How to use relative permeability correlations

A general procedure which honors the most reliable laboratory determined two-phase relative permeability data (end-point relative permeabilities and their corresponding fluid saturations), has been developed to assign relative permeability functions on a permeability distribution basis. Since this approach considers more factual data and involves fewer assumptions, it should provide more meaningful flow characteristics on a reservoir unit basis. A general two-phase relative permeability model which includes water-oil and gas-oil systems has been developed to curve fit the experimentally determined end-point relative permeabilities and their corresponding fluid saturations. A versatile, inexpensive iteration procedure has been proposed to change the shape of the relative curves during the history match. The changes in the shape of the relative curves could be justified due to the uncertainties in rock wettability, saturation history, pore-geometry, and fluid distribution within the reservoir. Although the proposed approach to the relative permeability problem could demand more engineering time during the initial stages of a simulation study, the procedure optimizes both engineering and computing time during the history match phase.