Well testing in gas-condensate and volatile oil reservoirs with flowing bottomhole pressure below the saturation pressure creates multiphase flow in the reservoir, resulting in relative permeability reduction and a rate-dependent skin factor. In lean gas condensate reservoirs, the wellbore skin effect calculated using single-phase pseudo-pressures has often been found to be constant or even to decrease with increasing gas rates, instead of increasing as in dry gas reservoirs. This behaviour has been tentatively attributed to capillary number effects compensating for condensate blockage and inertia effects, but no detailed study of this behaviour has appeared in the literature to-date.

This paper investigates wellbore skin behaviours in lean and rich gas condensate reservoirs and in volatile oil reservoirs by using compositional simulation with capillary numbers and non-Darcy flow to generate well test data. It is shown that below saturation pressure, gas condensate well test analyses with single-phase pseudo-pressures and volatile oil well test analyses with pressures do not correctly estimate the rate-independent wellbore skin effects and the non-Darcy flow coefficients, whereas analyses with two-phase pseudo-pressure do, provided that non-Darcy and capillary number effects are included in the two-phase pseudo-pressure calculations. In gas condensate reservoirs below the dew point pressure, the rate independent skin factor and the non-Darcy flow coefficient calculated with two-phase pseudo-pressures are identical to the corresponding values calculated above the dew point pressure with single-phase pseudo-pressures. These simulation results are applied to actual field data.

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