The Validation of Methods to Calculate Gas-Oil Relative Permeability Using Capillary Pressure Data from South Pars Reservoir

Abstract

Gas-oil relative permeability is the most important parameter in the simulation of fluid flow in the gas condensate reservoirs. Experimental measurements of relative permeability need core samples with regular shape, which is costly and time consuming. On the other hand, experimental data of relative permeability may also have significant error and uncertainty in many cases. One source of uncertainty is that the input to numerical simulator is uncertain and inaccurate; it may be reduced if the number of input parameters is decreased, especially if the parameters with the greatest uncertainty are avoided. It is possible to impose only capillary pressure data, because relative permeability can be predicted consistently using specific models. The present methods, which are based on capillary pressure, considered the porous media as a bundle of capillary tubes; they indeed are mercury flow paths that are filled during the mercury injection capillary pressure test at the certain value of capillary pressure. The authors applied the existing capillary models for relative permeability calculations to a gas condensate reservoir. The tested samples have a wide range of liquid permeability from less than 1 to 18 md. The results of this study show that the Purcell model has the best fit with experimental data for wetting phase (oil), and the differences between measured and model data were almost negligible. The predictions of nonwetting phase (gas) relative permeability were a good agreement with experimental data except for Purcell model. Results reveal that the relative permeability could be computed by using accurate capillary pressure data.