Plain Language Summary
The relative permeability is a crucial parameter in a system where two fluid phases exist simultaneously. For example, in carbon capture and storage, relative permeability is important to assess the replacement mechanism of the existing fluid in the reservoir (wetting fluid) by the injected CO2 (non-wetting fluid). It is also an important parameter in enhanced oil recovery fields, as high relative permeability of oil indicates that the oil in the reservoir can be extracted quickly. The relative permeability is temporally and spatially varied by reservoir conditions (e.g., temperature). But currently, in reservoir-scale fluid flow simulation, relative permeability is assumed to be constant regardless of the different conditions. In this study, we conducted simulations to calculate relative permeability in various viscosity ratio (M ) and capillary number (Ca ) conditions. We found that relative permeability changes dramatically in differentM and Ca conditions, and we further mapped relative permeability on the diagram between M and Ca to predict relative permeability accurately in various reservoir conditions. Our findings can be useful to determine the suitable fluid properties to be used in reservoir management and to accurately estimate fluid behavior based on reservoir-scale simulation with variant relative permeability.