Petroleum Research最新文献

{"title":"Investigation of the anionic-zwitterionic and anionic-nonionic surfactant mixtures on enhanced oil recovery using microfluidic devices","authors":"Yafei Liu ,&nbsp;Chenyue Ling ,&nbsp;Yixin Luo ,&nbsp;Na Liu ,&nbsp;Gaoxin Li ,&nbsp;Desheng Zhou","doi":"10.1016/j.ptlrs.2025.07.004","DOIUrl":"10.1016/j.ptlrs.2025.07.004","url":null,"abstract":"<div><div>Surfactant flooding is one of the widely applied enhanced oil recovery methods. However, the application of a single surfactant is often insufficient to meet the demand for oil recovery. Consequently, a variety of surfactant mixtures have been employed to enhance oil recovery efficiency. A comprehensive understanding of the interactions between surfactant mixtures, crude oil, formation water and rock is essential for the effective design and optimization of the surfactant flooding procedures. In this work, anionic-zwitterionic and anionic-nonionic surfactant mixtures with varying compositions were investigated using different microfluidic devices. Single dead-end pore structure that was captured from a real rock pore throat structure was initially employed for a quick screening of the optimum surfactant composition, considering the effect of the presence of connate brine. The selected surfactant compositions were tested using a micromodel with heterogeneous pore-throat network. The results indicate that 0.4 wt% sodium dodecyl benzene sulfonate with 0.6 wt% octadecyl dimethyl betaine and 0.4 wt% sodium dodecyl benzene sulfonate with 0.6 wt% hexyl D-glucoside surfactant mixtures resulted in higher recovery rate in the dead-end pore structure. In the subsequent micromodel experiments, 0.4 wt% sodium dodecyl benzene sulfonate with 0.6 wt% octadecyl dimethyl betaine showed better oil recovery performance. To further explain the oil recovery performance of the surfactant mixtures, interfacial tension, viscoelasticity and critical micelle concentration values were measured and calculated to provide an insight into their interfacial activities. It was observed that anionic-zwitterionic and anionic-nonionic surfactant mixtures displaced oil in different manners attributing to their distinct interfacial properties. The anionic-zwitterionic surfactant mixture primarily displaced the crude oil through solubilization and emulsification due to its lower interfacial tension and critical micelle concentration of the surfactant mixture, whereas the anionic-nonionic surfactant mixture displaced oil through peeling and mobilization as a result of relatively higher interfacial tension and interfacial viscoelasticity.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 1","pages":"Pages 38-49"},"PeriodicalIF":4.0,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147556505","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 quantification of the depositional–diagenetic heterogeneities in paleokarst hydrocarbon reservoirs: Sarvak Formation, Zagros Basin, Iran","authors":"Hamzeh Mehrabi,&nbsp;Rakhshandeh Ataei,&nbsp;Vahid Tavakoli,&nbsp;Elham Talebi","doi":"10.1016/j.ptlrs.2025.06.003","DOIUrl":"10.1016/j.ptlrs.2025.06.003","url":null,"abstract":"<div><div>This study explores the depositional and diagenetic heterogeneities of the Sarvak Formation, a paleokarst carbonate reservoir in the Zagros Basin, Iran, using sedimentological, diagenetic, and statistical analyses. Petrographic studies and well log data, combined with methods like Winland rock type classification, hydraulic flow unit analysis, and Lorenz zonation, were used to assess reservoir properties at multiple scales. Two heterogeneity scales were identified: small-scale (millimeter to centimeter), driven by facies variations and diagenesis, and large-scale (meter), linked to facies transitions and sequence stratigraphy. Large-scale heterogeneities, particularly those tied to sequence stratigraphic boundaries, are traceable within third-order sequences and systems tracts. The highest-quality reservoir intervals, characterized by rudist-rich zones and dissolved shoal facies, are found beneath the Cenomanian–Turonian boundary, preserving youthful karst features. In contrast, non-reservoir intervals beneath the mid-Turonian disconformity exhibit collapsed features from prolonged subaerial exposure, forming an over-mature karst profile. Small-scale heterogeneities require further investigation within lower-order sequences for accurate prediction. This research integrates various analytical methods, providing a robust framework for understanding how depositional and diagenetic factors control reservoir quality, enhancing predictability in karstified carbonate systems for hydrocarbon exploration and development.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 1","pages":"Pages 17-37"},"PeriodicalIF":4.0,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147556512","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 experimental study of proppant transport mechanisms to the pump intake in low-flow oil wells","authors":"Evgenii Kozhevnikov ,&nbsp;Fedor Belkov ,&nbsp;Mikhail Turbakov ,&nbsp;Zakhar Ivanov ,&nbsp;Evgenii Riabokon ,&nbsp;Dmitrii Fedurov ,&nbsp;Mikhail Guzev ,&nbsp;Evgenii Gladkikh ,&nbsp;Jiangyu Wu","doi":"10.1016/j.ptlrs.2025.07.007","DOIUrl":"10.1016/j.ptlrs.2025.07.007","url":null,"abstract":"<div><div>The exploitation of low-flow oil wells following hydraulic fracturing is often hindered by residual proppant and proppant production during early production phases, which can infiltrate pumps and drastically shorten their service life. Managing proppant reliably and cost-effectively in these wells remains challenging due to the limited understanding of proppant transport mechanisms from the well bottom to the pump intake. This manuscript addresses this critical knowledge gap by presenting novel experimental insights into proppant transport in low-flow oil wells, marking the first elucidation of the underlying mechanism. Through innovative laboratory experiments simulating post-fracturing well conditions, we demonstrate that proppant invariably ascends to the pump intake, driven by a previously unrecognized process: droplets of immiscible hydrocarbon fluids capture and transport proppant particles upward. Comparative analyses using fluids of varying viscosities reveal, for the first time, that the viscosity of the immiscible phase has negligible impact on droplet transport capacity. Additionally, our studies establish that proppant concentration during transport is independent of well flow rate, challenging conventional assumptions. A key novel finding is the pivotal role of free gas bubbles in enhancing proppant transport probability, as they facilitate capture by oil and kerosene droplets; higher gas content correlates directly with elevated proppant concentrations in the flow. These experimental discoveries are validated by field trial data from wells with high free gas content under bottomhole conditions, where reduced pump operational times were observed, confirming the mechanism's real-world relevance. By unveiling this transport mechanism, the manuscript provides a foundational basis for developing targeted proppant management strategies, offering new pathways to enhance pump longevity and operational efficiency in low-flow oil wells.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 1","pages":"Pages 163-175"},"PeriodicalIF":4.0,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147556438","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":"Mechanical analysis and structural optimization of anchorage for split segment inserted tooth slips","authors":"Zhongzhi Hu ,&nbsp;Kaixin Lv ,&nbsp;Xiang Gao ,&nbsp;Zhilin Ye ,&nbsp;Tiejun Lin","doi":"10.1016/j.ptlrs.2025.08.002","DOIUrl":"10.1016/j.ptlrs.2025.08.002","url":null,"abstract":"<div><div>To meet the operational requirements of slip-type packers within TP140V casing in ultra-deep wells and enhance the anchoring performance and load-bearing capacity of the packer's anchoring mechanism during setting, this paper focuses on the study of tooth-embedded slips. The Abaqus finite element software was used to analyze the stress and contact pressure distribution patterns in key components such as the embedded teeth, casing, and slip base during the anchoring process of tooth-embedded slips. An orthogonal experimental method was employed to optimize the structural parameters of segmented tooth-embedded slips. Based on the results of the orthogonal experiments, the optimal combination of slip structural parameters was obtained: the front-end distance was 12 mm, the tooth installation spacing was 24 mm, the dip angle of the groove was 76.5°, the groove depth was 6.8 mm, and the slip wedge angle was 13°. After optimization, the maximum Von Mises stress in the slip base was reduced from 1080 MPa to 512.2 MPa, the embedding depth decreased from 0.2156 mm to 0.1338 mm, and the maximum contact pressure at the tooth tips dropped from 4247 MPa to 2965 MPa. Compared to the pre-optimization values, these reductions were 52.6%, 37.9%, and 30.2%, respectively. Moreover, the optimized casing bite depth and tooth-tip contact pressure exhibited a more uniform axial distribution. Additionally, physical prototypes of the optimized slips were manufactured and subjected to laboratory tests, which demonstrated that the axial bearing capacity of the slips could reach 450 kN, capable of withstanding axial loads in a 152.5-mm inner diameter casing under a downhole pressure environment of 100 MPa. The research findings in this paper provide a theoretical reference for optimizing the structural parameters of tooth-embedded slips within TP140V steel grade casing.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 1","pages":"Pages 250-262"},"PeriodicalIF":4.0,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147556440","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":"Carbon capture and storage: An evidence-based review of its limitations and missed promises","authors":"Muhammad Hammad Rasool ,&nbsp;Syed Abdul Moiz Hashmi","doi":"10.1016/j.ptlrs.2025.09.005","DOIUrl":"10.1016/j.ptlrs.2025.09.005","url":null,"abstract":"<div><div>Despite over $40 billion invested globally, Carbon Capture and Storage (CCS) captures and stores less than 0.1% of annual global CO₂ emissions, raising serious questions about its efficacy as a climate solution. This review addresses the critical disconnect between modelled expectations and empirical outcomes of CCS, offering a comprehensive, evidence-based reassessment of its technical, economic, and strategic performance. The analysis integrates data from peer-reviewed literature, international reports (IPCC, IEA, Carbon Tracker), and investigative journalism, evaluating both failed and superficially successful projects, including Petra Nova, Gorgon, Sleipner, and In Salah. These case studies expose recurring patterns of cost overruns, suboptimal capture rates, geological uncertainties, and public liability transfer. Projects hailed as “successful” often fall short when scrutinized against durability, scale, and emissions offset claims. While these findings raise valid concerns, this review does not categorically dismiss CCS. Instead, it emphasizes the need for strategic deployment in specific, hard-to-abate sectors where alternatives are limited such as cement production or legacy infrastructure retrofits. Beyond critique, the review explores proven alternatives: renewables, bio-based removals, mineralization; that offer higher scalability and permanence with fewer systemic risks. A predictive evaluation framework is introduced to match/compare capture and mitigation/avoidance technologies to emission contexts using criteria such as CO₂ concentration, energy demand (2.5–8 GJ/tCO₂), cost ($50–600/tCO₂), scalability, and permanence. Ultimately, the findings underscore that continued reliance on CCS is a high-cost gamble that risks delaying the deployment of truly effective climate solutions; yet, if strategized properly, 2026–2030 could still mark a decisive turning point in determining its role in the energy transition.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 1","pages":"Pages 176-205"},"PeriodicalIF":4.0,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147556442","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":"DLVO-based prediction of critical pH for fines migration in sandstone reservoirs","authors":"Elmira Dalabayeva ,&nbsp;Peyman Pourafshary ,&nbsp;Rizwan Muneer","doi":"10.1016/j.ptlrs.2025.06.002","DOIUrl":"10.1016/j.ptlrs.2025.06.002","url":null,"abstract":"<div><div>Fines migration is a formation damage mechanism that occurs in sandstone formations due to the incompatibility between injected fluids and in situ fluids during various operations such as water flooding, drilling, and completion. Fines migration can lead to production problems such as pore blockage and reduced permeability. Parameters such as salinity, pH, and flow rate affect the forces between fines and the rock surface, potentially triggering fines migration. Therefore, predicting the conditions that lead to fines release and migration is critical for ensuring safe operations. Enhanced oil recovery methods, such as low-salinity water injection and alkaline flooding, alter the salinity and pH within the formation, affecting the electrostatic interaction forces between fines and the rock surface. Hydrodynamic forces also influence fines release. Therefore, predicting the initiation of fines migration requires considering and analyzing all these forces. In this work, a modified method based on DLVO theory was developed to predict the critical pH for fines release. The model estimates the onset of fines migration by evaluating electrostatic and hydrodynamic repulsive and attractive forces. For example, the model predicted critical pH values of 8 and 10 at salinities of 0.2 M NaCl and 0.25 M NaCl, respectively. Several core flooding tests were conducted to measure the critical pH for fines release, validating the developed model. The experimental observations showed good agreement with the model, with an error of approximately 13% in predicting the critical pH. The developed approach enables the identification of optimal brine conditions to mitigate fines migration and formation damage, which is a significant finding for enhanced oil recovery and production operations.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 1","pages":"Pages 72-83"},"PeriodicalIF":4.0,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147556513","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":"Fracture facies estimation utilizing machine learning algorithm and Formation Micro-Imager (FMI) log","authors":"Hassan Bagheri ,&nbsp;Reza Mohebian","doi":"10.1016/j.ptlrs.2025.04.006","DOIUrl":"10.1016/j.ptlrs.2025.04.006","url":null,"abstract":"<div><div>Natural open fractures (NOFs) in reservoir rocks are critical factors influencing permeability. Identifying these fractures and fractured zones typically involves analyzing core samples and image logs. However, core data are limited topecific depths within the reservoir, and image log data are confined to a small number of wells. In this study, fracture facies in a carbonate reservoir (Kangan-Dalan Formation) were predicted using Formation Micro-Imager (FMI) logs, conventional well logs, and petrophysical parameters, with a machine learning algorithm. Initially, open fractures were identified in wells A and B using the FMI log. In well A, the open fractures exhibit an average dip of 61°, an azimuth of N79E, and a strike direction of N11W/S11E. In well B, the fractures have an average dip of 69°, an azimuth of N26E, and a strike direction of N64W/S64E. Subsequently, fracture density logs for wells A and B were calculated, with average values of 0.41 and 0.33, respectively. Conventional well logs, including density (RHOB), sonic (DT), and petrophysical parameters, specifically effective porosity (PHIE), were used as input data for a Multi-Resolution Graph-Based Clustering (MRGC) algorithm, which is one of the machine learning algorithms employed in this study. Additionally, a synthetic log called FLAG, derived from the fracture density log (with values of 0 and 1 indicating the presence or absence of fractures), was incorporated into the algorithm as an associated input log. This algorithm enabled the identification of fracture facies, representing open fractures or fractured zones, in well A. To evaluate the accuracy of the algorithm, the results obtained were compared with two other clustering algorithms: Ascendant Hierarchical Clustering (AHC) and Self-Organizing Maps (SOM). Well B was used as a blind test to validate the clustering model. In this test, the clustering algorithm was applied excluding the FLAG synthetic log derived from the FMI log. The results from well B demonstrated that the developed algorithm accurately identifies fracture facies in wells lacking image log and core data. The algorithm was subsequently extended to wells C and D, which lacked core or image log data. Fractured zones in these wells were successfully identified as fracture facies. Additionally, a two-dimensional map of fracture facies thickness was generated for the study area. The developed hybrid algorithm demonstrated strong potential for generalizing to other wells in the field, enabling fracture facies modeling in both 2D and 3D.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 764-781"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760649","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":"The application of radio-frequency identification (RFID) technology in the petroleum engineering industry: Mixed review","authors":"Ali Akbari","doi":"10.1016/j.ptlrs.2025.05.001","DOIUrl":"10.1016/j.ptlrs.2025.05.001","url":null,"abstract":"<div><div>Radio Frequency Identification (RFID) technology has emerged as a promising solution for real-time tracking and monitoring in the petroleum industry. This study systematically reviews recent advancements in RFID applications for petroleum asset management, logistics, and safety. The research is based on an extensive review of peer-reviewed literature, industry reports, and experimental case studies involving RFID deployment in refinery operations and pipeline monitoring. The study also examines practical implementation challenges, including signal interference due to metal surfaces, high initial costs associated with infrastructure setup, and integration complexities with existing digital systems such as SCADA and IoT platforms. Furthermore, issues related to data security and the potential for unauthorized access are discussed as critical concerns that need to be addressed for large-scale adoption. Despite these limitations, RFID technology demonstrates significant potential in optimizing supply chain management, enhancing real-time asset tracking, and improving workplace safety in petroleum engineering. The ability to automate inventory management, reduce operational downtime, and enhance predictive maintenance further underscores its strategic importance. Future research should focus on overcoming technical barriers through the development of advanced RFID tags with higher resistance to extreme environmental conditions and improved data encryption techniques. Additionally, cost-effective deployment strategies and interoperability standards must be established to facilitate broader industry adoption. Collaborative efforts between researchers, technology developers, and industry stakeholders will be essential in driving innovation and ensuring the successful integration of RFID into the petroleum sector.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 912-922"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760697","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":"Dolomitization history and fracture development of Lower Cambrian Longwangmiao Formation in the NE Sichuan Basin, SW China","authors":"Shuyuan Shi ,&nbsp;Yongjie Hu ,&nbsp;Jinxiong Luo ,&nbsp;Zhuangzhuang Bai ,&nbsp;Wenliang Shang","doi":"10.1016/j.ptlrs.2025.09.010","DOIUrl":"10.1016/j.ptlrs.2025.09.010","url":null,"abstract":"<div><div>The deeply buried dolostone reservoir hosts economically significant hydrocarbon reserves. The Cambrian Longwangmiao Formation at the Nanjiang outcrop in northern Sichuan Basin is investigated using an integrated approach combing petrographic, paleo-thermometric, and geochemical analyses to yield a better understanding of dolomitization history and reservoir evolution. Petrographic observations identify five distinct types of host dolostone and three types of dolomite cement. Well-preserved sedimentary textures, fluid inclusions data and seawater-like δ¹³C-δ¹⁸O values suggest that most host dolostone (excluding zebra dolostone), along with fine-crystalline dolomite cement, were formed through reflux dolomitization in near-surface to shallow-burial settings. Subsequently, burial dolomitization likely led to the precipitation of medium-to coarse-crystalline dolomite cement during the Triassic. Saddle dolomite, representing the final phase of dolomite formation, is characterized by high homogenization temperatures (150–230 °C), significantly depleted δ¹⁸O values (−9.9 ± 0.3‰), and elevated radiogenic ⁸⁷Sr/⁸⁶Sr ratios (0.7133). The upward-decreasing trend in ⁸⁷Sr/⁸⁶Sr ratios in saddle dolomite is likely attributable to a diminishing volume of hydrothermal fluids during upward migration. Three types of fractures are recognized. The first type of fracture is cross-cut by stylolite and is likely formed during near-surface environments. The second and third types of fracture cross-cut stylolite and are partially filled by medium-to coarse-crystalline dolomite cement as well as saddle dolomite. The second and third types are likely formed under shallow to intermediate burial conditions. Both outcrop and core data reveal well-developed fractures, which significantly enhance reservoir quality by improving permeability and connectivity. This study offers important insights into the genesis and reservoir characteristics of deeply buried dolostone systems.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 725-737"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760646","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":"Mechanistic study on the effect of seepage force on fracture propagation behavior in multi-cluster fracturing of horizontal wells","authors":"Haiyang Wang ,&nbsp;Yufei Wang ,&nbsp;Xu Su ,&nbsp;Chen Lu ,&nbsp;Desheng Zhou ,&nbsp;Qingqing Wang","doi":"10.1016/j.ptlrs.2025.05.002","DOIUrl":"10.1016/j.ptlrs.2025.05.002","url":null,"abstract":"<div><div>During multi-cluster fracturing of horizontal wells, low-viscosity fracturing fluid permeates extensively along the fracture walls into the rock pores, exerting seepage forces on the rock skeleton. However, the mechanism of how seepage forces influence multi-cluster fracture propagation behavior remains unclear. In this study, we analyze the response relationship between the pore pressure field and the seepage field under transient seepage conditions. We established a numerical simulation model of multi-cluster fracture propagation in horizontal wells considering seepage forces based on the discrete element particle flow method. Using this model, we examined the mechanisms by which seepage forces affect the dynamic evolution of the induced stress field and fracture propagation behavior under various combinations of fracturing fluid viscosity, injection rate, in-situ stress, and cluster spacing. Numerical simulation results indicate that the infiltration of fracturing fluid into rock pores and the resulting seepage forces significantly alter the propagation patterns of inter-cluster fractures and the distribution of the induced stress field. Under the influence of seepage forces, hydraulic fractures suppressed by stress shadows are redirected and captured by adjacent fractures. Selecting appropriate fracturing fluid viscosity and injection rate can effectively utilize seepage forces to mitigate the inhibitory effects of the high compressive stress zones within stress shadows on intermediate fracture propagation, thereby increasing the likelihood of inter-fracture communication and the formation of a complex fracture network. This study not only underscores the importance of considering seepage forces in the design of multi-stage fracturing treatments but also provides critical theoretical insights for optimizing fracturing operation parameters.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 4","pages":"Pages 803-817"},"PeriodicalIF":4.0,"publicationDate":"2025-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145760652","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}