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Because of the strong random distribution of fractures and caves, fault-solution carbonate reservoirs exhibit significantly different flow mechanisms and development methods from conventional carbonate reservoirs. Natural elastic and edge-bottom water flooding are the main processes for developing fault-solution reservoirs. The rapid decline in production and the complex residual oil distribution are major challenges for oil production. This study is aimed at (1) assessing the residual oil migration law, (2) determining the residual oil distribution characteristics, and (3) identifying the main controlling factors using numerical simulation, to provide suggestions for enhancing oil recovery. The results showed that fractures are the main channel for oil flow and the main path of bottom water coning in the fault-solution reservoirs. The channeling of bottom water along high-angle fractures is the main reason for the decline in oil production. In addition, bottom water coning and gas/water injection are the key factors affecting the distribution of residual oil, while the irregular development of fractures and caves is the main factor causing diversified distribution patterns of the residual oil. The residual oil distribution patterns of fault-solution reservoirs include 4 types, namely, attic, bottom water rising and blocking, separated fracture-cavity, and pores near high-conductivity channel types. For tapping the potential of residual oil, several approaches can be used, namely, deploying new wells or using sidetracking of old wells in the loft and the separated fracture-cavity reservoirs. In addition, the attic residual oil type can also be developed using drainage oil recovery or gas injection for oil replacement. Liquid lift pump, water shutoff, and water cone restrain can also be used to tap residual oil from rising bottom water. Optimizing profile control and water shutoff measures and adjusting the injection and production relationship can be effective approaches for developing residual oil in the pores and cracks beside the high diversion channel.

A fractured-vuggy carbonate reservoir is a special reservoir formed by long-term physical, chemical, and geological processes. Its reserves are large in scale and widely distributed, showing the characteristics of free flow-seepage coupling. Conventional simulation is usually simplified by equivalent permeability, which cannot reflect the actual development characteristics. Given this, the flow in caves and fractures is treated with free flow, using the Navier–Stokes equation. The seepage simulation is used for other areas, and the Darcy formula is used. Finally, the simulation results are obtained by coupling, and the influence of oil production speed, fracture-cavity size, fracture-cavity location, dynamic viscosity, permeability, and other factors on bottom pressure is analyzed to effectively guide the field development. The results show that the production pressure of fractured-vuggy reservoirs diffuses from the central fractured-vuggy area to the surrounding matrix, and the pressure increases from the fractured-vuggy area to the surrounding matrix. The flow velocity in the seepage area is relatively stable and flows gently into the middle fracture cavity from all directions. There will be eddy current in the free-flow area. Different factors have different effects on the development. The oil production speed and oil dynamic viscosity are positively correlated with it, while the formation permeability is negatively correlated with it. The size and location distribution of fracture cavity will also have a certain impact. Simulation in advance can effectively avoid some reservoir development problems.