Visual Study of the Effect of Viscosity Ratio, Flow Rate and Porous Medium Topology on Two-Phase Relative Permeabilities
Ortiz-Arango, J.D. and Kantzas, A.
CIPC 2009-168, presented at the 60th Annual Technical Meeting of the Petroleum Society held in Calgary, June 16-18, 2009.
One of the most important properties for understanding the dynamic behavior of multiphase flow in porous media is relative permeability. Particularly in two-phase flow, the relative permeability to a given phase is generally assumed to be only a function of the saturation of that phase, independent of the properties of fluids involved and/or flow conditions and ranging in value from zero to one.
In this work, experiments were conducted to determine the effect of viscosity ratio, flow rate and porous medium topology on two-phase relative permeabilities. Two different etchedglass micromodels and acrylic-made triangular capillary tubes were used as porous media. Three different pairs of fluids with viscosity ratios ranging from 0.005 to 202.3 were used. Primary drainage and secondary imbibition displacements were carried out at different injection flow rates and unsteady-state relative permeability curves were constructed.
It was found that relative permeability to both the wetting and the non-wetting phase varied with the viscosity ratio and the injection flow rate. It was also observed that relative permeability to the non-wetting phase took values larger than unity when viscosity ratio was larger than one. This “lubrication effect” observed in the non-wetting phase was affected by the topology of the porous medium.
Experimental relative permeabilities were compared to those predicted by the triangular capillary model presented by Ortiz- Arango and Kantzas
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