The Effect of Fluid-Flow Rate and Viscosity on Laboratory Determinations of Oil-Water Relative Permeabilities

Abstract

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 36–43. Abstract The effect of fluid-flow rate and fluid viscosity on oil-water relative permeability determinations was studied using the "dynamic flow technique." In this work relative permeability curves were obtained for homogeneous small core samples from several sandstone outcrop formations. Radio-tracers were used for the determination of fluid saturation and for the detection of saturation gradients. Cobalt–60 in the form of cobaltous chloride was used as a water-phase tracer in some of the experiments. Iodine–131 in the form of iodobenzene and Mercury–203 in the form of mercury diphenyl were used as oil-phase tracers in other experiments. Flow rates for each phase were varied within a range of 2.5 to 140.6 ml/hr. Oil-phase viscosities under flowing conditions were varied from 0.398 to 1.683 cp. The relative permeabilities obtained were found to be solely a function of saturation and independent of flow rate, provided there was no saturation gradient induced in the core sample by "boundary effect." Even though equilibrium with respect to flowing conditions was obtained at the lower flow rates, where a saturation gradient exists, this equilibrium is of a "contingent" -type rather than the "steady-state" equilibrium implicit in the relative permeability concept. The only effect of increasing the oil or non-wetting phase viscosity was to decrease the flow rate required for the elimination of the boundary effect. Fairly good agreement between experimentally determined and calculated values of the boundary effect was obtained when the non-wetting oil phase was the only flowing phase. Introduction In the characterization of reservoir rock, as well as in the solution of reservoir production problems, it is most desirable to have reliable relative permeability measurements for the rock and fluids of interest. Many techniques have been developed for the laboratory determination of the relative permeability of both large and small core samples. In varying degree, difficulties attend the use of all of the methods. Each of the methods requires the metered flow of fluids of known viscosity through the core sample under conditions wherein the pressure drop in the individual flowing phases can be measured or closely approximated. Since the relative permeability is a function of the saturation and distribution of the flowing fluids, some means of obtaining such information is also required.