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.

Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO₂, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO₂ sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. We also review the research and field-trial literature on CO₂ foam sweep efficiency, capillary gas trapping in foam, issues involved in surfactant selection for CO₂ foam applications, foam field trials, and the state of the art from laboratory and modelling research on CO₂ foam properties, in order to present the prospects and challenges for foam-assisted CO₂ sequestration. Challenges to foam-assisted CO₂ sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) optimizing injectivity and sweep efficiency in the field-design strategy.

Foam is utilized in enhanced oil recovery and CO₂ sequestration. Surfactant-alternating-gas (SAG) is a preferred approach for placing foam into reservoirs, due to it enhances gas injection and minimizes corrosion in facilities. Our previous studies with similar permeability cores show that during SAG injection, several banks occupy the area near the well where fluid exhibits distinct behaviour. However, underground reservoirs are heterogeneous, often layered. It is crucial to understand the effect of permeability on fluid behaviour and injectivity in a SAG process. In this work, coreflood experiments are conducted in cores with permeabilities ranging from 16 to 2300 mD. We observe the same sequence of banks in cores with different permeabilities. However, the speed at which banks propagate and their overall mobility can vary depending on permeability. At higher permeabilities, the gas-dissolution bank and the forced-imbibition bank progress more rapidly during liquid injection. The total mobilities of both banks decrease with permeability. By utilizing a bank-propagation model, we scale up our experimental findings and compare them to results obtained using the Peaceman equation. Our findings reveal that the liquid injectivity in a SAG foam process is misestimated by conventional simulators based on the Peaceman equation. The lower the formation permeability, the greater the error.

Long-distance propagation of foam is one key to deep gas mobility control for enhanced oil recovery and CO₂ sequestration. It depends on two processes: convection of bubbles and foam generation at the displacement front. Prior studies with N₂ foam show the existence of a critical threshold for foam generation in terms of a minimum pressure gradient or minimum total interstitial velocity, beyond which strong-foam generation is triggered. The same mechanism controls foam propagation. There are few data for or for CO₂ foam. We extend previous studies to quantify and for CO₂ foam generation, and relate and with factors including injected quality (gas volume fraction in the fluids injected) - f_g, surfactant concentration - C_s, and permeability - K. In each experiment, steady pressure gradient, ∇p, is measured at fixed injection rate and quality, with total interstitial velocity, v_t, increasing-then-decreasing in a series of steps. The trigger for strong-foam generation features an abrupt jump in ∇p upon an increase in v_t. In most cases, the data for ∇p as a function of v_t identify three regimes: coarse foam with low ∇p, an abrupt jump in ∇p, and strong foam with high ∇p. The abrupt jump in ∇p upon foam generation demonstrates the existence of and for CO₂ foam. We further show how and scale with f_g, C_s and K. Conditions that stabilize lamellae reduce the values of the thresholds: both and increase with f_g and decrease with increasing C_s or K. Specifically, scales with f_g as (f_g)² and scales as (f_g)⁴, and both and scale with C_s as (C_s)^−0.4. The effect of K on the thresholds for foam generation is greater than the effects of f_g and C_s. Our data in artificial consolidated cores show that scales with K as K⁻² for CO₂ foam, in comparison to K⁻¹ for N₂ foam in unconsolidated sand/bead packs. More data are needed to verify the confidence of these correlations. It is encouraging that in the cores with K = 270 mD or greater is less than 0.17 bar/m (~ 0.75 psi/ft), 2 to 3 orders of magnitude less than for N₂ foam. Such low can be easily attainable throughout a formation. This suggests that: limited ∇p deep in formations is much less of a restriction for long-distance propagation of CO₂ foam than for N₂ foam. Foam propagation could still be challenging in low-K reservoirs (~ 10 bar/m for K = 27 mD). Nevertheless, formation heterogeneity and alternating slug injection of gas and liquid help foam generation and may well reduce the values of. More research is needed to predict long-distance propagation of foam under those conditions.

Microfluidic devices offer unique opportunities to directly observe multiphase flow in porous media. However, as a representation of flow in geological pore networks, conventional microfluidics face several challenges. One is whether steady simultaneous two-phase flow through a two-dimensional network is possible without fluctuating occupancy of the pore constrictions. Flow without fluctuations can occur only if the flow paths of the two phases can cross on the 2D network; this requires that wetting phase can form a bridge across the gap between grains at a pore constriction while non-wetting phase flows through the constriction. We consider the conditions under which this is possible as a function of the local capillary pressure and the geometry of the constriction. Using the Surface Evolver software, we determine conditions for stable interfaces in constricted geometries, the range of capillary pressures at which bridging can occur, and those where the wetting phase would re-invade the constriction to block the flow of the non-wetting phase (“snap-off”). If a constriction is long and either straight or uniformly curved, snap-off occurs at the same capillary pressure as bridging. For constrictions of concave shape, which we represent as constrictions between cylindrical grains, however, we find a range of capillary pressures at which bridging is stable; the range is greater the narrower the diameter of the cylinders (i.e. the more strongly concave the throat) relative to the width of the constriction. For smaller-diameter pillars, the phenomenon of “Roof” snap-off as non-wetting phase invades a downstream pore body, is predicted not to occur.

Upscaling of geothermal properties is necessary given the computational cost of numerical simulations. Nevertheless, accurate upscaling of thermo-physical properties of layers combined in simulation grid blocks has been a long-standing challenge. In stratified porous media, non-uniform velocity between layers combined with transverse thermal conduction across layers causes spreading of the thermal front: thermal Taylor dispersion. Neither effect of heterogeneity is accounted for in conventional upscaling. Based on thermal Taylor dispersion, we develop a new upscaling technique for simulation of geothermal processes in stratified formations. In particular, we derive a model for effective longitudinal thermal diffusivity in the direction of flow, α_eff, to represent this phenomenon in two-layer media. α_eff, accounting for differences in velocity and transverse thermal conduction, is much greater than the thermal diffusivity of the rock itself, leading to a remarkably larger effective dispersion. We define a dimensionless number, N_TC, a ratio of times for longitudinal convection to transverse conduction, as an indicator transverse thermal equilibration of the system during cold-water injection. Both N_TC and α_eff equations are verified by a match to numerical solutions for convection/conduction in two-layer systems. We find that for N_TC > 5, thermal dispersion in the system behaves as a single layer with α_eff This suggests a two-layer medium satisfying N_TC > 5 can be combined into a single layer with an effective longitudinal thermal diffusivity α_eff. Compared with conventional approaches by averaging, the α_eff model provides more accurate upscaling of thermal diffusivity and thus more-accurate prediction of cooling-front breakthrough. In stratified geothermal reservoirs with a sequence of layers, upscaling can be conducted in stages, e.g. combining two layers satisfying the N_TC criterion in each stage. The application of the new technique to upscaling geothermal well-log data will be presented in a companion paper.

Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether inaquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstratedfor foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and thechallenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping,dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geologicaltraps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden.Maximizing storage while minimizing overburden stress in the near term depends on residual trapping inthe swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiencyand capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foamapplications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both propertiesreduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foamgeneration, better injectivity, and better prospects for long-distance foam propagation at low pressuregradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil,as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency whilereducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helpsequalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reducesgravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantagesindicated by laboratory research at the field scale 2) optimizing surfactant performance, while furtherreducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution ofsurfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactantdegrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, eitherthrough pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-designstrategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research onCO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.

Foam is applied in enhanced oil recovery to improve the sweep of injected gas and increase oil recovery, by greatly reducing the mobility of gas. In the laboratory, X-ray computed tomography is commonly used to evaluate the performance of foam in core plugs. However, foam properties, such as bubble size and capillary pressure, are much more difficult to measure. In recent years, microfluidic models have gained much attention because they easily facilitate the imaging study of in-situ foam. However, it is still challenging to estimate capillary pressure, in a model with a uniform depth of etching. In this paper, we report a novel technique to estimate water saturation and capillary pressure of foam in two 1-meter-long model fractures. Both model fractures are made of glass plates. They have different roughness and hydraulic apertures. Unlike microfluidics with uniform depth of etching, our model fractures each has a variation of aperture. We characterize the roughness and represent the aperture distribution of the fracture as a network of pore bodies and pore throats. In this study, foam is pre-generated and then injected into the fractures. The inlet and outlet valves are closed for 24 hr after foam reaches steady-state. We use a high-speed camera to visualize foam in the fractures. We use ImageJ software to analyze foam texture and quantify bubble density, average bubble size and polydispersivity. In addition, we estimate water saturation and capillary pressure by analyzing images in terms of fracture geometry. We found that water in foam resides in locations of narrow aperture, Plateau borders, lamellae between bubbles, and water films on glass walls. Water-filled zones of narrow aperture and Plateau borders account for almost all the water. During the re-distribution of water and gas in static foam, in-flow and out-flow of water must take paths along the network of Plateau borders and water-occupied zones, as they are the only continuous paths for water flow. In both model fractures, the decrease in water saturation coincides with an increase in capillary pressure, as expected. This novel technique of estimation of water saturation and capillary pressure of foam provides insights for studies of foam in naturally fractured reservoirs with complex geometry, where measuring such foam properties is challenging. This analysis is possible because aperture varies along our model fractures, unlike most microfluidic devices. Our technique would also have an application to foam aquifer remediation and CO ₂ sequestration.

Foam injection is a promising means of reducing the relative mobility of gas, and hence improving the sweep efficiency of gas, in CO₂ and H₂ storage, soil-contaminant removal in aquifer remediation, enhanced oil recovery, and matrix-acid well stimulation. Theory (Rossen and Gauglitz, 1990; Ashoori et al., 2012) and experiments (Gauglitz et al., 2002; Yu et al., 2019, 2020) indicate that both foam generation and propagation in steady flow in porous media require the attainment of a sufficiently large superficial velocity or pressure gradient ∇P. Here we examine several foam-simulation models for their ability to represent a minimum velocity, or trigger, for foam generation. We define criteria for representation of such a trigger. For simplicity, we assume a homogeneous porous medium and absence of an oleic phase. We examine the Population-Balance (PB) models of Kam and Rossen (2003) and one of its variants (Kam, 2008), and the PB model of Chen et al. (2010); and the implicit-texture (IT) models in CMG-STARS (Computer Modeling Group, 2017) and of Lotfollahi et al. (2017). Our result show that the PB models of Kam and Rossen and its variant, and the IT models of CMG-STARS and of Lotfollahi et al. do represent a minimum velocity for foam generation. They achieve this by modeling an abrupt decrease in gas mobility with increasing pressure gradient over some range of ∇P. The model of Chen et al. (2010) is based on the model of Kovscek and Radke (1996), which was not intended to represent a trigger for foam generation (Kovscek and Radke, 1993). We cannot say categorically whether it could predict a trigger for any set of model parameter values. Instead, we derive criteria that must be satisfied by the choice of parameters to represent a trigger for foam generation. In simulations of radial foam propagation the STARS foam model predicts that foam propagation fails at the radius at which local ∇P cannot maintain strong foam, not at a greater velocity and ∇P as seen in experiments (Yu et al., 2020). In addition, we identify a fundamental challenge in representing foam generation at the large ∇P at the wellbore in a numerical simulation: conventional simulators do not represent ∇P at the wellbore. Foam generation at the very high superficial velocity at the well radius is not represented in the absence of truly exceptional grid refinement.

Foam is remarkably effective in the mobility control of gas injection for enhanced oil recovery (EOR) processes and CO₂ sequestration. Our goal is to better understand immiscible three-phase foam displacement with oil in porous media. In particular, we investigate (i) the displacement as a function of initial (I) and injection (J) conditions and (ii) the effect of improved foam tolerance to oil on the displacement and propagation of foam and oil banks. We apply three-phase fractional-flow theory combined with the wave-curve method (WCM) to find the analytical solutions for foam-oil displacements. An n-dimensional Riemann problem solver is used to solve analytically for the composition path for any combination of J and I on the ternary phase diagram and for velocities of the saturations along the path. We then translate the saturations and associated velocities along a displacement path to saturation distributions as a function of time and space. Physical insights are derived from the analytical solutions on two key aspects: the dependence of the displacement on combinations of J and I and the effects of improved oil-tolerance of the surfactant formulation on composition paths, foam-bank propagation and oil displacement. The foam-oil displacement paths are determined for four scenarios, with representative combinations of J and I that each sustains or kills foam. Only an injection condition J that provides stable foam in the presence of oil yields a desirable displacement path, featuring low-mobility fluids upstream displacing high-mobility fluids downstream. Enhancing foam tolerance to oil, e.g. by improving surfactant formulations, accelerates foam-bank propagation and oil production, and also increases oil recovery. Also, we find a contradiction between analytical and numerical solutions. In analytical solutions, oil saturation (S_o) in the oil bank is never greater than the upper-limiting oil saturation for stable foam (fmoil in our model). Nevertheless, in numerical simulations, S_o may exceed the oil saturation that kills foam in the oil bank ahead of the foam region, reflecting a numerical artifact. This contradiction between the two may arise from the calculation of pressure and pressure gradient using neighboring grid blocks in a numerical simulation. The analytical solutions we present can be a valuable reference for laboratory investigation and field design of foam for gas mobility control in the presence of oil. More significantly, the analytical solutions, which are free of numerical artifacts, can be used as a benchmark to calibrate numerical simulators for simulating foam EOR and CO2 storage processes.

CO₂-foam injection is a promising technology for reducing gas mobility and increasing trapping within the swept region in deep brine aquifers. In this work, a consistent thermodynamic model based on a combination of the Peng-Robinson equation of state (PR EOS) for gas components with an activity model for the aqueous phase is implemented to accurately describe the complex phase-behavior of the CO₂-brine system. The phase-behavior module is combined with the representation of foam by an implicit-texture (IT) model with two flow regimes. This combination can accurately capture the complicated dynamics of miscible CO₂ foam at various stages of the sequestration process. The Operator-Based Linearization (OBL) approach is applied to improve the efficiency of the highly nonlinear CO₂-foam problem by transforming the discretized nonlinear conservation equations into a quasi-linear form based on state-dependent operators. We first validate our simulation results for enhanced CO₂ dissolution in a small domain with and without the presence of a capillary transition zone (CTZ). Then a 3D unstructured reservoir is used to examine CO₂-foam behavior and its effects on CO₂ storage. Simulation studies show good agreement with analytical solutions in both cases with and without CTZ. Besides, the presence of a CTZ enhances the CO₂ dissolution rate in brine. Foam simulations show that foams can reduce gas mobility effectively by trapping gas bubbles and inhibit CO₂ from migrating upward in the presence of gravity, which in turn improves the sweep efficiency and opens the unswept region for CO₂ storage. In the long run (post-injection), with the increasing effects of dissolution, the mechanism of residual trapping, due to the presence of foam, may not be significant. This work suggests a possible strategy to develop an efficient CO₂ storage technology.

Foam injection is one efficient way to mitigate gravity segregation during CO2 injection into porous media. The effect of gravity segregation on foam propagation in heterogeneous porous media is not yet fully resolved. To assess CO2 foam transport for enhanced oil recovery (EOR) and for CO2 storage processes in heterogeneous reservoirs, an accurate prediction of foam behavior is essential. In this study, we investigate the effect of heterogeneity on gravity segregation in the presence of foam. For nonlinear analysis, we use an extension of an Operator-Based Linearization (OBL) approach proposed recently. The OBL approach helps to reduce the nonlinearity of complex physical problems by transforming the discretized nonlinear conservation equations into a quasi-linear form based on state-dependent physical operators. The state-dependent operators are approximated by discrete representation on a uniform mesh in parameter space. In our study, foam in porous media is described using an implicit-Texture (IT) foam model with two flow regimes. We first validate the numerical accuracy of the foam simulation with OBL by comparing segregation length using the IT foam model with Newtonian rheology to analytical solutions. Next, the foam-model parameters are fit to foam-quality scan data for four sandstone formations ranging in permeability by an order of magnitude using a least-squares optimization approach. We then construct several hypothetical models containing two communicating layers with different permeability and thickness ratios to examine foam s effect on gravity segregation. The numerical results of the segregation length in homogeneous domains show good agreement with analytical solutions, except in a transition zone beneath the override zone which is not included in the analytical model. Through fractional-flow theory, we find that the transition zone is not a numerical artefact, but caused by low gas relative-mobility during the transient displacement process. Permeability affects both the mobility reduction of wet foam in the low-quality regime and the limiting capillary pressure at which foam collapses. Thus the segregation length varies with permeability and foam strength. In two-layer models, the thickness of the top layer plays an important role in the ultimate segregation length. A thin top layer does not affect segregation in the bottom layer, while a thicker top layer dominates the segregation length, with less influence of the bottom layer.