Compositional pore-network modeling of gas flooding in gas-condensate reservoirs

Resumo

Gas flooding in gas-condensate reservoirs can delay pressure depletion below the dew-point and re-
vaporize accumulated condensate in the near wellbore region. For condensate bank removal, the method’s success

depends on a series of parameters, such as the injected gas composition, the total injected volume, the reservoir
depletion level and the porous medium heterogeneity. In order to investigate the influence of these parameters at

the pore-scale, we used a compositional pore-network model to reproduce gas injection in porous media after con-
densate accumulation. With the model, the effects of complex phase behavior arisen from the interaction between

injected gas and accumulated fluids in the porous medium could be evaluated. The performances of methane,

ethane, carbon dioxide, nitrogen and produced gas flooding to improve flow following condensate banking at dif-
ferent pressure levels were compared. Condensate re-vaporization rate, recovery of heavy components, relative

permeabilities, and final saturations were quantified so that optimal injection scenarios were identified. Results
indicated that the injected gas composition affects significantly condensate banking removal by gas flooding, with
C2 and CO2 being the most favorable candidates among the tested gases for the method. The injection pressure
also affected greatly the results, curtailing the condensate recovery as it was decreased below the dew point.