Imbibition Capillary Pressure and Relative Permeability of Mixed-Wet Microporous Rock: New Insights from History Matching

We use a Darcy-scale simulator to extract residual oil saturation, forced imbibition capillary pressure, and relative permeability by history matching to measured pressure drop and cumulative oil production during multi-speed centrifuge experiments and constant-rate waterfloods in Indiana limestone cores under four different wettability states established by adding different naphthenic acids to the oil phase. Residual oil saturation decreases monotonically as advancing bulk contact angle increases from $$\theta _\text {a} = 110^\circ $$θa=110∘ to $$150^\circ $$150∘, in sharp contrast to the non-monotonic dependence displayed by the core-averaged oil saturation which are often mis-interpreted to be representative of true residual saturation. The magnitude of the capillary pressure required to establish a particular water saturation increases with $$\theta _\text {a}$$θa. Saturation-normalized water relative permeability exceeds one at $$\theta _\text {a}\ge 125^\circ $$θa≥125∘, with equivalent slip lengths of up to O(200) nm. The simulations indicate that capillary end effects may be significant during displacement experiments under typical laboratory conditions, even in mixed-wet media of relatively low permeability, and highlight the importance of using numerical simulation to interpret displacement experiments under capillary-dominated conditions.