Low salinity waterflooding and CO2 injection are enhanced oil recovery (EOR) methods that are currently growing at a substantial rate worldwide. Linking these two EOR methods appears to be a promising approach in mature fields and for the exploration of post- and pre-salt basins in Brazil. Moreover, the latter reservoirs already have high CO2 content in the gas phase. Interfacial phenomena between fluids and rock in low salinity brine/CO2 environment still remain unclear, particularly the wettability behavior induced by the pH of the medium. In this study, coreflooding experiments, zeta potential, contact angle, interfacial tension (IFT), and pH measurements at ambient and reservoir conditions were performed to investigate the influence of the rock composition and brine/CO2 mixtures at different pH values for low salinity water-CO2 EOR (LSW-CO2 EOR) applications in Brazilian reservoirs. Brazilian light crude oil, pure CO2, and different brine solutions were used to represent the fluids in actual oil reservoirs. The experiments were carried out on Botucatu sandstone samples, with mineralogy determined by energy dispersive X-ray analysis. Coreflooding experiments were conducted by injection of 10 pore volumes of high salinity water followed by low salinity water. Contact angles, IFT and pH measurements at atmospheric and elevated pressures were performed in a high-pressure view cell (Pmax = 10,000 psi, Tmax = 180 °C) by different methods. The contact angle results were compared to those of earlier publications for other rock types. Increased oil recovery was observed in the coreflooding experiments during LSW injection. In addition, the effluent pH during LSW injection increased 0.7-4.3 points more than initial pH in high salinity water injection. Zeta potential measurements confirmed expansion in the water film on Botucatu sandstone surface at low salt concentrations. These observations indicate that during LSW injection solely, an increase in pH would increase water wettability of Botucatu sandstone, as all edges and faces of its surface become negatively charged and may repel polar compounds in crude oil. On the other hand, contact angle experiments reveal that water wettability is further enhanced in LSW when CO2 is dissolved in the water, and the system changes to acidic conditions. It seems that a change in the medium pH enhances interactions with water molecules for which the respective interfacial energy decreases, and hence the contact angle as well. Therefore, low salinity brine/CO2 mixtures may synergistically lead to increased oil recovery by decreasing the contact angle. This study advances the understanding of interfacial properties and wettability behavior in low salinity brine/CO2 environment, facilitating the design of LSW-CO2 EOR applications in Brazilian fields. Moreover, the study provides useful information for oil companies that have acquired mature wells and exploration blocks in Brazil, supporting them in operational and economic decisions.

Carbonate rocks have become very important in Brazil with pre-salt reservoir discoveries in Santos and Campos Basins. Since then, great efforts in research and technology have been made to characterize and develop these reservoirs. In this sense, outcrop analogue studies have become a powerful tool for helping the recognition of geological heterogeneities responsible for controlling the fluid flow in hydrocarbon reservoirs. Besides that, pre-salt oil recovery is associated with high carbon dioxide (CO 2) production, and due environmental issues, it is required a sustainable destination for this contaminant. CO 2 injection in the reservoir, either pure or mixed to the produced gas stream, could be a good manner to deal with this undesirable component and increase the oil recovery. This work uses outcrop analogue characterization to understand how carbonate reservoir characteristics impact the selection of the best recovery strategy under Brazilian-pre-salt-like conditions. Numerical simulation models were run using the flow simulator TEMPEST MORE (version 7.1) with isothermal compositional modeling. The oil recovery process was modeled by continuous and alternating injection of CO 2 and water. The recovered oil fractions for the simulation case with water alternating CO 2 injection were higher than with the use of continuous injection of CO 2 or water.