Occurrence and Spatial Distribution of CO₂, Heavy Oil, and Water Phases in the Porous Media of Conventional Heavy-Oil Reservoirs

Targeting the problems of fingering and early breakthrough in heavy-oil-water-CO₂ three-phase flow through heterogeneous porous media, we develop a pore-scale three-phase flow model based on image masks. The model employs Corey–Stone II relative permeability and Brooks-Corey capillary pressure, and incorporates capillary-diffusion effects to represent the competition between viscous and capillary forces. We propose two diagnostics: a flux-intensity map and key-instant velocity-field analysis. Results show that, for a fixed geometry, increasing the displacement-pressure gradient markedly raises instantaneous production rate and overall recovery at the same injected pore volume, but it also widens and connects the main pathways, thereby increasing the risks of channelization and early breakthrough; under low pressure gradients, sheet-like trapping and block-like accumulation are prone to occur. When porosity is increased from 0.60 to 0.76, connectivity is enhanced, unswept zones shrink, and recovery improves, although overly high porosity tends to create short-circuit pathways. The model reproduces, on near-realistic pore geometries, the key sequence of front propagation- preferential channeling-breakthrough-residual enrichment, and provides quantitative guidance for the joint optimization of pressure gradient and porosity, as well as for throttle-rate control, mobility control, and distributed-injection design.