Experimental and numerical simulation of gas injection for enhanced oil recovery in naturally fractured condensate gas reservoirs

Abstract

Gas condensate reservoirs constitute important natural gas resources; however, their development is frequently hindered by condensate banking and complex multiphase flow behavior. Naturally fractured gas condensate reservoirs present additional challenges because their dual-porosity and dual-permeability structure induces strong phase redistribution and nonuniform flow between matrix and fracture systems, thereby complicating reservoir characterization and compositional simulation. In this study, integrated laboratory experiments and numerical simulations were performed for a deep, rich, naturally fractured gas condensate reservoir. Depletion, diffusion, and core flooding experiments involving CO₂, N_2, and dry gas injection were conducted using fractured core samples. A dual-porosity and dual-permeability compositional model incorporating a five-spot well pattern was established to evaluate condensate liquid recovery and to quantify mass transfer between matrix and fracture networks. The effect of matrix-fracture permeability contrast on production performance was systematically analyzed. The results indicate that matrix permeability is a primary parameter controlling recovery in gas condensate reservoirs. The ratio of matrix-fracture permeability contrasts exerts a stronger influence on condensate liquid recovery than on natural gas recovery. Pressure maintenance through gas injection is critical for improving recovery performance. When reservoir pressure declines below the dew-point pressure, early gas injection is recommended to mitigate condensate accumulation in the near-well region. Among the injected gases evaluated, CO₂ demonstrated superior pressure maintenance performance compared with N₂ and dry gas.