Numerical Modeling of Fluid-Rock Interactions During Low-Salinity-Brine-CO2 Flooding in Carbonate Reservoirs

Fluid-rock interactions can modify certain reservoir properties, notably porosity, permeability, wettability, and capillary pressure, and they may significantly influence fluid transport, well injectivity, and oil recovery. The profound influence of low-salinity-brine flooding is primarily based on wettability alteration, while that of CO2 flooding is based on oil swelling, viscosity reduction, and interfacial tension reduction. Low saline brine, when combined with CO2, leads to higher CO2 solubility and diffusion, and increased brine acidity. The low-salinity-brine-CO2 injection further contributes to the synergy of mechanisms underlying the two processes to improve oil recovery. A reactive transport model, which uses surface complexation reactions (SCR) to describe the equilibrium between the rock surface sites and ion species in the brine solution coupled with transport equation, was developed to predict a set of low-salinity-brine-CO2 flooding experiments conducted on carbonate rocks. While conducting batch simulations of the model, it was shown that the thermodynamic parameters reported in the literature for SCRs in a rock–brine system are not suited to natural carbonate rocks. The same thermodynamic parameters could not fit the model to experimental zeta potential data with pulverized and intact carbonate cores at varying potential determining ion concentrations. The model was further utilized to predict the effluent compositions of potential determining ions in single-phase flooding experiments on natural carbonate cores. The failure of thermodynamic parameters in the prediction of reactive transport single-phase experiments, implies that zeta potential is not enough to optimize such parameters for the reactive transport model. The reactive–transport model parameters were fitted to the single-phase experiments and a temperature-dependent relationship was generated for the thermodynamic parameters. Then, the optimized model was used in investigating the equilibrium between rock, oil and brine in a set of low-salinity-brine-CO2 flooding experiment. The model showed an incremental recovery of 28% over the formation water flooding, similar to the reported recovery from the experiment. The simulation results show that the incremental recovery can be associated with increased CO2 solubility leading to the formation of in-situ carbonated water to reduce interfacial tension and alter wettability. The performance of low-salinity-brine-CO2 flooding in terms of oil production, relative injectivity, and CO2 storage was evaluated on a field case study using field-specific injection parameters. The results demonstrate that the water injected, and injection scheme has a substantial influence on injectivity and oil production. The injectivity was significantly greater for the water-alternating-gas injection, mainly because the rock surface has an increased contact time with CO2-saturated brine. Meanwhile, carbonated water injection shows greater injectivity compared to formation water and low-salinity-brine, and also has higher oil recovery compared to low salinity waterflood and conventional waterflood in the respective order.