| description abstract | Abstract. Foam flooding is an effective enhanced oil recovery method for deep fractured vuggy carbonate reservoirs, but its application is limited by reservoir heterogeneity and foam stability. We systematically investigated the foam flow behavior and displacement characteristics in fractured vuggy carbonate reservoirs through experiments and simulations. A multi-factor fracture visualization model was constructed to characterize the complex reservoir structure, and the displacement and flow characteristics of the foam were investigated. Furthermore, the influence of the gas–liquid ratio and injection flow on the foam sealing effect was analyzed. A foam flow model was established using the level set method, and it simulated the foam drainage and explored the effects of the surface tension, liquid viscosity, and gas properties on the foam stability. The results indicated that the foam preferentially entered low-resistance channels and formed dominant channels to gradually diffuse to the secondary fractures, thus improving the spread range and oil displacement efficiency. Furthermore, the recovery rate in the foam displacement process presented a three-stage trend: the initial slow-increase stage (5–10 min before and after foam injection), the subsequent rapid-rise stage (10–30 min), and the final stable stage (after 30 min). When the surface tension was <0.01 mN/s and the liquid viscosity reached 100 mPa·s, the foam life was the longest, whereas the stability of the carbon dioxide foam was relatively poor. These results provide theoretical support for optimizing foam flooding and identifying flow laws for enhanced oil recovery in deep reservoirs. | |
