Quantifying the crossover from capillary fingering to viscous fingering in heterogeneous porous media

Studying immiscible fluid displacement patterns can provide a better understanding of displacement processes within heterogeneous porous media, thereby helping improving oil recovery and optimizing geological CO₂ sequestration. As the injection rate of water displacing oil increases and the displacement pattern transits from capillary fingering to viscous fingering, there is a broad crossover zone between the two that can adversely affect the oil displacement efficiency. While previous studies have utilized phase diagrams to investigate the influence of the viscosity ratio and wettability of the crossover zone, fewer have studied the impact of rock heterogeneity. In this study, we created pore network models with varying degrees of heterogeneity to simulate water flooding at different injection rates. Our model quantifies capillary and viscous fingering characteristics while investigating porous media heterogeneity's role in the crossover zone. Analysis of simulation results reveals that a higher characteristic front flow rate within the crossover zone leads to earlier breakthrough and reduced displacement efficiency. Increased heterogeneity in the porous media raises injection-site pressure, lowers water saturation, and elevates the characteristic front flow rate, thereby expanding the extent of crossover zone.