Mechanistic Modeling of Pseudo-Single-Phase Flow in Gas Condensate Reservoirs

Abstract Multiphase flow in gas condensate reservoirs differs significantly from black oil reservoirs due to the presence of immobile condensate and the complex interaction of viscous, capillary, and gravity forces. Recent studies have identified a pseudo-single-phase flow region where the condensate is fog-like (aerosols). This flow behavior alters the condensate saturation profile, making accurate flow prediction challenging. A mechanistic model was developed to represent flow in this region and its impact on well productivity. The relative permeability of gas and condensate phases was defined as a function of the trapping number, which accounts for the balance of the forces that control the flow behavior. The trapping number (TN), expressed as the ratio of the bond number (TBN) to a correction factor (τ), was used to model relative permeability at the reservoir scale. Results show that buoyancy forces dominate in the pseudo-single-phase region, decreasing the size of the condensate bank by 0.15% to 28.48% for corrections parameters(τ) in the ranges of 0.25 to 4. At higher correction values, well productivity increased by 4.3%. However, scenario modeling showed that a high trapping number does not always enhance well productivity. This is because the mobile condensate in the pseudo-single-phase region can become trapped near the wellbore, where capillary forces dominate, causing permeability damage and productivity loss. Hence, the understanding flow in the pseudo-single-phase region is essential for managing condensate banks and optimizing well productivity in gas condensate reservoirs.