Low salinity waterflood (LSF) is a promising technology for improving oil recovery. Several laboratory studies have demonstrated the potential of LSF to alter the rock wettability and improve oil recovery in carbonate reservoirs. Some studies have considered calcite dissolution as a mechanism behind the wettability alteration by LSF in carbonates. Moreover, the interaction between rock and injected brine can lead to change in the injected brine composition and pH. Therefore, it is important to better understand the interaction between injected brine and carbonate rock to de-risk the LSF technology for field applications.
A numerical model was developed by coupling a reservoir simulator (Shell in-house Simulator, MoReS) with a geochemical model (PHREEQC) to study the interaction between the injected brine and carbonate rock. Calcite is assumed to be the rock mineral to represent most of carbonate reservoirs. Two reservoir rock models are presented: one for coreflood scale and another for field scale. To mimic reservoir condition, the rock is saturated with formation brine (180 g/l) and several brines with different salinity and composition are injected. The model is calibrated to the published experimental data in the literature. Both Local Equilibrium and Kinetic approaches are used to model the interaction between injected brines and rock. Furthermore, the impact on calcite dissolution is examined against various parameters such as brine composition and pH, and temperature.
The model results indicate that interaction between calcite and brine can reach equilibrium quickly. As a result, LSF may dissolve calcite from part or the whole core during flooding experiments depending on the kinetics of the interaction. However at field scale, the calcite dissolution occurs only in the area near the injector. This suggests that if calcite dissolution is one of the LSF mechanisms, this mechanism will not contribute to improving oil recovery at field scale. Although calcite dissolution can occur only near the injector, it can still change the composition and pH of the injected brine, which may have an impact on the oil recovery. The increase in salinity due to calcite dissolution in not significant in absence of CO2, but the brine pH may reach 8-9.