The Tong's Chart is widely used in water flooding performance analysis, but a similar universal chart is lacking for gas injection performance analysis, making it difficult to evaluate the effectiveness of gas flooding and related measures in engineering applications. Through the momentum conservation equation in porous media, under steady-state flow conditions, the flow velocity of gas follows Darcy's fractional flow law, whether in miscible or immiscible flooding. The study indicates that: ① Based on the fundamental theory of gas-liquid fractional flow, and considering the comprehensive effects of capillary pressure, gravity segregation, injection-production driving forces, and reservoir heterogeneity on the stable migration of the gas-liquid interface during gas injection after water flooding in heterogeneous reservoirs, a theoretical chart with strict theoretical significance for analyzing the performance of gas injection after water flooding in heterogeneous reservoirs was derived and established; ② A method and procedure for developing corresponding universal charts for specific reservoirs were proposed. Two distinct case reservoirs—the Layer CⅢ1 of the Donghe Block, Tarim Oilfield and the 4 Oil Group in the X Oilfield, both transitioning from water flooding to gas injection—were selected for detailed comparative analysis. The application of this method achieved favorable results in predicting the performance of both miscible gas-assisted flooding in the top of the Layer C Ⅲ 1 of the Donghe Block, Tarim Oilfield and immiscible gas injection in the top of the 4 Oil Group in the X Oilfield, demonstrating its good universality for different types of gas flooding after water flooding; ③ This chart possesses universal functions similar to those of the Tong's Chart. It can be used to analyze gas injection performance and assess the stability of the gas-liquid interface in gas injection reservoirs, thereby providing guidance for the regulation of gas injection development.

In high-dip-angle reservoirs, the strong intra- and inter-layer heterogeneity combined with pressure propagation between injection and production wells renders top gas injection-assisted gravity drainage prone to trigger instability of the gas-liquid interface. Maintaining the stability of the gas-liquid interface is crucial to enhancing oil recovery from these reservoirs. Focusing on the X oil reservoir, we construct a 2D profile-based physical model with high dip angles. By combining saturation monitoring techniques, we systematically simulate the displacement process of water-to-gas flooding. Based on the analysis of the dimensionless gravity number and capillary number, as well as the visualized gas saturation profiles from 2D physical simulation, we explore the microscopic mechanical mechanisms behind top gas injection-assisted gravity drainage and elucidate the stability mechanisms of the gas-liquid interface. Based on the residual oil distribution after water and gas flooding, we determine the conditions required for stable gas flooding. The results indicate that increasing the formation dip and the injection-production ratio (IPR) can enhance gravitational differentiation and compress the pressure drop funnel, thereby extending the stability period of the gas-liquid interface. The gas flooding process can be divided into three stages: the initial, effective, and gas breakthrough stages. The first two stages are primarily subjected to gravitational differentiation, which drives the upward migration of the gas phase and helps maintain the interface stability. In contrast, the breakthrough stage is governed by viscous forces, which accelerate the fingering expansion and promote the formation of preferential seepage pathways.

This study explores the relationship between gas recovery and water invasion dynamics in carbonate gas reservoirs with varying storage spaces to achieve their efficient exploitation. Using physical simulation experiments on vuggy, fractured, and fractured-vuggy carbonate rock samples taken from gas reservoirs in the Sinian Dengying Formation, Sichuan Basin, we comparatively analyze the water invasion dynamics of these reservoirs, and propose a novel equation for predicting water invasion dynamics: ω = AR^B. The results indicate that the proposed method is highly effective in predicting water invasion in rock samples with different 3D storage space structures, and applicable for both heterogeneous gas reservoirs with bottom water and carbonate gas reservoirs. Furthermore, it provides encouraging prediction results of apparent relative pressure and fitted water invasion volume for both vuggy cores with strong homogeneity and fracturedvuggy cores with extreme heterogeneity. Under identical experimental conditions, carbonate gas reservoirs with varying degrees of heterogeneity exhibit distinct variation in coefficient A (related to gas production rate) and constant B (associated with water invasion intensity) values. For the cores of carbonate gas reservoirs, the extent and connectivity of pores are positively correlated with the producing reserves through water drive. Higer reservoir heterogeneity is associated with a more significant reduction in formation energy and a steeper decline in actual apparent relative pressure during the late stage of reservoir exploitation. Notably, among the tested cores, water body energy produces the least impact on the experimental results of the vuggy cores compared to the fractured and fractured-vuggy cores.