Foam flooding is essential for enhancing oil recovery in fractured vuggy carbonate reservoirs, combining gas flooding's profile control and water flooding's stability. However, strong reservoir heterogeneity leads to problems such as crossflow and poor foam stability, which restrict its effectiveness. This research addresses these challenges by investigating the evolution of foam flow and oil displacement through experiments and simulations. Experimentally, a vertical flat fracture model was constructed to examine the effects of foam quality and fracture openings on layering, exploring stratified flow characteristics in horizontal and vertical orientations. A two-dimensional visual model analyzed the distributions of oil, gas, and water during foam flooding, examining injection parameters, fractured vuggy conditions, and displacement methods. The oil displacement characteristic of the foam stratification in typical fractured vuggy structures was also revealed. Simulations employed the level set method to model the evolution of foam flow and analyze bubble coalescence and deformation through narrow spaces. Research showed that increasing the gas–liquid ratio shifted foam flow in fractures from stratified to bubble flow, achieving maximum stability at a 4:1 ratio. High ratios caused foam compression and gas channeling. Foam filled top spaces in pre-semi-filled caverns and accumulated densely in pre-completely filled caverns, effectively utilizing “attic oil” at a 20° inclination angle. In high permeability areas, foam compression led to gas channeling and reduced oil displacement. Systems with low interfacial tension and high viscosity enhanced stability and displacement, with simulations matching experimental findings. The research provides a theoretical basis for optimizing foam flooding in fractured vuggy reservoirs, which is crucial for advancing deep oil and gas resource development.
Xu et al. (Fri,) studied this question.