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.

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.

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.

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.

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.

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.

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.

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.

The gas displacement in porous media is a crucial process with extensive industrial and environmental applications. A notable example is underground hydrogen storage, where it is important to understand hydrogen mixing with cushion gas. The current paper explores anomalies in dispersion behaviour of gas mixtures under opposing flow directions (injection and production) from a modelling perspective. Due to the gaseous nature of the system, it presents significant complexities due to non-ideal mixing, compressibility, and higher diffusivity compared to Newtonian fluid transport. The findings reveal distinct dispersion behaviour during injection and production, where augmenting the mixture non-ideality enhanced the non-unique behaviour. In contrast to the dispersivity seen in Newtonian fluid flow in porous media, our research identifies that dispersivity in gas displacement depends not only on the porous medium but also on the gaseous components’ properties.

Gas hydrates are crystalline compounds of water and small guest molecules, relevant both as a hazard in hydrocarbon production and CO2 sequestration, and as a potential energy resource in natural reservoirs. This work presents a kinetic simulation model for hydrate formation and dissociation in porous media, implemented using the Operator-Based Linearization (OBL) technique. We verify thermodynamic assumptions through Gibbs energy analysis, showing consistency between kinetic and equilibrium reaction models. The framework is validated against literature on methane hydrates and can be extended to CO2 systems. Applications are demonstrated at core and field scales, including gas production by depressurization and thermal stimulation. Results highlight the strong influence of kinetic parameters on hydrate behavior, underscoring the importance of selecting appropriate reaction models for accurate physical and numerical predictions.

The global energy transition requires novel carbon utilization methods to enable integrated and optimized low-carbon energy production. Coupling CO₂-based geothermal energy extraction with CO₂-enhanced oil recovery (EOR) represents a promising yet largely unexplored approach for improving resource efficiency and carbon sequestration. This study investigates the integration of CO₂-Plume Geothermal (CPG) energy production with CO₂-EOR in mature oil reservoirs using numerical simulations of conceptual heterogeneous reservoir models. The interplay between EOR and CPG performance in terms of energy production and CO₂ storage is evaluated and compared to understand the geotechnical implications of this integration. The analysis highlights that initiating CPG operations after EOR significantly benefits from the established CO₂ plume, facilitating immediate and efficient geothermal energy extraction. Results show that integrating CPG with EOR increases total energy recovery by 20%–50% relative to the energy produced by EOR alone, yielding CPG thermal power outputs ranging from 13 to 23 MW_th/km². Continued CO₂ injection during CPG operations further increases total CO₂ storage by 80%–280%, driven primarily by improved volumetric sweep of previously unswept reservoir volumes and enhanced CO₂ density resulting from reservoir cooling. While reservoir heterogeneity strongly influences oil recovery during EOR, its effect on CPG thermal output is less pronounced, since native reservoir fluids (oil and brine) have already been largely displaced during the EOR stage, and the CO₂ plume gradually stabilizes over time. These findings demonstrate the viability and advantages of integrated CO₂-EOR and CPG systems, offering insights into novel methods essential for sustainable subsurface resource management and climate-change mitigation.

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.

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.

Fluid dispersion directly influences the transport, mixing, and efficiency of hydrogen storage in depleted gas reservoirs. Pore structure parameters, such as pore size, throat geometry, and connectivity, influence the complexity of flow pathways and the interplay between advective and diffusive transport mechanisms. Hence, these factors are critical for predicting and controlling flow behavior in the reservoirs. Despite its importance, the relationship between pore structure and dispersion remains poorly quantified, particularly under elevated flow conditions. To address this gap, this study employs pore network modeling (PNM) to investigate the influence of sandstone and carbonate structures on fluid flow properties at the micro-scale. Eleven rock samples, comprising seven sandstone and four carbonate, were analyzed. Pore network extraction from CT images was used to obtain detailed pore structure parameters and their statistical measures. Pore-scale simulations were conducted across 60 scenarios with varying average interstitial velocities and water as the injected fluid. Effluent hydrogen concentrations were measured to generate elution curves as a function of injected pore volumes (PV). This approach enables the assessment of the relationship between the dispersion coefficient and pore structure parameters across all rock samples at consistent average interstitial velocities. Additionally, dispersivity and n-exponent values were calculated and correlated with pore structure parameters.

To achieve effective long-term CO2 storage in saline aquifers, it is essential to understand and monitor CO2 distribution and trapping mechanisms, which are significantly influenced by groundwater flow. This study investigates the impact of background flow velocity and direction on CO2 plume behavior and different trapping mechanisms (residual and solubility) using numerical analysis. The results of simulation show that in the flat (0° dip) model, increasing background flow velocity significantly extends the plume migration distance, enhancing both solubility and residual trapping through a larger CO2-water contact area and increased pore space occupation. The analysis is further extended to a dipping aquifer scenario to assess the role of groundwater flow direction. In the co-current flow case, where water and CO2 move in the same direction, the plume attains its maximum lateral extension, resulting in the highest storage efficiency. Conversely, in the counter-current flow scenario, where CO2 and water move in opposite directions, lower CO2 trapping is observed because, particularly at high velocity, the drag force exerted by water overcomes buoyancy force and limits further plume extension.

Depleted gas reservoirs are viable choices for large-scale CO₂ storage and to displace remaining methane volumes to further increase the storage capacity (EGR). However, deployment of such projects depends on an informed knowledge of the magnitude of mixing of the miscible gases, efficiency in displacing in-situ methane by CO₂, composition of the produced gas, and CO₂ storage capacity. This study focuses on the fundamental analysis of mixing during CO₂-EGR using a numerical approach. We propose to conduct very fine grid compositional simulations to provide insights into the mixing of CO₂ and methane in a gas reservoir at different reservoir and operational conditions. We first analyze a stratified layer model to understand the basic mechanisms of scale-dependency of dispersion and the significance of reservoir heterogeneity on fluid mixing. To consider more realistic reservoir heterogeneity, a two-dimensional stochastic reservoir model is analyzed to estimate dispersivity generated as fluids flow in porous media at different scales. Reservoir heterogeneity is represented by the Dykstra Parsons coefficient (V_DP) and autocorrelation length, and fluid properties are modeled depending on pressure and temperature conditions. Field-scale simulation is also performed to discuss the way dispersion is modeled in reservoir simulation affects simulated gas recovery. Our study shows that the variance of permeability and convective spreading are the primary causes of fluid mixing at any scale. In addition, molecular diffusion is not always negligible in gas mixing even in large-scale heterogeneous reservoirs since gas has much larger diffusivity than liquid. Furthermore, the mechanism of fluid mixing during CO₂-EGR is complex with the interplay between convective spreading, transverse dispersion (including molecular diffusion), and gravity segregation. Although geoscientists often assume numerical dispersion can represent physical dispersion, our study indicates this is an oversimplification and could cause significant errors in calculated gas recovery. Permeability heterogeneity is essential for the dispersion growth process and the final displacement behavior. Reservoir heterogeneity should be modeled with high-resolution grid models to analyze mixing behaviors more accurately.

Injection of high-pressure CO₂ into depleted gas reservoirs can lead to low temperatures promoting formation of hydrate in the near wellbore area resulting in reduced injection rates. The design of effective mitigation methods requires an understanding of the impact of crucial parameters on the formation and dissociation of CO₂ hydrate within the porous medium under flowing conditions. This study investigates the influence of water saturation (ranging from 20% to 40%) on the saturation and kinetics of CO₂ hydrate during continuous CO₂ injection. The experiments were conducted under a medical X-ray computed tomography (CT) to monitor the dynamics of hydrate growth inside the core and to calculate the hydrate saturation profile. The experimental data reveal increase in CO₂ hydrate saturation with increasing water saturation levels. The extent of permeability reduction is strongly dependent on the initial water saturation: beyond a certain water saturation the core is fully blocked. For water saturations representative of the depleted gas fields, although the amount of generated hydrate is not sufficient to fully block the CO₂ flow path, a significant reduction in permeability (approximately 80%) is measured. It is also observed that the volume of water+hydrate phases increases during hydrate formation, indicating a lower-than-water density for CO₂ hydrate. Having a history of hydrate at the same water saturation leads to an increase in CO₂ consumption compared to the primary formation of hydrate, confirming the existence of the water memory effect in porous media.

Hydrogen plays a crucial role in the transition to low-carbon energy systems, especially when integrated into energy storage applications. In this study, the concept of exergy-return on exergy-investment (ERoEI) is applied to investigate the exergetic efficiency (defined as the ratio of useful exergy output to invested exergy input) and CO2 equivalent intensity of the hydrogen supply chain, with a specific focus on the underground hydrogen storage process. Our findings reveal that the overall exergetic efficiency of the electricity-to-hydrogen-to-electricity conversion process can reach up to 25 %. Among the hydrogen production methods, green hydrogen, produced via electrolysis powered by renewable energy, exhibits the lowest CO2 equivalent intensity. Blue hydrogen, produced from natural gas with carbon capture, can significantly reduce the carbon footprint of electricity generation, though this advantage comes at the expense of decreased exergetic efficiency. Analysis further indicates that the exergetic efficiency of underground storage components ranges from 72 % to 92 %. A substantial fraction of the exergy is lost during compression and injection of the stored hydrogen. Nevertheless, the subsurface operations contribute a minimal CO2 emission, between 1.46–4.56 grams of equivalent CO2 per megajoule (gr-CO2eq/MJ) when powered by low-carbon energy sources. Furthermore, it is found that hydrogen loss in the reservoir, along with methane and hydrogen leak during surface operations, notably affects the overall efficiency of the storage process.