Pub Date : 2026-03-01Epub Date: 2025-12-05DOI: 10.1016/j.geoen.2025.214311
Eleni Himona , Robin S. Fletcher , Huw E.L. Williams , Sean P. Rigby
Pore structure-transport relationships greatly impact potential gas storage within, and producibility from, rocks of the Aphrodite Mediterranean gas field, but the former are difficult to discern with current typical methods. However, rarely-used gas overcondensation data have been shown here to be essential for representative and accurate invasion percolation-based determination of the pore connectivity for pore sizes over the whole range from ∼100s μm down to nanometres in these rocks. Combined gas overcondensation and scanning curves have revealed the presence of two sub-networks of large macropores, each shielded by very differently-sized necks, and enabled the separate pore body size distribution and pore connectivity to be obtained for the sub-network shielded by pore-blocking necks. A ‘pore-sifting’ strategy, implemented with either serial nitrogen and iodononane adsorption, or integrated gas sorption and mercury porosimetry, has assessed the different accessibility and/or mass transport contributions of each sub-network. Independent findings from nitrogen kinetic gas uptake suggested, perhaps counter-intuitively, that mass transport rates are faster in the sub-network ultimately shielded for desorption by smaller orifices, though explanations for this have been provided. Computerised X-ray tomography, SEM and PFG NMR have suggested that the pore bodies are associated with the cavities of planktonic foraminifera, while the shielding necks with the semi-permeable fossil shells or embedding clay matrix.
{"title":"Pore connectivity and structure-transport relationships in rocks from the Aphrodite gas field","authors":"Eleni Himona , Robin S. Fletcher , Huw E.L. Williams , Sean P. Rigby","doi":"10.1016/j.geoen.2025.214311","DOIUrl":"10.1016/j.geoen.2025.214311","url":null,"abstract":"<div><div>Pore structure-transport relationships greatly impact potential gas storage within, and producibility from, rocks of the Aphrodite Mediterranean gas field, but the former are difficult to discern with current typical methods. However, rarely-used gas overcondensation data have been shown here to be essential for representative and accurate invasion percolation-based determination of the pore connectivity for pore sizes over the whole range from ∼100s μm down to nanometres in these rocks. Combined gas overcondensation and scanning curves have revealed the presence of two sub-networks of large macropores, each shielded by very differently-sized necks, and enabled the separate pore body size distribution and pore connectivity to be obtained for the sub-network shielded by pore-blocking necks. A ‘pore-sifting’ strategy, implemented with either serial nitrogen and iodononane adsorption, or integrated gas sorption and mercury porosimetry, has assessed the different accessibility and/or mass transport contributions of each sub-network. Independent findings from nitrogen kinetic gas uptake suggested, perhaps counter-intuitively, that mass transport rates are faster in the sub-network ultimately shielded for desorption by smaller orifices, though explanations for this have been provided. Computerised X-ray tomography, SEM and PFG NMR have suggested that the pore bodies are associated with the cavities of planktonic foraminifera, while the shielding necks with the semi-permeable fossil shells or embedding clay matrix.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214311"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738221","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: 2025-12-25DOI: 10.1016/j.geoen.2025.214349
Gabriel Brandão de Miranda , Anderson de Moura Ribeiro , Grigori Chapiro , Rodrigo Weber dos Santos , Bernardo Martins Rocha
Foam has been widely employed to control gas mobility in porous media, playing a crucial role in enhanced oil recovery (EOR). However, the presence of crude oil can significantly impact foam stability through complex physico-chemical interactions, leading to reduced apparent viscosity and diminished effectiveness. While several experimental studies have investigated foam weakening mechanisms in the presence of oil, systematic approaches to estimating oil-related parameters in implicit-texture models have received limited attention. This study addresses this gap by developing a computational framework to analyze foam behavior using systematic core flooding protocols with progressive oil injection. By simulating steady-state core flooding experiments, we evaluate strategies for isolating oil-induced foam destabilization and improving parameter estimation techniques. The results provide insights into the robustness of current modeling approaches and guide experimental protocols for more accurate foam characterization in EOR applications. The results support the refinement of injection strategies, demonstrating that gradual increases in oil–water injection ratios are crucial to provide reliable parameter estimation, addressing limitations in current experimental protocols with abrupt injection increases. Simulations on heterogeneous cases illustrate the difficulties related to fitting oil-related parameters for a sparse dataset.
{"title":"Modeling foam flow in porous media influenced by oil: A computational framework for improved parameter estimation","authors":"Gabriel Brandão de Miranda , Anderson de Moura Ribeiro , Grigori Chapiro , Rodrigo Weber dos Santos , Bernardo Martins Rocha","doi":"10.1016/j.geoen.2025.214349","DOIUrl":"10.1016/j.geoen.2025.214349","url":null,"abstract":"<div><div>Foam has been widely employed to control gas mobility in porous media, playing a crucial role in enhanced oil recovery (EOR). However, the presence of crude oil can significantly impact foam stability through complex physico-chemical interactions, leading to reduced apparent viscosity and diminished effectiveness. While several experimental studies have investigated foam weakening mechanisms in the presence of oil, systematic approaches to estimating oil-related parameters in implicit-texture models have received limited attention. This study addresses this gap by developing a computational framework to analyze foam behavior using systematic core flooding protocols with progressive oil injection. By simulating steady-state core flooding experiments, we evaluate strategies for isolating oil-induced foam destabilization and improving parameter estimation techniques. The results provide insights into the robustness of current modeling approaches and guide experimental protocols for more accurate foam characterization in EOR applications. The results support the refinement of injection strategies, demonstrating that gradual increases in oil–water injection ratios are crucial to provide reliable parameter estimation, addressing limitations in current experimental protocols with abrupt injection increases. Simulations on heterogeneous cases illustrate the difficulties related to fitting oil-related parameters for a sparse dataset.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214349"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145884593","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: 2025-12-20DOI: 10.1016/j.geoen.2025.214348
Yaozeng Xie , Long Cheng , Zhifeng Luo , Luwei Qiu
A thermo-hydro-mechanical-damage coupling model is established in this study to discuss the geothermal extraction in fractured karst reservoirs. The rock deformation, Darcy-Stokes flow and heat transport coupled matrix rock system, fracture system and cavity system are solved by the extended finite element and mixed finite element methods. Then after the model validation, numerical analysis is carried out. Results reveal that the THMD process has significant impacts on the thermal extraction. Rock damage and fracture activation caused by thermo-poroelastic deformation will induce a complex fracture-cave network and enhanced permeability, thereby greatly improving the performance of fluid flow, heat transfer and thermal extraction. And increasing fluid injection rate and production pressure difference will accelerate the breakthrough of cold fluid, leading to the decline of thermal recovery. Raising the fracture aperture can effectively improve the thermal recovery, but there is a threshold that thermal recovery will reach to a limitation. Besides, high fracture-cavity density can greatly enhance the flowability and diffusivity, while early breakthrough of cold fluid is obtained, resulting a small thermal power at later stage.
{"title":"Numerical analysis of heat extraction performance in fractured-karst carbonate geothermal reservoirs with thermo-hydro-mechanical-damage coupling model","authors":"Yaozeng Xie , Long Cheng , Zhifeng Luo , Luwei Qiu","doi":"10.1016/j.geoen.2025.214348","DOIUrl":"10.1016/j.geoen.2025.214348","url":null,"abstract":"<div><div>A thermo-hydro-mechanical-damage coupling model is established in this study to discuss the geothermal extraction in fractured karst reservoirs. The rock deformation, Darcy-Stokes flow and heat transport coupled matrix rock system, fracture system and cavity system are solved by the extended finite element and mixed finite element methods. Then after the model validation, numerical analysis is carried out. Results reveal that the THMD process has significant impacts on the thermal extraction. Rock damage and fracture activation caused by thermo-poroelastic deformation will induce a complex fracture-cave network and enhanced permeability, thereby greatly improving the performance of fluid flow, heat transfer and thermal extraction. And increasing fluid injection rate and production pressure difference will accelerate the breakthrough of cold fluid, leading to the decline of thermal recovery. Raising the fracture aperture can effectively improve the thermal recovery, but there is a threshold that thermal recovery will reach to a limitation. Besides, high fracture-cavity density can greatly enhance the flowability and diffusivity, while early breakthrough of cold fluid is obtained, resulting a small thermal power at later stage.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214348"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145840563","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: 2025-12-10DOI: 10.1016/j.geoen.2025.214315
Xin Liu , Meng Sun , Qi Sun , Jiangru Yuan , Yuhao Zhou , Zheng Yuan , Shibo Gu
The remaining oil distribution plays a vital role in enhanced oil recovery (EOR), which directly guides the development of oilfields. However, efficiently predicting the remaining oil distribution is a challenge due to the complex reservoir fluid distribution after water flooding. As a popular method for remaining oil studies, reservoir numerical simulation is frequently confronted with challenges such as high computational complexity and long matching time. This paper proposes a reservoir cellular automata (RCA) to predict the remaining oil distribution during water flooding. We divide the oil reservoir into a grid space, which is mapped to a cellular space. Each grid is a cellular node in the cellular space, and its state is characterized by oil saturation. The eight nodes geographically adjacent to a node are its neighbor nodes, forming a Moore-type neighborhood. We design lightweight deduction rules that transform the remaining oil dynamic evolution into nodes state iterative updates. Based on the pressure difference, Darcy’s law calculates the volume change of two-phase fluid, which is combined with porosity to update the node state. Then, the pressure after the fluid flow is updated by the material balance equation. In addition, a data supplement method is also presented to initialize the RCA. On a sand body in northern China, we apply the RCA to predict the remaining oil distribution based on reservoir data. Experiments show that RCA reduces deduction time by 87 % compared to numerical simulation while achieving an MRE of less than 10 %.
{"title":"Reservoir cellular automata: a lightweight method for reservoir remaining oil distribution prediction","authors":"Xin Liu , Meng Sun , Qi Sun , Jiangru Yuan , Yuhao Zhou , Zheng Yuan , Shibo Gu","doi":"10.1016/j.geoen.2025.214315","DOIUrl":"10.1016/j.geoen.2025.214315","url":null,"abstract":"<div><div>The remaining oil distribution plays a vital role in enhanced oil recovery (EOR), which directly guides the development of oilfields. However, efficiently predicting the remaining oil distribution is a challenge due to the complex reservoir fluid distribution after water flooding. As a popular method for remaining oil studies, reservoir numerical simulation is frequently confronted with challenges such as high computational complexity and long matching time. This paper proposes a reservoir cellular automata (RCA) to predict the remaining oil distribution during water flooding. We divide the oil reservoir into a grid space, which is mapped to a cellular space. Each grid is a cellular node in the cellular space, and its state is characterized by oil saturation. The eight nodes geographically adjacent to a node are its neighbor nodes, forming a Moore-type neighborhood. We design lightweight deduction rules that transform the remaining oil dynamic evolution into nodes state iterative updates. Based on the pressure difference, Darcy’s law calculates the volume change of two-phase fluid, which is combined with porosity to update the node state. Then, the pressure after the fluid flow is updated by the material balance equation. In addition, a data supplement method is also presented to initialize the RCA. On a sand body in northern China, we apply the RCA to predict the remaining oil distribution based on reservoir data. Experiments show that RCA reduces deduction time by 87 % compared to numerical simulation while achieving an MRE of less than 10 %.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214315"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145790971","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: 2025-12-10DOI: 10.1016/j.geoen.2025.214338
Pedro A.L.P. Firme , Julio Rueda , Cristian Mejia , Deane Roehl , Diogo Rossi , Francisco H. Ferreira , Ricardo Chaves
The Brazilian Pre-salt reservoirs hold significant hydrocarbon (HC) reserves. Considering the decarbonization trends, a sustainable destination for the carbon dioxide (CO2) produced with the HCs is mandatory. Recovery methods such as waterflooding, including CO2 injection, are crucial for environmentally adequate continued production. However, they strongly impact reservoir geomechanics. This work analyzes the thermo-hydro-mechanical effect of cold water injection in a Pre-salt reservoir with special regard to the impact of the salt caprock response. The investigation is based on a one-way coupled numerical simulation of a conceptual model subjected to injection over 30 years. The analyses aim to assess: i) how the combined effect of cooling and pressurization affects the mechanical response of the reservoir and caprock; ii) the critically affected regions; and iii) the impact of different salt rock mechanical models (elastic, elastoplastic, and viscoelastic) on the global response. Results show that: i) the thermomechanical effect prevails over the hydromechanical effect in the cooled region; ii) the lower interval of the caprock is the most critical region in terms of horizontal stress drop, tension, and plastification; and iii) different integrity aspects are highlighted depending on the constitutive model of the caprock. The most critical drop in the horizontal stress leading to tension occurs just above the reservoir and at its top. The extension of the tension region in the lower interval of the caprock depends on the selected mechanical behavior. These findings help guide injection actions.
{"title":"Salt caprock geomechanics applied to pre-salt reservoirs subjected to cold waterflooding","authors":"Pedro A.L.P. Firme , Julio Rueda , Cristian Mejia , Deane Roehl , Diogo Rossi , Francisco H. Ferreira , Ricardo Chaves","doi":"10.1016/j.geoen.2025.214338","DOIUrl":"10.1016/j.geoen.2025.214338","url":null,"abstract":"<div><div>The Brazilian Pre-salt reservoirs hold significant hydrocarbon (HC) reserves. Considering the decarbonization trends, a sustainable destination for the carbon dioxide (CO<sub>2</sub>) produced with the HCs is mandatory. Recovery methods such as waterflooding, including CO<sub>2</sub> injection, are crucial for environmentally adequate continued production. However, they strongly impact reservoir geomechanics. This work analyzes the thermo-hydro-mechanical effect of cold water injection in a Pre-salt reservoir with special regard to the impact of the salt caprock response. The investigation is based on a one-way coupled numerical simulation of a conceptual model subjected to injection over 30 years. The analyses aim to assess: i) how the combined effect of cooling and pressurization affects the mechanical response of the reservoir and caprock; ii) the critically affected regions; and iii) the impact of different salt rock mechanical models (elastic, elastoplastic, and viscoelastic) on the global response. Results show that: i) the thermomechanical effect prevails over the hydromechanical effect in the cooled region; ii) the lower interval of the caprock is the most critical region in terms of horizontal stress drop, tension, and plastification; and iii) different integrity aspects are highlighted depending on the constitutive model of the caprock. The most critical drop in the horizontal stress leading to tension occurs just above the reservoir and at its top. The extension of the tension region in the lower interval of the caprock depends on the selected mechanical behavior. These findings help guide injection actions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214338"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145790946","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: 2025-12-12DOI: 10.1016/j.geoen.2025.214326
Qiaochu Wang , Dongxia Chen , Meijun Li , Fuwei Wang , Zijie Yang , Zaiquan Yang , Sha Li , Yuqi Wang
Petroleum resources are among the most important fossil fuels in the world. With the development of field knowledge and exploration technology, the giant potential of petroleum resources in deep strata deeper than 5000 m has been recognized. However, the complex geological environment characterized by extremely high pressure seriously constrains deep-strata petroleum resource exploration and exploitation in terms of technology, engineering and economics. In this study, the generative adversarial network (GAN) deep learning algorithm is first applied to construct a virtual exploration well dataset to compensate for the lack of wells in deep strata and then to enlarge the well log dataset. Then, a boosted back propagation neural network (BPNN) is used to predict the complex pore pressure based on the enlarged GAN dataset. Finally, the gradient descent method is utilized for the calibration of the whole model to provide a precise deep-strata pore pressure prediction model. The final results show that with the enlarged GAN dataset, the pore pressure prediction model performs well during training and validation, with the highest correlation coefficients, 0.821 and 0.755, respectively. The test results without loss function calibration show a slightly lower accuracy, with correlation coefficients ranging from 0.584 to 0.606. The cross-validation also indicates similar accuracy, with correlation coefficients ranging from 0.589 to 0.606. By applying the data-driven and physical informed loss functions, both the GAN model and BPNN model are optimized. The loss of the GAN model shows a steady status after the 2000th calibration, which indicates that the best model is constructed. The final correlation coefficient between the actual and predicted pressures also reaches 0.98 as the loss of the BPNN model decreases from 4.0 to 1.1. This study not only introduces a novel method for pore pressure prediction for deeply buried petroleum reservoirs by using the deep learning algorithms of GANs and BPNN, which is the first use in the petroleum industry field, but also provides significant guidance for the utilization of artificial intelligence in petroleum exploration and exploitation, thus further extending the application of AI to small-dataset situations.
{"title":"The application of generative adversarial networks (GANs) for petroleum exploration in deep strata—A case study on overpressure prediction","authors":"Qiaochu Wang , Dongxia Chen , Meijun Li , Fuwei Wang , Zijie Yang , Zaiquan Yang , Sha Li , Yuqi Wang","doi":"10.1016/j.geoen.2025.214326","DOIUrl":"10.1016/j.geoen.2025.214326","url":null,"abstract":"<div><div>Petroleum resources are among the most important fossil fuels in the world. With the development of field knowledge and exploration technology, the giant potential of petroleum resources in deep strata deeper than 5000 m has been recognized. However, the complex geological environment characterized by extremely high pressure seriously constrains deep-strata petroleum resource exploration and exploitation in terms of technology, engineering and economics. In this study, the generative adversarial network (GAN) deep learning algorithm is first applied to construct a virtual exploration well dataset to compensate for the lack of wells in deep strata and then to enlarge the well log dataset. Then, a boosted back propagation neural network (BPNN) is used to predict the complex pore pressure based on the enlarged GAN dataset. Finally, the gradient descent method is utilized for the calibration of the whole model to provide a precise deep-strata pore pressure prediction model. The final results show that with the enlarged GAN dataset, the pore pressure prediction model performs well during training and validation, with the highest correlation coefficients, 0.821 and 0.755, respectively. The test results without loss function calibration show a slightly lower accuracy, with correlation coefficients ranging from 0.584 to 0.606. The cross-validation also indicates similar accuracy, with correlation coefficients ranging from 0.589 to 0.606. By applying the data-driven and physical informed loss functions, both the GAN model and BPNN model are optimized. The loss of the GAN model shows a steady status after the 2000th calibration, which indicates that the best model is constructed. The final correlation coefficient between the actual and predicted pressures also reaches 0.98 as the loss of the BPNN model decreases from 4.0 to 1.1. This study not only introduces a novel method for pore pressure prediction for deeply buried petroleum reservoirs by using the deep learning algorithms of GANs and BPNN, which is the first use in the petroleum industry field, but also provides significant guidance for the utilization of artificial intelligence in petroleum exploration and exploitation, thus further extending the application of AI to small-dataset situations.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214326"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145790948","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: 2025-12-05DOI: 10.1016/j.geoen.2025.214303
Zhongxi Zhu , Weiting Chen , Wanneng Lei , Lei Cao
Accurately locating the leakage location can reduce the loss caused by lost circulation, and a method of detecting the leakage location using transient pressure wave is proposed for leakage location. Firstly, the pressure wave signal is denoised using the improved adaptive noise complete ensemble empirical modal decomposition (ICEEMDAN), the joint classification of preferred components by Marginal Distance (MD) and cumulative mean (MASM), the improved wavelet thresholding method, and a multivariate optimisation signal denoising method based on ICEEMDAN-MD-MASM-IWT is proposed; compared with the other four denoising Secondly, the signal features are analysed using the neighbourhood difference method, and the leakage layer is located according to the peak time of the leakage features, which avoids the problems of too strong dependence on time-domain features, difficult time-frequency correspondence, and inconspicuous feature peaks in the traditional lost circulation detection methods; compared with the other traditional lost circulation detection methods, this method has the smallest average error in location. , which is reduced by 2.03 % compared to the time domain analysis method. Further discussion, multiple sets of experiments were conducted for different borehole sizes, and the error range was 3.11 %–7.98 %. The results show that the lost circulation detection method can effectively identify the location of lost circulation.
{"title":"Experimental detection method of lost circulation based on multivariate optimised signal processing","authors":"Zhongxi Zhu , Weiting Chen , Wanneng Lei , Lei Cao","doi":"10.1016/j.geoen.2025.214303","DOIUrl":"10.1016/j.geoen.2025.214303","url":null,"abstract":"<div><div>Accurately locating the leakage location can reduce the loss caused by lost circulation, and a method of detecting the leakage location using transient pressure wave is proposed for leakage location. Firstly, the pressure wave signal is denoised using the improved adaptive noise complete ensemble empirical modal decomposition (ICEEMDAN), the joint classification of preferred components by Marginal Distance (MD) and cumulative mean (MASM), the improved wavelet thresholding method, and a multivariate optimisation signal denoising method based on ICEEMDAN-MD-MASM-IWT is proposed; compared with the other four denoising Secondly, the signal features are analysed using the neighbourhood difference method, and the leakage layer is located according to the peak time of the leakage features, which avoids the problems of too strong dependence on time-domain features, difficult time-frequency correspondence, and inconspicuous feature peaks in the traditional lost circulation detection methods; compared with the other traditional lost circulation detection methods, this method has the smallest average error in location. , which is reduced by 2.03 % compared to the time domain analysis method. Further discussion, multiple sets of experiments were conducted for different borehole sizes, and the error range was 3.11 %–7.98 %. The results show that the lost circulation detection method can effectively identify the location of lost circulation.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214303"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738222","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.2025.214331
Jiale Zhao , Zijun Li , Yu Xu , Yin Chen
Geothermal energy, as a novel green energy source with high expectations, has garnered extensive research attention. The sheer volume of this research field has made it difficult for scientists to keep abreast of its development trends and cutting-edge areas. This paper utilizes bibliometric analysis to delve into the trends in the development of geothermal energy and Mine Geothermal Energy (MGE) exploitation since the 21st century. Through the Web of Science database, this paper identified 1185 and 138 documents respectively, examining the growth trends, research hotspots, and frontier issues in the Geothermal Energy Exploration (GEE) and MGE fields. The findings reveal an overall upward trend in the literature on GEE and MGE, with an increasing diversification of research directions. The focus of GEE research encompasses technologies such as Enhanced Geothermal Systems (EGS) and Ground Source Heat Pumps (GSHP), while MGE is concentrated on heat energy recovery using mine water and backfill materials. The study also delineates three developmental phases of geothermal energy exploitation and provides a prospective outlook on future trends. This research offers invaluable reference information for newcomers to the field and provides a scientific foundation for the sustainable development of geothermal energy.
地热能作为一种被寄予厚望的新型绿色能源，得到了广泛的研究关注。这个研究领域的庞大数量使得科学家们很难跟上它的发展趋势和前沿领域。本文运用文献计量学分析方法，探讨了21世纪以来地热能和矿用地热能开发的发展趋势。本文通过Web of Science数据库，对地热能勘探（GEE）和地热能勘探（MGE）领域的发展趋势、研究热点和前沿问题进行了梳理，检索文献分别为1185篇和138篇。研究结果显示，研究方向日益多样化，研究结果总体呈上升趋势。GEE的研究重点包括增强型地热系统（EGS）和地源热泵（GSHP）等技术，而MGE的研究重点是利用矿井水和回填材料回收热能。研究还划分了地热能开发的三个发展阶段，并对未来的发展趋势进行了展望。本研究为地热能领域的新手提供了宝贵的参考信息，为地热能的可持续发展提供了科学依据。
{"title":"Trends and frontiers in geothermal energy and mine geothermal energy extraction: A bibliometric study","authors":"Jiale Zhao , Zijun Li , Yu Xu , Yin Chen","doi":"10.1016/j.geoen.2025.214331","DOIUrl":"10.1016/j.geoen.2025.214331","url":null,"abstract":"<div><div>Geothermal energy, as a novel green energy source with high expectations, has garnered extensive research attention. The sheer volume of this research field has made it difficult for scientists to keep abreast of its development trends and cutting-edge areas. This paper utilizes bibliometric analysis to delve into the trends in the development of geothermal energy and Mine Geothermal Energy (MGE) exploitation since the 21st century. Through the Web of Science database, this paper identified 1185 and 138 documents respectively, examining the growth trends, research hotspots, and frontier issues in the Geothermal Energy Exploration (GEE) and MGE fields. The findings reveal an overall upward trend in the literature on GEE and MGE, with an increasing diversification of research directions. The focus of GEE research encompasses technologies such as Enhanced Geothermal Systems (EGS) and Ground Source Heat Pumps (GSHP), while MGE is concentrated on heat energy recovery using mine water and backfill materials. The study also delineates three developmental phases of geothermal energy exploitation and provides a prospective outlook on future trends. This research offers invaluable reference information for newcomers to the field and provides a scientific foundation for the sustainable development of geothermal energy.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214331"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738716","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: 2025-12-10DOI: 10.1016/j.geoen.2025.214336
Qingchao Cheng , Ruixuan Bu , Jianguang Wei , Xiaofeng Zhou , Yujie Bai , Jiangtao Li , Guangsheng Cao
Unconventional reservoirs with low permeability have emerged as new mining objectives to assure the long-term development of oilfields. Fracture-assisted waterflooding (FAW) has become one of the essential technologies for more efficient and low-cost waterflooding development of low-permeability reservoirs. The steady-state and unsteady-state single-phase seepage models for FAW were derived by the potential superposition principle, the source function, and the Newman product solution in this paper. The accuracy of these models was validated using the devices that simulate hydraulic fracturing electrically. Equipotential lines and streamlines fields were calculated to exemplify the seepage mechanism of FAW. Numerical simulations of two-phase (oil-water) flow behavior under FAW conditions were conducted employing a black-oil model, with particular emphasis on production performance and water cut development. The oil production laws in the process of FAW were studied to analyze the formation adaptability of this method. The flow dynamics of oil-water displacement were experimentally investigated through a transparent physical model incorporating tracer visualization technology, enabling precise tracking of fluid front advancement. The results indicated that the equipotential lines spread gradually from the fracture tip to the fracture root, and oil was easily retained at the angle between the fracture and the oil-water well connection line. The FAW production process could be divided into the oil production natural decline stage, the FAW production increase stage, and the FAW production decline stage. Based on the oil production, both the increase in the early stage and the reduction in the subsequent stage were proportional to the increase of fracture length. When the reservoir permeability increased, the optimal fracture length decreased at any given angle. The increase of fracture angle (the angle between the oil-water well connection line and the fracture) could mitigate the water channeling effect caused by excessively long fractures. While the increase in injection pressure exacerbated the degree of water channeling. For reservoirs with permeability greater than 10 × 10−3μm2, the maximum length of the fracture generated by FAW should not exceed 20 m. The optimal range of reservoir permeability for FAW measures was between 0.1 × 10−3μm2 and 20 × 10−3μm2. The findings of this paper provide theoretical guidance for improving the application of FAW technology in low permeability reservoirs.
{"title":"Seepage mechanism and formation applicability of fracture-assisted waterflooding technology in low permeability reservoirs","authors":"Qingchao Cheng , Ruixuan Bu , Jianguang Wei , Xiaofeng Zhou , Yujie Bai , Jiangtao Li , Guangsheng Cao","doi":"10.1016/j.geoen.2025.214336","DOIUrl":"10.1016/j.geoen.2025.214336","url":null,"abstract":"<div><div>Unconventional reservoirs with low permeability have emerged as new mining objectives to assure the long-term development of oilfields. Fracture-assisted waterflooding (FAW) has become one of the essential technologies for more efficient and low-cost waterflooding development of low-permeability reservoirs. The steady-state and unsteady-state single-phase seepage models for FAW were derived by the potential superposition principle, the source function, and the Newman product solution in this paper. The accuracy of these models was validated using the devices that simulate hydraulic fracturing electrically. Equipotential lines and streamlines fields were calculated to exemplify the seepage mechanism of FAW. Numerical simulations of two-phase (oil-water) flow behavior under FAW conditions were conducted employing a black-oil model, with particular emphasis on production performance and water cut development. The oil production laws in the process of FAW were studied to analyze the formation adaptability of this method. The flow dynamics of oil-water displacement were experimentally investigated through a transparent physical model incorporating tracer visualization technology, enabling precise tracking of fluid front advancement. The results indicated that the equipotential lines spread gradually from the fracture tip to the fracture root, and oil was easily retained at the angle between the fracture and the oil-water well connection line. The FAW production process could be divided into the oil production natural decline stage, the FAW production increase stage, and the FAW production decline stage. Based on the oil production, both the increase in the early stage and the reduction in the subsequent stage were proportional to the increase of fracture length. When the reservoir permeability increased, the optimal fracture length decreased at any given angle. The increase of fracture angle (the angle between the oil-water well connection line and the fracture) could mitigate the water channeling effect caused by excessively long fractures. While the increase in injection pressure exacerbated the degree of water channeling. For reservoirs with permeability greater than 10 × 10<sup>−3</sup>μm<sup>2</sup>, the maximum length of the fracture generated by FAW should not exceed 20 m. The optimal range of reservoir permeability for FAW measures was between 0.1 × 10<sup>−3</sup>μm<sup>2</sup> and 20 × 10<sup>−3</sup>μm<sup>2</sup>. The findings of this paper provide theoretical guidance for improving the application of FAW technology in low permeability reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214336"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738717","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.2025.214330
Wenyu Fu , Yunzhong Jia , Hao Liu , Zhaolong Ge , Chenqing Shang , Xinge Zhao
The molecular structure of coal plays a pivotal role in coalbed methane recovery and geologic carbon storage (GCS) within depleted coal seams. To investigate the molecular structure evolution resulting from interactions between CO2 and CH4-containing anthracite, we conducted a series of six experimental trials using XRD, FTIR, and Raman spectroscopy under varying pressure conditions. The results indicate that the crystalline structure parameters, including aromaticity (fa), inter-layer spacing (d002), and average stacking height (Lc) remain largely insensitive to Sc-CO2 exposure. In contrast, oxygen-containing and hydroxyl functional groups exhibit significant and systematic variations, following distinct quadratic trends with respect to CO2 pressure. Specifically, the average diameter (La) decreases significantly with increasing injection pressure. while, the ID1/IG declined consistently, suggesting enhanced structural ordering and the formation of larger aromatic ring systems. A critical pressure range of 8.32–9.38 MPa was identified, within which carboxylic groups readily decompose, promoting crosslinking. Notably, aromatic and aliphatic structures maintain remarkable stability in their proportional distribution, while oxygen-containing structures undergo a characteristic dip-and-rebound trajectory corresponding to enhanced injection pressure levels. This pattern contrasts sharply with the behavior of hydroxyl structures, which exhibit the opposite trend. Maximum structural variation occurs at 8.59 MPa, identified as the critical transition pressure. These findings reveal pressure-dependent molecular reorganization mechanisms in anthracite and provide essential insights for optimizing injection parameters in CO2-ECBM and GCS projects.
{"title":"Molecular structural response of CH4-containing anthracite to Sc-CO2 pressure variations: Decoupling oxygen functionality dynamics for optimized carbon storage","authors":"Wenyu Fu , Yunzhong Jia , Hao Liu , Zhaolong Ge , Chenqing Shang , Xinge Zhao","doi":"10.1016/j.geoen.2025.214330","DOIUrl":"10.1016/j.geoen.2025.214330","url":null,"abstract":"<div><div>The molecular structure of coal plays a pivotal role in coalbed methane recovery and geologic carbon storage (GCS) within depleted coal seams. To investigate the molecular structure evolution resulting from interactions between CO<sub>2</sub> and CH<sub>4</sub>-containing anthracite, we conducted a series of six experimental trials using XRD, FTIR, and Raman spectroscopy under varying pressure conditions. The results indicate that the crystalline structure parameters, including aromaticity (<em>f</em><sub><em>a</em></sub>), inter-layer spacing (<em>d</em><sub><em>002</em></sub>), and average stacking height (<em>L</em><sub><em>c</em></sub>) remain largely insensitive to Sc-CO<sub>2</sub> exposure. In contrast, oxygen-containing and hydroxyl functional groups exhibit significant and systematic variations, following distinct quadratic trends with respect to CO<sub>2</sub> pressure. Specifically, the average diameter (<em>L</em><sub><em>a</em></sub>) decreases significantly with increasing injection pressure. while, the <em>I</em><sub><em>D1</em></sub>/<em>I</em><sub><em>G</em></sub> declined consistently, suggesting enhanced structural ordering and the formation of larger aromatic ring systems. A critical pressure range of 8.32–9.38 MPa was identified, within which carboxylic groups readily decompose, promoting crosslinking. Notably, aromatic and aliphatic structures maintain remarkable stability in their proportional distribution, while oxygen-containing structures undergo a characteristic dip-and-rebound trajectory corresponding to enhanced injection pressure levels. This pattern contrasts sharply with the behavior of hydroxyl structures, which exhibit the opposite trend. Maximum structural variation occurs at 8.59 MPa, identified as the critical transition pressure. These findings reveal pressure-dependent molecular reorganization mechanisms in anthracite and provide essential insights for optimizing injection parameters in CO<sub>2</sub>-ECBM and GCS projects.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"258 ","pages":"Article 214330"},"PeriodicalIF":4.6,"publicationDate":"2026-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145738695","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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