The spatial structural characteristics of fractured-vuggy units vary greatly in different karst patterns, which significantly influence the study of remaining oil distribution patterns in ultra-deep fractured-vuggy reservoirs and the determination of the most efficient development strategies. However, few numerical simulation studies have focused on improving water and gas injection in fractured-vuggy reservoirs by considering the effect of karst patterns. By taking a typical fractured-vuggy reservoir in C oilfield in Tarim Basin, China as an example, the development dynamic characteristics of eight typical fractured-vuggy units in three different karst patterns are analyzed, and based on the newly proposed numerical simulation method of fluid vertical equilibrium, the residual oil reservoir distribution in different karst pattern fractured-vuggy units are studied, and the effects of fracture-vuggy karst patterns on the development characteristics, on the remaining oil morphology pattern, on the development strategies, and on the injection-production parameters are explored. This study shows that for different karst patterns fractured-vuggy units, the complexity of spatial structure, reserve scale, and oil-water relationship aggravates the heterogeneity of reservoirs and results in substantial differences in the development of dynamic patterns. In the northern facing karst fractured-vuggy units, there are two main types of remaining oil: well-spacing type and local-blocking type, and the reasonable development strategies are affected by reservoir morphology and the connectivity of structure patterns. Attic-type remaining oil mainly occurs in platform margin overlay and fault-controlled karst fractured-vuggy units. In the southern fault-controlled karst area, the remaining oil is mostly found along the upper part, and periodic gas injection or N₂ huff-n-puff is recommended with priority for potential tapping. The fractured-vuggy karst patterns show a significant influence on the optimal level of injection-production parameters for improving the development of gas injection development strategies. The ideas of improving water injection and gas injection for fracture-vuggy reservoirs proposed in this paper also provide a good reference to further improve water control and increase oil production in other similar carbonate reservoirs.

Gravity segregation is a critical phenomenon in thick condensate gas reservoirs, significantly influencing fluid composition and phase behavior. Reservoir-scale numerical simulation, serving as an indispensable technical approach in modern petroleum engineering, provides both quantitative data support and theoretical frameworks for development strategy optimization. However, the impact of gravity segregation on the distribution of initial fluid compositions is often overlooked in conventional numerical simulations due to data limitations or underestimated importance. This oversight leads to systematic deviations between simulated reservoir performance and actual field observations, ultimately compromising the efficient development of reservoirs. This study analyzed PVT data from reservoir fluid samples at different depths to determine the initial fluid composition distribution. Two models were developed: one incorporating gravity segregation and another neglecting it, to evaluate their performance during gas injection. Key findings include: (i) Gravity segregation alters the initial fluid composition, creating lighter components near the reservoir top and heavier ones at the bottom, resulting in distinct phase behaviors and production dynamics. (ii) The model accounting for gravity segregation aligns better with historical production data, while the model neglecting it underestimates oil production rates by about 9% and overestimates oil recovery by 2–5% during gas injection, due to inaccurate fluid composition assumptions. (iii) The model without gravity segregation also underestimates differences in oil recovery between injection–production strategies, such as top versus bottom injection. This study highlights the critical role of gravity segregation in reservoir simulation and provides valuable insights for optimizing the development of condensate gas reservoirs with complex fluid distributions. The findings reveal that accounting for gravity segregation in reservoir simulation models through proper initialization of fluid distribution leads to improved simulation accuracy, thereby enabling more precise development strategy design.