Geoenergy Science and Engineering最新文献

{"title":"Hydrate decomposition and its influence on cement sheath strength in cementing process","authors":"Shichun Yan ,&nbsp;Mingming Zheng ,&nbsp;Zurui Wu ,&nbsp;Yawei Zhang ,&nbsp;Yunpeng Hu ,&nbsp;TianLe Liu ,&nbsp;Guosheng Jiang","doi":"10.1016/j.geoen.2025.214221","DOIUrl":"10.1016/j.geoen.2025.214221","url":null,"abstract":"<div><div>This study investigates the impact of gas hydrate decomposition on cement sheath integrity in deepwater wells encountering gas hydrate-bearing sediments (GHBS) using a novel coupled TOUGH + HYDRATE (T + H) and Particle Flow Code (PFC) model. The model simulates cement penetration, hydrate decomposition, and reverse invasion fluid migration, quantifying the collective effects on sheath integrity through crack development. Parametric studies show that hydrate dissociation extended up to 0.20 m, increase the cement sheath crack ratio by up to 40.64 %, and reduce compressive strength by up to 56.5 %. These findings evaluate the physical responses of the sediment-cement system under varying conditions, providing key insights for optimizing cementing strategies in GHBS.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214221"},"PeriodicalIF":4.6,"publicationDate":"2025-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106177","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":"Low carbon operation optimization of underground gas storage systems with embedded differential pressure generation based on user demand uncertainty","authors":"Jun Zhou ,&nbsp;Wenqi Fu ,&nbsp;Guangchuan Liang ,&nbsp;Shitao Liu ,&nbsp;Chengqiang Hu ,&nbsp;Ying He","doi":"10.1016/j.geoen.2025.214225","DOIUrl":"10.1016/j.geoen.2025.214225","url":null,"abstract":"<div><div>Underground gas storage (UGS) reservoirs operate with a large pressure difference between the injection-production pressure and the delivery pressure. To recover this residual pressure, this study proposes integrating natural gas pressure differential power generation technology (NGPDPGT) to UGS. Meanwhile, as a critical facility for natural gas storage and peak shaving, UGS must accommodate fluctuations in user demand. Therefore, this study establishes a low carbon operation optimization model of gas storage system with embedded differential pressure generation based on demand uncertainty (DPGC-Model). After preprocessing the uncertainty of user demand (UUD), the model is solved using a heuristic cycle optimization algorithm process. The optimization model is verified using UGS from a depleted gas reservoir in China (W-UGS), which proves that the carbon emissions are significantly reduced after the integration of differential pressure generator set (DPGS). The study investigates the changes in pressure and temperature at each well site after embedding DGPS and analyzes the operation of the UGS system under UUD. The results show that as the standard deviation and confidence level increase, both total operating carbon emissions and carbon reduction from differential pressure generation (DPG) increase. This study not only has significant implications for energy recovery and achieving low-carbon operations in UGS systems but also provides support for the application of NGPDPGT.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214225"},"PeriodicalIF":4.6,"publicationDate":"2025-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106278","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":"Enhancing gravel packing efficiency in horizontal wells with nitrogen foam: A numerical simulation study for weakly sandstone reservoirs","authors":"Changyin Dong ,&nbsp;Guolong Li ,&nbsp;Na Li ,&nbsp;Youchuang Liu ,&nbsp;Zhendong Li ,&nbsp;Li Bai","doi":"10.1016/j.geoen.2025.214216","DOIUrl":"10.1016/j.geoen.2025.214216","url":null,"abstract":"<div><div>Gravel packing is a widely used sand control technique in oil and gas wells, especially in horizontal wells, where formation instability and well deviation create significant challenges. Conventional gravel packing with Newtonian fluids often faces issues such as premature sand bed plugging, excessive operational stress, and an increased risk of formation fracturing. To address these limitations, this study systematically examines the rheological behavior of nitrogen foam under varying temperature and pressure conditions, developing a viscosity prediction model based on experimental data. By integrating classical fluid mechanics with granular flow theory, a refined three-layer hydraulic flow model is introduced to simulate the nitrogen foam gravel packing process. Numerical simulations assess the impact of key parameters—including gravel size, foam quality, foaming agent concentration, pump flow rate, and sand concentration—on packing efficiency. Experimental results show that at an SDBS (Sodium dodecyl benzene sulfonate) concentration of 1.5 %, nitrogen foam achieves optimal foaming performance and strong sand-carrying capacity. Using a field oil well as a case study, simulations indicate that optimized parameters, including a pumping rate of 65 m³/h, gravel density of 1600 kg/m³, foam quality of 67 %, and a sand concentration of 7.5 %, significantly enhance packing efficiency. Field validation in Well P15 of the high-fluid-loss Gudong reservoir in the Shengli Oilfield confirms that these optimized conditions achieve a packing rate of approximately 97.53 %. This study provides a solid foundation for applying nitrogen foam in gravel packing for horizontal wells, offering valuable insights into its rheological behavior, transport mechanisms, and field applicability.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214216"},"PeriodicalIF":4.6,"publicationDate":"2025-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106280","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":"Research on extension mechanism of directional hydraulic fracture under abutment stress based on XFEM","authors":"Dingchao Chen ,&nbsp;Xiangyu Wang ,&nbsp;Jianbiao Bai ,&nbsp;Feiteng Zhang ,&nbsp;Yuan Chu ,&nbsp;Xian Wang ,&nbsp;Guangjun Sun","doi":"10.1016/j.geoen.2025.214230","DOIUrl":"10.1016/j.geoen.2025.214230","url":null,"abstract":"<div><div>Directional hydraulic fracture (DHF) is a commonly used rock control technique in coal mining, with extensive applications in mitigating dynamic ground pressure, managing hard roof hanging, and depressurizing gob-side roadways. However, these fracture zones are typically located near roadways and working faces, where they are subjected to mining-induced disturbances and experience significant abutment stress. In this paper, numerical simulations using the extended finite element method (XFEM) were conducted to investigate the mechanism of DHF propagation in the presence of abutment stress. The influences of stress concentration factor, lateral pressure coefficient, vertical stress, and perforation angle on DHF were analyzed. The results demonstrate that the lateral pressure coefficient is the primary factor determining the redirection of the hydraulic fracture (HF), while the stress concentration factor and vertical stress have minimal influence on the redirection of HF. A perforation angle of 90° yields vertical HFs, but the HF influence range decreases with increasing lateral pressure coefficient. Furthermore, a comparison was made between HF effects with and without guiding boreholes. This research provides important theoretical insights for optimizing the HF technique in the presence of abutment stress in the roof strata.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214230"},"PeriodicalIF":4.6,"publicationDate":"2025-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145120904","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":"Enhanced CO2 foam stabilization with fluorescent nano polymer microspheres for improved oil recovery: Insights from microscopic and macroscopic displacement studies","authors":"Hongbin Yang ,&nbsp;Haocong Li ,&nbsp;Hao Xu ,&nbsp;Ruichao Wang ,&nbsp;Yubin Zhang ,&nbsp;Luyao Xing ,&nbsp;Xin Chen ,&nbsp;Liang Peng ,&nbsp;Wanli Kang ,&nbsp;Bauyrzhan Sarsenbekuly","doi":"10.1016/j.geoen.2025.214222","DOIUrl":"10.1016/j.geoen.2025.214222","url":null,"abstract":"<div><div>CO₂ foam flooding is an effective enhanced oil recovery (EOR) technique that has been extensively studied for development of low-permeability reservoirs. However, during its application, poor foam stability often leads to severe gas channeling, resulting in lower recovery. In order to improve the foam stability, a CO₂ foam system was constructed by using fluorescent nano polymer microspheres (PARC(Flu-Ac)-5) and anionic surfactant sodium α-alkene sulfonate (AOS). The macroscopic and microscopic stability of the CO₂ foam system stabilized by PARC(Flu-Ac)-5 was investigated through its rheological properties, adsorption characteristics, and microscopic morphology. Furthermore, the sweep range of different foam systems and the stability of the foam in the channel were explored through the microscopic visualization model. Finally, the plugging and oil displacement performance of the CO₂ foam system stabilized by fluorescent nano polymer microspheres was evaluated through dynamic core flooding experiments conducted under CO₂ flooding reservoir conditions. Thus, the oil displacement mechanism of fluorescent nano polymer microspheres stabilizing CO₂ foam was revealed. The experimental results demonstrate that PARC(Flu-Ac)-5 microspheres greatly enhance the stability of CO₂ foam by adsorbing at the gas-liquid interface. It remains stable for 30 min when formed with 5 % oil content. The microspheres' distinctive elastic deformation characteristics enable their migration and subsequent plugging of the pores following foam rupture, thereby establishing a dual anti-gas channeling mechanism. The total recovery of CO₂ foam system stabilized by fluorescent nano polymer microspheres is 46.71 %. The oil displacement effect is better than that of the single AOS foam system, and the total recovery rate is increased by 12.02 %. By adsorbing at the gas-liquid interface of foam liquid film, PARC(Flu-Ac)-5, acting as a foam stabilizer, enhances both the stability and oil resistance of foam within porous media. This adsorption behavior thereby enabling the foam to maintain its integrity upon encountering crude oil and preventing foam coalescence and defoaming. Concurrently, under the Jamin effect of the foam, the foam preferentially occupies the pore space in high permeability layers, and the injected fluid is diverted toward unswept regions following the plugging of high permeability pathways. Consequently, the sweep range and the driving ability of the subsequent foam to enter the blind end are increased, and the recovery rate of crude oil is improved. This work lays a theoretical foundation for the field application of polymer microspheres stabilized CO₂ foam system.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214222"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106179","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":"Stabilizing effect of tetrabutylammonium bromide on CO2 hydrate in kaolinite nanopores: A molecular dynamics study under static and flow conditions","authors":"Han Jia ,&nbsp;Fangning Fan ,&nbsp;Qiuxia Wang ,&nbsp;Qiuyu Xie ,&nbsp;Yuanbo Wang ,&nbsp;Canran Wang ,&nbsp;Yang Liu ,&nbsp;Xu Li ,&nbsp;Pan Huang ,&nbsp;Yurong Zhao","doi":"10.1016/j.geoen.2025.214219","DOIUrl":"10.1016/j.geoen.2025.214219","url":null,"abstract":"<div><div>The stability of CO₂ hydrate in clay-rich porous media is fundamental to the safety of geological CO₂ storage. While the TBAB is known as hydrate promoter, its stabilizing effect under the combined influence of thermodynamic condition and dynamic flow remains poorly understood. This study systematically investigates the stabilizing effect of TBAB on CO₂ hydrate stability in the kaolinite pores by molecular dynamics simulation across a range of temperature (255–295 K) and pressure gradients (0–50 MPa/nm). It is found that TBAB mitigates hydrate decomposition by forming a continuous, protective TBA⁺-CO₂-H₂O ternary composite structure near the hydrate. Innovatively, it is found that the stabilizing mechanism is non-monotonic with respect to flow. The moderate shear flow could enhance stability by organizing TBA⁺ ions into a more effective barrier, whereas high flow rates disrupt this layer. Similarly, high temperature facilitates the escapement of CO₂ from the ternary composite structure accelerating hydrate decomposition. These molecular-level insights offer crucial guidance for practical applications, informing the selection of favorable temperature conditions and suggesting that moderate injection flow rates may contribute to enhanced storage security. Ultimately, this work provides crucial insights for developing additives to ensure the long-term safety and efficiency of hydrate-based CO₂ storage.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214219"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106181","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":"Molecular dynamics insights into interfacial tension and solubility of hydrogen-cushion gas-water systems for underground hydrogen storage","authors":"Zhenxiao Shang ,&nbsp;Yongfei Yang ,&nbsp;Jiawei Li ,&nbsp;Qi Zhang ,&nbsp;Lei Zhang ,&nbsp;Hai Sun ,&nbsp;Junjie Zhong ,&nbsp;Kai Zhang ,&nbsp;Jun Yao","doi":"10.1016/j.geoen.2025.214215","DOIUrl":"10.1016/j.geoen.2025.214215","url":null,"abstract":"<div><div>Underground hydrogen storage (UHS) has been a promising option for large-scale hydrogen storage. Gas-water interfacial tension (IFT) and gas solubility are important parameters affecting the flow and distribution of hydrogen in underground porous media. The IFT and solubility of hydrogen-water systems at temperatures ranging from 298.15 K to 373.15 K, pressures ranging from 2.76 MPa to 46.88 MPa, and salinities up to 4.95 mol/kg were investigated using molecular simulation methods. The IFT of hydrogen-water systems exhibits a negative correlation with temperature and pressure but a positive correlation with salinity. Hydrogen solubility exhibits a positive correlation with pressure while showing a negative correlation with temperature and salinity. Hence, the high salinity caprock has a higher hydrogen-water IFT and lower hydrogen solubility, which is favorable for UHS projects. Cushion gas is used to maintain formation pressure and meanwhile mixed with hydrogen gas and diffused with each other. The effects of three different cushion gas types, including N₂, CO₂ and CH₄, and various cushion gas contents on the IFT and solubility of hydrogen-cushion gas-water systems were also investigated. Contrasting these three cushion gases, N₂ and CH₄ affect the IFT and solubility of hydrogen-cushion gas-water systems to a similar extent. In particular, CO₂ exhibits a propensity for interfacial accumulation, and can greatly reduce the gas-water IFT and has a high solubility. CO₂ is an excellent cushion gas, which is not only conducive to the solubility trapping of CO₂, but also forms a barrier at the gas-water interface and reduces the hydrogen loss by dissolution. This study focuses on revealing the influence of cushion gas on the two-phase system of UHS and clarifying the underlying mechanisms. Thus, it contributes to the selection of target formations and cushion gas types for UHS.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214215"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145158377","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 the concentration of commercial partially CO2-soluble surfactants on foam strength","authors":"Albert Barrabino ,&nbsp;Helene Berntsen Auflem ,&nbsp;Mohammad Masoudi ,&nbsp;Torleif Holt ,&nbsp;Bård Bjørkvik ,&nbsp;Alv-Arne Grimstad","doi":"10.1016/j.geoen.2025.214223","DOIUrl":"10.1016/j.geoen.2025.214223","url":null,"abstract":"<div><div>Injection of CO₂ foam is an emerging technology for CO₂ mobility control. When searching for suitable surfactant system for maximum effect of the foam application it is necessary to consider deployment methods (dissolved in brine or in CO₂) and ways to avoid loss of foam strength away from the injection well. Loss of strength is partially related to concentration depletion caused by surfactant adsorption and partitioning into formation brine.</div><div>Here, two non-ionic surfactants with different CO₂ solubilities were studied in steady-state core flooding experiments with co-injection of CO₂ and surfactant solution with varying concentrations. For each surfactant concentration apparent viscosities were calculated from the measured differential pressures.</div><div>The surfactant Brij L23 had a low partition coefficient at the experimental conditions used, meaning that little surfactant was found in the CO₂. With this surfactant, foam was formed for low concentrations. The other surfactant, Tergitol TMN 10, was more CO₂ soluble, and the partition coefficient increased when the pressure was increased. As a result of the pressure increase more surfactant partitioned into the CO₂ and a higher concentration of surfactant was needed to form strong foam.</div><div>The experimental observations are explained as a result of the surfactant partitioning and are related to the critical micelle concentration of surfactant in brine. Additional measurements were made to characterise the rheology of the CO₂-brine interface for the different surfactant systems. It was shown that the interface was more flexible for the systems and conditions where strong foam was observed in the core flooding tests.</div><div>The observation that surfactant systems with stronger partitioning into CO₂ required higher concentrations to form strong foam, and also collapsed more rapidly for decreasing surfactant concentrations, seems to reject a proposition that high CO₂ solubility is favourable for expanding the reservoir zone where foam is generated. This indicates that the search for methods for effective CO₂ mobility control should concentrate on surfactants that are mainly water soluble.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214223"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145158378","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":"Optimization of microcrack control and performance in deepwater well cementing with microencapsulated phase change materials","authors":"Mingming Zheng ,&nbsp;Zurui Wu ,&nbsp;Tianle Liu ,&nbsp;Shichun Yan ,&nbsp;Xiaoke Li ,&nbsp;Guosheng Jiang ,&nbsp;Guokun Yang ,&nbsp;Yichen Du ,&nbsp;Yawei Zhang","doi":"10.1016/j.geoen.2025.214220","DOIUrl":"10.1016/j.geoen.2025.214220","url":null,"abstract":"<div><div>As deep-sea resource exploration progresses, maintaining wellbore stability and preventing natural gas hydrate (NGH) decomposition during cementing pose persistent challenges. This study clarifies the mechanisms of microencapsulated phase change materials (mPCM) in cement slurry by optimizing mPCM particle size and dosage. An efficient synthesis method was developed to produce mPCM with a polymethyl methacrylate (PMMA) shell and a hexadecane-octadecane core, followed by detailed physicochemical characterization. The impact of mPCM particle size (unscreened and 5–50, 50–75, 75–100 μm) and dosage (0–12 wt%) on Class G oilwell cement performance was assessed under simulated deep-sea conditions (15 °C, 3.5 % NaCl solution) using calorimetry, micro-CT, scanning electron microscopy, and compressive strength tests. Findings reveal that mPCM reduces hydration heat by up to 15.56 %, accelerates hydration, and shortens the induction period. Adding 4 wt% mPCM with particles smaller than 50 μm enhances cement compressive strength by 12.55 % while maintaining slurry fluidity. Smaller mPCM particles improve pore structure uniformity, decreasing porosity by 46.33 %, whereas larger particles increase pore complexity, reducing mechanical integrity. Thermal regulation efficiency diminishes when ambient temperature exceeds the mPCM phase transition onset, though minimal heat control persists. These results provide a novel approach to designing low-heat cement slurries, offering theoretical and technical insights for safe, sustainable deep-sea oil and gas extraction with reduced ecological impact.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214220"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106207","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":"Evaluating rock wettability in CO2-water systems using relative permeability data: Implications for geologic CO2 sequestration in saline aquifers","authors":"Abouzar Mirzaei-Paiaman,&nbsp;Jerry L. Jensen,&nbsp;Sheng Peng","doi":"10.1016/j.geoen.2025.214228","DOIUrl":"10.1016/j.geoen.2025.214228","url":null,"abstract":"<div><div>Wettability of the reservoir rock plays a crucial role in CO₂ sequestration in saline aquifers, affecting trapping mechanisms, migration dynamics, spatial distribution, and injection performance. We present two methods to determine rock wettability in CO₂-water systems by analyzing water-displacing-CO₂ relative permeability data. The first method assesses whether the water saturation at the crossover point of relative permeability curves is above or below a reference value —defined as a function of endpoint saturations— to indicate water-wet, CO₂-wet, or neutral-wet conditions. The second method compares the areas under the CO₂ and water relative permeability curves, based on the principle that the wetting fluid's area should be smaller. We developed two indices for each method, ranging from −1 (strongly CO₂-wet) to 1 (strongly water-wet). Wettability was evaluated from 33 tests across sandstones, carbonates, and shales, showing a range of CO₂-wet to water-wet states that generally align with reported contact angle measurements. A key observation is that simpler water–oil systems used as proxies may not reliably represent CO₂–brine behavior, as they often remain water-wet due to cleaning procedures and the use of fluids that do not alter wettability during the experiment, even when viscosity ratios and interfacial tensions are matched. While uncertainties remain due to sampling origin (e.g., outcrop versus subsurface) and laboratory cleaning procedures, the ability to derive wettability directly from relative permeability data offers a practical advantage, as such measurements are more accessible than reliable contact angle data. This enables more robust interpretation of multiphase flow behavior, supporting improved assessments of CO₂ storage capacity, injectivity, and long-term containment. The approach presented in this research for inferring wettability from relative permeability data is not limited to CO₂–brine systems. It can also be applied to other systems, such as water displacing hydrogen sulfide (H₂S) in acid gas storage or water displacing hydrogen in underground hydrogen storage (UHS).</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214228"},"PeriodicalIF":4.6,"publicationDate":"2025-09-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145106206","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}