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.

This work uses pilot examples of CO₂ enhanced oil recovery to analyze whether and under which circumstances it is exergetically favorable to sequester CO₂ through enhanced oil recovery. We find that the net storage efficiency (ratio between the stored and captured CO₂) of the carbon capture and storage (CCS)-only projects is maximally 6–56% depending on the fuel used in the power plants. With the current state of technology, the CCS process will re-emit a minimum of 0.43–0.94 kg of CO₂ per kg of CO₂ stored. From thermodynamics point of view, CO₂ enhanced oil recovery (EOR) with CCS option is not sustainable, i.e., during the life cycle of the process more energy is consumed than the energy produced from oil. For the CCS to be efficient in reducing CO₂ levels (1) the exergetic cost of CO₂ separation from flue gas should be reduced, and/or (2) the capture process should not lead to additional carbon emission. Furthermore, we find that the exergy recovery factor of CO₂-EOR depends on the CO₂ utilization factor, which is currently in the low range of 2–4 bbl/tCO₂ based on the field data. Exergetically, CO₂ EOR with storage option produces 30–40% less exergy compared to conventional CO₂ enhanced oil recovery projects with CO₂ supplied from natural sources; however, this leads to storage of >400 kg of extra CO₂ per barrel of oil produced.

This study compares two methods of mobility-control design for chemical enhanced oil recovery processes. Method 1 matches the total relative fluid mobility upstream and downstream of the shock front. In method 2 the viscosity of the displacing agent is selected such that the total mobility at the shock water saturation is equal to or less than the minimum mobility across the saturation range. The two methods are based on fractional flow analysis of one-dimensional flow and they are validated against two-dimensional simulations of flow through heterogeneous permeable media. Our results emphasize the key role of the water/oil relative permeability curves for the design of mobility control in polymer and surfactant/polymer flooding. The polymer viscosity obtained by setting the shock-front mobility ratio to one (method 1) is the minimum viscosity to ensure a stable displacement front. Design by method 2 results in a larger viscosity than method 1. This shifts the shock water saturation to larger values and hence more oil is displaced. Moreover, we find that for surfactant-polymer (SP) solutions with ultra-low interfacial tension (IFT) reduction (Winsor type III), the required polymer viscosity is always greater than the oil viscosity (at low shear rates). However, for Winsor type I solutions, for oils with medium and large viscosity the non-linear shape of the relative permeability function leads to polymer viscosities that are less than that of the oil. For light oils the viscosity of the ASP solution should be significantly larger than the oil viscosity.

Physical adsorption and mechanical entrapment are two major causes of polymer retention in porous media. Physical adsorption is considered an equilibrium process and is often modeled by assuming a Langmuir isotherm. The outcome is a steady state pressure response because the permeability reduction is also accounted for by adsorption. However, some experimental data show gradual increase of pressure with time, implying that polymer retention is a time-dependent process. We discuss simultaneous effect of sorption and mechanical entrapment on the polymer retention in porous media. An exact solution for 1-D flow problem for the case of constant filtration coefficient and Langmuir-sorption isotherm, including explicit formulae for breakthrough concentration and pressure drop across the core is derived. The general model with a varying filtration coefficient was successfully matched with experimental data confirming the occurrence of simultaneous sorption with deep-bed filtration during polymer flow in porous media. In the absence of mechanical entrapment, the physical adsorption causes delay in the polymer front and does not affect the polymer concentration behind the front. Addition of mechanical entrapment results in slow recovery of the injected concentration at the outlet (for a varying filtration coefficient) or reaching to a steady state concentration, which is only a fraction of the injected concentration (for a constant filtration coefficient). Accurate assessment and quantification of the polymer retention requires both pressure and effluent concentration data at the outlet of the porous medium.