential contribution to well-rates and risk of core handling damage inflating pore-volume compressibility measurements","authors":"Ruud Weijermars","doi":"10.1016/j.engeos.2025.100432","DOIUrl":"10.1016/j.engeos.2025.100432","url":null,"abstract":"<div><div>By analyzing core data from an offshore Gulf of Mexico reservoir and developing analytical solutions, it can be demonstrated that laboratory measurements on pore-volume compressibility include artifacts, leading to a misinterpretation of porosity and permeability trends. A systematic evaluation of poro-elastic changes in pore volumes (and quantifying any consequent fluid expulsion during reservoir compaction) suggests that poro-elastic relaxation may enhance fluid production rates from deep reservoirs by up to 25 %. This value may be inadvertently inflated if the core samples used for pore-volume compressibility measurements suffered from handling damage. Nonetheless, poro-elastic fluid expulsion from the pores in producing reservoirs can provide additional lift and thus may enhance the recovery factor. Therefore, the possible contribution to well performance from poro-elastic production drive mechanisms ought to be carefully evaluated in reserves estimation. Reversely, injection wells may encounter poro-elastic suppression of injectivity due to elastic resistance, which would adversely affect the storage coefficient. By integrating geomechanical reservoir response with traditional fluid production models, reservoir model predictions of production under pressure depletion and injection conditions will be more accurate. The new insights reported here are essential for optimizing well performance, improving reservoir management, and extending the economic life of geological reservoirs. However, caution is warranted regarding pore-volume compressibility measurements. To what degree laboratory measurements of pore-volume compressibility measure true values or mainly record handling damage could not be conclusively settled in the present study.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100432"},"PeriodicalIF":0.0,"publicationDate":"2025-06-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144548787","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":"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":"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":"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}