RF
R. Farajzadeh
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1
Dispersion is influenced by the complex interplay between rock heterogeneity, flow dynamics, and thermodynamic conditions. Previous studies have shown that factors like heterogeneity and injection rate affect how fluids mix and spread in geological formations. However, the role of system pressure and flow regime in shaping dispersion characteristics, particularly under unstable flow conditions, remains less understood. This study examines the effects of system pressure and flow rate on the dispersion of CO₂ and CH₄ in Indiana limestone and Silurian dolomite, two carbonate rocks with distinct pore structures. Experiments were conducted at pressures of 300, 600, and 900 psi, with flow rates of 1.69 × 10⁻⁴ m/s, 2.12 × 10⁻⁴ m/s, and 3.39 × 10⁻⁴ m/s, to evaluate how dispersion characteristics evolve under varying conditions. The results indicate that under stable flow, pressure has minimal impact on dispersion. However, under unstable flow, increasing pressure alters velocity distributions and enhances fluid mixing, leading to deviations in the dispersion coefficient beyond the effects of rock heterogeneity alone. In more homogeneous media, a threshold is observed where dispersion under unstable flow is lower relative to stable flow. These findings demonstrate that pressure amplifies dispersion primarily under unstable flow governed by the fluid density contrasts, and that heterogeneity can either enhance or dampen these effects.
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Dispersion is influenced by the complex interplay between rock heterogeneity, flow dynamics, and thermodynamic conditions. Previous studies have shown that factors like heterogeneity and injection rate affect how fluids mix and spread in geological formations. However, the role of system pressure and flow regime in shaping dispersion characteristics, particularly under unstable flow conditions, remains less understood. This study examines the effects of system pressure and flow rate on the dispersion of CO₂ and CH₄ in Indiana limestone and Silurian dolomite, two carbonate rocks with distinct pore structures. Experiments were conducted at pressures of 300, 600, and 900 psi, with flow rates of 1.69 × 10⁻⁴ m/s, 2.12 × 10⁻⁴ m/s, and 3.39 × 10⁻⁴ m/s, to evaluate how dispersion characteristics evolve under varying conditions. The results indicate that under stable flow, pressure has minimal impact on dispersion. However, under unstable flow, increasing pressure alters velocity distributions and enhances fluid mixing, leading to deviations in the dispersion coefficient beyond the effects of rock heterogeneity alone. In more homogeneous media, a threshold is observed where dispersion under unstable flow is lower relative to stable flow. These findings demonstrate that pressure amplifies dispersion primarily under unstable flow governed by the fluid density contrasts, and that heterogeneity can either enhance or dampen these effects.
CO2 injection into depleted reservoirs is a promising strategy for carbon storage, but it poses operational risks from hydrate formation, which can result in injectivity impairment. Concurrently, the injection of dry CO2 drives a reservoir dry-out process by vaporizing formation water, which is counteracting the hydrate formation. This study uses numerical simulation to systematically investigate the competition between these two phenomena and to determine the conditions under which dry-out can mitigate or prevent hydrate formation. A five-phase, thermal-compositional model was developed to analyze the interplay between the advancing dry-out front and the thermal (cold) front. The results reveal two distinct regimes. A rapid and extensive leading dry-out front that outpaces the cold front and completely removes water before the reservoir cools. Conversely, a slow trailing dry-out front , where dry-out occurs within the already-cooled region. The leading dry-out front completely prevents hydrate formation. Even in the trailing-front scenario, the partial water removal ahead of the cold front significantly reduces the resulting hydrate saturation. Sensitivity analysis identifies initial reservoir temperature and initial water saturation as the most critical parameters governing this behavior. This work demonstrates that reservoir dry-out is an inherent mechanism for mitigating hydrate risk.
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CO2 injection into depleted reservoirs is a promising strategy for carbon storage, but it poses operational risks from hydrate formation, which can result in injectivity impairment. Concurrently, the injection of dry CO2 drives a reservoir dry-out process by vaporizing formation water, which is counteracting the hydrate formation. This study uses numerical simulation to systematically investigate the competition between these two phenomena and to determine the conditions under which dry-out can mitigate or prevent hydrate formation. A five-phase, thermal-compositional model was developed to analyze the interplay between the advancing dry-out front and the thermal (cold) front. The results reveal two distinct regimes. A rapid and extensive leading dry-out front that outpaces the cold front and completely removes water before the reservoir cools. Conversely, a slow trailing dry-out front , where dry-out occurs within the already-cooled region. The leading dry-out front completely prevents hydrate formation. Even in the trailing-front scenario, the partial water removal ahead of the cold front significantly reduces the resulting hydrate saturation. Sensitivity analysis identifies initial reservoir temperature and initial water saturation as the most critical parameters governing this behavior. This work demonstrates that reservoir dry-out is an inherent mechanism for mitigating hydrate risk.
Recent numerical simulations of geological CO2 storage in deep saline aquifers have demonstrated that vertical equilibrium (VE) models provide a robust and computationally efficient approach for reservoir prediction and upscaling. These studies also underscore the significant impact of fines migration and partial water-CO2 miscibility on the temporal evolution of storage behaviour. Specifically, capillary-driven detachment of clay and silica fines can reduce well injectivity, while water evaporation into the injected CO2 causes near-wellbore drying, salt precipitation, and further injectivity impairment. However, current VE models do not capture these coupled physical and geochemical phenomena. For the first time, this work develops an extended VE model with the following novel features: (i) permeability-reducing migration of natural reservoir fines, (ii) water evaporation into injected CO2, (iii) CO2 dissolution into the displaced brine. For a stratified (layer-cake) aquifer, an exact analytical solution of the developed model has been derived. It provides explicit formulae for sweep efficiency and injectivity decline. The analytical model reveals two distinct displacement fronts – the displacement-dissolution front (advanced front) and the full evaporation front (receded front) – which bound the two-phase flow region. The model downscaling reveals that in formations with decreasing permeability with depth, gas saturation declines monotonically with depth. Alternatively, in reservoirs with increasing permeability with depth, the competition between viscous and gravitational forces can result in non-monotonic vertical saturation profiles. The analysis also shows that fines migration, while detrimental to injectivity, enhances sweep efficiency – highlighting a complex trade-off in the design and assessment of CO2 storage operations.
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Recent numerical simulations of geological CO2 storage in deep saline aquifers have demonstrated that vertical equilibrium (VE) models provide a robust and computationally efficient approach for reservoir prediction and upscaling. These studies also underscore the significant impact of fines migration and partial water-CO2 miscibility on the temporal evolution of storage behaviour. Specifically, capillary-driven detachment of clay and silica fines can reduce well injectivity, while water evaporation into the injected CO2 causes near-wellbore drying, salt precipitation, and further injectivity impairment. However, current VE models do not capture these coupled physical and geochemical phenomena. For the first time, this work develops an extended VE model with the following novel features: (i) permeability-reducing migration of natural reservoir fines, (ii) water evaporation into injected CO2, (iii) CO2 dissolution into the displaced brine. For a stratified (layer-cake) aquifer, an exact analytical solution of the developed model has been derived. It provides explicit formulae for sweep efficiency and injectivity decline. The analytical model reveals two distinct displacement fronts – the displacement-dissolution front (advanced front) and the full evaporation front (receded front) – which bound the two-phase flow region. The model downscaling reveals that in formations with decreasing permeability with depth, gas saturation declines monotonically with depth. Alternatively, in reservoirs with increasing permeability with depth, the competition between viscous and gravitational forces can result in non-monotonic vertical saturation profiles. The analysis also shows that fines migration, while detrimental to injectivity, enhances sweep efficiency – highlighting a complex trade-off in the design and assessment of CO2 storage operations.
Exploring reservoir heterogeneity effects on halite precipitation during CO2 storage
Insights from an experimental study
Journal article
(2026)
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Lifei Yan, Rens Florian van der Vleuten, Saba Najjari Hagh, Sian Jones, Mahnaz Aghajanloo, Manon Arianne Renée Schellart, Diederik Boersma, Denis Voskov, Rouhi Farajzadeh
Carbon dioxide (CO2) storage in geological reservoirs is an effective approach to mitigate greenhouse gas emissions. However, salt precipitation induced by dry CO2 injection can reduce injectivity, thereby affecting storage efficiency and operational stability. This study investigates the impact of rock permeability on halite precipitation patterns and their influence on CO2 injectivity through core-flooding experiments. Using four distinct cores, three homogeneous and one heterogeneous under controlled conditions, we analyse the dynamic processes of brine displacement, water evaporation, salt accumulation, and permeability evolution with real-time computed tomography (CT) imaging and multiple fluid pressure sensors. Results indicate that permeability contrast redistributes brine and changes the location of salt deposition. Permeability impairment is not governed by initial permeability alone; instead, it reflects the combined influence of permeability, porosity, mineral heterogeneity, capillary retention, and local flow-path blockage. Salt precipitation is more dispersed in heterogeneous cores compared to homogeneous cores, where under our experimental conditions, it predominantly accumulates near the injection point. Furthermore, permeability impairment varies with initial rock properties, with higher-permeability cores experiencing more severe injectivity reduction due to increased pore clogging. These findings highlight the importance of incorporating reservoir heterogeneity in predictive models for CO2 storage operations. Understanding the dynamic interplay between brine migration, salt crystallization, and permeability evolution is crucial for optimizing long-term injectivity and ensuring the viability of geological carbon storage.
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Carbon dioxide (CO2) storage in geological reservoirs is an effective approach to mitigate greenhouse gas emissions. However, salt precipitation induced by dry CO2 injection can reduce injectivity, thereby affecting storage efficiency and operational stability. This study investigates the impact of rock permeability on halite precipitation patterns and their influence on CO2 injectivity through core-flooding experiments. Using four distinct cores, three homogeneous and one heterogeneous under controlled conditions, we analyse the dynamic processes of brine displacement, water evaporation, salt accumulation, and permeability evolution with real-time computed tomography (CT) imaging and multiple fluid pressure sensors. Results indicate that permeability contrast redistributes brine and changes the location of salt deposition. Permeability impairment is not governed by initial permeability alone; instead, it reflects the combined influence of permeability, porosity, mineral heterogeneity, capillary retention, and local flow-path blockage. Salt precipitation is more dispersed in heterogeneous cores compared to homogeneous cores, where under our experimental conditions, it predominantly accumulates near the injection point. Furthermore, permeability impairment varies with initial rock properties, with higher-permeability cores experiencing more severe injectivity reduction due to increased pore clogging. These findings highlight the importance of incorporating reservoir heterogeneity in predictive models for CO2 storage operations. Understanding the dynamic interplay between brine migration, salt crystallization, and permeability evolution is crucial for optimizing long-term injectivity and ensuring the viability of geological carbon storage.
DARTS-well
An open-source fully coupled well–reservoir numerical model using the Operator-based Linearization Approach
During subsurface energy-transition operations, such as carbon dioxide sequestration, underground hydrogen storage, and geothermal energy extraction, fluid flow into the well and reservoir can induce strong hydraulic and thermal interactions between the well and the near-wellbore region. These interactions are particularly critical during high-pressure CO2 injection into depleted reservoirs, where significant temperature reductions may occur along and around the well, leading to complex phase behavior and potentially reducing injectivity. Conventional standalone well or reservoir models, however, fail to resolve these well–reservoir interactions. A fully coupled well–reservoir model is therefore essential to ensure accurate, safe, and efficient subsurface energy-transition operations. To address this need, we develop an open-source, computationally efficient numerical model for transient, thermal, multiphase flow in a fully coupled well–reservoir system. A multiphase, transient wellbore model is developed using the Drift-Flux Model and fully coupled with the high-performance, open-source Delft Advanced Research Terra Simulator (open-DARTS). Open-DARTS uses Operator-Based Linearization (OBL), where state-dependent properties are grouped as operators and interpolated from multidimensional tables generated on the fly, reducing the cost of evaluating residuals and derivatives in Newton–Raphson iterations. The wellbore model is verified against an analytical solution and benchmarked against industry-standard well simulators for single- and two-phase, isothermal and thermal flow in vertical and inclined wells, and the coupling approach is also benchmarked against a commercial coupled simulator. We then simulate liquid CO2 injection into a North Sea–representative depleted gas reservoir using grid and OBL resolutions selected by convergence analyses.
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During subsurface energy-transition operations, such as carbon dioxide sequestration, underground hydrogen storage, and geothermal energy extraction, fluid flow into the well and reservoir can induce strong hydraulic and thermal interactions between the well and the near-wellbore region. These interactions are particularly critical during high-pressure CO2 injection into depleted reservoirs, where significant temperature reductions may occur along and around the well, leading to complex phase behavior and potentially reducing injectivity. Conventional standalone well or reservoir models, however, fail to resolve these well–reservoir interactions. A fully coupled well–reservoir model is therefore essential to ensure accurate, safe, and efficient subsurface energy-transition operations. To address this need, we develop an open-source, computationally efficient numerical model for transient, thermal, multiphase flow in a fully coupled well–reservoir system. A multiphase, transient wellbore model is developed using the Drift-Flux Model and fully coupled with the high-performance, open-source Delft Advanced Research Terra Simulator (open-DARTS). Open-DARTS uses Operator-Based Linearization (OBL), where state-dependent properties are grouped as operators and interpolated from multidimensional tables generated on the fly, reducing the cost of evaluating residuals and derivatives in Newton–Raphson iterations. The wellbore model is verified against an analytical solution and benchmarked against industry-standard well simulators for single- and two-phase, isothermal and thermal flow in vertical and inclined wells, and the coupling approach is also benchmarked against a commercial coupled simulator. We then simulate liquid CO2 injection into a North Sea–representative depleted gas reservoir using grid and OBL resolutions selected by convergence analyses.
Evaluation of operational strategies for underground hydrogen storage in depleted gas fields under diverse geological scenarios
Guidelines for site screening and development planning
Journal article
(2026)
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Ana Loyola, Denis Voskov, Rouhi Farajzadeh, Karin de Borst, Sebastian Geiger
Underground hydrogen storage in depleted gas fields is a potential solution for large-scale, seasonal storage of hydrogen, in support of the decarbonization of energy systems and other industrial activities. Its viability depends on the performance of the storage operations, which is influenced by the interaction between reservoir geology and operational strategies. However, general guidelines for development planning that account for geological uncertainty are still lacking. In addition, existing site screening criteria remain limited in that they do not account for how operational decisions can alter the suitability of a reservoir geology for hydrogen storage. Here, we employ a numerical model of flow and transport to evaluate a set of operational strategies in varying geological scenarios for depleted methane gas reservoirs of the Bunter Sandstone, an important formation in the North Sea. We investigate the following strategies for their impact on performance and interaction with geological features that are common in the Bunter sandstone: depletion level, injected hydrogen mass, cushion gas, well perforation, idle period, production rates, and methane reinjection. We found that depletion level, injected mass, and well perforation interact strongly with geology and are critical for site selection. The methane reinjection strategy provides pressure support that increases hydrogen production, though at the cost of purity in the long-term. Furthermore, cushion gas strategies show significant optimization potential but limited interaction with geology, whereas the duration of the idle period and target rates have low optimization potential. Based on these findings, we propose a site selection and development planning framework for underground hydrogen storage in depleted gas fields. The site selection phase introduces a novel screening criterion, the gravity–purity number, which integrates geological and operational considerations. The development phase provides criteria and guidelines for planning operational strategies, and establishes a hierarchy based on their optimization potential.
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Underground hydrogen storage in depleted gas fields is a potential solution for large-scale, seasonal storage of hydrogen, in support of the decarbonization of energy systems and other industrial activities. Its viability depends on the performance of the storage operations, which is influenced by the interaction between reservoir geology and operational strategies. However, general guidelines for development planning that account for geological uncertainty are still lacking. In addition, existing site screening criteria remain limited in that they do not account for how operational decisions can alter the suitability of a reservoir geology for hydrogen storage. Here, we employ a numerical model of flow and transport to evaluate a set of operational strategies in varying geological scenarios for depleted methane gas reservoirs of the Bunter Sandstone, an important formation in the North Sea. We investigate the following strategies for their impact on performance and interaction with geological features that are common in the Bunter sandstone: depletion level, injected hydrogen mass, cushion gas, well perforation, idle period, production rates, and methane reinjection. We found that depletion level, injected mass, and well perforation interact strongly with geology and are critical for site selection. The methane reinjection strategy provides pressure support that increases hydrogen production, though at the cost of purity in the long-term. Furthermore, cushion gas strategies show significant optimization potential but limited interaction with geology, whereas the duration of the idle period and target rates have low optimization potential. Based on these findings, we propose a site selection and development planning framework for underground hydrogen storage in depleted gas fields. The site selection phase introduces a novel screening criterion, the gravity–purity number, which integrates geological and operational considerations. The development phase provides criteria and guidelines for planning operational strategies, and establishes a hierarchy based on their optimization potential.
Heat exchange with surrounding formations and Joule–Thomson cooling during CO2 injection into deep saline aquifers and depleted hydrocarbon reservoirs can lead to substantial declines in well injectivity. This work addresses these challenges by introducing an analytical model for non-isothermal CO2 injection that accounts for both JT cooling and inter-formation heat exchange, assuming that heat transfer begins upon arrival of the temperature front rather than the gas–water front, as adopted in earlier models. An exact 1D solution is derived, providing closed-form expressions for temperature and pressure profiles. Model performance is evaluated through comparison with an exact 2D solution obtained from reservoir energy conservation. The new formulation demonstrates markedly improved accuracy over the previous model. The solution predicts a temperature drop from the injection temperature at the wellbore to a minimum at the temperature front, followed by a rapid rise back to the initial reservoir temperature. Mapping the evolving temperature and pressure profiles onto a (T, p) phase diagram enables assessment of hydrate-formation risk and identification of the distance from the injection well where hydrates may form.
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Heat exchange with surrounding formations and Joule–Thomson cooling during CO2 injection into deep saline aquifers and depleted hydrocarbon reservoirs can lead to substantial declines in well injectivity. This work addresses these challenges by introducing an analytical model for non-isothermal CO2 injection that accounts for both JT cooling and inter-formation heat exchange, assuming that heat transfer begins upon arrival of the temperature front rather than the gas–water front, as adopted in earlier models. An exact 1D solution is derived, providing closed-form expressions for temperature and pressure profiles. Model performance is evaluated through comparison with an exact 2D solution obtained from reservoir energy conservation. The new formulation demonstrates markedly improved accuracy over the previous model. The solution predicts a temperature drop from the injection temperature at the wellbore to a minimum at the temperature front, followed by a rapid rise back to the initial reservoir temperature. Mapping the evolving temperature and pressure profiles onto a (T, p) phase diagram enables assessment of hydrate-formation risk and identification of the distance from the injection well where hydrates may form.
Journal article
(2026)
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Lifei Yan, Manon Schellart, Diederik Boersma, Denis Voskov, Rouhi Farajzadeh
Carbon dioxide storage in deep saline aquifers and/or depleted hydrocarbon reservoirs is a widely recognized approach for reducing greenhouse gas emissions. However, two key phenomena, halite precipitation and CO2 hydrate formation, pose significant challenges to maintaining injectivity and permeability near the wellbore. This study provides novel experimental insights into how the two pore-scale processes influence porosity loss during CO2 sequestration. A series of controlled microfluidic experiments using glass-based porous networks were conducted to observe the interactions between brine, CO2, and porous media under reservoir-relevant conditions. High-resolution imaging techniques, coupled with advanced image processing algorithms, were employed to analyse water film behaviour and salt crystal growth dynamics. Separate experiments explored the effects of varying pore structures, pressure fluctuations, and thermal conditions on the spatial distribution and morphology of hydrates. The impact of local water saturation variations on fluid displacement and hydrate stability was also examined. The results indicate that heterogeneous pore networks retain more brine than homogeneous ones, leading to more salt precipitation and a maximum observed porosity reduction of 10%. Salt crystallization follows two distinct patterns: smooth-edged crystals form within the brine phase, whereas rough-edged deposits develop at the CO2-brine interface. Hydrate formation exhibits diverse morphologies, amongst others pore-filling, grain-coating, and patchy, hydrate films, influenced by pore size, wettability, and pressure variations. The formed hydrates can reduce porosity by maximum of 15% in the experiments. Additionally, the spatial distribution of hydrates is found to be non-uniform, governed by fluid-phase interactions, with a weak correlation between hydrate and local water saturations.
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Carbon dioxide storage in deep saline aquifers and/or depleted hydrocarbon reservoirs is a widely recognized approach for reducing greenhouse gas emissions. However, two key phenomena, halite precipitation and CO2 hydrate formation, pose significant challenges to maintaining injectivity and permeability near the wellbore. This study provides novel experimental insights into how the two pore-scale processes influence porosity loss during CO2 sequestration. A series of controlled microfluidic experiments using glass-based porous networks were conducted to observe the interactions between brine, CO2, and porous media under reservoir-relevant conditions. High-resolution imaging techniques, coupled with advanced image processing algorithms, were employed to analyse water film behaviour and salt crystal growth dynamics. Separate experiments explored the effects of varying pore structures, pressure fluctuations, and thermal conditions on the spatial distribution and morphology of hydrates. The impact of local water saturation variations on fluid displacement and hydrate stability was also examined. The results indicate that heterogeneous pore networks retain more brine than homogeneous ones, leading to more salt precipitation and a maximum observed porosity reduction of 10%. Salt crystallization follows two distinct patterns: smooth-edged crystals form within the brine phase, whereas rough-edged deposits develop at the CO2-brine interface. Hydrate formation exhibits diverse morphologies, amongst others pore-filling, grain-coating, and patchy, hydrate films, influenced by pore size, wettability, and pressure variations. The formed hydrates can reduce porosity by maximum of 15% in the experiments. Additionally, the spatial distribution of hydrates is found to be non-uniform, governed by fluid-phase interactions, with a weak correlation between hydrate and local water saturations.
CO2 hydrate saturation, permeability and injectivity in the saline environments
Effect of mean ionic activity
Journal article
(2026)
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M. Aghajanloo, S. M. Taghinejad, T. Zaynetdinov, S. Jones, D. Voskov, R. Farajzadeh
In depleted or low-pressure subsurface reservoirs, the formation of CO₂ hydrate at low temperatures, induced by vaporization and isenthalpic expansion during dense CO₂ injection, can significantly impair well injectivity. The formation of CO₂ hydrates is governed by multiple factors, including CO₂ availability and its solubility, the properties of the surrounding fluids, and the characteristics of the rock. A key parameter influencing water activity and CO₂ solubility is the salinity of in-situ brine, which affects both the thermodynamics and kinetics of hydrate formation. The impact of salinity varies with the type and concentration of dissolved salts. This study investigates the impacts of two prevalent formation water salts, NaCl and CaCl₂ on CO₂ hydrate induction time, hydrate saturation, rock permeability reduction, and their implications for CO₂ injectivity. Coreflood experiments were performed under dynamic flow conditions, supplemented by computed tomography (CT) scanning to provide in-situ saturation profiles. The primary aim is to establish a correlation between the aforementioned parameters and mean ionic activity, thereby facilitating a generalized application of the results irrespective of the specific salt type. Empirical results indicate a marginally extended induction period at elevated initial salinity levels. Furthermore, an increase in mean ionic activity correlates with a decrease in hydrate saturation, which consequently leads to less significant reductions in permeability and injectivity.
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In depleted or low-pressure subsurface reservoirs, the formation of CO₂ hydrate at low temperatures, induced by vaporization and isenthalpic expansion during dense CO₂ injection, can significantly impair well injectivity. The formation of CO₂ hydrates is governed by multiple factors, including CO₂ availability and its solubility, the properties of the surrounding fluids, and the characteristics of the rock. A key parameter influencing water activity and CO₂ solubility is the salinity of in-situ brine, which affects both the thermodynamics and kinetics of hydrate formation. The impact of salinity varies with the type and concentration of dissolved salts. This study investigates the impacts of two prevalent formation water salts, NaCl and CaCl₂ on CO₂ hydrate induction time, hydrate saturation, rock permeability reduction, and their implications for CO₂ injectivity. Coreflood experiments were performed under dynamic flow conditions, supplemented by computed tomography (CT) scanning to provide in-situ saturation profiles. The primary aim is to establish a correlation between the aforementioned parameters and mean ionic activity, thereby facilitating a generalized application of the results irrespective of the specific salt type. Empirical results indicate a marginally extended induction period at elevated initial salinity levels. Furthermore, an increase in mean ionic activity correlates with a decrease in hydrate saturation, which consequently leads to less significant reductions in permeability and injectivity.
The injection of humid (or wet) CO2 into geological aquifers offers a practical means of mitigating near-wellbore impairment caused by connate-water evaporation and the consequent formation damage induced by salt-precipitation in the dry zone. This study aims to develop a novel analytical model for this process. We extend the traditional Vertical Equilibrium (VE) formulation for immiscible displacement of brine by CO2 in layer-cake reservoirs to incorporate partial brine-CO2 miscibility, and formation damage due to fines migration and salt precipitation in the dry zone. The depth-averaging of the quasi-2D VE model yields explicit expressions for upscaled phase permeabilities and effective capillary pressure. The resulting 1D model allows for an exact self-similar solution, which provides explicit expressions for determining sweep efficiency and injectivity decline. The analysis of the model reveals the emergence of two distinct displacement fronts—a CO2 dissolution-displacement front (advanced front) and a full-evaporation front (receded front)—which delineate the two-phase flow region. The explicit analytical expressions derived enable rapid multivariate sensitivity studies on how CO2 humidity, reservoir heterogeneity, viscosity ratio and formation damage parameters influence overall sweep efficiency and well injectivity.
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The injection of humid (or wet) CO2 into geological aquifers offers a practical means of mitigating near-wellbore impairment caused by connate-water evaporation and the consequent formation damage induced by salt-precipitation in the dry zone. This study aims to develop a novel analytical model for this process. We extend the traditional Vertical Equilibrium (VE) formulation for immiscible displacement of brine by CO2 in layer-cake reservoirs to incorporate partial brine-CO2 miscibility, and formation damage due to fines migration and salt precipitation in the dry zone. The depth-averaging of the quasi-2D VE model yields explicit expressions for upscaled phase permeabilities and effective capillary pressure. The resulting 1D model allows for an exact self-similar solution, which provides explicit expressions for determining sweep efficiency and injectivity decline. The analysis of the model reveals the emergence of two distinct displacement fronts—a CO2 dissolution-displacement front (advanced front) and a full-evaporation front (receded front)—which delineate the two-phase flow region. The explicit analytical expressions derived enable rapid multivariate sensitivity studies on how CO2 humidity, reservoir heterogeneity, viscosity ratio and formation damage parameters influence overall sweep efficiency and well injectivity.
Lattice Boltzmann (LB) modeling has been extensively applied to porous media processes, including evaporation. Former pore-scale LB models for evaporation rely on oversimplified assumptions, such as matched viscosities. However, in subsurface CO2–brine systems, the viscosity ratio can exceed 100 under relevant temperature–pressure conditions. This study introduces a novel LB model based on the Volume-of-Fluid (VoF) method, capable of simulating two-phase flow in porous media with high-contrast viscosities and densities. The proposed VoF-LB model was further extended to model coupled evaporation and two-phase flow for water–CO2 in porous media. The simulation results were validated against analytical benchmarks and a pore-scale micromodel experiment. The model was employed to explore how pore size distribution variability influences the drying front and the redistribution of water due to capillary suction, with implications for geological CO2 storage in saline aquifers. This study presents two key advancements: (a) it demonstrates that the developed VoF-LB model accurately captures sharp phase interfaces and effectively handles extreme viscosity and density contrasts relevant to CO2–water systems; (b) the validated VoF-LB model is applied to simulate drying in both 2D and 3D porous media, introducing a dimensionless parameter to quantify evaporation-driven mass transfer relative to capillary flow. The results reveal that pore-size heterogeneity and capillary-pressure gradients play a crucial role in shaping the drying interface and governing water redistribution. In 3D simulations, greater water-phase connectivity amplifies these effects compared to 2D, highlighting the significance of corner flow and extensive liquid connectivity—phenomena not fully captured in 2D.
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Lattice Boltzmann (LB) modeling has been extensively applied to porous media processes, including evaporation. Former pore-scale LB models for evaporation rely on oversimplified assumptions, such as matched viscosities. However, in subsurface CO2–brine systems, the viscosity ratio can exceed 100 under relevant temperature–pressure conditions. This study introduces a novel LB model based on the Volume-of-Fluid (VoF) method, capable of simulating two-phase flow in porous media with high-contrast viscosities and densities. The proposed VoF-LB model was further extended to model coupled evaporation and two-phase flow for water–CO2 in porous media. The simulation results were validated against analytical benchmarks and a pore-scale micromodel experiment. The model was employed to explore how pore size distribution variability influences the drying front and the redistribution of water due to capillary suction, with implications for geological CO2 storage in saline aquifers. This study presents two key advancements: (a) it demonstrates that the developed VoF-LB model accurately captures sharp phase interfaces and effectively handles extreme viscosity and density contrasts relevant to CO2–water systems; (b) the validated VoF-LB model is applied to simulate drying in both 2D and 3D porous media, introducing a dimensionless parameter to quantify evaporation-driven mass transfer relative to capillary flow. The results reveal that pore-size heterogeneity and capillary-pressure gradients play a crucial role in shaping the drying interface and governing water redistribution. In 3D simulations, greater water-phase connectivity amplifies these effects compared to 2D, highlighting the significance of corner flow and extensive liquid connectivity—phenomena not fully captured in 2D.
Journal article
(2026)
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Michiel Wapperom, Sadegh M. Taghinejad, Xiaocong Lyu, Rouhi Farajzadeh, Denis Voskov
In this work, we present a kinetic simulation model for gas hydrates in porous media using the Operator-Based Linearization (OBL) technique. The OBL approach introduces algebraic operators that represent the physical terms in the mass and energy balance equations. Operators are calculated only in supporting points comprising the discretized parameter space, and operator values and partial derivatives for linear system assembly are readily obtained through (multi-)linear interpolation. Taking advantage of this setup, the implementation of advanced thermodynamic models for hydrate formation and dissociation under kinetic assumptions is simplified. We test the assumptions for thermodynamic modelling by analysing the Gibbs energy surfaces of the fluid and hydrate phases and demonstrate that, in the limit, the thermodynamic equilibrium for both kinetic and equilibrium reaction models is equivalent. We compare the simulation results with the published experimental results for CH4-hydrates and extend the assessment to a CO2-hydrate formation experiment in a semi-batch, constant-pressure configuration. The model reproduces the main pressure–temperature transients and hydrate evolution for both CH4- and CO2-systems. We demonstrate applicability at core scale for hydrate formation and, at field scale, for gas production from CH4-hydrates by thermal stimulation and depressurization. The interaction of thermal-compositional phenomena (phase changes, adiabatic expansion, kinetic rates, and reaction enthalpy) gives rise to highly nonlinear physics that an appropriate OBL discretization resolves. Overall, the patterns of hydrate formation and dissociation are highly sensitive to the kinetic-rate inputs; hence, the appropriate choice of the reaction model remains a key consideration from both physical and numerical perspectives.
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In this work, we present a kinetic simulation model for gas hydrates in porous media using the Operator-Based Linearization (OBL) technique. The OBL approach introduces algebraic operators that represent the physical terms in the mass and energy balance equations. Operators are calculated only in supporting points comprising the discretized parameter space, and operator values and partial derivatives for linear system assembly are readily obtained through (multi-)linear interpolation. Taking advantage of this setup, the implementation of advanced thermodynamic models for hydrate formation and dissociation under kinetic assumptions is simplified. We test the assumptions for thermodynamic modelling by analysing the Gibbs energy surfaces of the fluid and hydrate phases and demonstrate that, in the limit, the thermodynamic equilibrium for both kinetic and equilibrium reaction models is equivalent. We compare the simulation results with the published experimental results for CH4-hydrates and extend the assessment to a CO2-hydrate formation experiment in a semi-batch, constant-pressure configuration. The model reproduces the main pressure–temperature transients and hydrate evolution for both CH4- and CO2-systems. We demonstrate applicability at core scale for hydrate formation and, at field scale, for gas production from CH4-hydrates by thermal stimulation and depressurization. The interaction of thermal-compositional phenomena (phase changes, adiabatic expansion, kinetic rates, and reaction enthalpy) gives rise to highly nonlinear physics that an appropriate OBL discretization resolves. Overall, the patterns of hydrate formation and dissociation are highly sensitive to the kinetic-rate inputs; hence, the appropriate choice of the reaction model remains a key consideration from both physical and numerical perspectives.
Journal article
(2026)
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Jianxin Lu, Aleksei Novikov, Mengjie Zhao, Lifei Yan, Rouhi Farajzadeh, Denis Voskov
Accurate simulation of CO2 sequestration in deep saline aquifers requires consistent treatment of history-dependent processes. Operator-Based Linearization (OBL) provides an efficient and robust framework for compositional flow simulation. However, it was originally designed for reversible physical processes, since the operator evaluation depends solely on the instantaneous thermodynamic state. In this work, we extend the OBL approach by introducing history-dependent variables into the operator parameter space while keeping them outside the Newton unknown vector, thereby augmenting OBL with history dependency while preserving the dimension of the Jacobian matrix. To apply the augmented OBL framework to hysteresis modeling, a new hysteresis algorithm is proposed, in which the maximum gas saturation is used as the history coordinate; the flow equations are solved fully implicitly with respect to the primary variables, while this history variable is held fixed during Newton iterations and updated locally after timestep convergence to capture drainage–imbibition transitions and CO2 dissolution feedback. The augmented OBL approach is validated against the academic DARSim simulator and the commercial CMG simulator, demonstrating close agreement with conventional hysteresis modeling approaches. A sensitivity analysis of the operator parameterization shows that the resolution of the parameter space governs both accuracy and computational cost within the OBL framework. Numerical experiments in one-dimensional homogeneous and two-dimensional heterogeneous models further demonstrate that the proposed approach provides a practical and accurate means of incorporating history-dependent physics into reservoir-scale compositional simulations of CO2 sequestration.
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Accurate simulation of CO2 sequestration in deep saline aquifers requires consistent treatment of history-dependent processes. Operator-Based Linearization (OBL) provides an efficient and robust framework for compositional flow simulation. However, it was originally designed for reversible physical processes, since the operator evaluation depends solely on the instantaneous thermodynamic state. In this work, we extend the OBL approach by introducing history-dependent variables into the operator parameter space while keeping them outside the Newton unknown vector, thereby augmenting OBL with history dependency while preserving the dimension of the Jacobian matrix. To apply the augmented OBL framework to hysteresis modeling, a new hysteresis algorithm is proposed, in which the maximum gas saturation is used as the history coordinate; the flow equations are solved fully implicitly with respect to the primary variables, while this history variable is held fixed during Newton iterations and updated locally after timestep convergence to capture drainage–imbibition transitions and CO2 dissolution feedback. The augmented OBL approach is validated against the academic DARSim simulator and the commercial CMG simulator, demonstrating close agreement with conventional hysteresis modeling approaches. A sensitivity analysis of the operator parameterization shows that the resolution of the parameter space governs both accuracy and computational cost within the OBL framework. Numerical experiments in one-dimensional homogeneous and two-dimensional heterogeneous models further demonstrate that the proposed approach provides a practical and accurate means of incorporating history-dependent physics into reservoir-scale compositional simulations of CO2 sequestration.
Hydrocarbon fuels are widely recognized as significant contributors to climate change and the rising levels of CO2 in the atmosphere. As a result, it is crucial to reduce the net carbon intensity of energy derived from these fuels. This study explores the feasibility of using dimethyl ether (DME), produced through the hydrogenation of CO2, as a low-carbon method for generating electricity from hydrocarbon fuels. The proposed approach involves capturing the emitted CO2 during combustion and utilizing it to produce the necessary DME in a closed cycle. It is shown that for a mature reservoir in the Middle East, this method can mitigate approximately 75% of the CO2 emissions released from burning the produced oil. By incorporating zero-carbon electricity throughout the process, the total abatement of CO2 can reach 85%. Furthermore, the study highlights the importance of improving the DME utilization factor (bbl-oil/tDME). By optimizing this factor, high abatement rates can be achieved. However, it is important to note that implementing this method comes with a high exergetic cost. During a certain period in the field’s lifetime, the invested energy exceeds the energy produced. The stages with the highest exergy consumption are CO2 capture and hydrogen production.
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Hydrocarbon fuels are widely recognized as significant contributors to climate change and the rising levels of CO2 in the atmosphere. As a result, it is crucial to reduce the net carbon intensity of energy derived from these fuels. This study explores the feasibility of using dimethyl ether (DME), produced through the hydrogenation of CO2, as a low-carbon method for generating electricity from hydrocarbon fuels. The proposed approach involves capturing the emitted CO2 during combustion and utilizing it to produce the necessary DME in a closed cycle. It is shown that for a mature reservoir in the Middle East, this method can mitigate approximately 75% of the CO2 emissions released from burning the produced oil. By incorporating zero-carbon electricity throughout the process, the total abatement of CO2 can reach 85%. Furthermore, the study highlights the importance of improving the DME utilization factor (bbl-oil/tDME). By optimizing this factor, high abatement rates can be achieved. However, it is important to note that implementing this method comes with a high exergetic cost. During a certain period in the field’s lifetime, the invested energy exceeds the energy produced. The stages with the highest exergy consumption are CO2 capture and hydrogen production.
In various regions globally, societal pressure to transition away from fossil fuels and reduce carbon or greenhouse gas emissions has intensified. Consequently, there is a prevalent inclination to diminish the focus on petroleum engineering education and technological development. In this article, we elucidate the similarities between petroleum engineering and subsurface engineering as they pertain to the energy transition. First, we list ongoing subsurface research initiatives related to the energy transition, which includes projects focused on CO2 and hydrogen storage, geothermal energy, and metal extraction. We outline the main similarities between these processes and conventional oil and gas extraction. Next, we conduct an analysis of the expertise required for these projects. This analysis will cover the specific skills and knowledge needed to successfully implement and manage these initiatives. We discuss how these requirements are like those needed for traditional oil and gas extraction. In the fields of geophysics and surveillance, a significant shift has already been observed towards supporting the energy transition. However, more traditional disciplines such as petroleum engineering, which encompasses geochemistry, production chemistry, reservoir engineering, and production engineering, have not progressed at the same pace. This lag can be attributed partly to the "fossil" reputation associated with petroleum engineering and partly to the limited number of operational subsurface transition projects that have highlighted the deficiencies in reservoir, production, and geochemical/production chemistry engineering. Another contributing factor to the scarcity of work in this area is the prevailing perception that water injection and production (as in geothermal energy and pressure management) and storage (of CO2, H2, heat, or energy) are relatively straightforward single-phase problems. Hydrocarbon reservoirs, however, offer significant opportunities for rapid storage solutions. Furthermore, experience with gas injection, thermal and water-flood projects has revealed several potential issues that require meticulous attention to mitigate risks associated with the often-marginal energy transition projects. In conclusion, we advocate for an enhancement in education and technological development within the domain of subsurface development engineering. It is imperative to maximize the utilization of hydrocarbon technology, leveraging the existing knowledge and experience to facilitate the energy transition. Contrary to prevailing assumptions within industry and governmental bodies, there exists a critical need for education and technological development to optimize the utilization of subsurface resources in an efficient manner for the energy transition.
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In various regions globally, societal pressure to transition away from fossil fuels and reduce carbon or greenhouse gas emissions has intensified. Consequently, there is a prevalent inclination to diminish the focus on petroleum engineering education and technological development. In this article, we elucidate the similarities between petroleum engineering and subsurface engineering as they pertain to the energy transition. First, we list ongoing subsurface research initiatives related to the energy transition, which includes projects focused on CO2 and hydrogen storage, geothermal energy, and metal extraction. We outline the main similarities between these processes and conventional oil and gas extraction. Next, we conduct an analysis of the expertise required for these projects. This analysis will cover the specific skills and knowledge needed to successfully implement and manage these initiatives. We discuss how these requirements are like those needed for traditional oil and gas extraction. In the fields of geophysics and surveillance, a significant shift has already been observed towards supporting the energy transition. However, more traditional disciplines such as petroleum engineering, which encompasses geochemistry, production chemistry, reservoir engineering, and production engineering, have not progressed at the same pace. This lag can be attributed partly to the "fossil" reputation associated with petroleum engineering and partly to the limited number of operational subsurface transition projects that have highlighted the deficiencies in reservoir, production, and geochemical/production chemistry engineering. Another contributing factor to the scarcity of work in this area is the prevailing perception that water injection and production (as in geothermal energy and pressure management) and storage (of CO2, H2, heat, or energy) are relatively straightforward single-phase problems. Hydrocarbon reservoirs, however, offer significant opportunities for rapid storage solutions. Furthermore, experience with gas injection, thermal and water-flood projects has revealed several potential issues that require meticulous attention to mitigate risks associated with the often-marginal energy transition projects. In conclusion, we advocate for an enhancement in education and technological development within the domain of subsurface development engineering. It is imperative to maximize the utilization of hydrocarbon technology, leveraging the existing knowledge and experience to facilitate the energy transition. Contrary to prevailing assumptions within industry and governmental bodies, there exists a critical need for education and technological development to optimize the utilization of subsurface resources in an efficient manner for the energy transition.
Journal article
(2025)
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Christina Chesnokov, Kofi Ohemeng Kyei Prempeh, Rouhi Farajzadeh, Pavel Bedrikovetsky
Joule-Thomson cooling during CO2 injection into low-pressure fields can lead to injectivity impairment due to hydrate formation. This paper presents axial-symmetric flow model, which can be used to predict propagation of temperature and CO2 fronts during CO2 injection into porous formations accounting for Joule-Thomson cooling and unsteady-state delayed heat exchange between the reservoir and the adjacent formations. The solution of the 1D flow is validated by comparing with the quasi 2D analytical heat-conductivity solution. The non-steady state heat exchange results in a temperature front that propagates without limit into the reservoir with time. The temperature profiles exhibit a temperature decrease from the injected temperature to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The solution allows plotting temperature-pressure (T-P) profiles at fixed moments in the CO2-water phase diagram. By changing injection parameters such as injection rate, the T-P trajectories allow for assessment of hydrate formation.
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Joule-Thomson cooling during CO2 injection into low-pressure fields can lead to injectivity impairment due to hydrate formation. This paper presents axial-symmetric flow model, which can be used to predict propagation of temperature and CO2 fronts during CO2 injection into porous formations accounting for Joule-Thomson cooling and unsteady-state delayed heat exchange between the reservoir and the adjacent formations. The solution of the 1D flow is validated by comparing with the quasi 2D analytical heat-conductivity solution. The non-steady state heat exchange results in a temperature front that propagates without limit into the reservoir with time. The temperature profiles exhibit a temperature decrease from the injected temperature to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The solution allows plotting temperature-pressure (T-P) profiles at fixed moments in the CO2-water phase diagram. By changing injection parameters such as injection rate, the T-P trajectories allow for assessment of hydrate formation.
Halite precipitation during CO2 injection can significantly reduce injectivity and impact long-term storage in saline aquifers and depleted reservoirs. However, the impact of geological porous media on salt precipitation and brine movement is not fully undersood. This study explores salt precipitation dynamics from the pore to core scale using microfluidic experiments and core-flooding tests. Microfluidic results reveal three distinct phases of salt deposition: slow evaporation, rapid evaporation, and complete dry-out. Heterogeneous pore structures retain more initial water, leading to localized salt accumulation due to capillary effects. Core-scale experiments show that permeability strongly influences salt penetration and porosity reduction. In high-permeability cores, salt fronts extend deeper into the rock, causing up to 70% porosity reduction. In contrast, heterogeneous cores experience limited salt penetration but increased surface accumulation, suggesting that capillary pressure and brine redistribution control final deposition patterns. These findings highlight the complex interactions between fluid flow, rock properties, and salt crystallization, which provides valuable insights for predicting injectivity loss and optimizing CO2 storage strategies. Understanding these mechanisms is essential for improving reservoir management and ensuring the long-term stability of geological CO2 sequestration projects.
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Halite precipitation during CO2 injection can significantly reduce injectivity and impact long-term storage in saline aquifers and depleted reservoirs. However, the impact of geological porous media on salt precipitation and brine movement is not fully undersood. This study explores salt precipitation dynamics from the pore to core scale using microfluidic experiments and core-flooding tests. Microfluidic results reveal three distinct phases of salt deposition: slow evaporation, rapid evaporation, and complete dry-out. Heterogeneous pore structures retain more initial water, leading to localized salt accumulation due to capillary effects. Core-scale experiments show that permeability strongly influences salt penetration and porosity reduction. In high-permeability cores, salt fronts extend deeper into the rock, causing up to 70% porosity reduction. In contrast, heterogeneous cores experience limited salt penetration but increased surface accumulation, suggesting that capillary pressure and brine redistribution control final deposition patterns. These findings highlight the complex interactions between fluid flow, rock properties, and salt crystallization, which provides valuable insights for predicting injectivity loss and optimizing CO2 storage strategies. Understanding these mechanisms is essential for improving reservoir management and ensuring the long-term stability of geological CO2 sequestration projects.
Near-wellbore hydrate effect on CO2 injection
Insights from microfluidics and core flood experiments
Understanding CO2 hydrate formation near the injection wellbore is critical for improving the safety and efficiency of geological CO2 storage. Hydrate formation can significantly reduce rock permeability and impair injection performance, yet its pore-scale behavior and impact under realistic reservoir conditions remain insufficiently understood. This study combined microfluidic and core-flood experiments to investigate hydrate morphology, formation dynamics, and their effects on injectivity. Microfluidic chips with well-characterized pore structures were used to directly observe hydrate structures under gaseous and liquid CO2 phases, which reveal eight distinct morphologies, including pore-filling, load-bearing, cementing, grain-coating, patchy, worm-like, laminated-like, and banded-like forms where resulted in hydrate saturations reaching up to 15%. Complementary core-flood experiments on rock samples with permeabilities ranging from 0.004 to 2 Darcy employed high-resolution X-ray CT imaging to monitor CO2 and water saturations dynamically. Results indicated that lower permeability cores showed faster hydrate formation and higher saturation increases (up to 16%), which is consistent with microfluidic findings. This multi-scale experimental approach provides deeper insight into hydrate behavior under field-relevant conditions and its influence on CO2 injectivity and offers valuable guidance for optimizing injection strategies in geological carbon storage.
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Understanding CO2 hydrate formation near the injection wellbore is critical for improving the safety and efficiency of geological CO2 storage. Hydrate formation can significantly reduce rock permeability and impair injection performance, yet its pore-scale behavior and impact under realistic reservoir conditions remain insufficiently understood. This study combined microfluidic and core-flood experiments to investigate hydrate morphology, formation dynamics, and their effects on injectivity. Microfluidic chips with well-characterized pore structures were used to directly observe hydrate structures under gaseous and liquid CO2 phases, which reveal eight distinct morphologies, including pore-filling, load-bearing, cementing, grain-coating, patchy, worm-like, laminated-like, and banded-like forms where resulted in hydrate saturations reaching up to 15%. Complementary core-flood experiments on rock samples with permeabilities ranging from 0.004 to 2 Darcy employed high-resolution X-ray CT imaging to monitor CO2 and water saturations dynamically. Results indicated that lower permeability cores showed faster hydrate formation and higher saturation increases (up to 16%), which is consistent with microfluidic findings. This multi-scale experimental approach provides deeper insight into hydrate behavior under field-relevant conditions and its influence on CO2 injectivity and offers valuable guidance for optimizing injection strategies in geological carbon storage.
Depleted reservoirs present a substantial opportunity for carbon capture and storage (CCS), boasting an estimated global storage capacity of approximately 675 to 900 gigatons. Their proven seal integrity and familiarity, coupled with reusable infrastructure, make them appealing for CCS initiatives. However, the process of CO2 injection into these reservoirs is not without its complexities. One of the challenges in cold CO2 injection is injectivity impairment due to hydrate formation in the near-wellbore area. The severity of permeability damage due to hydrate formation can be influenced by different mechanisms. One such mechanism is the competition between dry-out and hydrate formation. This study investigates the dynamics between the dry-out front and the cold front during CO2 injection and their impact on hydrate formation. A comprehensive thermal model was developed to simulate a five-phase system, including water, (non-aqueous) liquid (typically, CO2-rich liquid phase), gas, and two solid phases, namely hydrate and salt. The model is designed to simulate the formation and dissociation of hydrate in porous media as well as CO2H2O partitioning. Three distinct water saturation regimes are identified in this numerical study: ahead of the cold front, in the immediate vicinity of the wellbore, and in between these two regions. Ahead of the cold front, water saturation remains at initial (connate) conditions. In the immediate vicinity of the wellbore, complete dry-out occurs, resulting in a water saturation of zero. Between these two regions, there is a partially dried zone with intermediate water saturation levels, which may be influenced by water recondensation due to the Joule-Thomson effect and water evaporation. The study reveals that as the initial reservoir temperature increases, the water saturation in the intermediate zone decreases. At a critical temperature range between 100°C and 140°C, the dry-out front advances faster than the cold front, effectively evaporating water before the cold front arrives. This research provides a novel insight into the interplay between dry-out and hydrate formation during cold CO2 injection. It demonstrates that controlling the dry-out front relative to the cold front can significantly reduce the risk of hydrate formation, offering a new approach to optimizing CO2 injection strategies for CCS applications.
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Depleted reservoirs present a substantial opportunity for carbon capture and storage (CCS), boasting an estimated global storage capacity of approximately 675 to 900 gigatons. Their proven seal integrity and familiarity, coupled with reusable infrastructure, make them appealing for CCS initiatives. However, the process of CO2 injection into these reservoirs is not without its complexities. One of the challenges in cold CO2 injection is injectivity impairment due to hydrate formation in the near-wellbore area. The severity of permeability damage due to hydrate formation can be influenced by different mechanisms. One such mechanism is the competition between dry-out and hydrate formation. This study investigates the dynamics between the dry-out front and the cold front during CO2 injection and their impact on hydrate formation. A comprehensive thermal model was developed to simulate a five-phase system, including water, (non-aqueous) liquid (typically, CO2-rich liquid phase), gas, and two solid phases, namely hydrate and salt. The model is designed to simulate the formation and dissociation of hydrate in porous media as well as CO2H2O partitioning. Three distinct water saturation regimes are identified in this numerical study: ahead of the cold front, in the immediate vicinity of the wellbore, and in between these two regions. Ahead of the cold front, water saturation remains at initial (connate) conditions. In the immediate vicinity of the wellbore, complete dry-out occurs, resulting in a water saturation of zero. Between these two regions, there is a partially dried zone with intermediate water saturation levels, which may be influenced by water recondensation due to the Joule-Thomson effect and water evaporation. The study reveals that as the initial reservoir temperature increases, the water saturation in the intermediate zone decreases. At a critical temperature range between 100°C and 140°C, the dry-out front advances faster than the cold front, effectively evaporating water before the cold front arrives. This research provides a novel insight into the interplay between dry-out and hydrate formation during cold CO2 injection. It demonstrates that controlling the dry-out front relative to the cold front can significantly reduce the risk of hydrate formation, offering a new approach to optimizing CO2 injection strategies for CCS applications.
This study uses the concept of exergy-return on exergy-investment (ERoEI) to evaluate the life-cycle exergetic efficiency and CO₂ intensity (grams CO₂ per MJ of electricity) of (diabatic and adiabatic) compressed air energy storage (CAES) systems. Several CAES configurations are assessed under defined system boundaries, including diabatic systems powered by methane (CH₄) or hydrogen (H2), and adiabatic system with a thermal energy storage (TES) facility.
The results show that conventional (diabatic) CAES system powered by natural gas has the lower exergetic efficiency and higher CO2 intensity compared to adiabatic CAES due to the heat dissipation during compression stage and additional fuel requirements for reheating the air during expansion. Integrating carbon capture and storage (CCS) plant with conventional diabatic CAES can nearly halve the CO₂ intensity for electricity generation although the additional exergy investment for the CCS process reduces the exergetic efficiency of the system. Transitioning to green H2 (produced from low-carbon electricity) as the primary turbine fuel in the diabatic CAES results in a 65–76 % reduction in CO₂ intensity. However, the average exergetic efficiency of system decreases by around 10 %, mainly due to the substantial exergy investment associated with hydrogen production. It is also found that the adiabatic CAES system integrated with TES demonstrates the highest thermodynamic and environmental performance. When 100 % of compression heat is captured and reused during discharge phase, the system reaches ERoEI values up to 61 % with CO2 intensity of 12–26 g CO₂ per MJe.
Disclaimer: The results and performance metrics presented in this study are based on modelled scenarios and literature-derived parameters under defined system boundaries. Actual performance of CAES systems may vary depending on site-specific conditions, technology maturity, and operational configurations. All efficiency values, CO₂ intensity estimates, and comparative assessments should be interpreted within the context of the assumptions and limitations described herein. This study does not constitute a commercial endorsement or performance guarantee. The authors have made every effort to ensure accuracy but accept no liability for decisions made based on this analysis. ...
The results show that conventional (diabatic) CAES system powered by natural gas has the lower exergetic efficiency and higher CO2 intensity compared to adiabatic CAES due to the heat dissipation during compression stage and additional fuel requirements for reheating the air during expansion. Integrating carbon capture and storage (CCS) plant with conventional diabatic CAES can nearly halve the CO₂ intensity for electricity generation although the additional exergy investment for the CCS process reduces the exergetic efficiency of the system. Transitioning to green H2 (produced from low-carbon electricity) as the primary turbine fuel in the diabatic CAES results in a 65–76 % reduction in CO₂ intensity. However, the average exergetic efficiency of system decreases by around 10 %, mainly due to the substantial exergy investment associated with hydrogen production. It is also found that the adiabatic CAES system integrated with TES demonstrates the highest thermodynamic and environmental performance. When 100 % of compression heat is captured and reused during discharge phase, the system reaches ERoEI values up to 61 % with CO2 intensity of 12–26 g CO₂ per MJe.
Disclaimer: The results and performance metrics presented in this study are based on modelled scenarios and literature-derived parameters under defined system boundaries. Actual performance of CAES systems may vary depending on site-specific conditions, technology maturity, and operational configurations. All efficiency values, CO₂ intensity estimates, and comparative assessments should be interpreted within the context of the assumptions and limitations described herein. This study does not constitute a commercial endorsement or performance guarantee. The authors have made every effort to ensure accuracy but accept no liability for decisions made based on this analysis. ...
This study uses the concept of exergy-return on exergy-investment (ERoEI) to evaluate the life-cycle exergetic efficiency and CO₂ intensity (grams CO₂ per MJ of electricity) of (diabatic and adiabatic) compressed air energy storage (CAES) systems. Several CAES configurations are assessed under defined system boundaries, including diabatic systems powered by methane (CH₄) or hydrogen (H2), and adiabatic system with a thermal energy storage (TES) facility.
The results show that conventional (diabatic) CAES system powered by natural gas has the lower exergetic efficiency and higher CO2 intensity compared to adiabatic CAES due to the heat dissipation during compression stage and additional fuel requirements for reheating the air during expansion. Integrating carbon capture and storage (CCS) plant with conventional diabatic CAES can nearly halve the CO₂ intensity for electricity generation although the additional exergy investment for the CCS process reduces the exergetic efficiency of the system. Transitioning to green H2 (produced from low-carbon electricity) as the primary turbine fuel in the diabatic CAES results in a 65–76 % reduction in CO₂ intensity. However, the average exergetic efficiency of system decreases by around 10 %, mainly due to the substantial exergy investment associated with hydrogen production. It is also found that the adiabatic CAES system integrated with TES demonstrates the highest thermodynamic and environmental performance. When 100 % of compression heat is captured and reused during discharge phase, the system reaches ERoEI values up to 61 % with CO2 intensity of 12–26 g CO₂ per MJe.
Disclaimer: The results and performance metrics presented in this study are based on modelled scenarios and literature-derived parameters under defined system boundaries. Actual performance of CAES systems may vary depending on site-specific conditions, technology maturity, and operational configurations. All efficiency values, CO₂ intensity estimates, and comparative assessments should be interpreted within the context of the assumptions and limitations described herein. This study does not constitute a commercial endorsement or performance guarantee. The authors have made every effort to ensure accuracy but accept no liability for decisions made based on this analysis.
The results show that conventional (diabatic) CAES system powered by natural gas has the lower exergetic efficiency and higher CO2 intensity compared to adiabatic CAES due to the heat dissipation during compression stage and additional fuel requirements for reheating the air during expansion. Integrating carbon capture and storage (CCS) plant with conventional diabatic CAES can nearly halve the CO₂ intensity for electricity generation although the additional exergy investment for the CCS process reduces the exergetic efficiency of the system. Transitioning to green H2 (produced from low-carbon electricity) as the primary turbine fuel in the diabatic CAES results in a 65–76 % reduction in CO₂ intensity. However, the average exergetic efficiency of system decreases by around 10 %, mainly due to the substantial exergy investment associated with hydrogen production. It is also found that the adiabatic CAES system integrated with TES demonstrates the highest thermodynamic and environmental performance. When 100 % of compression heat is captured and reused during discharge phase, the system reaches ERoEI values up to 61 % with CO2 intensity of 12–26 g CO₂ per MJe.
Disclaimer: The results and performance metrics presented in this study are based on modelled scenarios and literature-derived parameters under defined system boundaries. Actual performance of CAES systems may vary depending on site-specific conditions, technology maturity, and operational configurations. All efficiency values, CO₂ intensity estimates, and comparative assessments should be interpreted within the context of the assumptions and limitations described herein. This study does not constitute a commercial endorsement or performance guarantee. The authors have made every effort to ensure accuracy but accept no liability for decisions made based on this analysis.