Geoenergy Science and Engineering最新文献

{"title":"Impact of through-layer fracturing on CO2 storage efficacy of interbedded reservoirs in inclined formations","authors":"Yaohui Wang ,&nbsp;Fugang Wang ,&nbsp;Donghui Wang ,&nbsp;Heng Li ,&nbsp;Hui Cheng ,&nbsp;Hailong Tian ,&nbsp;Yilong Yuan ,&nbsp;Guanhong Feng ,&nbsp;Qingcheng He","doi":"10.1016/j.geoen.2025.214132","DOIUrl":"10.1016/j.geoen.2025.214132","url":null,"abstract":"<div><div>Large-scale carbon dioxide geological storage (CGS) is an effective means of mitigating global warming. However, inconsistencies between the distribution of high-quality reservoirs and CO₂ source locations hinder the large-scale implementation of CGS. Studies indicate that saline aquifer sequestration plays a dominant role in geological storage, yet not all saline aquifers serve as high quality reservoirs for CO₂ sequestration. Sandstone-mudstone interbedded deposits are common in natural formations. What kind of engineering measures can improve the CO₂ injection performance of such an interbed reservoir is a challenging problem. This study targets sandstone-mudstone interbedded reservoirs, and proposes a new interbedded reservoir modification concept using through-layer fracturing in horizontal wells. A three-dimensional numerical model was developed to systematically evaluates the effectiveness of fracturing in enhancing CO₂ storage under various dip angles, accounting for formation dip angle and fracture height. Results show that fracturing increases both the CO₂ migration distance and injection volume within the reservoir across different dip angles. In this study, migration distance increased by up to 66.7 %, and injection volume by up to 67.5 %. Compared to horizontal formations, inclined formations exhibit more significant injection enhancement, with a maximum enhancement of 12.5 %. An analysis of post-modification injection safety indicates that localized pressures may exceed safe injection thresholds due to the impact of fracture planes and formation slope. Adjusting injection well pressure effectively prevents this occurrence. The findings provide new insights and methodologies for optimizing CGS site selection and improving reservoir sequestration performance.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214132"},"PeriodicalIF":4.6,"publicationDate":"2025-07-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144725073","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 and numerical investigations into the influence of temperature on the permeability of sediments containing CO2 hydrate","authors":"Ruirui Li ,&nbsp;Luqing Zhang ,&nbsp;Zhejun Pan ,&nbsp;Jian Zhou ,&nbsp;Zhenhua Han ,&nbsp;Xiaowei Hou ,&nbsp;Rafig Azzam","doi":"10.1016/j.geoen.2025.214129","DOIUrl":"10.1016/j.geoen.2025.214129","url":null,"abstract":"<div><div>Induced by heat injection or climate change, temperature change in CO₂ hydrate sequestration reservoir significantly affects the permeability, which is crucial for the sealing ability of target reservoir. A combination of experimental tests and fluid-mechanical-thermal coupling simulations is applied to investigate the temperature influence on CO₂ hydrate-bearing sediments. Below the critical temperature for phase transformation, the permeability exhibits a decreasing trend with increasing temperature, demonstrating a quadratic relationship. Moreover, higher hydrate saturation will promote this reduction. In principle, the increase of temperature leads to linear narrowing of pore throats, further causes the quadratic relationship between permeability and temperature. Higher hydrate saturation will increase the thermal expansion and reduce the initial size of pore throats, which results in a more significant temperature sensitivity. The reduction of permeability may inhibit the advancement of decomposition front and enhance the sealing ability. Accordingly, a predictive model is developed to elucidate the relationship between permeability, temperature, and saturation, thereby providing valuable support for the modeling and prevention of CO₂ leakage in marine CO₂ sequestration practices.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214129"},"PeriodicalIF":4.6,"publicationDate":"2025-07-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144721074","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":"Novel enhanced oil recovery screening methodologies by implementing improved stacking ensemble learning algorithms","authors":"Min Zhang ,&nbsp;Na Zhang ,&nbsp;Dawei Ren ,&nbsp;Liujun Chen ,&nbsp;Ya Yao ,&nbsp;Shengshuai Su ,&nbsp;Han Wang ,&nbsp;Yongxin Hu","doi":"10.1016/j.geoen.2025.214104","DOIUrl":"10.1016/j.geoen.2025.214104","url":null,"abstract":"<div><div>Precise and dependable screening for Enhanced Oil Recovery (EOR) is essential for the optimal planning and design of EOR projects. The adoption of machine learning-based models for EOR screening presents a promising solution to the challenges inherent in the process. Nonetheless, issues such as data imbalance and overfitting pose significant hurdles to enhancing the predictive accuracy of these models. The goal of this research is to develop innovative EOR screening models utilizing an improved Stacking ensemble learning approach to address these challenges, thereby offering reservoir engineers more precise guidance for the swift and effective selection of the most appropriate EOR methods. In this study, traditional models such as Random Forests (RF), Extreme Gradient Boosting (XGBoost), Artificial Neural Networks (ANN), Decision Tree (DT), Support Vector Machine (SVM) and Logistic Regression (LR) were employed to establish classical EOR screening frameworks. Then based on the improved Stacking ensemble learning, these models were integrated to form advanced EOR ensemble screening models. To comprehensively assess model performance in the context of data imbalance, in addition to conventional evaluation indicators, the Kappa coefficient and the Matthews Correlation Coefficient (MCC) were introduced as novel evaluation metrics. The findings indicate that the accuracy, Kappa coefficient and MCC value of the newly developed models can reach up to 96.87 %, 0.955 and 0.955, which are much higher than other EOR screening models. The new models can provide more accurate and faster EOR screening decision support for reservoir engineers.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214104"},"PeriodicalIF":0.0,"publicationDate":"2025-07-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144713810","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":"Simulation and analysis of reactive flow in fractured carbonate reservoir using extended finite element method","authors":"Tianshu He ,&nbsp;Zhifeng Luo ,&nbsp;Long Cheng ,&nbsp;Yaozeng Xie ,&nbsp;Liqiang Zhao ,&nbsp;Li Shang ,&nbsp;Zhiguang Yao","doi":"10.1016/j.geoen.2025.214096","DOIUrl":"10.1016/j.geoen.2025.214096","url":null,"abstract":"<div><div>Acidizing is one of the effective means to increase oil and gas production in carbonate reservoirs, which improves the fracturing process by forming high conductivity oil and gas seepage channels. However, there are few studies on the acid flow reaction of matrix-fracture dual media. In order to solve the problem of acid flow reaction discontinuity in fractured media, this paper introduces the extended finite element method into the carbonate acid flow reaction model, and the migration level set method is combined to characterize the discontinuity of fractures. The model of matrix-fracture transfer of acid flow reaction in carbonate is established based on the double scale model, and the fully implicit method is used to discretely solve the established model. The effect of fracture parameters and geological engineering parameters on acid flow reaction are studied. The results show that the fracture length and azimuth angle have a great influence on the acid flow reaction. The width of acid fracture can reach 0.0015 m under the condition of 20 m, while the condition of 60 m can reach 0.00103 m. Compared with the condition of 90 °and 50°, when the length of fracture reaches 25 m, the width of acid fracture increases by 0.00025 m. The acid filtration and direction of wormhole propagation are only affected by the anisotropy of matrix permeability, and the wormhole development and fracture width of acid etching are less affected. Natural fractures have a great influence on the formation of complex acid-etched fracture network. Compared with the case of connecting main fractures, more acid is needed to form complex fracture networks when natural fractures are not connected to main fractures. The simulation and discussion show that the modeling of acid flow reaction in carbonate rock is of great significance to improve the effect of acidizing.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214096"},"PeriodicalIF":0.0,"publicationDate":"2025-07-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144713886","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":"Permeability characteristics of hydrate-bearing sediments during hydrate formation and depressurization decomposition processes","authors":"Hui-e Chen ,&nbsp;Wenchong Shan ,&nbsp;Yueqiang Ma","doi":"10.1016/j.geoen.2025.214099","DOIUrl":"10.1016/j.geoen.2025.214099","url":null,"abstract":"<div><div>The permeability of hydrate-bearing sediment (HBS) reservoirs governs fluid migration and directly influences the efficiency of gas hydrate extraction. In this study, HBS samples with varying hydrate saturations were prepared using two distinct methods: direct hydrate formation (Method A) and depressurization-induced decomposition (Method B). Permeability measurements were conducted under effective confining pressures ranging from 1.5 to 4.5 MPa. Hydrate growth modes during formation and decomposition were characterized using the Kozeny grain model (KGM), enabling mechanistic analysis of permeability evolution. Key findings reveals that the permeability decreases with increasing hydrate saturation and effective confining pressure. Under an effective stress of 4.5 MPa, permeability values decline to 3.76 mD (at <em>S</em>_<em>h</em> = 29.30 %), 9.44 mD (at <em>S</em>_<em>h</em> = 19.66 %), and 13.3 mD (at <em>S</em>_<em>h</em> = 11.27 %), respectively, closely matching field-scale observations. Notably, HBS samples subjected to hydrate formation and subsequent decomposition exhibit higher permeability than those without hydrate decomposition, highlighting the irreversible impact of hydrate dynamics on pore structure. Method B, simulating depressurization mining conditions, induces distinct hydrate growth modes, which critically alter permeability behavior. This method better replicates field-scale hydrate dissociation processes, demonstrating its superiority in predicting reservoir responses during gas extraction.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214099"},"PeriodicalIF":0.0,"publicationDate":"2025-07-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144680560","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":"MEOR-on-Chip: Lab-scale visualization of dynamics and mechanisms in microbial enhanced oil recovery via microfluidic technology","authors":"Wu-Juan Sun ,&nbsp;Ya-Ting Deng ,&nbsp;Zhi-Hui Jiang ,&nbsp;Xiao-Jun Wang ,&nbsp;Yong Gao ,&nbsp;Zhi-Rui Liu ,&nbsp;Cong-Yu Ke ,&nbsp;Si-Chang Wang ,&nbsp;Qun-Zheng Zhang ,&nbsp;Rui-Fei Wang","doi":"10.1016/j.geoen.2025.214082","DOIUrl":"10.1016/j.geoen.2025.214082","url":null,"abstract":"<div><div>Microbial enhanced oil recovery (MEOR) technology has made significant strides in both theoretical research and practical applications, yet gaps persist in understanding its mechanism. This study utilizes a microfluidic chip to delve into the microbial flooding process, simulating MEOR and employing in-situ monitoring through microscopic visualization. The on-chip microbial flooding experiments feature a composite microbial community which swiftly reproduces using petroleum hydrocarbons as the sole carbon source, producing biosurfactants, organic acids, and biogas with notable emulsification and viscosity reduction effects on crude oil. Microbial flooding, building on primary water flooding, elevates oil recovery by 16.7 %. In-situ imaging examines oil displacement, residual oil morphology, microbial dynamics, and MEOR mechanisms across displacement processes. Conclusions highlight microbial strains' robust growth and metabolite effects, with the composite community enhancing viscosity reduction by 74.1 %. Facilitated by microfluidic technology, mechanistic studies reveal microorganisms' interactions with oil, leading to emulsification and dispersion. Microorganisms primarily utilize petroleum hydrocarbons at the oil/water interface for growth, whilst use dissolved hydrocarbons in the aqueous phase as carbon sources. Microbial transportation in the reservoir during water injection reveals migration patterns across channels and blind ends, underscoring MEOR complexities. These findings enrich MEOR theory and inform future research and application endeavors.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214082"},"PeriodicalIF":0.0,"publicationDate":"2025-07-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144680561","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 carbon capture and storage technology using sodium alginate through response surface methodology","authors":"Muhammad Arqam Khan ,&nbsp;Shaine Mohammadali Lalji ,&nbsp;Moiz Ali Khan Sial ,&nbsp;Areeba Batool ,&nbsp;Mohsin Ayubi ,&nbsp;Syed Imran Ali ,&nbsp;Muhammad Mustafa ,&nbsp;Mei-Chun Li","doi":"10.1016/j.geoen.2025.214095","DOIUrl":"10.1016/j.geoen.2025.214095","url":null,"abstract":"<div><div>The increasing demand for sustainable carbon capture technologies necessitates the exploration of novel solvents for CO₂ absorption. Carbon Capture and Storage (CCS) is a critical technology for controlling greenhouse gas emissions and tackling climate change. This study investigated the efficiency of sodium alginate (Na-Alg) as a bio-based solvent in carbon capture technology using the simulation software, Aspen Plus. The model was developed to simulate the absorption of CO₂ in a tray column, and the performance of sodium alginate solution was analyzed using various key parameters, including temperature, pressure, and solvent flow rate, to maximize the carbon capture efficiency. The simulation was then validated with the help of existing literature and experimental data and was found to be in good correlation. The carbon capture efficiency of CO₂ was observed at 97 % using sodium alginate solution. The relations between process parameters and their influence on CO₂ capture were evaluated by applying response surface methodology, identifying optimal conditions at 10–20 °C, 10 bar pressure, and a solvent flow rate of 20–25 kmol/h. These findings highlight the potential of sodium alginate as an effective, eco-friendly solvent for CCS, offering both environmental and operational advantages. The study also demonstrates the utility of simulation and optimization techniques in enhancing CCS performance.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214095"},"PeriodicalIF":0.0,"publicationDate":"2025-07-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144680565","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":"Key mechanical properties of hydrate bearing sediment: state of the art and prospects","authors":"Qing Yang,&nbsp;Jiaolong Xu,&nbsp;Yubin Ren,&nbsp;Yunrui Han,&nbsp;Chen Zhou,&nbsp;Gang Yang,&nbsp;Yin Wang,&nbsp;Long Yu","doi":"10.1016/j.geoen.2025.214079","DOIUrl":"10.1016/j.geoen.2025.214079","url":null,"abstract":"<div><div>Natural gas hydrates (NGH), as an exceptionally promising source of clean alternative energy, are widely stored in the seabed. Insufficient understanding of the mechanical behavior of hydrate-bearing sediments (HBS) may increase the risk probability of triggering geological disasters and threatening safe exploitation. The objective of this paper is to make a comprehensive review of the key mechanical characteristics of HBS. Firstly, the preparation technology of HBS samples, including in-situ sampling and indoor synthesis technology was introduced. Then, the compressive characteristics of HBS were systematically concentrated from experimental research, mechanism analysis, numerical simulation and mathematical model. It was followed by the summaries of static mechanical properties, including the current development of test equipment, typical shear behavior of HBS at different conditions, and the major influencing factors. In particular, the research progress of the dynamic mechanical properties of HBS was generalized mainly from two aspects of large or small strain conditions and numerical simulation. Finally, the summary of this review and the shortcomings of the current research, as well as the prospects were made and proposed. This review is expected to deepen the understanding of the mechanical behavior of HBS for subsequent researchers and provide reference for future exploitation.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214079"},"PeriodicalIF":0.0,"publicationDate":"2025-07-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144711223","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 investigation on improving sweep efficiency through temperature-resistant gel foam in heavy oil reservoirs","authors":"Bin Zhang ,&nbsp;You Zhou ,&nbsp;Bojun Wang ,&nbsp;Changfeng Xi ,&nbsp;Weifeng Lv ,&nbsp;Pengcheng Liu","doi":"10.1016/j.geoen.2025.214117","DOIUrl":"10.1016/j.geoen.2025.214117","url":null,"abstract":"<div><div>As global demand for crude oil increases, the problem of steam channeling faced in the thermal recovery of heavy oil reservoirs seriously affects the oil recovery and operation cost. Due to the limitations of profile control in traditional foams, the aim of this experimental investigation is to develop a high-temperature-resistant gel foam system to plug steam channeling paths. Gel foam can compensate for the defect of poor thermal stability in single-component foam, and shows great potential in oil reservoir development. This paper mainly expounds that the gel foam system (0.5 wt% foaming agent AOS + 0.5 wt% polymer HPAM + 0.4 wt% crosslinker PE + 0.5 wt% stabilizer), as a profile control agent for improving the recovery, has better performance than the single foaming agent AOS. Through the experiments on the foam volume and the half - life of liquid separation, the foaming agent AOS has the highest foam complex index both at room temperature and under the high temperature condition of 200 °C. Subsequently, AOS is selected to be compounded with the gel, and the formula of the gel foam system with good gel - forming performance is determined: 0.5 wt% AOS +0.5 wt% HPAM +0.4 wt% PE + 0.5 wt% stabilizer. In the profile control experiment, when the gas-liquid ratio is 1:1, the addition of AOS to the gel can increase its resistance factor by 14 times, which confirms that compared with AOS, this system can effectively block the high - permeability dominant channels and improve the sweep volume, demonstrating great potential for enhancing oil recovery. Moreover, after the gel foam system is aged at 200 °C for 48 h and then subsequent water flooding of 15 PV is carried out, the plugging rate of the gel foam system is still as high as 86.4 %, which also indicates that this system can carry out long - term and effective profile control. Moreover, the heavy oil recovery of the gel foam slug is 6.3 % higher than that of the AOS slug. Therefore, as a profile control agent for improving the sweep efficiency, the gel foam system has greater advantages than AOS profile control.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214117"},"PeriodicalIF":0.0,"publicationDate":"2025-07-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144704279","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"CO2 plume monitoring and visualization using pathlines, source cloud and time cloud","authors":"Hongquan Chen,&nbsp;Ao Li","doi":"10.1016/j.geoen.2025.214093","DOIUrl":"10.1016/j.geoen.2025.214093","url":null,"abstract":"<div><div>Effective monitoring of subsurface fluid motion is crucial for successful carbon sequestration. While streamlines are commonly used to visualize fluid flow, they are based on instantaneous velocity fields and do not account for changing field conditions. To address this problem, pathlines are introduced to track the history of individual fluid particles as they move in a changing velocity field.</div><div>This paper presents the development and application of pathlines for flow visualization in CO₂ storage projects. By splicing streamline segments over time, pathlines can trace the trajectory of a particle under a changing velocity field. In addition, streaklines and timelines can be visualized from pathlines. Streaklines represent all fluid particles emitted at the same location, while timelines show the contour formed by all fluid particles emitted at the same instant, representing the fluid front movement. In 3D, these concepts are visualized in groups of points, referred to as source cloud and time cloud.</div><div>To test the effectiveness of our proposed injection monitoring methods, we conducted experiments on 3D synthetic CO₂ storage models. The results show that pathlines, source cloud and time cloud provide a more accurate display of the CO₂ plume than streamlines, particularly in field situations where well schedules are changing.</div><div>Finally, we applied the proposed method to visualize the CO₂ plume in a sequestration model based on Norway's Sleipner site. Under dynamic injection, the pathline-based swept volume closely matched the CO₂ saturation-defined volume (95 % overlap), while the streamline-based volume overestimated it by 127 %. This highlights the effectiveness of pathlines, source cloud, and time cloud for CCUS visualization.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"255 ","pages":"Article 214093"},"PeriodicalIF":0.0,"publicationDate":"2025-07-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144704379","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}