Effect of Viscosity Ratio on Relative Permeability (includes associated paper 1496-G)

Abstract

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 346–353.Additional discussion published in Journal of Petroleum Technology, Volume 12, Number 11, November, 1960, pages 65–66. Abstract The mechanism of two-phase flow in porous media has been a subject of wide controversy. One of the properties essential for understanding the dynamic behavior of two phase flow is relative permeability. Relative permeability to a certain phase is defined as the ratio of the effective permeability of that phase to its permeability when it is the only fluid present and flowing. In this research, a theoretical analysis was made to determine the effect of viscosity ratio between the non-wetting and the wetting phase on relative permeability. Experimental work was conducted to test the validity of the derived equations. The experiment was conducted on four natural cores. Four oils were used as the non-wetting phases with a viscosity range of 0.42 to 71.30 cp and two wetting phases with a viscosity range of 0.86 to 0.96 cp. Oil and brine were made to flow simultaneously at various ratios, and relative permeability curves were constructed. A total of eight relative permeability cycles representing eight viscosity ratios were run on each sample. It was found that relative permeability to the nonwetting phase varies with viscosity ratio. The relative effect of this variation on relative permeability values was a function of the sample's single-phase permeability, decreasing with its increase. It was concluded that, for samples of single-phase permeability over 1 darcy, the effect of viscosity ratio could be disregarded, and relative permeability would be, in effect, a function of saturation only. Introduction Two-phase as well as multiphase flow occurs in many fields of science. This type of flow is of particular interest in petroleum production. The knowledge of relative permeability, which describes the dynamic behavior of two-phase as well as multiphase flow, is essential for solution of problems arising in that field. The relative permeability of a porous medium to a given phase in multiphase flow, is generally considered to be only a function of the saturation of that phase, independent of the properties of fluids involved and ranging in value from zero to unity. Work by Leverett and Leverett and Lewis apparently supports this concept. In his experiments Leverett used a clean, packed unconsolidated sand of high permeability (3.2 to 6.2 darcies) with two phases (water and oil) flowing and a viscosity ratio range of 0.057 to 90.0. His results showed that the wide range of viscosity had practically no effect on relative permeability-saturation relationship.