Pub Date : 2026-03-01Epub Date: 2025-12-09DOI: 10.1016/j.geoen.2025.214318
Blandine Feneuil, Elie N'Gouamba, Nils Opedal, Ragnhild Skorpa, Bjørnar Lund
Drilling fluids left static in the well during its operational life tend to form sediments. When the time comes for well Plugging and Abandonment (P&A), these sediments may hinder casing removal, making the operation more time consuming and expensive. But the sediments may also be an advantage for P&A, as dense and impermeable sediments may be used as a barrier material. A better understanding of the sediment formation would help improving the efficiency of P&A operations. We have investigated this issue by observing experimentally columns of oil-based drilling fluid at rest for 500 days. A particle-free dark layer forms at the top and grows until it reaches a final height between 300 and 500 days. We note that the severity and velocity of the dark layer growth are promoted by a larger height of the fluid column and depend on the drilling fluid composition (oil-brine ratio and barite content). We study the composition of the sediment, i.e., the lower section of the column containing particles, at different points and note that the droplet-particle ratio remains constant in the sediment. On the other hand, the oil content is largest at the top of the sediment. We show that these results cannot be explained by classical sedimentation models but show that the particle migration can be modelled as a saturated porous medium under compaction.
{"title":"Long term phase separation in an oil-based drilling fluid","authors":"Blandine Feneuil, Elie N'Gouamba, Nils Opedal, Ragnhild Skorpa, Bjørnar Lund","doi":"10.1016/j.geoen.2025.214318","DOIUrl":"10.1016/j.geoen.2025.214318","url":null,"abstract":"<div><div>Drilling fluids left static in the well during its operational life tend to form sediments. When the time comes for well Plugging and Abandonment (P&A), these sediments may hinder casing removal, making the operation more time consuming and expensive. But the sediments may also be an advantage for P&A, as dense and impermeable sediments may be used as a barrier material. A better understanding of the sediment formation would help improving the efficiency of P&A operations. We have investigated this issue by observing experimentally columns of oil-based drilling fluid at rest for 500 days. A particle-free dark layer forms at the top and grows until it reaches a final height between 300 and 500 days. We note that the severity and velocity of the dark layer growth are promoted by a larger height of the fluid column and depend on the drilling fluid composition (oil-brine ratio and barite content). We study the composition of the sediment, i.e., the lower section of the column containing particles, at different points and note that the droplet-particle ratio remains constant in the sediment. On the other hand, the oil content is largest at the top of the sediment. We show that these results cannot be explained by classical sedimentation models but show that the particle migration can be modelled as a saturated porous medium under compaction.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214318"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738693","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}
Pub Date : 2026-03-01Epub Date: 2025-12-08DOI: 10.1016/j.geoen.2025.214325
Peng Li , Xiangyu Wang , Hucheng Deng , Chuanghui Zhou , Yanyu Zhang
Accurately predicting the variation of steam thermophysical parameters within wellbores is crucial for the optimal recovery of oil shale via in-situ technologies leveraging superheated steam (SS). Despite its importance, research on SS flow in full-length horizontal wells, particularly regarding phase changes, remains scarce. This study introduces a mathematical model to simulate SS flow in full-length horizontal wells within oil shale reservoirs. The coupling between the wellbore of vertical and horizontal sections, as well as the phase transition from SS to wet steam, is systematically investigated. Additionally, the effects of key injection parameters on the distribution of steam thermophysical parameters in the wellbore and thermal utilization efficiency are comprehensively analyzed. The proposed model demonstrates high reliability, with a maximum relative error of 2.11 % compared to CMG simulations. Results reveal that the impact of phase change on temperature reduction is 3.119 times greater than its effect on pressure drop, indicating a significantly stronger influence on mitigating temperature losses. An earlier phase transition facilitates achieving higher temperatures in the horizontal annulus. Steam temperature is identified as the primary factor for oil shale development, while steam quality is comparatively less critical. In scenarios where steam temperature and steam quality exhibit opposing trends, parameter optimization should prioritize maintaining higher steam temperatures. To enhance the heat absorption rate along the horizontal wellbore and improve thermal utilization efficiency, it is recommended to employ lower superheat degrees, higher injection pressures, and reduced injection rates. Furthermore, field engineers can utilize the steam superheat degree at the wellhead as a quick and preliminary indicator to evaluate the potential for achieving high steam quality within the wellbore. These findings provide valuable guidance for optimizing operational parameters in oil shale reservoir development.
{"title":"A numerical model for predicting the thermophysical parameters of superheated steam in full-length horizontal wells considering phase change","authors":"Peng Li , Xiangyu Wang , Hucheng Deng , Chuanghui Zhou , Yanyu Zhang","doi":"10.1016/j.geoen.2025.214325","DOIUrl":"10.1016/j.geoen.2025.214325","url":null,"abstract":"<div><div>Accurately predicting the variation of steam thermophysical parameters within wellbores is crucial for the optimal recovery of oil shale via in-situ technologies leveraging superheated steam (SS). Despite its importance, research on SS flow in full-length horizontal wells, particularly regarding phase changes, remains scarce. This study introduces a mathematical model to simulate SS flow in full-length horizontal wells within oil shale reservoirs. The coupling between the wellbore of vertical and horizontal sections, as well as the phase transition from SS to wet steam, is systematically investigated. Additionally, the effects of key injection parameters on the distribution of steam thermophysical parameters in the wellbore and thermal utilization efficiency are comprehensively analyzed. The proposed model demonstrates high reliability, with a maximum relative error of 2.11 % compared to CMG simulations. Results reveal that the impact of phase change on temperature reduction is 3.119 times greater than its effect on pressure drop, indicating a significantly stronger influence on mitigating temperature losses. An earlier phase transition facilitates achieving higher temperatures in the horizontal annulus. Steam temperature is identified as the primary factor for oil shale development, while steam quality is comparatively less critical. In scenarios where steam temperature and steam quality exhibit opposing trends, parameter optimization should prioritize maintaining higher steam temperatures. To enhance the heat absorption rate along the horizontal wellbore and improve thermal utilization efficiency, it is recommended to employ lower superheat degrees, higher injection pressures, and reduced injection rates. Furthermore, field engineers can utilize the steam superheat degree at the wellhead as a quick and preliminary indicator to evaluate the potential for achieving high steam quality within the wellbore. These findings provide valuable guidance for optimizing operational parameters in oil shale reservoir development.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214325"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738696","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}
Pub Date : 2026-03-01Epub Date: 2025-12-06DOI: 10.1016/j.geoen.2025.214309
Shuai Hou , Zhiyu Hou , Danping Cao
Extrapolating realistic 3D pore structures from discontinuous and limited 2D rock slices is essential for recovering rock transport properties. However, most existing 2D-to-3D reconstruction methods, whether traditional or deep learning-based, struggle to accurately reconstruct pore structures in highly heterogeneous rocks due to their inability to capture out-of-plane spatial information. While emerging solutions have begun to address this gap, their reconstruction accuracy remains constrained by network architecture limitations and inadequate prior knowledge. To address these challenges, we propose an enhanced diffusion model that integrates multi-modal information to improve reconstruction accuracy. Specifically, the diffusion model leverages its inherent multi-step chain sampling process to overcome limitations in capturing long-range connectivity within pore structures. Further, multi-modal information, including sparse slice pairs, porosity and pore structure parameters, is fused in the forward process to provide global guidance for reconstructing the entire pore space, with a channel-embedded cyclic mechanism in the inference procedure is introduced to refine the reconstruction of fine-scale transitions between pores and the surrounding matrix, while preserving long-range pore connectivity and sequence rationality. Experiments on three highly heterogeneous carbonate samples demonstrate that our model generalizes effectively across both grayscale and binary domains. Under single-slice input, our model achieves a 3.6× reduction in porosity error and a 3.4× increase in pore structure correlation compared to traditional 2D-to-3D methods, indicating stronger controllability and reconstruction robustness. When multi-modal constraints are incorporated, structural and morphological fidelity improve by 2.3× and 3.2× , respectively, while relative errors in porosity and permeability decrease by 3.5× and 3.7× compared with the single-modal baseline. This suggests that the diffusion model integrating multi-modal information can effectively enhance reconstruction accuracy, particularly for highly heterogeneous rocks, which is beneficial for gaining deeper insights into fluid transport behavior in incomplete media.
{"title":"3D digital core reconstruction from limited core-scanned images: An improved diffusion model with multi-modal information fusion","authors":"Shuai Hou , Zhiyu Hou , Danping Cao","doi":"10.1016/j.geoen.2025.214309","DOIUrl":"10.1016/j.geoen.2025.214309","url":null,"abstract":"<div><div>Extrapolating realistic 3D pore structures from discontinuous and limited 2D rock slices is essential for recovering rock transport properties. However, most existing 2D-to-3D reconstruction methods, whether traditional or deep learning-based, struggle to accurately reconstruct pore structures in highly heterogeneous rocks due to their inability to capture out-of-plane spatial information. While emerging solutions have begun to address this gap, their reconstruction accuracy remains constrained by network architecture limitations and inadequate prior knowledge. To address these challenges, we propose an enhanced diffusion model that integrates multi-modal information to improve reconstruction accuracy. Specifically, the diffusion model leverages its inherent multi-step chain sampling process to overcome limitations in capturing long-range connectivity within pore structures. Further, multi-modal information, including sparse slice pairs, porosity and pore structure parameters, is fused in the forward process to provide global guidance for reconstructing the entire pore space, with a channel-embedded cyclic mechanism in the inference procedure is introduced to refine the reconstruction of fine-scale transitions between pores and the surrounding matrix, while preserving long-range pore connectivity and sequence rationality. Experiments on three highly heterogeneous carbonate samples demonstrate that our model generalizes effectively across both grayscale and binary domains. Under single-slice input, our model achieves a 3.6× reduction in porosity error and a 3.4× increase in pore structure correlation compared to traditional 2D-to-3D methods, indicating stronger controllability and reconstruction robustness. When multi-modal constraints are incorporated, structural and morphological fidelity improve by 2.3× and 3.2× , respectively, while relative errors in porosity and permeability decrease by 3.5× and 3.7× compared with the single-modal baseline. This suggests that the diffusion model integrating multi-modal information can effectively enhance reconstruction accuracy, particularly for highly heterogeneous rocks, which is beneficial for gaining deeper insights into fluid transport behavior in incomplete media.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214309"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145790951","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}
Pub Date : 2026-03-01Epub Date: 2025-12-09DOI: 10.1016/j.geoen.2025.214313
Meruyet Zhanabayeva, Peyman Pourafshary
One of the relatively new and promising indirect physical methods used for the determination of interwell connectivity is Capacitance Resistive Models (CRM). The CRM is a combination of material balance and reservoir productivity equations for characterizing a reservoir performance and oil production optimization. The main advantages of using CRM are its computational time and minimum required input data for the model as in many situations running full-scale numerical simulations do not meet the economical requirement and the time limit restrictions of the project. The literature indicates that while CRM is a well-established method for waterflooding, its application in gas flooding is evolving, with ongoing research aimed at modifying the model for these scenarios. Modelling a gas flow with CRM is challenging as we need to account for the compressibility of gas and the variation of gas properties with pressure. It is important to understand how accurate current CRM is to simulate immiscible gas flooding. The objective of this study is to define the ranges of rock/fluid properties, where CRM is accurate enough to model immiscible gas flooding. The results show that a large diffusivity coefficient results in a better performance of CRM, for a diffusivity coefficient smaller than the CRM results become more inconsistent and shows an error of more than 20 % even for a homogeneous reservoir. Increasing the heterogeneity of the reservoir worsens the performance of CRM. Mobility ratio (M) also affects the CRM performance. For favorable flooding (M < 1), the model matches the oil production history better. Moreover, reservoirs with high pressure, low temperature, and relatively dense gas are good candidates for CRM modeling. Finally, acceptable ranges of reservoir parameters and limitations of the model are comprehensively discussed.
{"title":"“How accurate is the conventional CRM to model immiscible gas flooding?”","authors":"Meruyet Zhanabayeva, Peyman Pourafshary","doi":"10.1016/j.geoen.2025.214313","DOIUrl":"10.1016/j.geoen.2025.214313","url":null,"abstract":"<div><div>One of the relatively new and promising indirect physical methods used for the determination of interwell connectivity is Capacitance Resistive Models (CRM). The CRM is a combination of material balance and reservoir productivity equations for characterizing a reservoir performance and oil production optimization. The main advantages of using CRM are its computational time and minimum required input data for the model as in many situations running full-scale numerical simulations do not meet the economical requirement and the time limit restrictions of the project. The literature indicates that while CRM is a well-established method for waterflooding, its application in gas flooding is evolving, with ongoing research aimed at modifying the model for these scenarios. Modelling a gas flow with CRM is challenging as we need to account for the compressibility of gas and the variation of gas properties with pressure. It is important to understand how accurate current CRM is to simulate immiscible gas flooding. The objective of this study is to define the ranges of rock/fluid properties, where CRM is accurate enough to model immiscible gas flooding. The results show that a large diffusivity coefficient results in a better performance of CRM, for a diffusivity coefficient smaller than <span><math><mrow><msup><mn>10</mn><mn>6</mn></msup><mspace></mspace><msup><mi>m</mi><mn>2</mn></msup><mo>/</mo><mi>s</mi></mrow></math></span> the CRM results become more inconsistent and shows an error of more than 20 % even for a homogeneous reservoir. Increasing the heterogeneity of the reservoir worsens the performance of CRM. Mobility ratio (M) also affects the CRM performance. For favorable flooding (M < 1), the model matches the oil production history better. Moreover, reservoirs with high pressure, low temperature, and relatively dense gas are good candidates for CRM modeling. Finally, acceptable ranges of reservoir parameters and limitations of the model are comprehensively discussed.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214313"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738721","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}
Pub Date : 2026-03-01Epub Date: 2025-12-08DOI: 10.1016/j.geoen.2025.214332
Sowjanya Kandadai , Lorenzo Parrabbi , Daniele Della Sala , Beatrice Castellani
This study investigates CO2 hydrate formation in marine environments using controlled experiments in pure water, 3 wt% NaCl, and 4 wt% NaCl solutions. Gas uptake decreased from 31.51 % in pure water to 13.97 % and 5.30 % in 3 wt% and 4 wt% NaCl solutions, respectively, as well as formation density (from 19.36 kg/m3 to 8.71 kg/m3 and 3.61 kg/m3). A non-linear effect was observed wherein 4 wt% NaCl solutions with slightly higher hydrate formation than 3 wt% under certain conditions, suggesting complex interdependencies between salinity, pressure and temperature. The pressure decline rate (ΔP/Δt) varies with pressure and salinity, demonstrating a direct correlation between formation pressure, water conditions and hydrate growth kinetics. Stability tests conducted at 65 bar in 4 wt% NaCl solutions confirmed CO2 hydrate persistence for over 10 days, reinforcing the feasibility of hydrate-based carbon sequestration in marine settings and providing critical insights for optimizing CO2 storage in deep-sea environments.
{"title":"Towards hydrate-based CO2 storage in marine environments: salinity effects in CO2-H2O binary systems","authors":"Sowjanya Kandadai , Lorenzo Parrabbi , Daniele Della Sala , Beatrice Castellani","doi":"10.1016/j.geoen.2025.214332","DOIUrl":"10.1016/j.geoen.2025.214332","url":null,"abstract":"<div><div>This study investigates CO<sub>2</sub> hydrate formation in marine environments using controlled experiments in pure water, 3 wt% NaCl, and 4 wt% NaCl solutions. Gas uptake decreased from 31.51 % in pure water to 13.97 % and 5.30 % in 3 wt% and 4 wt% NaCl solutions, respectively, as well as formation density (from 19.36 kg/m<sup>3</sup> to 8.71 kg/m<sup>3</sup> and 3.61 kg/m<sup>3</sup>). A non-linear effect was observed wherein 4 wt% NaCl solutions with slightly higher hydrate formation than 3 wt% under certain conditions, suggesting complex interdependencies between salinity, pressure and temperature. The pressure decline rate (ΔP/Δt) varies with pressure and salinity, demonstrating a direct correlation between formation pressure, water conditions and hydrate growth kinetics. Stability tests conducted at 65 bar in 4 wt% NaCl solutions confirmed CO<sub>2</sub> hydrate persistence for over 10 days, reinforcing the feasibility of hydrate-based carbon sequestration in marine settings and providing critical insights for optimizing CO<sub>2</sub> storage in deep-sea environments.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214332"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738223","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}
Pub Date : 2026-03-01Epub Date: 2025-12-11DOI: 10.1016/j.geoen.2025.214312
Jinming Liu, Pingli Liu, Juan Du, Xiyi Luo, Jinlong Li, Guan Wang, Wenhao Tian, Qisheng Huang, Chengwei Zuo, Haoze Yue
<div><div>The choice of acid system is a critical determinant of stimulation effectiveness in carbonate reservoirs. With the extension of carbonate reservoir exploration and development into deeper formations, traditional hydrochloric (HCl) acid-based systems (e.g., gelled, cross-linked, and diverting acid) have exhibited significant technical limitations. Solid acid systems, offering advantages such as convenient storage/transportation, controllable acid-rock reaction rates, low corrosion rates, and self-diverting properties, show great potential as effective alternatives to conventional HCl acid systems. Based on preparation methods and mechanisms, solid acid systems were classified into three categories: conventional powder-based, encapsulated, and dry-cured types. Their application advantages, physicochemical characteristics, and acid-rock reaction mechanisms were systematically summarized. Results indicated that solid inorganic acids (e.g., solid nitric acid, solid HCl acid, sulfamic acid) still maintained rapid reaction rates under high temperatures, but controlled release can be achieved through encapsulation technologies. Encapsulated solid acids employed polymers, nanomaterials, lipid-based materials or their composites as encapsulation shells, but their temperature resistance was constrained by the thermal stability of shell materials (typically below 100 °C). Dry-cured solid acids generally consisted of self-generating acid precursors that produce acid in situ, demonstrating good temperature resistance (up to 180 °C), yet faced challenges including low fracture etching efficiency and potential toxicity from components like formaldehyde. Aminopolycarboxylic acids (APCAs) exhibited superior temperature resistance (up to 200 °C), low corrosion rates, controllable reaction kinetics, and iron ion chelation capacity to inhibit secondary precipitation. Moreover, most APCAs exhibited low solubility in aqueous solutions; The undissolved portion provided self-diverting effects by temporarily plugging microfractures and wormholes. As temperature increased, they continuously etched fracture surfaces while gradually dissolving without damaging reservoir matrix or etched fractures. Future research should focus on developing high-temperature-resistant polymer encapsulation materials with multi-stimuli responsiveness, to enhance the thermal stability and mechanical strength of encapsulated solid acids. Additionally, optimization of solid APCA systems (e.g., synergist formulations, pH regulation) and injection modes (e.g., alternate injection) should be investigated to improve stimulation performance. In addition, experimental studies should advance high-temperature and high-pressure visualization systems, integrated with <em>in-situ</em> characterization techniques such as CT and NMR, to enable precise capture and quantitative analysis of acid release and reaction behaviors. On the modeling side, it is urgent to establish a fully coupled simulation fr
{"title":"Solid acids for stimulating high-temperature carbonate reservoirs: A review","authors":"Jinming Liu, Pingli Liu, Juan Du, Xiyi Luo, Jinlong Li, Guan Wang, Wenhao Tian, Qisheng Huang, Chengwei Zuo, Haoze Yue","doi":"10.1016/j.geoen.2025.214312","DOIUrl":"10.1016/j.geoen.2025.214312","url":null,"abstract":"<div><div>The choice of acid system is a critical determinant of stimulation effectiveness in carbonate reservoirs. With the extension of carbonate reservoir exploration and development into deeper formations, traditional hydrochloric (HCl) acid-based systems (e.g., gelled, cross-linked, and diverting acid) have exhibited significant technical limitations. Solid acid systems, offering advantages such as convenient storage/transportation, controllable acid-rock reaction rates, low corrosion rates, and self-diverting properties, show great potential as effective alternatives to conventional HCl acid systems. Based on preparation methods and mechanisms, solid acid systems were classified into three categories: conventional powder-based, encapsulated, and dry-cured types. Their application advantages, physicochemical characteristics, and acid-rock reaction mechanisms were systematically summarized. Results indicated that solid inorganic acids (e.g., solid nitric acid, solid HCl acid, sulfamic acid) still maintained rapid reaction rates under high temperatures, but controlled release can be achieved through encapsulation technologies. Encapsulated solid acids employed polymers, nanomaterials, lipid-based materials or their composites as encapsulation shells, but their temperature resistance was constrained by the thermal stability of shell materials (typically below 100 °C). Dry-cured solid acids generally consisted of self-generating acid precursors that produce acid in situ, demonstrating good temperature resistance (up to 180 °C), yet faced challenges including low fracture etching efficiency and potential toxicity from components like formaldehyde. Aminopolycarboxylic acids (APCAs) exhibited superior temperature resistance (up to 200 °C), low corrosion rates, controllable reaction kinetics, and iron ion chelation capacity to inhibit secondary precipitation. Moreover, most APCAs exhibited low solubility in aqueous solutions; The undissolved portion provided self-diverting effects by temporarily plugging microfractures and wormholes. As temperature increased, they continuously etched fracture surfaces while gradually dissolving without damaging reservoir matrix or etched fractures. Future research should focus on developing high-temperature-resistant polymer encapsulation materials with multi-stimuli responsiveness, to enhance the thermal stability and mechanical strength of encapsulated solid acids. Additionally, optimization of solid APCA systems (e.g., synergist formulations, pH regulation) and injection modes (e.g., alternate injection) should be investigated to improve stimulation performance. In addition, experimental studies should advance high-temperature and high-pressure visualization systems, integrated with <em>in-situ</em> characterization techniques such as CT and NMR, to enable precise capture and quantitative analysis of acid release and reaction behaviors. On the modeling side, it is urgent to establish a fully coupled simulation fr","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214312"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738692","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}
Pub Date : 2026-03-01Epub Date: 2025-12-15DOI: 10.1016/j.geoen.2025.214343
Luis A. García-Navarrete , Fernando J. Guerrero , Edgar Santotyo
Modeling transport in fractured geologic media has historically been treated with two main approaches: continuum and discrete. Both are often based on the same physical principles, but differ in their ability to represent fracture-scale phenomena. In this work, we evaluate the scope and performance of two numerical simulation tools based on the finite volume method that have been designed for transport in porous-fractured media: TOUGH2, which implements a Multiple Continua approach, and the open-source software open-DARTS, which works under Discrete Fracture-Matrix models. We first benchmark the simulation tools with a 1D homogeneous reservoir in order to highlight methodological and performance differences between them. Next, an Enhanced Geothermal System is proposed and simulated for the geothermal area of Acoculco, Mexico. Two fracture configurations are tested in TOUGH2 and six in open-DARTS to evaluate heterogeneity and fracture density. The 1D benchmark yields consistent results once an optimal space resolution is input into open-DARTS. With regard to the fractured reservoir, 14 MW may be delivered over a period of 30 years. The inherent channeling flow associated with Discrete Fracture-Matrix leads to an accelerated production decline, which is explicitly simulated by open-DARTS, at the cost of a higher computing time. For dense and regular fracture networks, however, both tools produce comparable results with a much lower computing time for TOUGH2. The averaged nature of Multiple Continua makes it a computationally efficient method. It is therefore necessary to develop robust strategies for fracture network averaging.
{"title":"Scope of TOUGH2 and open-DARTS for the simulation of transport in porous-fractured media: an application to enhanced geothermal systems","authors":"Luis A. García-Navarrete , Fernando J. Guerrero , Edgar Santotyo","doi":"10.1016/j.geoen.2025.214343","DOIUrl":"10.1016/j.geoen.2025.214343","url":null,"abstract":"<div><div>Modeling transport in fractured geologic media has historically been treated with two main approaches: continuum and discrete. Both are often based on the same physical principles, but differ in their ability to represent fracture-scale phenomena. In this work, we evaluate the scope and performance of two numerical simulation tools based on the finite volume method that have been designed for transport in porous-fractured media: TOUGH2, which implements a Multiple Continua approach, and the open-source software open-DARTS, which works under Discrete Fracture-Matrix models. We first benchmark the simulation tools with a 1D homogeneous reservoir in order to highlight methodological and performance differences between them. Next, an Enhanced Geothermal System is proposed and simulated for the geothermal area of Acoculco, Mexico. Two fracture configurations are tested in TOUGH2 and six in open-DARTS to evaluate heterogeneity and fracture density. The 1D benchmark yields consistent results once an optimal space resolution is input into open-DARTS. With regard to the fractured reservoir, <span><math><mo>∼</mo></math></span>14 MW may be delivered over a period of 30 years. The inherent channeling flow associated with Discrete Fracture-Matrix leads to an accelerated production decline, which is explicitly simulated by open-DARTS, at the cost of a higher computing time. For dense and regular fracture networks, however, both tools produce comparable results with a much lower computing time for TOUGH2. The averaged nature of Multiple Continua makes it a computationally efficient method. It is therefore necessary to develop robust strategies for fracture network averaging.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214343"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145790947","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}
Pub Date : 2026-03-01Epub Date: 2025-12-08DOI: 10.1016/j.geoen.2025.214320
Sun Tengfei , Liu Ziyang , Zhang Yang , Zhang Bo , Liu Hao , Zhang Qixing
The porosity of rocks significantly impacts the load characteristics during cutters operations. To further investigate the variation in load characteristics under different rock porosities, CT scan experiments were conducted to obtain sandstone images. A micropore removal program was developed to eliminate pores smaller than 50 μm from the CT images. After analysis, it was found that the rock model's porosity decreased by only 1.38 % after micropore removal, indicating minimal impact on the model's mechanical properties. Digital core finite element models with varying porosities were then constructed by progressively covering the pores in the CT images to study the effect of porosity on cutters load characteristics. Results showed that as porosity increased, the average cutting force gradually decreased, while the standard deviation of cutting force initially increased and then decreased. Using secondary development methods, rock models with the same pore size but different pore quantities were constructed. Simulations confirmed that the load variation trends matched the earlier findings. These results indicate that both rock porosity and pore geometry influence the load characteristics of cutters, with porosity playing a dominant role. These findings enhance understanding of how pore characteristics affect cutter load behavior.
{"title":"Study on the impact of pore structure variations in digital core on cutter load characteristics","authors":"Sun Tengfei , Liu Ziyang , Zhang Yang , Zhang Bo , Liu Hao , Zhang Qixing","doi":"10.1016/j.geoen.2025.214320","DOIUrl":"10.1016/j.geoen.2025.214320","url":null,"abstract":"<div><div>The porosity of rocks significantly impacts the load characteristics during cutters operations. To further investigate the variation in load characteristics under different rock porosities, CT scan experiments were conducted to obtain sandstone images. A micropore removal program was developed to eliminate pores smaller than 50 μm from the CT images. After analysis, it was found that the rock model's porosity decreased by only 1.38 % after micropore removal, indicating minimal impact on the model's mechanical properties. Digital core finite element models with varying porosities were then constructed by progressively covering the pores in the CT images to study the effect of porosity on cutters load characteristics. Results showed that as porosity increased, the average cutting force gradually decreased, while the standard deviation of cutting force initially increased and then decreased. Using secondary development methods, rock models with the same pore size but different pore quantities were constructed. Simulations confirmed that the load variation trends matched the earlier findings. These results indicate that both rock porosity and pore geometry influence the load characteristics of cutters, with porosity playing a dominant role. These findings enhance understanding of how pore characteristics affect cutter load behavior.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214320"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145884591","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}
Pub Date : 2026-03-01Epub Date: 2025-12-09DOI: 10.1016/j.geoen.2025.214335
Ahmed K. Al-Yasiri , Usama Alameedy , Hani Al Mukainah , Mahmoud A. Abdulhamid , Ahmed Al-Yaseri
Creating eco-friendly stimulation fluids is still a major challenge in capturing CO2 and improving wellbore injectivity. This study presents a dual-function approach utilizing a water-soluble chitosan–salt (CS) solution as a green additive to simultaneously enhance CO2 uptake and generate carbonated acid for carbonate reservoir stimulation. This approach improves reservoir permeability and enables CO2 sequestration, aligning with global sustainability goals. Chitosan, a biodegradable biopolymer, was converted into a water-soluble chitosan salt (CS) and carbonated under controlled laboratory conditions (25 °C, 508 psi) using a mixing reactor. The resulting CS–CO2 system was injected into Indiana limestone cores to evaluate its efficiency in promoting wormhole formation and improving flow conductivity. Core-flooding experiments conducted across varying temperatures (25–75 °C), injection rates (0.5–2 cm3/min), and salinities (DI water and seawater) revealed a 250 % increase in CO2 uptake compared to conventional carbonated water. The generated carbonated acid facilitated calcite dissolution, producing dominant wormhole structures with smoother geometries at 1000 ppm CS concentration. Pressure monitoring indicated a sharp ΔP rise exceeding 1000 psi at 5 PVBT under low-temperature conditions, confirming strong fluid–rock interactions. Compared to traditional acid systems, the CS–CO2 formulation reduced PVBT by 60 %, increased porosity by 10 %, and doubled permeability. CT imaging validated the formation of continuous wormhole pathways, demonstrating the importance of CS–CO2 systems as scalable, environmentally benign alternatives for carbonate reservoir stimulation.
{"title":"Innovative use of chitosan salt for enhanced CO2 capture and wellbore injectivity","authors":"Ahmed K. Al-Yasiri , Usama Alameedy , Hani Al Mukainah , Mahmoud A. Abdulhamid , Ahmed Al-Yaseri","doi":"10.1016/j.geoen.2025.214335","DOIUrl":"10.1016/j.geoen.2025.214335","url":null,"abstract":"<div><div>Creating eco-friendly stimulation fluids is still a major challenge in capturing CO<sub>2</sub> and improving wellbore injectivity. This study presents a dual-function approach utilizing a water-soluble chitosan–salt (CS) solution as a green additive to simultaneously enhance CO<sub>2</sub> uptake and generate carbonated acid for carbonate reservoir stimulation. This approach improves reservoir permeability and enables CO<sub>2</sub> sequestration, aligning with global sustainability goals. Chitosan, a biodegradable biopolymer, was converted into a water-soluble chitosan salt (CS) and carbonated under controlled laboratory conditions (25 °C, 508 psi) using a mixing reactor. The resulting CS–CO<sub>2</sub> system was injected into Indiana limestone cores to evaluate its efficiency in promoting wormhole formation and improving flow conductivity. Core-flooding experiments conducted across varying temperatures (25–75 °C), injection rates (0.5–2 cm<sup>3</sup>/min), and salinities (DI water and seawater) revealed a 250 % increase in CO<sub>2</sub> uptake compared to conventional carbonated water. The generated carbonated acid facilitated calcite dissolution, producing dominant wormhole structures with smoother geometries at 1000 ppm CS concentration. Pressure monitoring indicated a sharp ΔP rise exceeding 1000 psi at 5 PVBT under low-temperature conditions, confirming strong fluid–rock interactions. Compared to traditional acid systems, the CS–CO<sub>2</sub> formulation reduced PVBT by 60 %, increased porosity by 10 %, and doubled permeability. CT imaging validated the formation of continuous wormhole pathways, demonstrating the importance of CS–CO<sub>2</sub> systems as scalable, environmentally benign alternatives for carbonate reservoir stimulation.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214335"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738722","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}
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