Understanding the Flow Behavior of Carbon Dioxide in Porous Media: Insights from Innovative Core Modeling and Two-Phase Flow Simulations

Understanding the flow behavior of carbon dioxide (CO2) in porous media is essential for the success of carbon capture, utilization, and storage. Although many models have investigated CO2 flow characteristics based on fluid properties, little attention has been paid to how the complex development and spatial distribution of pores, vugs, and fractures within porous media influence flow behavior. In this study, we developed an innovative core modeling approach by processing the grayscale values of rock particles obtained from micro-CT scanning experiments through conversion, filtering, and interpolation. Using this method, three distinct core models were constructed: porous, vuggy, and fractured. A two-phase flow simulation technique was implemented based on the Volume of Fluid method, leveraging GPU parallel computing to improve computational efficiency. After validating the model’s accuracy through experiments, we conducted simulation studies of CO2-driven water displacement under laboratory conditions (298 K, 0.1 MPa) and supercritical carbon dioxide (scCO2)-driven water displacement under reservoir conditions (354 K, 15 MPa). The results indicate that, under laboratory conditions, CO2 rapidly displaces water along the high-permeability zones formed by fractures in a fractured core, leading to significant water retention in smaller pores. This results in a sharp decline in the relative permeability of water and a very short duration of CO2-water two-phase co-flow. In a vuggy core, CO2 preferentially invades vugs with higher concentrations of mobile fluids, achieving the highest sweep efficiency and the longest two-phase co-flow duration. For a porous core, the residual water saturation and co-flow duration fall between those of the fractured and vuggy cores. Under reservoir conditions, the viscosity ratio of scCO2 to water increases, and their flow follows a liquid-liquid regime. In porous and vuggy cores, the invasion efficiency of scCO2 improves, prolonging the two-phase co-flow stage and displacing more water from corners. However, in fractured cores, the flow behavior of scCO2 and water closely resembles that observed under laboratory conditions, predominantly flowing through fractures with limited penetration into smaller pores. This suggests that temperature, pressure, and fluid properties have minimal impact on two-phase flow in the presence of pronounced preferential flow paths. Unlike conventional core modeling methods, the approach we propose offers a more intuitive and detailed representation of the development and distribution of vugs and fractures within reservoir rocks. It enables the visualization of fluid mobilization on a larger scale, as well as the distribution of residual fluids at microscopic scales. This study holds significant potential for advancing microscopic mechanistic research in gas storage development, oil and gas recovery, and geological CO2 sequestration.