Laboratory studies have shown that certain modifications to the ionic composition of the injection water increase oil recovery from carbonates. The impact of salinity is related to wettability alteration of the system toward more water wetness, demonstrated by a reduction in the measured oil-water contact-angles. It is not confirmed that the wettability shift contributes to all or most of the oil recovery increase. This is mainly because conventional multiphase fluid flow simulators, commonly used to predict oil recovery, do not incorporate directly the role of wettability conditions and contact-angles. This paper provides a new method to estimate the additional oil recovery that results from wettability alteration of carbonate cores.

A pore network model (PNM) was used to predict relative permeability curves at different wettability conditions. The effect on oil recovery was quantified from imbibition relative permeability curves that were generated from the PNM. These curves were used to simulate displacements. The simulation was run using a brine tracking function that estimates the instantaneous relative permeability based on tracing the injection brine salinity. The proposed approach was applied to the experimental core-flood experiments reported by Alshakhs and Kovscek (2015a).

The PNM was constructed for a representative bimodal carbonate system. A drainage capillary pressure curve from a mercury injection experiment guided the construction of the static model structure. The static PNM model generated two relative permeability sets that correspond to contact-angles of 95° and 55°. The simulation results showed comparable additional oil recovery to observations from the experimental core-flood experiments, 7.5% compared to 6.4%, respectively. The good match supports that the additional oil recovery is mainly attributed to wettability alteration.

You can access this article if you purchase or spend a download.