Laboratory determination of relative permeability

Abstract

Earlier works have indicated that relative permeabilities are markedly dependent on the saturation, and more recent studies show that the spatial distribution of the phases at a given saturation which will depend upon the mechanism used in introducing the second phase into the system is also a definite variable. Three important mechanisms, viz, capillary-pressure displacement, dynamic displacement, and solution-gas displacement, are recognized. In the capillary-pressure displacement method the core is held in a pressurized rubber sheath. Porous diaphragms in capillary contact with both ends of the core conduct the flow of the wetting phase; whileflowof the non-wetting phase is through openings in the diaphragms. The sample is desatur-ated stepwise by successively increased gas presures. The flow rates are measured at each saturation after the system has reached equilibrium, and after the relative permeability values have been calculated. Theoretical considerations indicate that a porous sample with an even distnbution of capillary sizes would give relative permeability curves quite similar to those reported for unconsolidated sands. However, naturally occuring sandstones usually have uneven size distribution, as can be seen from typical capillary-pressure curves. This unevenness results in deviations from a smooth relative permeability curve. Curves for porous media are shown for oil-gas, for oil-gas and connate water, and for water-gas systems. It is concluded that relative permeabilities are unique for each capillary system and desaturation method, and that results obtained by one method can be applied only with reservations to calculations of field performance for reservoirs in which the type of depletion does not correspond with the method used in the laboratory. This paper presents an apparatus and procedure for the capillary-pressure method of measuring relative permeability.