Geoenergy Science and Engineering最新文献

{"title":"Reviewing CO2 dynamics in acidizing carbonate reservoirs: Mechanisms, impacts, and models","authors":"Mohammad Khojastehmehr,&nbsp;Mohammad Bazargan,&nbsp;Mohsen Masihi","doi":"10.1016/j.geoen.2025.213767","DOIUrl":"10.1016/j.geoen.2025.213767","url":null,"abstract":"<div><div>Acidizing is a stimulation technique used in underground reservoirs to enhance well productivity by increasing the permeability of the rock matrix. During the reaction between acid and carbonates, carbon dioxide (CO₂) is produced, and factors such as its quantity and physical state significantly influence the efficiency of the acidizing process. This review explores the impact of CO₂ on acidizing through four primary mechanisms: relative permeability reduction, surface area reduction, diffusivity modification, and oil viscosity reduction. Each mechanism can either positively or negatively influence the efficiency of wormhole propagation, which is crucial for the success of acidizing treatments. Experimental studies reveal that the production of non-aqueous CO₂ leads to a reduction in relative permeability. The reduction in available surface area caused by CO₂ leads to enhanced acid propagation. The effect of CO₂ on diffusion is complex, as it can either decrease or increase the diffusion coefficient depending on its phase—aqueous, gaseous, liquid, or supercritical—and whether it promotes enhanced mixing. Additionally, oil viscosity reduction in the presence of an additional phase can improve acid propagation under certain conditions. This review also highlights key research gaps. The threshold backpressure required to maintain CO₂ in the aqueous phase remains poorly defined, with studies indicating that even pressures exceeding 6.90 MPa (1000 psi) may not suffice in certain cases. The combined and individual effects of aqueous and non-aqueous CO₂ under diverse reservoir conditions remain poorly understood. Additionally, while multiphase pore-scale numerical models have shown promise in simulating CO₂ behavior during acidizing, core-scale models often fail to capture the intricate interplay of mechanisms, particularly when multiple phases coexist. Addressing these gaps requires future experimental and numerical studies to focus on the porous media implications of CO₂ interactions. Specifically, research should aim to identify the critical parameters and develop robust methodologies to quantify the effects of CO₂-related mechanisms. By doing so, this work can guide future research toward improving the predictability and effectiveness of acidizing treatments while ensuring practical applicability across diverse reservoir conditions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213767"},"PeriodicalIF":0.0,"publicationDate":"2025-02-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143488840","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 review on mechanisms of CO2-fluid-rock interaction during CO2 injection into carbonate reservoirs","authors":"Qigui Tan ,&nbsp;Haoping Peng ,&nbsp;Jian Tian ,&nbsp;Zhongkai Cao","doi":"10.1016/j.geoen.2025.213773","DOIUrl":"10.1016/j.geoen.2025.213773","url":null,"abstract":"<div><div>CO₂ injection into carbonate reservoirs is regarded as a promising technology for enhanced oil recovery (EOR) and CO₂-emission reduction. Currently, due to the unknown relationships between CO₂ EOR and storage, petrophysical properties and induced formation damage, the application of CO₂ EOR and storage in carbonate reservoirs is still limited. In this work, we comprehensively review the CO₂ injection into carbonates reservoirs for EOR and storage from reservoir characteristics, CO₂-fluid-rock interaction mechanisms and induced changes of petrophysical properties. The <em>in-situ</em> fluid properties and mineralogical characteristics of carbonate reservoirs are first described. The CO₂ storage mechanisms in carbonate reservoirs are addressed, including structural trapping, residual trapping, solubility trapping and mineral trapping. Mechanisms of CO₂-oil interaction and CO₂-fluid-rock interaction are discussed to reveal the performance of CO₂ EOR in carbonate reservoirs. Variations in petrophysical properties of carbonate reservoirs obtained from the published experimental and numerical simulations are reported during CO₂ injection in this review. Meanwhile, formation damage issues caused by CO₂-fluid-rock interaction in heterogeneous and homogeneous carbonate reservoirs are highlighted, referring to mineral precipitation, fine detachment and migration, which have the negative effects on CO₂ EOR. Finally, the future challenges of CO₂ injection into carbonate reservoirs are pointed out, mainly including CO₂-fluid-rock interaction mechanisms with complex mineral compositions, and formation damage control during CO₂ injection. This review provides the significant sights into the CO₂-fluid-rock interaction mechanisms and its effect on reservoir characteristics, in a manner the reader can use for future work on technology optimization for CO₂ EOR and storage in carbonate reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213773"},"PeriodicalIF":0.0,"publicationDate":"2025-02-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143436564","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":"Trapping mechanism of a compound droplet on a heterogeneous substrate undergoing the Marangoni effect","authors":"Nang X. Ho,&nbsp;Hoe D. Nguyen,&nbsp;Vinh T. Nguyen,&nbsp;Truong V. Vu","doi":"10.1016/j.geoen.2025.213776","DOIUrl":"10.1016/j.geoen.2025.213776","url":null,"abstract":"<div><div>We numerically study the trapping mechanism of a compound droplet attached to a heterogeneous substrate undergoing the Marangoni effect. The substrate consists of a main part and a wettability-contrasted part. The investigated parameters included <em>Ma</em> (ranging from 0.4 to 0.8), <em>μ</em>_<em>am</em> (varying from 0.8 to 2.4), <em>R</em>_<em>io</em> (varying from 0.3 to 0.7), and Δ<em>θ</em>_<em>e</em> (ranging from 3° to 7°). The droplet becomes trapped at a low value of <em>Ma</em>, <em>μ</em>_<em>am</em>, and a high value of Δ<em>θ</em>_<em>e</em> as it moves toward the hot side. When the droplet moves toward the cold side, it becomes trapped at a low value of <em>Ma</em>, but a high value of <em>μ</em>_<em>am</em> and Δ<em>θ</em>_<em>e</em>. The inner droplet, in terms of the radius ratio <em>R</em>_<em>io</em>, has a significant impact on the trapping behavior of the outer droplet. Interestingly, the compound droplet with <em>R</em>_<em>io</em>≤ 0.3 crosses the wettability-contrasted part more easily the one with <em>R</em>_<em>io</em> = 0.4. In addition, when migrating toward the hot side, the compound droplet with a large contact angle allowing a larger inner droplet (0.5 ≤ <em>R</em>_<em>io</em> ≤ 0.7) is pulled across the wettability-contrasted part by the inner droplet as <em>Ma</em> ≥ 0.5. The trapping behavior rarely occurs in this case. Phase diagrams showing the transition between the trapping and passing behaviors are also proposed.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213776"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143444517","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":"New strategy for injection well stimulation by continuous bio-acid and nanofluid treatment: Laboratory and field trials","authors":"Fan Zhang ,&nbsp;Qing Feng ,&nbsp;He Zhu ,&nbsp;Bo Wang ,&nbsp;Xiaonan Li ,&nbsp;Shengsheng Li ,&nbsp;Yanni Sun ,&nbsp;Yulong Liu ,&nbsp;Shanshan Sun ,&nbsp;Yuehui She","doi":"10.1016/j.geoen.2025.213763","DOIUrl":"10.1016/j.geoen.2025.213763","url":null,"abstract":"<div><div>The efficacy of continuous bio-acid and nanofluid treatment in reducing injection pressure and enhancing the injectivity of water injection wells was evaluated through laboratory and field trials. Injection well stimulation demonstrated notable effects, supporting the feasibility of combining acidisation and hydrophobic nanofilm formation. Core displacement experiments, particle migration assessments, and scanning electron microscopy images revealed a positive interaction between bio-acids and nanofluids in plugging removal and injection pressure reduction. Bio-acids exhibit high etching performance, enabling the removal of plugging and modification of the surface charge of natural rock minerals, thereby enhancing nanoparticle adsorption on porous media surfaces. Nanofluids exhibit strong film-forming properties, altering the wettability of porous media surfaces and inhibiting particle migration, which mitigates the damage associated with acidisation. Field trials conducted on five injection wells in the BH oil field demonstrated sustained reductions in injection pressure and increased injection capacity following continuous bio-acid and nanofluid treatment. These effects persisted for over six months. Thus, the feasibility and high efficacy of integrating acidisation with hydrophobic nanofilm formation were confirmed, leading to the proposal of a novel strategy for injection well stimulation through continuous bio-acid and nanofluid treatment.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213763"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143452803","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":"Study on the mechanism of CO2 composite pressure flooding recovery enhancement in deep medium-low permeability heavy oil reservoirs","authors":"Bin Zou ,&nbsp;Haishun Feng ,&nbsp;Xin Xia ,&nbsp;Tiantian Yu ,&nbsp;Wangang Zheng ,&nbsp;Hongguang Xu ,&nbsp;Chuanzhi Cui","doi":"10.1016/j.geoen.2025.213764","DOIUrl":"10.1016/j.geoen.2025.213764","url":null,"abstract":"<div><div>To address the challenges of poor development performance in deep medium-low permeability heavy oil reservoirs, which are attributed to low permeability and high viscosity of crude oil, a CO₂ composite pressure flooding technology has been proposed in the field. This study investigates the interaction mechanisms among solubilizer, CO₂, and heavy oil through the performance of CO₂ solubilization and synergistic viscosity reduction. High-temperature and high-pressure micro-displacement experiments were conducted to examine the oil displacement mechanisms of CO₂ composite pressure flooding from the perspectives of seepage characteristics and residual oil distribution. The results indicate that the addition of solubilizing and enhancing agents can increase CO₂ solubility by more than 25% under pressures ranging from 5 MPa to 30 MPa, with a synergistic viscosity reduction rate exceeding 95%. Microscopic experiments demonstrate that the dissolving-carrying-extraction effect of CO₂ composite pressure flooding is significant, as it reduces the viscosity of crude oil through dissolving diffusion, leading to alterations in the morphology, volume, and flow state of oil droplets, thereby facilitating rapid extraction. The residual oil primarily exists in the form of disconnected phase pore blind ends and oil film-like crude oil. The CO₂ composite pressure flooding technology enhances oil recovery through the mechanisms of solubilization and viscosity reduction, energy assistance, and mass transfer efficiency, enabling the effective utilization of deep medium-low permeability oil reservoirs and providing technical support for the effective development of deep heavy oil.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213764"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143456005","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":"Occurrence characterization and geological significance of polar organic matter in carbonate rocks","authors":"Danting Feng ,&nbsp;Xiaofeng Wang ,&nbsp;Wenhui Liu ,&nbsp;Dongdong Zhang ,&nbsp;Zuodong Wang ,&nbsp;Peng Liu","doi":"10.1016/j.geoen.2025.213768","DOIUrl":"10.1016/j.geoen.2025.213768","url":null,"abstract":"<div><div>Organic matter in various occurrence states exists in carbonate rocks, which provides essential information for understanding diagenesis and sedimentary environment. However, the source, occurrence state, and hydrocarbon generation mechanism of carbonate organic matter are unclear. The method of automatic rapid extraction is used. Through the principle of similarity and compatibility, strong polar methanol is selected as a suitable solvent for extracting organic matter in carbonate rocks. Infrared spectroscopy is used to identify fatty acids, aliphatic ketones, fatty esters, and aliphatic hydrocarbons with oxygen-bearing groups. The aliphatic compounds, combined with the analysis of pyrolysis gas chromatography-mass spectrometry, characterize the occurrence and thermal evolution of organic matter. The results show that these organic matters are partly derived from the pyrolysis of biological lipids and partly connected with kerogen or geological macromolecules in the form of polar covalent bonds, mainly ester/ether bonds. The detection of high-abundance saturated fatty acids and n-alkan-2-ones confirms that carbonate organic matter can be physically or chemically adsorbed on the surface of carbonate minerals or encapsulated within crystalline minerals. It can interact with metal cations to form organic ligands. The evolution of pyrolysis products of carbonate organic matter at varying temperatures is related to the occurrence state of organic matter and thermal desorption/cleavage of chemical bonds, which is an effective approach for studying carbonate organic matter.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213768"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143444514","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":"Adsorption kinetics of water vapor in shale and their dependence on in-situ conditions and the composition of reservoirs","authors":"Weidong Xie ,&nbsp;Xiaofei Fu ,&nbsp;Haixue Wang ,&nbsp;Yu Sun ,&nbsp;Veerle Vandeginste","doi":"10.1016/j.geoen.2025.213779","DOIUrl":"10.1016/j.geoen.2025.213779","url":null,"abstract":"<div><div>Adsorption kinetic experiments were conducted to investigate the dynamic diffusion and adsorption behaviors of water vapor in shale gas reservoirs. Experimental results were fitted by a total of seven kinetic models to determine the optimum adsorption kinetic theory of water vapor. Furthermore, the kinetic parameters of water vapor diffusion coefficient and adsorption rate were calculated correspondingly. Then, the controlling and mechanism of relative humidity (RH) and experimental temperature on the adsorption kinetic process were discussed. Besides, two experimental groups of total organic carbon content (TOC) variation and clay content variation shale samples were set to clarify the influence of the major adsorption carriers on the adsorption kinetic behavior. The results indicate that Weber and Morris model (WMM) is the best fitting model, with a goodness of fit (GOF) is much higher than that of the other six models. Overall, diffusion coefficients of water vapor in shale are in the order of magnitude of 10⁻⁴ to 10⁻³ s⁻¹, increase with higher RH (0–0.9), whereas drop sharply for RH &gt; 0.9. The adsorption rate exhibits a tripartite characteristic of rise (RH: 0–0.6), drop (RH: 0.6–0.9), and rise (RH &gt; 0.9) with higher RH. The influence of experimental temperature on diffusion coefficient is complex with a non-monotonic correlation, whereas adsorption rate increases with higher temperature. Additionally, a higher TOC or clay content are conducive to water diffusion and adsorption processes in shale, with clear positive correlations. These results are of significant reference for determining the optimum kinetic theory for water adsorption and diffusion in shale gas reservoirs, and exploring the constrains of reservoir composition and in-situ multiphysics on water accumulation mechanism.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213779"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143444515","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":"Leaching simulation of horizontal salt cavern energy storage in bedded salt considering the dissolution of “inactive segment”","authors":"Qiqi Wanyan ,&nbsp;Kang Li ,&nbsp;Song Bai ,&nbsp;Jianan Wu ,&nbsp;Song Zhu ,&nbsp;Jia Liu ,&nbsp;Zhuoteng Wang ,&nbsp;Junchi Liu ,&nbsp;Gangwei Liu ,&nbsp;Xiangsheng Chen ,&nbsp;Jinlong Li","doi":"10.1016/j.geoen.2025.213784","DOIUrl":"10.1016/j.geoen.2025.213784","url":null,"abstract":"<div><div>Horizontal salt caverns are ideal places to store energy. The distribution of concentration fields and flow fields is critical for the shape prediction of horizontal salt caverns. However, the area between the deviated well and the injection segment is regarded as an inactive segment in the current simplified model. The simplified model assumes that there is no freshwater inflow and that rock salt is not dissolved in the inactive segment, which is quite different from the engineering site. To improve the accuracy and efficiency of the leaching simulation, a program is developed using a modified flow field model. The concentration fields and flow fields are simulated by solving the Navier-Stokes equations and convective diffusion equations. Simulation results show that injected freshwater continuously mixes with brine and forms a buoyant jet during the upward floating. After reaching the cavern top, the mixed flow first flows along the wall and then gradually flows downward to the left and right sides of the inlet. The concentration is the lowest at the cavern top above the inlet and increases from the inlet to the left and right sides. To describe these patterns, the modified flow field model divides the flow field into four segments and considers the dissolution of the \"inactive segment\". The simulation program is written with the dynamic mesh method and leaching experiments are simulated for verification. Simulated cavern shapes coincide well with actual shapes, indicating that the modified model and the program are reliable.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213784"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143456004","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":"The formation mechanisms and management techniques of carbonate scale in CO2-rich coalbed methane wells","authors":"Linan Su ,&nbsp;Qian Wang ,&nbsp;Xiaoming Wang","doi":"10.1016/j.geoen.2025.213780","DOIUrl":"10.1016/j.geoen.2025.213780","url":null,"abstract":"<div><div>Scale deposition during the drainage of coalbed methane (CBM) can significantly damage both coal reservoirs and wellbore utilities, consequently impairing well productivity. The mechanisms underlying scale formation in carbon dioxide (CO₂)-rich CBM wells, however, remain inadequately understood. This study incorporates laboratory experiments with field production data to systemically investigate the formation mechanisms and management techniques for scale in CO₂-rich CBM wells. Initial investigations involved acid dissolution experiments and X-ray diffraction (XRD) analyses of scale samples from two CBM wells to determine their mineral compositions. The results reveal that carbonate scale is the predominant component, with a minor presence of iron oxide scale. Further laboratory experiments were performed to simulate the formation of carbonate scale and examine its controlling factors. The findings demonstrate that the CO₂ partial pressure significantly influences carbonate scale formation. Specifically, higher initial CO₂ partial pressures enhance the dissolution of CO₂ in the water, leading to the generation of more carbonate ions under alkaline conditions. These carbonate ions then react with calcium ions to form CaCO₃ precipitates upon the release of gas pressure. In contrast, lower initial CO₂ partial pressures result in reduced dissolution of CO₂ and a smaller amount of CaCO₃ precipitate following gas pressure release. Field production data from two CBM wells confirm that gas drainage gradually decreases both bottom-hole pressure and CO₂ partial pressure, thus facilitating significant carbonate scale formation. Based on these insights and outcomes of field acid stimulation operations in a CBM well, this study concludes that maintaining higher CO₂ partial pressure during the initial gas drainage stage and utilizing acid treatments are effective methods for preventing and removing carbonate scale.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213780"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143444518","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":"Semi-dimensionless approach for simulating heat transfer of wellbore to optimize the temperature drop","authors":"Shahab Ghasemi,&nbsp;Saeid Khasi,&nbsp;Apostolos Kantzas","doi":"10.1016/j.geoen.2025.213769","DOIUrl":"10.1016/j.geoen.2025.213769","url":null,"abstract":"<div><div>A reliable prediction of temperature changes in a wellbore is crucial for maximizing the efficacy of the geothermal energy extraction. Modeling such changes across a wellbore is a complex task that poses numerous challenges which require sophisticated numerical models and advanced computational tools. To simulate the real condition of a well, high fidelity simulations are needed due to the large well length to well radius ratio. This limitation causes high computational cost for each run. This study aims to develop and validate a computational model to optimize temperature predictions in geothermal wellbores while reducing computational costs. To reduce such time complexity while keeping calculation error below a reasonable bound, a novel approach is proposed in this paper. To validate the proposed model, an experimental setup of a closed loop system was designed. The experimental data and results obtained from simulations were in a good agreement. Based on the validated model, different controlling parameters of a wellbore were investigated to maximize the heat recovery from a geothermal well. Under two different scenarios from tubing or annulus space, different wellbore depths, and tubing to annulus size ratios, the extracted thermal energies were calculated. The study analyzed a range of injection rates from 0.1 kg/s to 100 kg/s, revealing the intricate relationship between injection rate, heat transfer, and heat loss in fluid-casing systems. The research also considered geothermal power generation systems to assess the potential of generated energy under various operating conditions. Annulus injection consistently resulted in higher outlet temperatures than tubing injection, especially at lower injection rates and deeper wells. The impact of tubing insulation and the tubing-to-annulus area ratio was also analyzed, showing that insulating the tubing significantly increased outlet temperatures by reducing heat loss.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"249 ","pages":"Article 213769"},"PeriodicalIF":0.0,"publicationDate":"2025-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143465301","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}