Geoenergy Science and Engineering最新文献

{"title":"Rheological and displacement performance of modified nano-SiO2 grafted polymeric system for enhanced oil recovery","authors":"Ousseini Seidina Ousseini ,&nbsp;Bo Peng ,&nbsp;Zhuang Miao ,&nbsp;Kai Cheng ,&nbsp;Jingwei Li ,&nbsp;Muhammad Faisal Altaf ,&nbsp;Ibrahim Issaka Ramatou ,&nbsp;Moussa Z. Salim ,&nbsp;Xuechao Yang ,&nbsp;Honfeng Zhang ,&nbsp;Weifeng Lv","doi":"10.1016/j.geoen.2025.214213","DOIUrl":"10.1016/j.geoen.2025.214213","url":null,"abstract":"<div><div>Polymer flooding is a widely used enhanced oil recovery technique, yet its efficiency is frequently limited by viscosity loss, shear degradation, and poor salt tolerance under harsh reservoir conditions. to address these challenges, this study presents a novel hybrid polymer nanocomposite, synthesized by grafting KH570-modified nano-SiO₂ into a poly(acrylamide-co-acrylic acid-co-2-acrylamido-2-methylpropanesulfonic acid) backbone. This molecular architecture has not been previously reported in EOR applications and provides dual advantages, such as robust covalent bonding between polymer and nanoparticle, and significantly enhanced nanoparticle dispersion within the polymer matrix. Comprehensive characterization using FTIR, SEM, and rheological analyses confirmed successful grafting and improved structural integrity. Unlike conventional polymer solutions, the new nanocomposite exhibited a 23 % higher viscosity retention in 10 g/L NaCl solutions, demonstrating excellent salt resistance and shear stability. Dynamic oscillation tests revealed significantly improved viscoelastic properties, suggesting superior performance in controlling mobility and minimizing viscous fingering. Core flooding experiments achieved an impressive oil recovery increase of 41–46 %, surpassing typical polymer flooding systems and highlighting the material's potential for improved sweep efficiency and conformance control in high salinity reservoirs. These results represent a significant breakthrough in polymer EOR technology, demonstrating that KH570-modified nano-SiO₂ grafting can effectively overcome traditional polymer limitations and offers promising pathway toward next generation EOR agents capable of maintaining performance under challenging reservoir conditions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214213"},"PeriodicalIF":4.6,"publicationDate":"2025-09-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049991","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":"Modeling and experimental studies on high-velocity slug and churn gas-liquid upward flows in vertical pipes","authors":"Rida Elgaddafi ,&nbsp;Ramadan Ahmed ,&nbsp;Raj Kiran ,&nbsp;Saeed Salehi","doi":"10.1016/j.geoen.2025.214210","DOIUrl":"10.1016/j.geoen.2025.214210","url":null,"abstract":"<div><div>Two-phase gas-liquid flow in vertical pipes is widely encountered in various industrial applications including oil and gas, nuclear, and petrochemical sectors. In petroleum production, it occurs in wellbores, risers, and pipelines, where pressure variations significantly influence flow patterns. Gas release from the liquid phase due to pressure reduction leads to distinct two-phase flow regimes, which, if not properly controlled, may result in blowout incidents. A comprehensive understanding of flow characteristics, including liquid holdup, void fraction, and pressure drop, is crucial for accurately modeling Worst-Case Discharge (WCD) and predicting wellhead pressure. This knowledge facilitates the estimation of hydrocarbon flow rates and the development of effective well control strategies to mitigate blowout risks.</div><div>This study aims to improve the understanding of gas-liquid slug, and churn flows in vertical pipes under high superficial gas and liquid velocities (V_Sg: 8.5–70 m/s, V_Sl: 0.12–2.89 m/s), conditions that remain insufficiently characterized in the existing literature. A combination of experimental and theoretical approaches was employed to investigate these flow regimes. Air-water two-phase experiments were conducted in an 83 mm vertical stainless steel pipe equipped with a transparent section, allowing direct visual observation of flow patterns using a high-speed digital camera. To improve the prediction of slug and churn flow behavior at elevated gas and liquid velocities, new mechanistic models are developed by integrating hydrodynamic frameworks from existing mechanistic models, refining the description of flow dynamics.</div><div>The study identified high-velocity slug and churn flow patterns within the investigation section of the experimental setup, which aligned with established flow maps. The pressure gradient behavior was found to vary with superficial gas and liquid velocities, revealing a critical transition point where the dominant flow mechanism shifts from gravitational to frictional forces. The proposed models significantly enhance the accuracy of pressure gradient predictions, with discrepancies generally remaining below 20 % and a maximum deviation of 15 % for churn flow predictions. However, at high gas velocities exceeding 30 m/s, the models exhibit an overestimation of liquid holdup by up to 64 %, particularly near the churn-annular transition. Improved accuracy in liquid holdup predictions is achieved by averaging the predictions from the churn and annular flow models, emphasizing the necessity of combining flow-specific models to enhance reliability in transitional flow conditions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214210"},"PeriodicalIF":4.6,"publicationDate":"2025-09-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049988","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 impact of ScCO2 exposure on the imbibition of shale and the potential for water block removal","authors":"Nianjie Kuang ,&nbsp;Junping Zhou ,&nbsp;Xuefu Xian ,&nbsp;Hongzhang Wang ,&nbsp;Jinyuan Zhang ,&nbsp;Zhengjie Liu ,&nbsp;Zixuan Huo ,&nbsp;Chenghao Xu ,&nbsp;Yifan Peng ,&nbsp;Huaquan Jiang","doi":"10.1016/j.geoen.2025.214207","DOIUrl":"10.1016/j.geoen.2025.214207","url":null,"abstract":"<div><div>Shale gas production in its later stages is severely limited by water block due to the retention of massive fracturing fluids in the reservoir. Effective water block removal is critical for improving shale gas production. Supercritical CO₂ (ScCO₂) has emerged as a promising fluid for alleviating water block in shale; however, its potential and mechanisms remain poorly understood. This study investigates the changes in shale imbibition behavior induced by ScCO₂ exposure, and verifies its water blockage removal effect. Then, from a microscopic perspective, the water block removal mechanisms by ScCO₂ exposure were clarified. The results reveal that ScCO₂ exposure promotes the imbibition capability of shale, especially accelerating both its initial spontaneous imbibition rate and subsequent diffusion rate, which can be attributed to ScCO₂ exposure-induced formation of new corrosion pores and microfractures, as well as increases in pore size, total pore volume, and specific surface area. Consequently, the hydrophilicity of shale is reinforced, which facilitates the diffusion of fracturing fluid. As water saturation within the reservoir decreases, the flow resistance of gas in shale reservoir accordingly decreased, then the water block was alleviated. This study provides new insight for understanding the mechanism of ScCO₂ enhanced shale gas recovery.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214207"},"PeriodicalIF":4.6,"publicationDate":"2025-09-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049989","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":"Statistical assessment of optimization algorithms in empirical correlations for enhancing methane hydrate equilibrium predictions","authors":"Mohammed S. Asif,&nbsp;R. Asaletha","doi":"10.1016/j.geoen.2025.214194","DOIUrl":"10.1016/j.geoen.2025.214194","url":null,"abstract":"<div><div>In the pursuit of a low carbon future, natural gas emerges as a promising energy resource. One environmentally conscious and non-explosive approach to efficient natural gas storage is through its preservation in clathrate hydrates, renowned for their remarkable volumetric storage capacity. In the gas and oil industry, gas hydrates, which often form in pipelines causing flow blockages, present significant flow assurance challenges. Accurate estimation of gas hydrate formation conditions is essential for maximizing clathrate hydrate storage potential, mitigating hydrate related issues, and addressing varied industrial and environmental needs. This paper assesses some of the existing empirical correlations and subjects them to statistical analysis for identifying the most suitable model for calculating methane (CH₄) hydrate equilibrium in pure water, particularly for storage applications. Statistical analysis reveals that these correlations excel in localized pressure conditions but exhibit limitations in high pressure environments. To address this challenge, optimization algorithms like Genetic Algorithm (GA) and Particle Swarm Optimization (PSO) are employed to optimize the correlation coefficients. The modified correlations resulting from optimization are compared with their original counterparts, demonstrating enhancements in predictive accuracy.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214194"},"PeriodicalIF":4.6,"publicationDate":"2025-09-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049987","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":"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":"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":"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":"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}