| One of the primary goals of any enhanced recovery project is to maximize the ability of the fluids to flow through a porous medium, i.e., the reservoir. The topic of this study is the effect of the capillary number, a dimensionless group describing the ratio of viscous to capillary forces, on two-phase (oil-water) relative permeability curves. Specifically, a series of steady-state measurements were carried out to determine if the capillary number causes changes in the two-phase permeabilities or if any one of its constituents, such as flow velocity, fluid viscosity, or interfacial tension, are the controlling variables.;It was found that the non-wetting phase (oil) relative permeability shows no correlation with the capillary number. As the interfacial tension decreased below 2.0 dyne/cm, the oil permeability increased dramatically. However, as the wetting phase viscosity increased, the non-wetting phase demonstrated less ability to flow. For the wetting phase (water) relative permeability, the opposite effect was shown. For both the viscosity increase and the tension reduction, i.e., a capillary number rise, the water permeability increased, but not as pronounced as with the oil curves. No velocity effects were noted for the range studied.;Other properties involving relative permeabilities were also found. The residual oil saturation and the imbibition-drainage hysteresis were both found to decrease with an increase in the capillary number. However, the irreducible water saturation was a function of interfacial tension only.;A relative permeability model was then developed from the experimental data, based on fluid saturation, interfacial tension, fluid viscosities, and the residual saturations using regression analysis. Both phases were modeled for both the imbibition and drainage processes. These models demonstrated similar or better fits with experimental data, of other fluid and wetting systems, when compared with other existing relative permeability models. These regression models were then applied to a two-phase reservoir simulator to determine the effects of interfacial tension and viscosity on the oil recovery of a reservoir.;For the core tests, run in fired Berea sandstone, a Soltrol 170 oil-calcium chloride brine-isopropyl alcohol-glycerin system was utilized. Alcohol was the tension reducer and glycerin was used as the wetting phase viscosifier. |
