Geoenergy Science and Engineering最新文献

{"title":"Preventing and controlling water influx in gas wells: Key technologies and challenges","authors":"Sujuan Gao ,&nbsp;Ying Li ,&nbsp;Haitao Li ,&nbsp;Keliu Wu ,&nbsp;Song Nie ,&nbsp;Xiaojiang Cui ,&nbsp;Xintian Tai","doi":"10.1016/j.geoen.2026.214405","DOIUrl":"10.1016/j.geoen.2026.214405","url":null,"abstract":"<div><div>Gas reservoirs exhibit diverse water production mechanisms and variable manifestations, posing complex challenges to efficient gas recovery. While numerous water control technologies have been developed (covering wellbore liquid unloading, shutoff interventions, and reservoir-scale water invasion prevention), existing research predominantly addresses isolated techniques or provides parallel overviews, lacking a systematic classification and integrated evaluation. This review introduces a unified classification framework for water control technologies in gas reservoirs, grounded in the two primary water invasion types: edge-water drive and bottom-water drive. By integrating reservoir-scale invasion patterns with near-wellbore production behaviors, four distinct categories are defined: (1) deliquification, (2) water invasion prevention in gas zones, (3) wellbore shutoff and control, and (4) life-cycle coordinated water management. The framework delineates the functional roles and operational features of each category, and critically examines their technical limitations and implementation challenges. Through this multidimensional and systematic approach, the review enhances understanding of gas reservoir water control and addresses gaps in prior literature. It underscores the complexity of multi-scale, multi-mechanism systems, emphasizing that no single technology is sufficient for dynamic water production scenarios. A transition toward intelligent, refined, and data-driven strategies is essential. Future development should prioritize real-time monitoring, intelligent completions, and full life-cycle water management to replace empirical practices with science-based decision-making. This review provides both theoretical insight and practical guidance, offering value for future research and field deployment.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214405"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146081370","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":"Microscopic mechanism study of CO2 storage and enhanced oil recovery in hydrated nanopores of shale reservoirs: Focus on quartz and montmorillonite","authors":"Kanyuan Shi ,&nbsp;Xusheng Guo ,&nbsp;Baojian Shen ,&nbsp;Bing Zhou ,&nbsp;Junqing Chen ,&nbsp;Fujie Jiang ,&nbsp;Shasha Hui ,&nbsp;Tao Hu ,&nbsp;Benjieming Liu ,&nbsp;Peng Deng ,&nbsp;Enze Wang ,&nbsp;Xin Wang ,&nbsp;Zhangxin Chen","doi":"10.1016/j.geoen.2026.214392","DOIUrl":"10.1016/j.geoen.2026.214392","url":null,"abstract":"<div><div>The complex geological characteristics of shale reservoirs result in lower oil recovery rates. With its strong fluidity and diffusivity, supercritical CO₂ can improve oil recovery considerably while achieving CO₂ geological storage and reducing carbon emissions. Due to the difficulties associated with traditional experiments to reveal fluid behavior at the nanoscale and the impact of different shale oil components on CO2 storage, this study investigated the suitable conditions and microscopic mechanisms of CO₂ storage and enhanced oil recovery (CS–EOR) under different temperature, pressure, water content, and mineral hydrated nanopore conditions using molecular dynamics methods. Research has shown that water exists in the form of water clusters and columns in the quartz and montmorillonite nanopore walls, which weakens the adsorption capacity of the CO₂ and oil. High pressure, low temperature, and high water content conditions increase the density of the CO₂ on the mineral nanopore walls, reduce the interaction energy between the oil and the mineral nanopore walls, and enhance the solubility of the CO₂ and the extraction ability of the oil (saturated hydrocarbons have the best extraction effect), which is beneficial for CS–EOR. The interaction energy between asphaltene and CO₂ is the highest in the oil component. Compared with montmorillonite, quartz hydrated nanopores have higher fluid diffusion coefficients and stronger interaction between CO₂ and oil, exhibiting superior CS–EOR effects. By optimizing injection parameters, adjusting temperature and pressure, and reducing water content, the stability of CS and oil and gas recovery can be improved, providing important support for the efficient development of the energy industry.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214392"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146081369","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":"Studies on enhanced oil recovery using a novel Gemini ionic liquid-based deep eutectic surfactant","authors":"Shima Yaghoubi ,&nbsp;Javad Saien ,&nbsp;Mona Kharazi ,&nbsp;Samaneh Sanei Movafagh","doi":"10.1016/j.geoen.2026.214373","DOIUrl":"10.1016/j.geoen.2026.214373","url":null,"abstract":"<div><div>A novel deep eutectic surfactant (DESU) was synthesized from a Gemini surface active ionic liquid (GSAIL), [C₄im-C₆-C₄im][Br]₂, and urea precursors. Density functional theory (DFT) calculations, FT-IR, ¹H NMR, ¹³C NMR and TGA-DTG analyses revealed the hydrogen bond formation and the stability of the DESU product. Different aspects of enhanced oil recovery (EOR) were improved in the presence of the product. The crude oil−water interfacial tension (IFT) was reduced from 30.26 to very low value of 0.10 mN/m, exhibiting high performance, compared with individual precursors and even with their simple mixture (no eutectic formation). Temperature rising, from 298.2 to 328.2 K, improved this capability by reaching IFT to 0.03 mN/m i.e. 99.9 % reduction. Stable emulsions of water-in-oil were also prepared with emulsion index of 63.1 %. Furthermore, surface wettability was transformed from oil-wet to water-wet, evidenced by contact angle variations from 137^° to 34^° using about 1.0 mol/dm³ of the DESU in the aqueous phase. The IFT data were precisely reproduced based on the Frumkin isotherm model, and corresponding adsorption and thermodynamic parameters were determined. This study highlights potential application of the new generation of surfactants for EOR purposes.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214373"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146045209","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":"Effect of system wettability on three-phase displacements saturation paths and pore occupancies in the immiscible to miscible transition","authors":"S. Mahmoudvand,&nbsp;K.S. Sorbie,&nbsp;A. Skauge","doi":"10.1016/j.geoen.2026.214386","DOIUrl":"10.1016/j.geoen.2026.214386","url":null,"abstract":"<div><div>The extended Bartell-Osterhof theory of van Dijke et al. has been applied in previous work to study the physics of three-phase displacements in porous media of non-uniform wettability. The underlying theory has previously been confirmed by experimental data. More recently, the model has been verified by comparing its predictions on three phase pore occupancies with experimental micro-CT image results. These imaging experiments were carried out on water-wet and oil-wet systems and the comparisons were qualitatively good. However, the theory can be applied to any arbitrary wettability distributions in the porous medium to study the effect of the immiscible to miscible transition on three-phase flow in porous media. In this work, nine wettability cases (water-wet, oil-wet, mixed-wet and fractional wet) have been considered to cover all possible behaviour of the rock, and the results of different phase invasion are presented for the immiscible to miscible transition. Although experimental data is not available for several of these cases, a list of clear predictions are made which can be tested in due course.</div><div>The results show that <em>gas invasion</em> saturation paths at immiscible condition depends on wettability state of the system, while at near miscible conditions they become similar for all wettability states. Such behaviour is also predicted for <em>oil invasion</em> as well. However, the situation is quite different for <em>water invasion</em>. In case of water injection, no matter what the system IFTs are, in both immiscible and near miscible conditions, saturation paths are predicted to be identical. The details of the physics of this behaviour have been discussed by considering the role of the phase wetting order in three-phase systems.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214386"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146191266","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":"Coupled thermal-hydrodynamic-chemical modeling of calcite scaling in geothermal wells","authors":"Mojtaba Ghaedi ,&nbsp;Raoof Gholami ,&nbsp;Spyros Bellas ,&nbsp;Emmanuel Stamatakis","doi":"10.1016/j.geoen.2026.214415","DOIUrl":"10.1016/j.geoen.2026.214415","url":null,"abstract":"<div><div>Calcite scaling is a common and persistent issue in geothermal reservoirs, leading to flow restrictions, reduced operational efficiency, increased maintenance costs, and, in severe cases, system failure. Accurate prediction of the location, thickness, and temporal evolution of calcite scale is, therefore, essential for effective management and treatment planning of geothermal wells. This study presents a coupled thermal-hydrodynamic-chemical modeling framework to simulate calcite scaling in geothermal systems. An iterative drift-flux model was employed to resolve the temperature and pressure profiles along the wellbore, while the geochemical interactions driving calcite precipitation were modeled using PHREEQC. The simulation incorporates both crystallization and particulate scaling mechanisms, as well as the potential for scale removal from the wellbore walls. Model validation against field data from wells SNLG87-29 (Nevada, USA) and RN-15 (Reykjanes, Iceland) demonstrated strong agreement in temperature and pressure profiles. Furthermore, solubility models for calcite and CO₂ were calibrated against existing experimental data. The modeling approach accurately captured the evolution of calcite scaling in well 84-7 (Dixie Valley, USA), predicting a maximum scale thickness of approximately 30 mm and a vertical distribution span of around 290 m after 75 days of operation. It also appeared that in well 84-7, a 25% increase in calcium concentration led to a 50% reduction in flow area within only 56 days, compared to 74 days in the case with the original calcium concentration. These results underscore the ability of the proposed modeling approach as an important tool for predicting and managing calcite scaling, thereby enhancing the sustainability of geothermal energy production.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214415"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146191267","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":"Prediction and experimental study of gas-water-foam three-phase flow patterns in vertical wells using BKA-BP neural network","authors":"Shuqiang Shi ,&nbsp;Yaning Wang ,&nbsp;Donglin Li ,&nbsp;Dan Qi ,&nbsp;Jian Hui ,&nbsp;Zhen Wang ,&nbsp;Mei Xu ,&nbsp;Danlin Chen ,&nbsp;Shaokang Lin ,&nbsp;Qingyin Yu","doi":"10.1016/j.geoen.2026.214404","DOIUrl":"10.1016/j.geoen.2026.214404","url":null,"abstract":"<div><div>Liquid loading poses a major challenge in late-stage gas well production, requiring effective deliquification to sustain output. Foam-assisted gas lift, achieved by injecting a foaming agent into the wellbore, uses gas-liquid agitation to generate foam, reducing liquid density and surface tension while modifying the flow regime. This study focus on the Sulige Gas Field, where production data under field conditions were scaled using similarity principles. Utilizing the multiphase flow simulation apparatus, gas-water-foam three-phase flow experiments were conducted under varying gas volume flowrate, liquid volume flowrate, and foam drainage agent concentrations at normal temperature and pressure, resulting in the collection of 5572 experimental data sets. And the three-phase flow pattern of gas-water-foam under different experimental conditions was established. Additionally Based on typical gas-water-foam three-phase flow patterns in vertical wells, we identified the flow pattern under different experimental conditions and mapped them for vertical well. The BKA-BP neural network was optimized through the Black-winged Kite Algorithm (BKA) to improve flow pattern prediction accuracy. The optimization process involved adjusting the BP neural network's weights and biases, enhancing its learning efficiency and convergence rate. BKA, a metaheuristic algorithm inspired by the hunting behavior of the Black-winged Kite, searched for the global optimum by balancing exploration and exploitation in the solution space. This optimization resulted in a 97.8456% accuracy for recognizing flow patterns, outperforming other neural network models.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214404"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146191269","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":"Inference of pattern-based geological CO2 sequestration and oil recovery potential in a commingled main pay and residual oil zone CO2-EOR flood","authors":"C. Özgen Karacan,&nbsp;Emil D. Attanasi,&nbsp;Sean T. Brennan,&nbsp;Peter D. Warwick","doi":"10.1016/j.geoen.2026.214414","DOIUrl":"10.1016/j.geoen.2026.214414","url":null,"abstract":"<div><div>Several detailed studies have shown that residual oil zones (ROZs) can present significant resources for additional hydrocarbon recovery as well as subsurface carbon dioxide (CO₂) sequestration via enhanced oil recovery by injecting CO₂ (CO₂-EOR). Field development strategies included new wells drilled dedicated to main pay zones (MPZ) and ROZs, or existing wells in MPZs deepened to ROZs for commingled injection-production using different well patterns. The latter presented a challenge when discerning the injection and production from each of the zones, and for subsequent quantification of CO₂ sequestration and EOR potential from different patterns and from the field.</div><div>In this paper, an innovative method for analyzing commingled injections and productions from MPZs and ROZs, with application to pattern-based data from four staggered line drive patterns in Wasson Field's Denver Unit, Texas, USA, was developed. Decline curve and ratio-trend methods were used as means of history-matching and forecasting. Cumulative production-time and cumulative production-rate data for oil, gas, and water, as well as water-oil ratio (WOR) and gas-oil ratio (GOR), were analyzed along with injection data for time intervals covering major injection events in MPZ, or MPZ and ROZ combined. A combined analysis enabled inference of allocation of fluids into different zones during WAG (water alternating gas) injection and thereby estimation of CO₂ storage, utilization, and retention in different zones as a function of total injection. Results show that ROZs generally present higher CO₂ sequestration potential compared to MPZs, and a comparable incremental oil recovery factor of ∼20%, on average. Results based on ratio analysis further show that while the WOR trend of the pattern production is mostly dominated and controlled by ROZ, GOR is controlled by both intervals. Although the method relying on decline curves and the approach used in zonal fluid allocations are subject to their limitations, this study presents a practical and innovative well-pattern-based method to infer and forecast CO₂ sequestration and oil recovery quantities and fluid ratios from MPZs and ROZs in commingled operations and highlight the added potential offered by ROZs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214414"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190684","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 comprehensive evaluation system for the underground U-shaped salt cavern sediment voids oil storage in the high-impurity salt mine","authors":"Xinxing Wei ,&nbsp;Xilin Shi ,&nbsp;Yinping Li ,&nbsp;Yashuai Huang ,&nbsp;Yang Hong ,&nbsp;Xiaoyi Liu ,&nbsp;Chunhe Yang","doi":"10.1016/j.geoen.2026.214402","DOIUrl":"10.1016/j.geoen.2026.214402","url":null,"abstract":"<div><div>Underground salt caverns represent a crucial approach for large-scale oil storage. In the high-impurity salt mine, plenty of insoluble sediment particles accumulated at the salt cavern during cavern leaching, which markedly reduces salt cavern oil storage capacity. Exploiting sedimentary void spaces for oil storage presents an effective mitigation strategy, especially in a U-shaped salt cavern. To evaluate the operational feasibility in salt cavern sediment voids, a combination of theoretical modeling, physical simulations, and field test were developed. The theoretical framework development based on oil-brine hydrodynamic equilibrium principles was built. An experimental system simulating sediment voids was developed to investigate oil operational processes. The field oil storage capacity evaluation and void connectivity test were conducted. The results demonstrate that the oil storage in a U-shaped salt cavern sediment void is feasible, with an oil recovery ratio reaching 90 %. The theoretical model indicates that oil injection pressure is positively correlated with the oil injection rate and the oil-brine interface depth, and the brine injection pressure exhibits a negative relationship with brine density and oil-brine interface depth. Field test proved that the sediment void connectivity is great, and the fractional resistance is below 0.5 MPa. These findings offer critical engineering references for optimizing China's strategic salt cavern oil energy storage.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214402"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190686","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 fracture initiation pressure and tortuosity along perforations","authors":"Bruno Broesigke Holzberg ,&nbsp;Lucas do Nascimento Sagrilo ,&nbsp;Romulo Reis Aguiar ,&nbsp;Carlos André Bertolini ,&nbsp;Francisco Henriques Ferreira","doi":"10.1016/j.geoen.2026.214399","DOIUrl":"10.1016/j.geoen.2026.214399","url":null,"abstract":"<div><div>A model to perform a joint analysis of fracture initiation pressure and tortuosity along perforations in arbitrary wells is presented. Existing analytical solutions for fracture initiation analyses along perforations were reviewed and extended to incorporate tortuosity. To verify the representativeness of the solutions, finite element analyses were conducted. Comparisons between analytical and numerical methods revealed that although analytical solutions provide reliable stress estimates along the perforations, they tend to fail when applied to zones close to the perforation edges. To address this limitation in analytical modeling, it is proposed to discard results obtained near the edges and replace them with slightly offset values, where the solution remains valid. The importance of analyzing fracture initiation conditions along the perforation, including tortuosity is also demonstrated. Zones of a perforation with low fracture initiation pressures may exhibit high-tortuosity effects, compromising fracture initiation. This study enhances the understanding of the fracture initiation process and provides analytical solutions that consider both fracture initiation pressure and tortuosity along perforations. These elements can be used to define new criteria for fracture initiation in perforated wellbores, contributing to more effective fracturing jobs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214399"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190221","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":"Coupled effects of gas-water occurrence and velocity-induced permeability damage in CO2-ECBM","authors":"Yong Shu ,&nbsp;Yi Jin ,&nbsp;Shuxun Sang ,&nbsp;Yan Liang ,&nbsp;Zhenzhi Wang ,&nbsp;Jincheng Zhao ,&nbsp;Linxian Gong ,&nbsp;Yunbo Li ,&nbsp;Junqi Bao","doi":"10.1016/j.geoen.2026.214394","DOIUrl":"10.1016/j.geoen.2026.214394","url":null,"abstract":"<div><div>Gas-water occurrence and velocity-induced permeability damage (VIPD) are key coupled mechanisms governing coalbed methane (CBM) production. However, comprehensive studies on the coupled control of these factors in CO₂-enhanced coalbed methane recovery (CO₂-ECBM) processes remain scarce. Therefore, this study develops a fully coupled Thermal-Hydraulic-Mechanical numerical model for CO₂-ECBM considering VIPD. Numerical simulations were conducted to investigate gas injection-production behavior, fluid migration patterns, and permeability evolution under varying key parameters and initial water saturations (<em>S</em>_<em>w</em>0). The main findings are summarized as follows. (1) The gas-driven water effect and high-<em>S</em>_<em>w</em> zone formation are the primary reasons for VIPD and CH₄ production inhibition. Permeability variations induced by gas adsorption/desorption further cause differential VIPD responses. (2) VIPD significantly impacts CO₂-ECBM processes. Higher <em>S</em>_<em>w</em>0 intensifies VIPD severity near both production and injection wells. (3) Compared with regular drainage, CO₂-ECBM achieves significantly greater CH₄ production enhancement in high-<em>S</em>_<em>w</em>0 reservoirs. However, CO₂ injection may induce or exacerbate VIPD. (4) For high-<em>S</em>_<em>w</em>0 reservoirs, delayed CO₂ injection enhances both the peak CH₄ production rate and CO₂ sequestration. As <em>S</em>_<em>w</em>0 decreases, this strategy yields further improvements in CH₄ recovery and CO₂ storage. (5) Higher CO₂ injection pressure shortens the production ceasing time, reducing CH₄ production while increasing CO₂ sequestration. In high-<em>S</em>_<em>w</em>0 reservoirs, this pressure increase causes greater CH₄ production loss and smaller gains in CO₂ sequestration. (6) Deep CBM reservoirs featuring low-<em>S</em>_<em>w</em>0 and underdeveloped tectonically deformed coals help avoid VIPD, demonstrating high viability for CO₂-ECBM implementation. These findings provide significant theoretical insights and practical implications for enhancing CBM recovery and guiding CO₂ geological sequestration in coal seams.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214394"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146081232","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}