Estimation of oil recovery due to wettability changes in carbonate reservoirs

TL;DR

This study introduces a coupled geochemical and multiphase flow model to quantify wettability changes during low salinity waterflooding in carbonate reservoirs, aiding optimized oil recovery strategies.

Contribution

It develops an integrated reactive transport model combining surface complexation and compositional dynamics to predict wettability alterations during LSWF.

Findings

Magnesium and sulfate concentrations influence wettability by modulating TBP.

Acidic crude oils show higher TBP, indicating stronger wettability shifts.

Synergistic effects of magnesium and sulfate reduce oil-rock adhesion.

Abstract

Low salinity waterflooding (LSWF) enhances oil recovery at low cost in carbonate reservoirs, but its effectiveness requires precise control of injected water chemistry and interaction with reservoir minerals. This study develops an integrated reactive transport model coupling geochemical surface complexation modeling (SCM) with multiphase compositional dynamics to quantify wettability alteration during LSWF. The framework combines PHREEQC-based equilibrium calculations of the Total Bond Product (TBP), a wettability indicator derived from oil-calcite ionic bridging, with Corey-type relative permeability interpolation, resolved via COMSOL Multiphysics. Core flooding simulations, compared with experimental data from calcite systems at 100 degrees Celsius and 220 bar, reveal that magnesium and sulfate concentrations modulate TBP, reducing oil-rock adhesion under controlled low-salinity conditions. Parametric analysis demonstrates that acidic crude oils (TAN higher than 1 mg KOH per gram) exhibit TBP values approximately 2.5 times higher than sweet crudes, due to carboxylate-calcite bridging, while pH elevation (above 7.5) amplifies wettability shifts by promoting deprotonated carboxyl interactions. The model further identifies synergistic effects between magnesium (50 to 200 millimoles per kilogram of water) and sulfate (above 500 millimoles per kilogram of water), which reduce calcium-mediated oil adhesion through competitive mineral surface binding. By correlating TBP with fractional flow dynamics, this framework could support the optimization of injection strategies in carbonate reservoirs, suggesting that ion-specific adjustments are more effective than bulk salinity reduction.