Instability due to wettability alteration in displacements through porous media

Wettability of some petroleum reservoir rocks can be altered by changing the brine composition, e.g., lowering salinity or adding surfactants. Wettability alteration can mobilize stranded oil and enhance oil recovery. Analytical solutions for 1D tertiary low-salinity floods show two saturation shocks one of which is associated with an adverse mobility ratio. The adverse mobility ratio across this shock is not very large, about 1.5–3 in the cases considered. As the viscosity ratio increases, the width of the oil bank decreases and one of the shocks disappears at a high viscosity ratio (>10)(>10). The remaining shock at high viscosity ratio is stable. A viscous fingering model is applied to describe the flow instability in relatively homogeneous multi-dimensional porous media. It shows that the viscous fingering is mild and the breakthrough of low-salinity injectant is only 11–31% faster than in the 1D flow. Numerical simulation of these displacements in 2D permeability fields show that the fingering model approximates the average saturation profile if the standard deviation in permeability heterogeneity is low. Fingering behavior depends mostly on permeability standard deviation, but not on correlation length for the spherical variogram model used in this study. Low-salinity floods are expected to be mildly unstable due to the low mobility ratio at adverse saturation shocks.