Geoenergy Science and Engineering最新文献

{"title":"Unlocking the potential of bacterial consortia from oilfield wastewater for enhanced heavy oil recovery by efficient biodegradation and biosurfactant production","authors":"Huizhen Yang ,&nbsp;Lu Ren ,&nbsp;Huihui Zhu ,&nbsp;Junhui Zhang","doi":"10.1016/j.geoen.2025.214191","DOIUrl":"10.1016/j.geoen.2025.214191","url":null,"abstract":"<div><div>Microbial techniques are increasingly used in the extraction of heavy oil from reservoirs. The use of consortia containing heavy oil-degrading and biosurfactant-producing bacteria is a promising strategy for microbial enhanced oil recovery (MEOR), which can provide higher efficiency and robustness over single strains. The aim of this study was to construct bacterial consortia for enhanced heavy oil recovery with strains isolated from oilfield wastewater. Three strains with strong abilities to degrade petroleum hydrocarbons and produce biosurfactants were obtained. They were identified as <em>Bacillus paraclicheniformis</em> (W1), <em>Microbacterium barkeri</em> (W2), and <em>Bacillus halotolerans</em> (W3) based on morphological analysis and 16S ribosomal gene sequencing. Four heavy oil-degrading consortia were developed using three strains. Among them, W12, W13, and W123 performed well in heavy oil biodegradation (34.2–40.2 %). Heavy oil treatment with these three bacterial consortia led to transformation and redistribution of major fractions by increasing the saturate content and reducing the aromatic, resin, and asphaltene contents. Gas chromatography-mass spectrometry evidenced the degradation of saturates (C₂₀–C₂₉ <em>n</em>-alkanes) by 42.3 % (W12), 19.2 % (W13), and 40.9 % (W123). Inductively-coupled plasma mass spectrometry revealed prominent effects of W12, W13, and W123 on demetallization of Ni, Fe, and V, with maximum removal rates of 54.0 %, 90.7 %, and 51.0 %, respectively. The viscosity of heavy oil was decreased by up to 43.6 % after 30 days of bacterial treatment. Our results unlock the potential of bacterial consortia containing <em>Bacillus</em> and <em>Microbacterium</em> strains as oil degraders and displacement agents for use in enhanced heavy oil recovery.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214191"},"PeriodicalIF":4.6,"publicationDate":"2025-09-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049984","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":"Technological advances and operational challenges of the FAWAG (Foam-Assisted Water Alternating Gas) method in advanced oil recovery: a comprehensive review of principles, applications, and future perspectives","authors":"Janiele Alves Eugênio Ribeiro ,&nbsp;Luana Beatriz de Sales Oliveira ,&nbsp;Gregory Vinicius Bezerra de Oliveira ,&nbsp;Dennys Correia da Silva ,&nbsp;Alcides de Oliveira Wanderley Neto ,&nbsp;Marcos Allyson Felipe Rodrigues","doi":"10.1016/j.geoen.2025.214206","DOIUrl":"10.1016/j.geoen.2025.214206","url":null,"abstract":"<div><div>This article presents a comprehensive review of the technological advancements and operational challenges associated with the FAWAG (Foam-Assisted Water Alternating Gas) method in advanced oil recovery, with a particular focus on its fundamental principles, practical applications, and future perspectives. The study underscores FAWAG as a robust and adaptable technique capable of overcoming the limitations of conventional Enhanced Oil Recovery (EOR) methods, particularly in reservoirs characterized by high heterogeneity, extreme pressure, and elevated temperature conditions. Recent innovations, including the development of thermally stable foams and biodegradable surfactants, as well as the integration of artificial intelligence and advanced modeling for real-time optimization, further reinforce its relevance in the context of energy transition and environmental compliance. Comparative analyses with traditional methods, global case studies, and regulatory perspectives are examined to highlight FAWAG's strategic role in maximizing sweep efficiency and enabling sustainable operations. This work consolidates FAWAG as a state-of-the-art solution to address the challenges of the oil and gas industry, fostering a critical interface between innovation, sustainability and competitiveness.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214206"},"PeriodicalIF":4.6,"publicationDate":"2025-09-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049990","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 preliminary study of CO2 effects on heavy oil recovery in CO2-assisted thermal injection","authors":"Haitao Wang ,&nbsp;Hanxing Su ,&nbsp;Wenjin Hu ,&nbsp;Xiao Yan ,&nbsp;Dengfeng Zhang ,&nbsp;Jie Zou","doi":"10.1016/j.geoen.2025.214193","DOIUrl":"10.1016/j.geoen.2025.214193","url":null,"abstract":"<div><div>CO₂-assisted thermal injection incorporates the merits of non-thermal CO₂ injection and thermal injection methods on heavy oil recovery. However, the effects of CO₂ on heavy oil recovery are unclear considering the extremely high temperatures. In this work, we studied the CO₂-heavy oil interactions and oil displacement by CO₂ under high temperatures and pressures. The carbon number distribution and four groups (asphaltene, colloid, saturates, and aromatics) of heavy oil were tested. The oil displacement by CO₂ was captured using <em>T</em>₂ NMR and NMR imaging analyses. Our results showed that the light hydrocarbons were extracted under an elevated temperature of 333.15 K, while the heavy hydrocarbons were extracted under a low temperature of 313.15 K. As the CO₂ exposure pressure increased, the extraction effect was improved by expanding extractable carbon numbers and vaporing more saturates. The oil displacement efficiency by CO₂ increased as the temperature rose, but it did not strictly increase with increasing pressure. The spatial oil recovery of a sample, determined by NMR imaging, was unevenly distributed, i.e., it was larger on one side of the sample than on the other side. This phenomenon could be related to the gravity effect, under which the oil flows downward during the CO₂ injection experiment. This study helps to provide a full picture of CO₂ roles in CO₂-assisted thermal injection for heavy oil recovery.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214193"},"PeriodicalIF":4.6,"publicationDate":"2025-09-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049986","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":"Study on parameters influencing fracture propagation and the influence of sensitive parameters on CO2 enhanced oil reservoirs in Gulong shale oil","authors":"Xiaodong Dai ,&nbsp;Jianguang Wei ,&nbsp;Yuwei Li ,&nbsp;Ying Yang","doi":"10.1016/j.geoen.2025.214197","DOIUrl":"10.1016/j.geoen.2025.214197","url":null,"abstract":"<div><div>The CO₂ fracturing of shale oil reservoirs is influenced by engineering and geological parameters. In this paper, the CO₂ fracturing in Gulong shale oil is taken as the research object. First, the production dynamic characteristics and the advantages and disadvantages of CO₂ fracturing effect in Gulong shale oil reservoirs are summarized. Second, the influencing factors such as crude oil viscosity, initial oil to gas ratio, and permeability on CO₂ enhanced oil production are analyzed, and the law of sensitive factors affecting CO₂ enhanced oil reservoirs is summarized. Third, by comparing different blocks, the relationship between CO₂ intensity and cumulative oil production is elucidated. Results show that: (a) under the same injection volume, the viscosity of the fracturing fluid increases from 40 mPa·s to 120 mPa·s, the maximum length of a single fracture decreases by 32 m, and the maximum fracture width increases by 0.84 mm. (b) When the cluster spacing is 7 m, there is severe interference between the seams. After increasing the spacing between clusters to 15 m, there is a certain loss in the length of fracture propagation. (c) The viscosity of crude oil is directly proportional to the CO₂ oil change rate. When the oil to gas ratio is low, it has an auxiliary effect on CO₂ assisted fracturing in oil production increasing.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214197"},"PeriodicalIF":4.6,"publicationDate":"2025-09-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106680","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":"Revisiting capacitance-resistance model connectivity estimates for directional and distance effects","authors":"Jerry L. Jensen","doi":"10.1016/j.geoen.2025.214198","DOIUrl":"10.1016/j.geoen.2025.214198","url":null,"abstract":"<div><div>Connectivity has been described as one of the fundamental reservoir characteristics which directly impacts recovery. Numerous studies have reported on how it can be measured and used to manage waterfloods. Largely missing from these reports, however, is how connectivity can be integrated with the available geological information to identify which geological features are controlling interwell communication. Having a structured approach to connectivity analysis helps to identify geological controls on fluid flow and avoids overlooking important features.</div><div>Through three cases, we show how connectivity—as measured using the capacitance-resistance model—can be systematically analyzed for geological information. Two methods—not used in prior literature—prove particularly useful for connectivity analysis. First, a semi-log crossplot of connectivity versus interwell distance helps compare connectivity behaviors from different parts of the reservoir to assess geological effects, provide initial estimates of connected region sizes, and establish the noise level in the results. Second, histograms of azimuthal sensitivities of connectivities offer insights into preferential orientations of geological features.</div><div>Two field cases are clastic reservoirs where the depositional features prove to be the primary controls on connectivity. One carbonate reservoir shows the effects of post-depositional characteristics on connectivity. All three cases illustrate how careful connectivity evaluations can inform waterflood recovery strategies.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214198"},"PeriodicalIF":4.6,"publicationDate":"2025-09-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106681","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":"CO2 foam-assisted fracturing fluid flowback and CO2 sequestration in tight sandstone gas reservoirs: Experimental and numerical study","authors":"Bo Han ,&nbsp;Hui Gao ,&nbsp;Yuanxiang Xiao ,&nbsp;Zhanguo Ma ,&nbsp;Zhilin Cheng ,&nbsp;Teng Li ,&nbsp;Chen Wang ,&nbsp;Kaiqing Luo ,&nbsp;Xiaohang Li","doi":"10.1016/j.geoen.2025.214199","DOIUrl":"10.1016/j.geoen.2025.214199","url":null,"abstract":"<div><div>CO₂ foam fracturing is an advanced CO₂-based fracturing technique with distinct advantages over other methods, such as enhanced proppant transport capacity and reduced filtration loss, making it highly promising for applications in tight gas reservoirs. Additionally, CO₂ foam fracturing presents the potential for underground CO₂ sequestration, which contributes to the reduction of carbon emissions. During CO₂ foam fracturing, both flowback efficiency and the microscopic retention of fracturing fluid are crucial factors influencing subsequent gas production. However, limited research has specifically investigated the flowback behavior of fracturing fluids after CO₂ foam fracturing, and the potential for CO₂ sequestration during this process remains insufficiently explored. This study combines physical displacement experiments with low-field nuclear magnetic resonance (LF-NMR) techniques to investigate the flowback efficiency and microscopic retention of fracturing fluid. Additionally, the CO₂ sequestration efficiency is analyzed. Numerical simulations are performed to examine the field-scale flowback of fracturing fluid and CO₂ sequestration, focusing on the effects of foam quality, injection rate, injection volume, and soaking time. Experimental results demonstrate that increasing foam quality enhances both fracturing fluid flowback efficiency and CO₂ sequestration. Specifically, as foam quality increases from 50 % to 70 %, fracturing fluid flowback efficiency increases from 70.32 % to 87.3 %, while CO₂ sequestration efficiency rises from 32.56 % to 38.68 %. NMR test results reveal that fracturing fluid is primarily retained in small pores, and increasing foam quality reduces fluid retention across various pore sizes. In this study, increasing the foam quality from 50 % to 70 % reduces the fracturing fluid retention by 22.23 % in small pores, 6.7 % in large pores, and 20.83 % overall across all pore sizes. Numerical simulations indicate that fracturing fluid flowback efficiency increases with both foam quality and foam injection rate, while it decreases with increasing foam volume and soaking time. The CO₂ sequestration efficiency increases with foam quality, injection rate, injection volume and soaking time. Therefore, during CO₂ foam fracturing, these injection parameters should be optimized to strike a balance between maximizing fracturing fluid flowback and CO₂ sequestration. This paper provides significant insights into improving fracturing fluid flowback and CO₂ sequestration in tight gas reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214199"},"PeriodicalIF":4.6,"publicationDate":"2025-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049983","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":"Estimation of FMI-derived fracture aperture from conventional petrophysical well logs applying ensemble machine learning methods","authors":"Ali Gholami Vijouyeh ,&nbsp;Ali Kadkhodaie ,&nbsp;Mohammad Hassanpour Sedghi ,&nbsp;Hamed Gholami Vijouyeh ,&nbsp;David A. Wood","doi":"10.1016/j.geoen.2025.214187","DOIUrl":"10.1016/j.geoen.2025.214187","url":null,"abstract":"<div><div>Studying fracture aperture can yield valuable insights, including detecting high production rate zones, fluid flow and production rate. Conventional techniques are applicable to obtain fracture aperture. However, they are expensive and time-consuming. Innovatively, an integrated, robust, intelligent model is developed to address the challenge of accurately estimating fracture aperture by applying full-bore formation micro imager (FMI) and well-log data from the GHS oilfield (Iran). The model reaps the benefits of the hybrid, ensemble, boosting and tree-based standalone machine learning (ML) algorithms integrated into the optimisation committee machine (CM) and multi-variable linear regression (MVLR) algorithms applying a two-step CM sequence. Six standalone ML models were employed for the initial prediction. Subsequently, four optimisation algorithms were employed within the CM configuration to integrate standalone algorithms, improving the accuracy of fracture aperture predictions by assigning weight coefficients to each algorithm. The genetic algorithm (GA) slightly outperformed the others based on the mean squared error (MSE) and correlation coefficient (R). Utilisation of the CM with GA (CMGA) substantially minimised MSE by 64.48 % (from 0.0020 to 0.0007220) and improved R by 5.68 % (from 0.8971 to 0.9480) compared to the average measurements of standalone models. Further improvement was achieved in the utilisation of MVLR, where all CMs were integrated using the weights derived from the least squares approach. This method unified all CMs into a single structure and enhanced the prediction performance of final fracture aperture estimations with a 1.32 % reduction in MSE and a 0.055 % increase in correlation coefficient compared to the average outcomes of the CMs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214187"},"PeriodicalIF":4.6,"publicationDate":"2025-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049985","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":"Field experiment research on the penetrability of insoluble sediment in high-impurity salt mine caverns","authors":"Yinping Li ,&nbsp;Xilin Shi ,&nbsp;Xiangsheng Chen ,&nbsp;Zhengyou Liu ,&nbsp;Qingfeng Lu ,&nbsp;Xinxing Wei","doi":"10.1016/j.geoen.2025.214196","DOIUrl":"10.1016/j.geoen.2025.214196","url":null,"abstract":"<div><div>The solution mining salt caverns in impure salt mines include generally two parts: the above clear brine space and the down sediment/brine mixed space. Gas storage by displacing brine in the sediment as well as in the above space is an optimal pathway to overcome barriers of building caverns in high-impurity salt mines and to achieve large-scale underground energy storage. Field experiments of sediment connectivity were carried out in a butted well salt cavern to determine the connectivity of voids within the sediments. Through a combination of sonar and downhole television surveys, as well as drilling exploratory wells, the height and spatial occupancy of the sedimentary deposits, the three-dimensional salt cavern morphology, and the undetectable horizontal section locations due to sediment burying were revealed. Based on this, a test plan for sediment void connectivity was designed, with real-time monitoring of wellhead pressure, temperature, and flow rate using sensors during the experiment. The analysis of field experiment results indicates that over 95 % of the target salt cavern space is occupied by sediments, but the sediment voids have good connectivity, with approximately 1 kPa/m pressure loss during brine flow. The sediment permeability ranges from 10⁻⁹ m² to 10⁻¹¹ m², and the void ratio can reach up to 40 %.</div><div>Implementing gas storage in sediment voids has many advantages and promising application prospects, 1) 4.5 times capacity expansion compared to conventional salt cavern gas storage; 2) Faster gas storage compared to new cavern construction; 3) Additional surrounding rock support to reduce salt cavern creep; 4) Reduced demand for precise cavern measurements, lowering technical complexity and costs. This research provides field experiments and data support for gas storage in high-impurity salt mine sediment voids, contributing to expanded salt cavern site selection and increased storage capacity.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214196"},"PeriodicalIF":4.6,"publicationDate":"2025-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145020037","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 innovative approach to discrete facture network modeling driven by geomechanics and multiple factors","authors":"Qiqiang Ren ,&nbsp;Tongsheng Liu ,&nbsp;Dongping Wan ,&nbsp;Jin Wang ,&nbsp;Rongtao Jiang ,&nbsp;Mengping Li ,&nbsp;Yegang Feng ,&nbsp;He Du","doi":"10.1016/j.geoen.2025.214200","DOIUrl":"10.1016/j.geoen.2025.214200","url":null,"abstract":"<div><div>The Keshen 8 gas field, with reservoirs exceeding 6000 m in depth, relies on structural fractures to enhance permeability due to poor matrix properties resulting from intense compaction and cementation. This study aims to conduct a new approach to establish the discrete fracture model considering geomechanical characteristics. Through a combination of field observations, core samples, imaging logging, and thin section analysis, fracture attributes, distribution, and development were analyzed. Structural influences and reservoir characteristics were evaluated to identify the key factors controlling fracture formation and development. A discrete fracture network (DFN) model was constructed based on multi-scale and multi-constraint principles, with model reliability verified through comparison with field data. The results showed that: (1) Sear fractures dominated the fracture system, with high-angle fractures being the most prevalent. The fractures are mostly partially filled, with gypsum and calcite as the main filling materials. Fracture density primarily ranges from 0.41 to 0.76 fractures/m, with dominant orientations in the NNW-SSE and NEE-SWW directions. (2) Fractures are more developed near faults, especially near major faults, with layer thickness influencing fracture density, particularly in mudstone and sandstone layers. (3) Three major tectonic events have influenced fracture development, with the most significant fractures occurring during the third event in the Miocene-Pliocene. (4) A geomechanical-driven fracture strength model was constructed by combining various geological factors, including stress fields, fault proximity, and lithology, resulting in a more accurate representation of the fracture network in the reservoir. The findings of this research provide valuable insights into fracture characterization and modeling for gas reservoir development, contributing to more accurate reservoir simulation and management.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214200"},"PeriodicalIF":4.6,"publicationDate":"2025-09-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145020035","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":"In-situ high-strength Poly(styrene-methyl methacrylate)-2D nanofiller composite microbeads as potential proppants in hydraulic fracturing","authors":"Mohan Raj Krishnan ,&nbsp;Wengang Li ,&nbsp;Bader Alharbi ,&nbsp;Edreese Alsharaeh","doi":"10.1016/j.geoen.2025.214195","DOIUrl":"10.1016/j.geoen.2025.214195","url":null,"abstract":"<div><div>Many fracturing treatments involve the injection of solid proppants to ensure that hydraulic fractures remain open after they are created. Traditional proppants have drawbacks, including reduced propped-fracture volume and causing abrasion to pumping equipment. To solve these problems, this study presents copolymer composite microbeads that incorporate 2D nanofillers as high-strength in situ proppants for hydraulic fracturing operations. The poly(styrene-methyl methacrylate)-2D nanofiller (PS-PMMA-2D nanofiller) composite microbeads were synthesized using the emulsion polymerization technique. Various 2D nanofillers, including commercial graphene (CG), hexagonal boron nitride nanosheets (h-BN), and a combination of CG and h-BN (CG:BN), were utilized in the preparation of the copolymer composite microbeads. The morphology of the composite microbeads was thoroughly characterized using scanning electron microscopy (SEM), while Fourier Transform Infrared (FT-IR) spectroscopy and X-ray diffraction (XRD) methods indicated the successful formation of the composites. Differential scanning calorimetry (DSC) was employed to assess thermal stability, revealing that the composite's glass transition temperature (T_g) is 104.4 °C. Notably, these copolymer composite microbeads demonstrated impressive crush resistance, achieving levels of up to 12,000 psi. As such, they hold significant potential as candidates for successful hydraulic fracturing applications.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214195"},"PeriodicalIF":4.6,"publicationDate":"2025-09-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145050132","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}