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.

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.

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.

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.

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.

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.

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.

Carbon dioxide capture and storage in subsurface geological formations is a potential solution to limit anthropogenic CO₂ emissions and combat global warming. Depleted gas fields offer significant CO₂ storage volumes; however, injection of CO₂ into these reservoirs poses some potential challenges for the injectivity, containment and well/facility integrity due to low temperatures caused by isenthalpic expansion of CO₂. A key injectivity risk is due to possible formation of hydrates at the low expected temperatures. This study aims to address main causes of CO₂ hydrate formation and its impact on permeability of porous media. This review highlights the current state of knowledge in the literature while emphasizing the need to bridge existing gaps in derisking CO₂ injection into (depleted) low-pressure gas reservoirs. In summary, according to the existing literature, the potential for hydrate formation is assessed to be credible. Current industry solutions exist to manage this risk; however, they are costly and energy intensive. Future research will be needed to provide capabilities to manage this risk more efficiently.