Geoenergy Science and Engineering最新文献

{"title":"A convection-free optical method for measuring CO2 diffusion in porous media","authors":"Enoc Basilio,&nbsp;Simon Zougheib,&nbsp;Mouadh Addassi,&nbsp;Mohammed Al-Juaied,&nbsp;Tadd Truscott,&nbsp;Hussein Hoteit","doi":"10.1016/j.geoen.2026.214395","DOIUrl":"10.1016/j.geoen.2026.214395","url":null,"abstract":"<div><div>Carbon sequestration in saline aquifers is a promising strategy to mitigate anthropogenic carbon dioxide (CO₂) emissions. This study presents a novel experimental methodology to quantify CO₂ mass diffusion in porous media by employing a transmitted-light visualization technique. Unlike conventional approaches, our method isolates pure molecular diffusion by positioning the capillary tubes vertically with their open ends facing downward. In this inverted configuration, denser CO₂-enriched fluid is introduced from the bottom, naturally suppressing buoyancy-driven convection and ensuring that mass transfer occurs solely through diffusion. These transparent tubes, packed with glass beads of defined grain-size distributions and saturated with a pH-sensitive indicator solution, allow for real-time visualization and quantification of CO₂ dissolution. The acidification from dissolved CO₂ causes a color transition in the indicator, which is recorded and analyzed to extract effective diffusion coefficients. This setup enables direct observation of CO₂ transport in porous media under controlled, convection-free conditions. Systematic experiments examining the effects of salinity and pore structure reveal that increased salinity and reduced grain size significantly decrease CO₂ diffusivity. This work offers a simple method for convection-free quantification of CO₂ diffusivity in brine-saturated porous media, enabling more accurate modeling of solubility trapping and improving predictions of long-term CO₂ transport and retention in saline aquifers.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214395"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190718","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":"Seawater-based surfactant formulation for supercritical CO2 injection into coastal saline aquifers: Implications for fresh-water conversion and carbon management","authors":"Seokgu Gang ,&nbsp;Joo Yong Lee ,&nbsp;Shuang Cindy Cao ,&nbsp;Jeonghwan Lee ,&nbsp;Jae-Eun Ryou ,&nbsp;Jongwon Jung","doi":"10.1016/j.geoen.2026.214416","DOIUrl":"10.1016/j.geoen.2026.214416","url":null,"abstract":"<div><div>Coastal saline aquifers exhibit salinity levels comparable to seawater due to the intrusion of seawater. To effectively utilize the storage potential of aquifers, researchers have investigated the enhancement of carbon dioxide injection performance through the use of chemical additives such as polymers, surfactants, and nanofluids. In field applications, a significant amount of freshwater is typically required to prepare aqueous solutions containing these chemical additives. However, the use of salt-free freshwater necessitates additional transportation infrastructure and procurement costs, which in turn increases the overall cost of subsurface storage. In light of this, the present study evaluates the feasibility of utilizing seawater—which is more readily available than freshwater—for the offshore preparation of chemical additive solutions. For this evaluation, a surfactant known to be effective under deionized water conditions was introduced into a NaCl solution with a concentration similar to that of seawater. The interfacial characteristics between supercritical carbon dioxide and the aqueous solution, along with the injection efficiency in a porous medium, were subsequently assessed. The results indicate that the presence of NaCl induces salt screening and salting-out effects, leading to a further reduction in interfacial tension compared to that in pure water. While the contact angle exhibits only minor variations compared to interfacial tension, the capillary factor—defined as the product of interfacial tension and the cosine value of the contact angle—is predominantly influenced by the interfacial tension. Nonetheless, within the range of conditions and surfactant formulations tested in this study, the reduction in the capillary factor driven by interfacial tension did not lead to any measurable additional increase in injection efficiency. These results indicate that, for the present system, seawater-based surfactant solutions with added NaCl can achieve injection efficiencies comparable to those prepared with freshwater, suggesting that seawater is a promising substitute in practical applications. However, the extent to which this behavior holds in other reservoir conditions and for different surfactant systems should be examined in future studies.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214416"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190685","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 study on cave compensation mechanism in heat extraction of fractured karst geothermal reservoirs","authors":"Yu Shi ,&nbsp;Junlan Peng ,&nbsp;Congyue Liu ,&nbsp;Xu Zhang ,&nbsp;Xianzhi Song ,&nbsp;Huayang Liu","doi":"10.1016/j.geoen.2026.214407","DOIUrl":"10.1016/j.geoen.2026.214407","url":null,"abstract":"<div><div>Fractured karst geothermal reservoirs, characterized by multi-scale heterogeneity (fractures, caves, pores), exhibit complex flow-heat transfer processes, with unclear interactions between fractures and caves on heat extraction efficiency. This study establishes a thermo-hydraulic coupling model based on discrete fracture-cave network (DFCN), quantifying fracture-cave synergy via connectivity parameters. For the first time, it reveals the cave compensation mechanism for thermal breakthrough under moderate fracture density (0.02): At optimal fracture density, caves extend heat extraction lifetime from 17.67 to 19.68 years (11.3 % increase) by expanding low-temperature fluid diffusion area and prolonging heat exchange paths, while maintaining 0.6 kg/(m·s) outlet flow rate and 105 kW/m heat extraction power. Key findings include: (1) The core mechanisms of the cave compensation include: fluid diffusion path regulation, thermal breakthrough buffering, and connectivity complementary effects. (2) The cave compensation mechanism has a defined scope of application: namely, the fracture density is within the range of 0.005–0.03, and the cave density is within the range of 0–0.15; (3) Multi-parameter and fracture-cave system collaborative regulation can help fractured-karst geothermal reservoirs achieve long-term and high-flow efficient development. This research challenges the conventional focus on fractures alone, providing a theoretical framework for \"fracture-cave collaborative regulation\" in efficient geothermal development. The quantitative method directly guides well pattern design and parameter optimization in karst geothermal fields.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214407"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190217","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":"Experimental study of hybrid surfactant-gas enhanced oil recovery for liquid–rich tight reservoirs","authors":"Rohan Vijapurapu ,&nbsp;Abhishek Sarmah ,&nbsp;David S. Schechter ,&nbsp;Hadi Nasrabadi","doi":"10.1016/j.geoen.2026.214403","DOIUrl":"10.1016/j.geoen.2026.214403","url":null,"abstract":"<div><div>Enhanced oil recovery (EOR) in unconventional reservoirs commonly uses gas injection, while surfactant-based methods have recently gained attention. This study investigates a hybrid approach that combines surfactant-assisted spontaneous imbibition (SASI) with CO₂ injection in silica-rich, oil-wet tight rocks. Core flooding experiments were conducted on Scioto sandstone and Meramec shale, with surfactants selected through contact angle, interfacial tension, and imbibition tests.</div><div>Results show that surfactant injection followed by CO₂ consistently improves oil recovery compared to either method alone. Gas-first sequences recovered oil but caused delayed and reduced surfactant response. Gas chromatography confirmed that surfactants primarily mobilize heavier hydrocarbons, while CO₂ recovers lighter fractions. Gas utilization analysis further indicated higher efficiency when surfactant preceded gas injection. These findings demonstrate that the surfactant–gas sequence is more effective for hybrid EOR in liquid-rich, tight reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214403"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190719","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":"Determination of minimum operating pressure of salt cavern gas storage based on dynamic expansion model","authors":"Haoran Li ,&nbsp;Junsong Chang ,&nbsp;Ziheng Wang ,&nbsp;Cuiyao Zhuo ,&nbsp;Jiaqi Liang ,&nbsp;Feng Chen","doi":"10.1016/j.geoen.2026.214400","DOIUrl":"10.1016/j.geoen.2026.214400","url":null,"abstract":"<div><div>The minimum operating pressure is a critical parameter for underground salt cavern gas storage, yet no consensus exists on its determination despite various proposed approaches. Here, the volume expansion, Acoustic emission (AE) activity, and dilation angle characteristics of salt rock under different confining pressures are studied, and a constitutive model considering dilation angle variation is established to determine the minimum operating pressure of salt cavern gas storage in numerical simulation. The results show that the initial expansion stress increases linearly with confining pressure, with a coefficient of determination of 0.98, while the volume expansion exhibits a logarithmic relationship with confining pressure, with a coefficient of determination of 0.99. AE events occurring in the crack expansion stage post-expansion is 7.1 times more than in the crack compaction stage pre-expansion. Under low (5 MPa) and high (20 MPa) confining pressures, AE signals are predominantly high-frequency, indicating tensile fracture. In contrast, under medium confining pressures (10 and 15 MPa), AE signals are mainly characterized by low-frequency components, indicating shear fracture. The dilation angle of salt rock increases gradually with the increase of plastic shear strain and tends to be stable. The relation between plastic shear strain and the dilation angle of salt rock is obtained, and a constitutive model considering the variation of dilation angle is established and tested. A method for determining the minimum operating pressure of salt cavern gas storage is proposed and applied based on the principle of not allowing expansion. In this case, the minimum operating pressure of 8 MPa can effectively prevent sidewall expansion and ensure the safe long-term operation of the underground salt cavern gas storage.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214400"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190218","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":"Decision making on salt precipitation risk in geologic carbon storage: Driving factors and uncertainties","authors":"Hakan Alkan ,&nbsp;Nematollah Zamani ,&nbsp;Oleksandr Burachok ,&nbsp;Dirk Baganz ,&nbsp;Mohd Amro","doi":"10.1016/j.geoen.2026.214411","DOIUrl":"10.1016/j.geoen.2026.214411","url":null,"abstract":"<div><div>Salt precipitation during geologic carbon storage (GCS) can significantly impact injectivity, both positively and negatively, making accurate prediction of this phenomenon critically important. Injected CO₂—owing to its strong evaporation potential—displaces and evaporates in-situ brine in a process known as drying-out (DO). Once the salt solubility limit is exceeded, salt begins to precipitate (salting-out, SO), potentially leading to substantial permeability reduction and, in extreme cases, complete pore blockage.</div><div>In this study, we aim to advance the understanding of DO and SO dynamics by integrating insights from our ongoing research with a critical review of existing literature. Our goal is to develop a comprehensive workflow to assess the extent, distribution, and controlling factors of SO, along with its feedback mechanisms and mitigation strategies relevant for engineering practice. We first revisit the fundamental physics of DO and SO in the context of GCS, identifying key drivers and thresholds. Subsequently, we evaluate how geological, reservoir, and operational parameters influence these processes and their implications for storage performance. We further synthesize current uncertainties derived from laboratory experiments and numerical modeling approaches. The study concludes with a ranking of the relevancy of the driving factors and their associated uncertainty levels, supporting the design of sustainable and efficient CO₂ injection strategies. Rather than focusing solely on technical complexities, this work aims to provide reservoir and production engineers with a practical, decision-oriented workflow that also includes proposed methods for mitigating the risk of salt precipitation in GCS operations.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214411"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190683","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":"Erosion damage mechanism of fractured rock mass during cyclic compressed air storage and release in depleted sandstone oil-gas fields","authors":"Fuqiang Xu ,&nbsp;Xianzhi Song ,&nbsp;Yu Shi ,&nbsp;Mengmeng Zhou ,&nbsp;Gaosheng Wang","doi":"10.1016/j.geoen.2026.214389","DOIUrl":"10.1016/j.geoen.2026.214389","url":null,"abstract":"<div><div>Using depleted sandstone oil-gas reservoirs as underground storage vessels for compressed air energy storage (CAES) plays a crucial role in supporting the integration and consumption of renewable energy, while also reducing the costs associated with well abandonment. During the high-frequency and high-velocity cyclic injection-extraction of compressed air, sandstone reservoirs are susceptible to erosion damage under the combined action of compressed air and particles, particularly at microfractures. Therefore, this study establishes a thermal-hydraulic-mechanical (THM) coupling model based on particle tracking, aiming to analyze the characteristics and evolution rules of fractured rock mass erosion damage during the storage-release cycles. The research results indicate that the undulations of rough fracture surfaces exacerbate the heterogeneity of tracer particle distribution and velocity distribution, with particle impact being the primary cause of erosion damage. Specifically, higher flow velocities, larger particle diameters, higher particle release frequency, and lower Vickers hardness of rock mass lead to higher maximum erosion damage degree, cumulative erosion mass, and cumulative erosion area on fracture surfaces. Additionally, the erosion magnitude on the lower fracture surface is significantly higher than that on the upper fracture surface. Under the storage-release cycles, the alternating forward and reverse erosion of fracture surfaces by compressed air-particle mixtures intensifies the damage effect. This study provides insights for the design of CAES schemes and risk assessment for fractured rock mass of depleted sandstone oil-gas reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214389"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190219","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":"Probabilistic approach for static carbon storage capacity estimation: A case study on the VR014 depleted gas field in offshore Louisiana, USA","authors":"Ahmed K. Eleslambouly ,&nbsp;Mursal Zeynalli ,&nbsp;Emad W. Al-Shalabi ,&nbsp;Mohammad Alsuwaidi","doi":"10.1016/j.geoen.2026.214397","DOIUrl":"10.1016/j.geoen.2026.214397","url":null,"abstract":"<div><div>Depleted hydrocarbon reservoirs offer a technically viable and cost-effective solution for long-term geological carbon storage (GCS), particularly in offshore settings where infrastructure and subsurface data are well established. This study assesses the CO₂ storage potential of the VR014 Field, a depleted gas reservoir located offshore Louisiana in the Gulf of Mexico, by developing a static petrophysical model reflecting the field's depleted conditions. The workflow integrates 3D geostatistical modeling techniques to characterize five gas-bearing sandstone intervals. Three-dimensional spatial variations of petrophysical parameters were analyzed to assess reservoir heterogeneity and depleted static conditions, to inform volumetric storage estimation using a probabilistic approach. Storage capacity, as determined by a probabilistic Monte Carlo analysis, yields a total CO₂ storage capacity ranging from 56.1 million tonnes (Mt; P90) to 221.6 Mt (P10), with a P50 estimate of 115.4 Mt. The CRISI2 and BIG2_1C intervals account for the largest share of this capacity, driven by their superior reservoir quality, favorable structural positioning, and depleted volumes. Sealing integrity is supported by regionally continuous low-permeability shale units and fault transmissibility analysis, which confirms predominantly sealing behavior. The existing pressure depletion allows a wide operational injection window while maintaining safety margins below fracture thresholds. These findings demonstrate that VR014 Field offers favorable low-risk conditions for secure and efficient CO₂ sequestration. The integrated static modeling framework developed in this study provides a scalable and transferable methodology for the accelerated evaluation of CO₂ storage potential in other depleted gas fields across the Gulf of Mexico, thereby contributing to the advancement of basin-wide screening, site selection, and pre-injection certification strategies for offshore CO₂ storage deployment.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214397"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190223","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":"Structural reconstruction characteristics of mesopores, macropores, and fractures in anthracite matrix induced by supercritical CO2 injection","authors":"Bin Ren ,&nbsp;Changcheng Han ,&nbsp;Meng Wang ,&nbsp;Yiheng Li ,&nbsp;Xin Li","doi":"10.1016/j.geoen.2026.214391","DOIUrl":"10.1016/j.geoen.2026.214391","url":null,"abstract":"<div><div>The objective of this research was to investigate how the injection of supercritical CO₂ (scCO₂), with samples sourced from the southern margin of the Qinshui Basin, affects the properties of the samples. scCO₂ Alters the pore-fracture network within anthracite reservoirs, utilizing samples collected from the south edge of the Qinshui Basin. A comprehensive analysis was conducted using high-pressure mercury intrusion (MIP), low-temperature nitrogen adsorption (LTNA), and scanning electron microscopy (SEM), integrated with fractal theory. These methods facilitated a systematic study of the mesopore, macropore, and fracture structures in the coal specimens pre- and post-scCO₂ exposure. The results indicate that scCO₂-induced dissolution and swelling significantly alter the coal pore-fracture network, manifesting in the widening of primary fractures, development of secondary fractures, reduction of clay mineral infillings, expansion of secondary pores, and formation of new pores through mineral dissolution. Among these processes, the preferential dissolution of carbonate minerals, such as calcite, is a key factor in enhancing pore-fracture connectivity. The volume of mesopores (2–50 nm) generally increases. However, their proportion slightly decreases, whereas both the volume and proportion of macropores (&gt;50 nm) show marked growth, reflecting the synergistic effects of micropore merging and the creation of new dissolution pores. Fractal dimension analysis reveals that the fractal dimensions of mesopores (<em>D</em>₁) and macropores (<em>D</em>₂) both decrease overall, indicating reduced surface roughness and structural complexity after scCO₂ treatment, with coal samples from different mining areas exhibiting distinct characteristics due to mineralogical differences. This study examines the alterations in pore-fracture structures within high-rank coal following scCO₂ treatment. Providing experimental evidence to support mechanistic research on CO₂ geological sequestration and efficient coalbed methane extraction.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214391"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190689","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":"Synergistic CO2 storage and utilization in carbonate reservoirs via nanoparticle-stabilized foam","authors":"Ahmed Aboahmed,&nbsp;Kishore Mohanty","doi":"10.1016/j.geoen.2026.214385","DOIUrl":"10.1016/j.geoen.2026.214385","url":null,"abstract":"<div><div>Underground storage of CO₂ in aquifers and depleted oil and gas reservoirs is a promising strategy for reducing carbon emissions, with hydrocarbon reservoirs offering the added economic benefit of enhanced oil recovery (EOR). However, the capacity of CO₂ storage and utilization in carbonate reservoirs is limited by viscous fingering, gravity override, and reservoir heterogeneity. Foam flooding has been used to improve sweep efficiency and provide conformance control. Many carbonate reservoirs are high-temperature, high-salinity (HTHS) and finding effective foaming agents under such conditions remains challenging. This study investigates CO₂ storage and oil recovery using surfactant- and nanoparticle (NP)-based foaming agents under HTHS conditions. Experiments were conducted at 90 °C and 255,000 ppm salinity using Indiana limestone cores to represent harsh reservoir conditions. Graphene Quantum Dots (GQD) NP, synthesized in-house, along with silica nanoparticles, and surfactants were screened for aqueous stability, foam stability, and apparent foam viscosity. Core flood experiments were then performed on heterogeneous Indiana limestone cores at 90 °C and 2000 psi to evaluate oil recovery and CO₂ storage. Among the surfactants evaluated, bulk foam tests identified the zwitterionic surfactant Z7 as the most effective foaming surfactant under HTHP conditions. Synergistic effects between surfactants and nanoparticles were confirmed through stability tests in the presence and absence of oil. Foam rheology revealed shear-thinning behavior, with each formulation showing a minimum shear rate required for foam generation. Core flooding demonstrated that nanoparticle-stabilized foam significantly improved both oil recovery and CO₂ storage compared to continuous gas injection and WAG injection schemes.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"260 ","pages":"Article 214385"},"PeriodicalIF":4.6,"publicationDate":"2026-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"146190690","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}