Petroleum Science最新文献

{"title":"Multivariate natural gas price forecasting model with feature selection, machine learning and chernobyl disaster optimizer","authors":"Pei Du ,&nbsp;Xuan-Kai Zhang ,&nbsp;Jun-Tao Du ,&nbsp;Jian-Zhou Wang","doi":"10.1016/j.petsci.2025.09.034","DOIUrl":"10.1016/j.petsci.2025.09.034","url":null,"abstract":"<div><div>The significance of accurately forecasting natural gas prices is far-reaching and significant, not only for the stable operation of the energy market, but also as a key element in promoting sustainable development and addressing environmental challenges. However, natural gas prices are affected by multiple source factors, presenting complex, unstable nonlinear characteristics hindering the improvement of the prediction accuracy of existing models. To address this issue, this study proposes an innovative multivariate combined forecasting model for natural gas prices. Initially, the study meticulously identifies and introduces 16 variables impacting natural gas prices across five crucial dimensions: the production, marketing, commodities, political and economic indicators of the United States and temperature. Subsequently, this study employs the least absolute shrinkage and selection operator, grey relation analysis, and random forest for dimensionality reduction, effectively screening out the most influential key variables to serve as input features for the subsequent learning model. Building upon this foundation, a suite of machine learning models is constructed to ensure precise natural gas price prediction. To further elevate the predictive performance, an intelligent algorithm for parameter optimization is incorporated, addressing potential limitations of individual models. To thoroughly assess the prediction accuracy of the proposed model, this study conducts three experiments using monthly natural gas trading prices. These experiments incorporate 19 benchmark models for comparative analysis, utilizing five evaluation metrics to quantify forecasting effectiveness. Furthermore, this study conducts in-depth validation of the proposed modelʼs effectiveness through hypothesis testing, discussions on the improvement ratio of forecasting performance, and case studies on other energy prices. The empirical results demonstrate that the multivariate combined forecasting method developed in this study surpasses other comparative models in forecasting accuracy. It offers new perspectives and methodologies for natural gas price forecasting while also providing valuable insights for other energy price forecasting studies.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages 4823-4837"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145698117","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Quantitative evaluation of brittleness anisotropy and its influencing factors in terrestrial shale","authors":"Jian-Yong Xie ,&nbsp;Yan-Ping Fang ,&nbsp;Chun-Wei Wu ,&nbsp;She-Bao Jiao ,&nbsp;Jing-Xiao Wang ,&nbsp;Ji-Xin Deng ,&nbsp;Xing-Jian Wang","doi":"10.1016/j.petsci.2025.07.026","DOIUrl":"10.1016/j.petsci.2025.07.026","url":null,"abstract":"<div><div>Brittleness is pivotal in predicting shale reservoir quality and designing hydraulic fracturing strategies. However, intricate diagenetic environment of shale, characterized by distinct bedding structures, challenges the isotropic-based brittleness assessment methods. This study introduces a new quantitative approach to assess shale brittleness anisotropy, integrating anisotropic elastic responses and tensile fracturing mechanisms. The proposed model effectively reduces uncertainty in the causal relationship between Young's modulus and brittle failure. Comprehensive experimental validation encompassed 18 samples from six groups of Chang 7 terrestrial shale in Ordos Basin. The optimal anisotropic tensile strength criterion (N-Z criterion, error &lt; 5%) was identified, enhancing the theoretical accuracy of the proposed model. Comparative experimental results demonstrate that the model adeptly predicts brittleness strength and directional variation characteristics across variations in mineral type, content and microstructure, underscoring its effectiveness. Additionally, theoretical predictions on shale samples with different organic matter reveal that brittleness strength and its anisotropy across varying OM are not monotonously decreasing. The research highlights that brittleness characteristics are influenced by both mineral type/content and microstructural distribution. Notably, the prevalence of isotropic brittle minerals is the primary determinant of brittleness strength, positively correlated. Conversely, ductile mineral content (striped skeletal support-type OM and clay) negatively correlates with brittleness strength, acting as secondary controlling factors. The impact of pore-filled OM on brittleness appears negligible. Rock physical modeling based on equivalent media theory for shale with pore-filled and/or striped OM further elucidates the mechanisms driving these variations. These findings attach great importance in assessment of terrestrial shale geological and engineering “sweet-spots\".</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages 4555-4572"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145697931","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental investigation into the fracture propagation behavior of horizontal well multi-stage and multi-cluster fracturing within the roof of crushed soft coal seams","authors":"Hai-Feng Zhao ,&nbsp;Jie-Lun Luo ,&nbsp;Xue-Jiao Li ,&nbsp;Wen-Jie Yao ,&nbsp;Liang Ji ,&nbsp;Huai-Bin Zhen","doi":"10.1016/j.petsci.2025.09.033","DOIUrl":"10.1016/j.petsci.2025.09.033","url":null,"abstract":"<div><div>The effectiveness of horizontal well multi-stage and multi-cluster fracturing in the fractured soft coal seam roof for coalbed methane (CBM) extraction has been demonstrated. This study focuses on the geological characteristics of the No. 5 and No. 11 coal seams in the Hancheng Block, Ordos Basin, China. A multi-functional, variable-size rock sample mold capable of securing the wellbore was developed to simulate layered formations comprising strata of varying lithology and thicknesses. A novel segmented fracturing simulation method based on an expandable pipe plugging technique is proposed. Large-scale true triaxial experiments were conducted to investigate the effects of horizontal wellbore location, perforation strategy, roof lithology, and vertical stress difference on fracture propagation, hydraulic energy variation, and the stimulated reservoir volume in horizontal wells targeting the soft coal seam roof. The results indicate that bilateral downward perforation with a phase angle of 120° optimizes hydraulic energy conservation, reduces operational costs, enhances fracture formation, and prevents fracturing failure caused by coal powder generation and migration. This perforation mode is thus considered optimal for coal seam roof fracturing. When the roof consists of sandstone, each perforation cluster tends to initiate a single dominant fracture with a regular geometry. In contrast, hydraulic fractures formed in mudstone roofs display diverse morphology. Due to its high strength, the sandstone roof requires significantly higher pressure for crack initiation and propagation, whereas the mudstone roof, with its strong water sensitivity, exhibits lower fracturing pressures. To mitigate inter-cluster interference, cluster spacing in mudstone roofs should be greater than that in sandstone roofs. Horizontal wellbore placement critically influences fracturing effectiveness. For indirect fracturing in sandstone roofs, an optimal position is 25 mm away from the lithological interface. In contrast, the optimal location for indirect fracturing in mudstone roofs is directly at the lithological interface with the coal seam. Higher vertical stress coefficients lead to increased fracturing pressures and promote vertical, layer-penetrating fractures. A coefficient of 0.5 is identified as optimal for achieving effective indirect fracturing. This study provides valuable insights for the design and optimization of staged fracturing in horizontal wells targeting crushed soft coal seam roofs.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages 4682-4713"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145698016","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"TOC","authors":"","doi":"10.1016/S1995-8226(25)00443-1","DOIUrl":"10.1016/S1995-8226(25)00443-1","url":null,"abstract":"","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages i-ii"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145697829","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effects of natural fractures in cap rock on CO2 geological storage: Sanduo Formation and Dainan Formation of the early Eocene epoch in the Gaoyou Sag of the Subei Basin","authors":"Yun-Zhao Zhang ,&nbsp;Quan-Qi Dai ,&nbsp;Lian-Bo Zeng ,&nbsp;Rui-Qi Li ,&nbsp;Rong-Jun Zhang ,&nbsp;Le Qu ,&nbsp;Yang-Wen Zhu ,&nbsp;Hai-Ying Liao ,&nbsp;Hao Wu","doi":"10.1016/j.petsci.2025.08.002","DOIUrl":"10.1016/j.petsci.2025.08.002","url":null,"abstract":"<div><div>During the CO₂ injection and geological storage process, the integrity of the cap rock significantly influences the long-term safety of CO₂ storage. Natural fractures within the cap rock serve as potential pathways for CO₂ migration, thereby increasing the risk of CO₂ leakage. In this study, we determined the types, developmental characteristics, permeability changes, and CO₂-H₂O-Rock reactions of natural fractures in the mudstone cap rocks of the Sanduo Formation (E₃s) and Dainan Formation (E₂d) in the Gaoyou Sag of the Subei Basin using core observations, thin-section analysis, rock mechanics experiments, and paleomagnetic directional analysis. We identified four tectonic fracture sets (NNW, NWW, EW, and NE); high-angle shear fractures, ranging from 60° to 90° (average 82°) and typically measuring 4–12 cm (average 7.5 cm), dominate the assemblage, while slip fractures, ranging from 32° to 50° (average 36°) and measuring 3–6 cm (average 3.9 cm), are also present. At the microscale, shear fractures average 160 μm, and bedding fractures average 82 μm. Notably, 85.78% of shear fractures are unfilled, with calcite filling observed in 14.22%, while other fracture types show no filling. Permeability tests on samples without fractures reveal that permeability declines rapidly below 9 MPa, especially in shallower samples, followed by a slower reduction between 9 and 13 MPa, and ultimately stabilizes at approximately 0.00003 mD. In contrast, samples with fractures exhibit permeability that is 3–4 orders of magnitude higher; their fracture permeability decays according to a power law with pressure yet remains above 10 mD even at 46 MPa. Fractures with larger dip angles and those aligned with the maximum principal stress demonstrate the highest permeability. While silicate-filled fractures exhibit negligible changes in permeability, carbonate-filled fractures experience a temporary enhancement due to dissolution; however, subsequent permeability remains controlled by factors such as effective stress and fracture orientation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages 4341-4356"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145697804","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimization and application of KCl polymer drilling fluid balancing wellbore stability and logging response accuracy","authors":"Xin Zhao ,&nbsp;Ying-Bo Wang ,&nbsp;Fu-Hua Cao ,&nbsp;Cao-Yuan Niu ,&nbsp;Zi-Qing Liu ,&nbsp;Lei Wang","doi":"10.1016/j.petsci.2025.10.012","DOIUrl":"10.1016/j.petsci.2025.10.012","url":null,"abstract":"<div><div>In Dagang Oilfield in China, the utilization of the KCl polymer water-based drilling fluid (WBDF) in mid-deep exploration/appraisal wells presents a challenge in simultaneously optimizing resistivity logging accuracy and wellbore stability. To address this, it is necessary to conduct geology-engineering integration studies. Based on the formation resistivity, an analytical model was developed to assess the impact of KCl concentration in the WBDF on array induction logging response accuracy. The maximum permissible KCl concentration for the target formations was determined, and technical strategies were proposed to maintain wellbore stability at a reduced KCl concentration. After that, considering the inhibitory, encapsulating, and plugging effects, a low-KCl-concentration WBDF was optimized and applied. Model calculations demonstrate that increasing KCl concentration in the WBDF decreases resistivity, thereby reducing logging accuracy. To maintain a logging accuracy of ≥80%, the upper limits for KCl concentration in the WBDF are 4.8%, 4.2%, and 3.6% for the 3rd Member of the Dongying Formation, the 1st and 2nd members of the Shahejie Formation, respectively. Cuttings recovery experiments revealed that a minimum KCl concentration of 3% is required to ensure basic shale inhibition. A combination of 3% KCl with 1% polyamine inhibitor yielded cuttings recovery and shale stability index comparable to those achieved with 7% KCl alone, and the shale inhibition performance was further enhanced with the addition of an encapsulator. The optimized WBDF has been successfully deployed in exploration/appraisal wells across multiple blocks within Dagang Oilfield, resulting in superior wellbore stability during operations. Furthermore, the electric logging interpretation coincidence rate improved from 68.1% to 89.9%, providing robust technical support for high-quality drilling and accurate reservoir evaluation in exploration/appraisal wells.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages 4645-4655"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145698014","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Near-wellbore 3D velocity imaging inversion method based on array acoustic logging data","authors":"Zi Wang ,&nbsp;Wen-Zheng Yue ,&nbsp;Yu-Ming Zhu ,&nbsp;Nai-Xuan Ji ,&nbsp;Shan-Shan Fan","doi":"10.1016/j.petsci.2025.06.023","DOIUrl":"10.1016/j.petsci.2025.06.023","url":null,"abstract":"<div><div>The characterization of subsurface formations via the analysis of near-wellbore velocity profiles represents a crucial method in geophysical exploration. This technique enables the evaluation of key parameters, including rock brittleness, wellbore stability, fracturing effects, and invasion extent, thereby enhancing comprehension of formation structures and informing exploration strategies. However, traditional near-wellbore formation velocity imaging methods exhibit two principal limitations. First, these methods lack azimuthal sensitivity, yielding results averaged across all directions. Second, they are computationally intensive and impractical for well-site environments. To address these drawbacks, we developed a rapid 3D velocity imaging method for array acoustic logging instruments equipped with azimuthal receivers, capable of producing 3D imaging results efficiently. The workflow entails the following steps: (1) Band-pass filtering of logging data to mitigate scattered wave interference caused by formation heterogeneity near the wellbore; (2) combination of receivers with varying detection ranges in each direction to derive radial velocity sequences, followed by integration of ray-tracing theory to obtain 2D velocity distributions; and (3) synthesis of final 3D velocity imaging results via interpolation of these 2D datasets. In the velocity sequence extraction process, we significantly reduced the computational load by employing an adaptive time window, ensuring rapid and stable application in well-site settings. We utilized the finite difference method to construct well models with heterogeneous formations. The compressional and shear wave 3D velocity imaging results derived from synthetic data correlated with the model, demonstrating the azimuthal sensitivity of our proposed method. Furthermore, we applied this method to a well in West China, successfully identifying the azimuth of near-wellbore anisotropy.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 11","pages":"Pages 4504-4519"},"PeriodicalIF":6.1,"publicationDate":"2025-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145698107","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Petroleum recovery from salt cavern through natural gas displacement: Insights from a gas–oil two-phase flow model with gas dissolution and exsolution","authors":"You-Qiang Liao ,&nbsp;Tong-Tao Wang ,&nbsp;Tao He ,&nbsp;Dong-Zhou Xie ,&nbsp;Kai Xie ,&nbsp;Chun-He Yang","doi":"10.1016/j.petsci.2025.06.005","DOIUrl":"10.1016/j.petsci.2025.06.005","url":null,"abstract":"<div><div>The challenge of wide brine source and its additional problems come from the economy (energy consumption and other costs), security (re-dissolution of surrounding salt rocks), and environment (groundwater pollution by brine) of salt cavern oil storage are worth examining to improve the efficiency of oil storage. Against this background, this work presented an operating mode of salt cavern oil and gas co-storage and using natural gas displacement for petroleum recovery. A gas–oil two-phase flow model with gas dissolution and exsolution was proposed to evaluate the application prospects of the new method precisely. Numerical studies indicated that the gas void fraction at the wellhead under quasi-steady state conditions is approximately 0.153, which belongs to bubbly flow, and the pressure at the wellhead of the central tube increased from 5.54 to 6.12 MPa during the entire transient flow stage, with an increase of 10.47%. Compared to the traditional method of using brine as the working fluid, the pump pressure rises from 2.92 to 14.01 MPa. However, if the new mode can be linked with the salt cavern gas storage and when the initial wellhead gas pressure exceeds 13 MPa, the energy consumption of the new method will be lower than that of the traditional brine-based operational mode. A new empirical formula is proposed to determine the two-phase flow pattern under different operating parameters. A special focus was given to energy consumption for oil recovery, which grows roughly in accordance with the operating pressure and oil recovery rate. However, the energy cost per volume of crude oil remains almost unchanged. This work provided a new solution for the serious brine problem and is expected to achieve petroleum recovery through natural gas displacement.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4226-4239"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384369","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Can clay-rich reservoirs in predominantly-freshwater lacustrine shale systems serve as primary exploration targets in low-medium maturity? A case study of the Triassic Yanchang Formation of the Ordos Basin","authors":"Enze Wang ,&nbsp;Maowen Li ,&nbsp;Xiaoxiao Ma ,&nbsp;Menhui Qian ,&nbsp;Tingting Cao ,&nbsp;Zhiming Li ,&nbsp;Sen Li ,&nbsp;Zhijun Jin","doi":"10.1016/j.petsci.2025.06.020","DOIUrl":"10.1016/j.petsci.2025.06.020","url":null,"abstract":"<div><div>Whether clay-rich shale reservoirs with low-medium maturity can serve as primary exploration targets remains a focal point of debate in the academic community. Clarifying the exploration potential of clay-rich shale reservoirs is crucial for the future exploration and development of lacustrine shale. The Triassic Yanchang Formation in the Ordos Basin has been one of most productive lacustrine shale oil systems in China, with substantial oil production capacity already established. While the primary productive layers are currently fine-grained siltstone interbeds, however, it remains a highly debated issue whether the volumetrically more significant clay-rich reservoirs can become viable exploration targets in the near future. To address this issue, we examined the exploration potential of different lithofacies assemblages in Member 7 (Mbr 7) of the Triassic Yanchang Formation, using a borehole in the Tongchuan area of the southern Ordos Basin as an example. We identified favorable exploration targets and assessed whether clay-rich reservoirs formed predominantly-freshwater conditions can become viable exploration targets. The results indicate the presence of six lithofacies in clay-rich reservoirs of Mbr 7 of the Yanchang Formation, with two main lithofacies assemblages: laminated organic-rich shale and massive mudstone. From the perspective of sandstone distribution, the sandstone interlayers within laminated organic-rich shale are primarily formed by gravity (hyperpycnal) flows, while sandstones deposited in delta front environments are typically associated with massive mudstone. Laminated organic-rich shale deposition occurred in an anoxic, deep-water environment characterized by high primary productivity, whereas massive mudstone formed in environments with high sedimentation rates and substantial terrigenous debris influx. Currently, the exploration potential of sandstone interlayers exceeds that of clay-rich reservoirs, with the greatest potential observed in the sandstone interlayers associated with laminated organic-rich shale formed by gravity (hyperpycnal) flows. Comparative analysis reveals that clay-rich reservoirs with low to medium maturity present great challenges for exploitation, making interlayer-type reservoirs the main focus of exploration at this stage. Nevertheless, clay-rich reservoirs in closed systems with high thermal maturity and organic matter content also hold considerable potential.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 3925-3938"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384471","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Real-time NMR investigation of water infiltration mechanisms and pore structure evolution in fractured sandstone near-wellbore regions","authors":"Sheng-Feng Wu,&nbsp;Yong-Fa Zhang,&nbsp;Yu Zhao,&nbsp;Chao-Lin Wang,&nbsp;Jing Bi,&nbsp;An-Fa Long,&nbsp;Yan Li","doi":"10.1016/j.petsci.2025.06.018","DOIUrl":"10.1016/j.petsci.2025.06.018","url":null,"abstract":"<div><div>During the exploitation of sandstone gas reservoirs, natural fractures near the wellbore affect water infiltration and pore evolution; however, the impact mechanisms of these fractures remain unclear. This study utilized real-time nuclear magnetic resonance (RT-NMR) technology to investigate the influence of near-wellbore fracture angle (<em>α</em>) at 0°, 15°, 30°, and 45° on water infiltration, migration patterns, and pore evolution mechanisms during water injection. Throughout the experiments, <em>T</em>₂ curves and magnetic resonance imaging (MRI) were monitored in real time during the water injection process. The pore evolution and water infiltration were translated by the evolution of <em>T</em>₂ curves and MRI. The results show that increasing injection pressure (<em>P</em>_inj) transforms adsorption pores into seepage pores, leading to enhanced pore damage. Pore damage predominantly occurs during the rapid pressurization stage and is concentrated around the near-wellbore fracture. The maximum infiltration area and rate were observed at <em>α</em> = 0°, while the minimum values occurred at <em>α</em> = 45°, which can be attributed to the significant influence of <em>α</em> on water infiltration and migration pathways. The increasing inclination of the infiltration front with <em>α</em> is attributed to the fact that the rate of water infiltration along the fracture wall is always higher than that at the fracture tip. In field fracturing, it is recommended to adjust the perforation direction to align with the natural fracture orientation and optimize pressurization strategies by reducing the slow pressurization duration while extending the rapid pressurization stage. These findings can provide important guidance for setting fracturing sections and optimizing injection parameters in sandstone gas reservoir exploitation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 10","pages":"Pages 4195-4210"},"PeriodicalIF":6.1,"publicationDate":"2025-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145384366","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}