Modeling relative permeability effects in gas-condensate reservoirs

Many gas condensate wells show a significant decrease in productivity once the pressure falls below the dew point pressure. This significantly decreases the productivity of very high rate gas wells in many of the world's largest hydrocarbon reservoirs. A widely accepted cause of this decrease in productivity index (PI) is the decrease in gas relative permeability due to build up of condensate in the near wellbore region. Predictions of well inflow performance require accurate models for the gas relative permeability as a function of interfacial tension (IFT) between the gas and condensate phases (actually it should be trapping number rather than IFT). Since these relative permeabilities depend on fluid composition and pressure as well as condensate and water saturations, a model is essential for both interpretation of lab data and for predictive field simulations. The key to such a gas condensate relative permeability model is the dependence of the critical condensate saturation on the capillary number or its generalization called the trapping number. We have made careful comparisons of such data with a capillary trapping model and have found that we can match these data with a simple two-parameter model. We then developed a general scheme for computing the gas and condensate relative permeabilities as a function of the capillary trapping model and with only data at low trapping number (high IFT) as input and have found good agreement with the experimental data in the literature. We then used this model and typical parameters for gas condensates in a compositional simulation study of a single well to better understand the PI behavior of the well and the significance of the condensate buildup.