Modelling of gas condensate relative permeability and its impact on prediction of reservoir performance

Experimental studies conducted using glass micro-model and steady-state relative permeability measurements on cores of different lithology have shown that the relative permeability of gas-condensate fluid systems is a function of interracial tension (IFT) and flow rate. Experimental tests have demonstrated that, specifically the gas phase relative permeability, could be improved by a reduction in IFT and an increase in the flow rate. Contrary to the widely held view that an increase in the fluid flow rate will introduce inertial effects which reduce the ability of the gas phase to flow, it was demonstrated experimentally that increasing the flow velocity to moderate values produce the opposite effect. Empirical correlations were developed which relate the change of gas-condensate relative permeability to the change in IFT and flow rate. These correlations account for both the coupling (positive) and the inertia (negative) flow rate effects. The reliability of the developed correlations was tested on experimental data collected from more than one hundred and twenty steady-state relative permeability tests conducted using a binary gas-condensate fluid on several different cores. These correlations were incorporated in a commercial compositional simulator (Eclipse 300) and now they are used by researchers and operation engineers alike. Studies have been conducted which all stress the need to take into consideration the role of IFT and flow rate in modelling the flow of gas condensates. Not accounting for the change in relative permeability due to these effects may result in a gross over-estimation of well impairment due to condensate build-up and hence a pessimistic view of well productivity.