Fractured-vuggy carbonate reservoirs differ from conventional reservoirs by exhibiting characteristics such as discontinuous spatial distribution of reservoir bodies, significant variations in effective storage space scale, complex internal structures and fracture-cavity connectivity, heterogeneous oil-water distribution relationships among different reservoir units, and complicated hydrocarbon flow mechanisms. Water flooding and gas injection serve as important methods for efficient development of fractured-vuggy carbonate reservoirs. However, the unclear timing for switching between water flooding and gas injection in fractured-vuggy carbonate reservoirs leads to difficulties in determining the optimal gas injection timing during field gas injection operations. Meanwhile, existing physical simulation models for fractured-vuggy carbonate reservoirs worldwide can only achieve either visualization or high-temperature-high-pressure conditions, resulting in insufficiently comprehensive research perspectives. To address these issues, this study independently developed a high-temperature-high-pressure two-dimensional visual physical model of fractured-vuggy reservoirs based on similarity principles. Using this model, we conducted water flooding and gas displacement experiments to investigate oil-gas-water flow mechanisms during the displacement process in fracture-cavity systems, evaluate the effects of different water-gas switching timings and various water injection positions on displacement efficiency, clarify the relationship between water and gas injection, and determine the optimal gas injection timing and spatial distribution characteristics of remaining oil. The experimental results show that: 1) Through water flooding followed by nitrogen injection experiments in the visual fractured-vuggy model, we confirmed that this method represents an effective development approach for fractured-vuggy reservoirs. Under the synergistic effects of water flooding characteristics and nitrogen gas-cap drive mechanisms, a high displacement efficiency of 67.67% was achieved. 2) Comparative experiments on different injection-production methods demonstrated that during water flooding development of fractured-vuggy reservoirs, the low-injection-high-production method provided larger water flooding sweep area and more effective water flooding performance compared with the high-injection-low-production method, resulting in 2%~4% higher overall displacement efficiency. 3) By comparing oil displacement effects under different nitrogen injection timings, the optimal development method was determined to be low-injection-high-production with nitrogen injection initiated after 1 PV of water flooding, which yielded the highest displacement efficiency. 4) After water flooding development in fractured-vuggy reservoirs, remaining oil primarily distributed as “oil films,” “attic oil,” and “bypassed oil.” Following gas flooding, the main remaining oil distribution patterns were “interfacial oil,” “bypassed oil,” and “oil films.” These research findings contribute to understanding the enhanced oil recovery mechanisms of water and gas injection in fractured-vuggy carbonate reservoirs, clarifying the optimal switching timing and remaining oil distribution patterns, and providing theoretical guidance for optimizing gas flooding development plans and remaining oil potential exploitation in fractured-vuggy reservoirs.