Petroleum Research最新文献

{"title":"A 3D printing approach to microfluidic devices for enhanced oil recovery research: An updated perspective","authors":"Chantal T. Tracey,&nbsp;Egor O. Ryabchenko,&nbsp;Mariia A. Moshkova,&nbsp;Pavel V. Krivoshapkin,&nbsp;Elena F. Krivoshapkina","doi":"10.1016/j.ptlrs.2024.11.004","DOIUrl":"10.1016/j.ptlrs.2024.11.004","url":null,"abstract":"<div><div>Reservoir simulation uses numerical models to study how reservoir properties impact oil recovery. However, numerical modelling is insufficient and is often paired with physical simulation, where physical models are used to verify and improve simulation results. Historically, physical simulation was conducted using difficult-to-extract reservoir rock samples; however, microfluidic devices (MFDs) have emerged as viable substitutes. Unfortunately, conventional approaches to MFD fabrication leads to devices with physical and chemical properties dissimilar to that of reservoir rock – which can decrease simulation accuracy. Thanks to significant advancements in three-dimensional printing, it can be used to fabricate MFDs with properties and dimensions close to those of reservoir rocks thanks to high resolution, good dimensional accuracy, and a wide range of printable substrates, resulting in more accurate simulation aimed at maximizing oil recovery.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 370-382"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314513","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":"Hydrocarbon generation potential of South Geisum Oilfield, Gulf of Suez, Egypt: Source rock evaluation and basin modeling for unconventional hydrocarbon prospects","authors":"Mohamed Osman ,&nbsp;Sherif Farouk ,&nbsp;Tamer Salem ,&nbsp;Mohammad A. Sarhan","doi":"10.1016/j.ptlrs.2024.11.002","DOIUrl":"10.1016/j.ptlrs.2024.11.002","url":null,"abstract":"<div><div>This study aims to define the hydrocarbon generation potential of source rocks by assessing various factors including quantity of organic matter, types of kerogen, thermal maturity, and source of organic matter input. Depositional conditions of source rocks from Thebes, Brown Limestone, and Matulla formations in Well G-9, Well GA-2 and Well GW-6, are assessed through pyrolysis, vitrinite reflectance and 1D basin modeling. Results show the source rocks of Thebes and Brown Limestone formations exhibit favorable to excellent source rock characteristics with Type I–II kerogen and have the capacity to generate oil. Conversely, the source rocks of the Matulla Formation show fair to good source rock characteristics with Type II–III kerogen and have the capacity to produce both oil and gas. Thermal maturity shows the source rocks are at an immature stage. A 1D basin model is constructed for Well G-9 to simulate multi-tectonic episodes, burial events, and the history of thermal maturity. Sedimentation rates of Cretaceous to Eocene deposits are characterized by a low burial rate, which contrasts with the high burial and sedimentation rates for Miocene and post Miocene (Pliocene–Recent) strata. Overall, the South Geisum oilfield petroleum system is found to be immature based on integration of source rock evaluation and petroleum basin modelling.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 266-278"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314369","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":"Optimum formation depths for CO2 structural trapping: Impact of salinity","authors":"Haiyang Zhang,&nbsp;Muhammad Arif","doi":"10.1016/j.ptlrs.2025.01.001","DOIUrl":"10.1016/j.ptlrs.2025.01.001","url":null,"abstract":"<div><div>Geological CO₂ storage is considered a promising solution to achieve net-zero goals. Structural trapping is one of the primary mechanisms that holds the injected CO₂ within the storage medium and prevents leakage via an impermeable seal/caprock. The capillary sealing efficiency of the caprock is also crucial in ensuring the safety of structural trapping. Capillary sealing and the associated CO₂ column height are determined by the balance of capillary threshold pressure and buoyancy pressure, which is strongly influenced by the CO₂/fluid/formation properties (i.e., density, interfacial tension (IFT), and wettability). However, subsurface formations typically exhibit a wide range of salt concentrations and depict heterogeneity in terms of wettability and pore radius, further influencing these critical properties. Thus, the impact of salinity, wettability, IFT, and pore radius on structural trapping efficiency is assessed in this study. Our analysis suggests that the optimal storage depth for structural trapping decreases as salinity increases; for instance, the highest CO₂ column height was observed at a depth of ∼1400 m in 5 wt% salinity formations. New correlations were also developed to quantify the CO₂ column height and mass under various formation depths and salinity conditions. Despite different dissolved salts (e.g., NaCl, CaCl₂, and MgCl₂) influencing the brine density and IFT, their impact on structural trapping is negligible. Additionally, the heterogeneity in formation properties (i.e., wettability, IFT, and pore radius) strongly influences the CO₂ column height, resulting in uncertainties in the CO₂ distribution prediction.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 416-424"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314516","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":"Comparing the effect of nanofluids in capillary imbibition with traditional displacing fluids","authors":"V.A. Zhigarev ,&nbsp;M.I. Pryazhnikov ,&nbsp;A.D. Skorobogatova ,&nbsp;A.I. Pryazhnikov ,&nbsp;A.V. Minakov ,&nbsp;S.M. Zharkov","doi":"10.1016/j.ptlrs.2025.01.004","DOIUrl":"10.1016/j.ptlrs.2025.01.004","url":null,"abstract":"<div><div>The effectiveness of surfactant solutions, polymers and nanosuspensions in capillary imbibition was studied comparatively. Two series of experiments on capillary imbibition with displacing liquids from cores saturated with low-viscosity (4.2 mPa s) and high-viscosity (28.9 mPa s) oil were performed. Water, a polymer solution of polyacrylamide, surfactant solutions (AES and SDS), as well as suspensions of spherical nanoparticles were considered as displacing fluids. The mass concentration of the substances varied from 0.05 to 0.25%. The rate of change in the volume of the displaced oil for 0.1% AES solution and suspension 1030 over time was greater than for other displacing liquids. The smallest increase in the volume of displaced oil was observed for the polymer solution. The coefficient of low-viscosity oil displacement from sandstone by water as a result of capillary imbibition was found to be 58%. When using surfactant solutions and suspensions, an increase in the oil displacement coefficient was observed: the SDS solution increased the capillary imbibition rate by 4%, and the suspension of SiO₂ nanoparticles (10 nm) gave a 3% increase. The polyacrylamide solution reduced the capillary imbibition rate by 12%. In the series with higher oil viscosity, the effect of additives was more significant. The rate of capillary imbibition increased by 22% in the case of 0.1% SDS solution and by 24% for 0.1% SiO₂ suspension (10 nm). The analysis of the factors influencing the displacement coefficient during capillary imbibition with solutions of surfactants, polymers and nanosuspensions was carried out. It has been shown that nanosuspensions are not inferior to surfactant solutions and leave polymer solutions far behind in terms of their positive effect on the oil displacement coefficient.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 432-442"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314518","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":"Combined mechanistic and machine learning method for construction of oil reservoir permeability map consistent with well test measurements","authors":"Evgenii Kanin ,&nbsp;Alsu Garipova ,&nbsp;Sergei Boronin ,&nbsp;Vladimir Vanovskiy ,&nbsp;Albert Vainshtein ,&nbsp;Andrey Afanasyev ,&nbsp;Andrei Osiptsov ,&nbsp;Evgeny Burnaev","doi":"10.1016/j.ptlrs.2024.09.001","DOIUrl":"10.1016/j.ptlrs.2024.09.001","url":null,"abstract":"<div><div>We introduce a novel method for estimating the spatial distribution of absolute permeability in oil reservoirs, consistent with well logging and well test measurements. The primary objective is to create a permeability map, incorporating the well test interpretation results and achieving hydrodynamic similarity to the actual permeability distribution around each well. This enhancement aims to improve the accuracy of reservoir modeling outcomes in reproducing real data. We utilize Nadaraya-Watson kernel regression to parameterize the two-dimensional spatial distribution of rock permeability. The kernel regression parameters are optimized by minimizing the discrepancies between actual and predicted values of permeability at well locations, the integral permeability of the reservoir domain around each well, and skin factors. This inverse optimization problem is addressed by repeatedly solving forward problems, where an artificial neural network (ANN) predicts the integral permeability of the formation surrounding a well and skin factor. The ANN is trained on a physics-based dataset generated through a synthetic well test procedure, which includes the numerical modeling of the bottomhole pressure decline curve in a reservoir simulator and its interpretation using a semi-analytical reservoir model. The proposed method is tested on the “Egg Model”, a synthetic reservoir with significant heterogeneity due to highly permeable channels. The permeability map created by our approach demonstrates hydrodynamic similarity to the original map. Numerical reservoir simulations, corresponding to the constructed and original permeability maps, yield comparable pore pressure and water saturation distributions at the end of the simulation period. Additionally, we observe a notable match in flow rates and total volumes of produced oil, water, and injected water between simulations. The developed approach outperforms kriging in terms of numerical reservoir modeling outcomes. This research advances existing geostatistical interpolation techniques by fusing well logging and well test data to build the reservoir permeability map through an optimization framework coupled with machine learning. Unlike traditional variogram-based geostatistical simulation algorithms, our method provides a permeability distribution that is hydrodynamically similar to the actual one, enhancing initial guess in the history matching process. The novel incorporation of well test interpretation results into the permeability map represents a significant improvement over existing methods, offering an innovative approach that can benefit the petroleum industry. We also provide recommendations for further development of the proposed algorithm to account for geological realism.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 247-265"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314628","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 the potential of depleted oil reservoirs for CO2 sequestration through simulation modeling","authors":"Malik Muhammad Ali Awan ,&nbsp;Farzain Ud Din Kirmani","doi":"10.1016/j.ptlrs.2025.01.003","DOIUrl":"10.1016/j.ptlrs.2025.01.003","url":null,"abstract":"<div><div>Leading to achieve net zero emissions, performing carbon capture and storage (CCS) on a large scale is becoming more necessary, especially for developing countries, which are highly affected by the continuously increasing release of carbon dioxide (CO₂). It has also been observed that developing countries does not participate much in the release of CO₂ in the atmosphere but are highly influenced by global warming because of geological location. Therefore, addressing challenges of climate changes and its impacts requires high-capacity storage in safe and reliable locations. Depleted oil and gas reservoirs offer a valuable option to store CO₂ due to their adequate porosity and permeability. In this research, an effort has been made to provide a simulation study and comprehensive analysis of CO₂ storage through reservoir simulation in subsurface oil reservoir. In contrast to prior works, this research article introduces a simulation approach to assess the feasibility of CO₂ storage in an oil reservoir. Storage in an oil reservoir was modeled using a commercial compositional simulator. CO₂ behavior during injection is examined using gas injection profiles throughout the injection duration and injection rate. Results of the study demonstrate that reservoir pressure changes equally in all layers and grid blocks making the evaluated reservoir suitable for CO₂ storage. Bottom hole pressure (BHP) behavior during injection shows the feasibility of CO₂ storage. The analysis revealed that continuous injection of CO₂ at a rate of 3500 Mscf/day over a period of 10 years led to a successful storage scenario, with the reservoir reaching its space limit and the injection rate dropping to zero. These results suggest the viability and effectiveness of CO₂ storage as a means of mitigating greenhouse gas (GHG) emissions.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 425-431"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314517","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":"Mitigating gas migration with eutectic bismuth alloy plugs","authors":"Lewaa Hmadeh,&nbsp;Andriani Manataki,&nbsp;Marcelo Anunciação Jaculli,&nbsp;Behzad Elahifar,&nbsp;Sigbjørn Sangesland","doi":"10.1016/j.ptlrs.2024.09.003","DOIUrl":"10.1016/j.ptlrs.2024.09.003","url":null,"abstract":"<div><div>Gas migration is an important concern to address in oil wells, especially in those that are to be abandoned. Stopping a gas leakage is not a simple task, and this can be particularly detrimental when setting a cement plug, as the migrated gas can undermine the integrity of said plug. In this context, and considering the recent attention given to metal plugs, we investigate the capability of bismuth plugs in shutting off gas leakages. The bismuth alloy employed to form the plug is to be melted downhole, and thus its proper solidification may be compromised if a leakage is underway. We test the sealing capability of two bismuth alloys – the eutectic bismuth-tin and the eutectic bismuth-tin-indium – along with two pipes – acrylic and steel. Results indicate that the bismuth plug can seal off the inner space of the pipe as long as the alloy used is eutectic; otherwise, a channel is created if the alloy is only near eutectic, effectively permitting that the leakage still continues. This sealing capability has been verified for both eutectic alloys tested, although it was also observed that voids are still present within the plugs themselves, potentially undermining their mechanical properties. Furthermore, we also observed that a slow and controlled cooling approach reduces the volume of inner voids, thus mitigating the plug degradation caused by the migrating gas. Further work should verify how these voids impact the hydraulic shear bond strength of the plug. From a microstructural perspective, it seemed that the solidification cooling rate plays a key role in the grain size of the material, which significantly impacts the microstructure of the alloy and, consequently, its mechanical properties. Considering the findings discussed in this work, we recommend that a two-plug approach is employed in leaking wells: a first, eutectic plug would shut down the leakage at the cost of its strength, and then a second – eutectic or non-eutectic – plug would be placed under no leakage ensuring the desired strength and sealability requirements. This study further highlights the potential of bismuth alloys to enhance safety and efficiency in plug and abandonment (P&amp;A) operations by mitigating gas migration issues.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 2","pages":"Pages 331-341"},"PeriodicalIF":0.0,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144314662","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":"Numerical validation of a novel cuttings bed impeller for extended reach horizontal wells","authors":"Chi Peng ,&nbsp;Yao Xiao ,&nbsp;Jianhong Fu ,&nbsp;Quan Cao ,&nbsp;Jiyun Zhang ,&nbsp;Yu Su ,&nbsp;Honglin Zhang ,&nbsp;Xing Wan ,&nbsp;Danzhu Zheng","doi":"10.1016/j.ptlrs.2024.07.002","DOIUrl":"10.1016/j.ptlrs.2024.07.002","url":null,"abstract":"<div><div>To reduce the risk of downhole accidents resulting from poor wellbore cleaning during the drilling of extended reach horizontal wells, a new cuttings bed impeller is developed. The performance of existing cuttings bed impellers on wellbore cleaning efficiency is analyzed by multiphase numerical simulation. Based on this analysis, a new type of cuttings bed impeller is proposed, and its key structure parameters are optimized. Its cuttings removal performance under different working conditions is verified. The results show that the spiral impellers have the highest annular velocity, promoting the movement of the cuttings bed. Increasing the rotation speed of the impeller causes the cuttings bed to move further from the low side of the wellbore, facilitating the cuttings removal. Two major improvements are introduced to the new cuttings bed impeller: a positive displacement motor that enables the self-rotation of the impeller, and the elastic contacts on the spiral blades that stir cuttings bed and reduce friction with the wellbore. The optimized parameters of the new impeller are: helix angle of 60°, 4 blades, elastic contacts arranged in crossed pattern, and self-rotation speed of 60 r/min. It is also demonstrated that the new impeller achieves satisfactory cleaning results in both rotary drilling (84.71%) and sliding drilling (71.07%) conditions. This work provides a new solution for the efficient removal of cuttings in extended reach horizontal wells.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 105-128"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141691513","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Development characteristics and controlling mechanism of different microfracture combinations in shale reservoir: A case study of Silurian Longmaxi Formation in Weiyuan area","authors":"Yuexiang Hao ,&nbsp;Lei Wu ,&nbsp;Wei Jiang ,&nbsp;Chao Qian ,&nbsp;Xin Zhou ,&nbsp;Yuanlin Wang","doi":"10.1016/j.ptlrs.2024.07.003","DOIUrl":"10.1016/j.ptlrs.2024.07.003","url":null,"abstract":"<div><div>Fractures in organic-rich shale are important reservoir spaces and seepage channels of shale gas, and they are closely related to the gas-bearing properties of shale. The development characteristics and laws of fractures are of great significance in the exploration and development of shale oil and gas. This study examines organic-rich shales of the Wufeng–Longmaxi Formation in the Weiyuan area of the Sichuan Basin. On the basis of two-dimensional large-area multi-scale combination electron microscopy characterization and digital core platform technology, the development degree and distribution of different fractures are quantitatively characterized. The results show the following. (1) The shale of the Wufeng and Longmaxi formations developed a variety of fractures with different occurrences, sizes, and origins. According to the number and combination relationship between fractures of different occurrences, the shale can be divided into four fracture combination types: horizontal bedding fractures; vein fractures; reticular fractures; and ring fractures. Of these, the horizontal bedding fracture group has the largest number of samples and a higher average fracture surface porosity. (2) The degree of fracture development in the shale is affected by many factors, such as the laminar type, mineral composition, mineral particle size, mineral distribution, and total organic carbon, and the controlling mechanisms of different fracture combination types differ. Factors such as horizontal stratification, high clay mineral content, and uneven mineral particle size are conducive to the development of horizontal bedding joints. (3) Differences in the sedimentary environment affect the variation laws of the vertical fracture combination types and density. The total organic carbon and organic quartz content of the Long1₁¹ layer with deeper sedimentary water is higher, and the vein fracture formation is more developed than in other small layers, while the clay mineral content of the Long1₁² and Long1₁⁴ layers with shallower sedimentary water is higher and the horizontal layer is more developed; the fracture combination type is dominated by the horizontal bedding fracture combination. At the same time, the fractures at the junction of each layer of the Long1₁ sub-member are the most developed because sea level rise and fall make the mineral particle size heterogeneity most prominent at the junction of the small layer.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 66-78"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141716314","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Modelling of physical and chemical properties of activated carbons which affect methane adsorption mechanisms","authors":"John Rwiza Rugarabamu","doi":"10.1016/j.ptlrs.2024.08.001","DOIUrl":"10.1016/j.ptlrs.2024.08.001","url":null,"abstract":"<div><div>Effect of important physical and chemical properties of activated carbons which affect the way methane adsorbs were studied. The Grand Canonical Monte Carlo (GCMC) simulations were used to study how the curvature and size of the platelets affect the mechanisms of methane adsorption process; and which role is played by the amount of oxygen present in activated carbons. Furthermore, Molecular dynamic (MD) simulations were carried out to study the effect of those properties on motion behavior of methane molecules during adsorption. The two simulations are very vital because they were able to exploit mechanisms which are difficult to obtain by using experiments alone. It was found that oxygen content, degree of curvature of platelets and size of basic structural units affected the availability of suitable methane binding sites in activated carbons and hence total methane adsorbed amount. Furthermore, the studied parameters were found to have impacts to the energy of interaction between activated carbons and methane, methane diffusion characteristics and amount of heat generated during adsorption process. It is concluded that the studied activated carbon properties hugely affect the way methane adsorbs and should be given attention during designing of the optimal adsorbent for methane adsorption.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 188-203"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684817","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}