Comparative Well-Test Behaviours in Low-Permeability Lean, Medium-Rich, and Rich Gas-Condensate Reservoirs

Abstract

Abstract Large condensate banks develop around producing wells in gas-condensate reservoirs when pressure drops below the dew point pressure, inducing severe losses of productivity. Actual well test behaviours depend on fluid composition, formation permeability and production rates. Several publications have presented well test behaviours in high permeability lean and rich gas-condensate reservoirs. This paper investigates well test behaviours below the dew point pressure in low permeability lean, medium-rich and rich gascondensate reservoirs using 3-D compositional simulation. It is shown that during a drawdown below the dew point pressure, medium-rich to rich gas-condensate fluids in the condensate bank change to near critical fluid near the wellbore. If such a drawdown is followed by a shut-in where the pressure builds up above the saturation pressure, the oil revaporizes completely and the fluid in the wellbore vicinity becomes single-phase gas again. This does not occur in lean gas reservoirs, where the condensate saturations at the end of a drawdown and in the subsequent build up are very similar. Another difference is that lean and medium-rich gas-condensate fluids yield three mobility zones on a derivative plot corresponding to: (1) the original gas in place away from the well where the pressure is above the dew point pressure; (2) the condensate bank closer to the well; and (3) capillary number effects in the immediate vicinity of the well. By contrast, only two mobility zones are created in the case of rich gas-condensate fluids (capillary number effects are not seen in practice). The understanding of pressure behaviour in low permeability, gas-condensate reservoirs developed in this paper was applied to actual well test data from a South Coast Gas field located offshore South Africa and helped optimize well performance and reservoir management strategies in that field.