Enhanced oil recovery in carbonates due to wettability alteration has received much attention recently. In contrast to sandstones reservoirs, carbonates are neutralwet or preferentially oil-wet. The use of CO 2 dissolved into water has emerged as an alternative method for EOR operations in carbonates reservoirs. In the present paper, oil recovery from two carbonate outcrop rocks was evaluated with different brines containing CO 2 . The evaluation included a qualitative approach by spontaneous imbibition tests and a quantitative assessment by the Amott-Harvey index. The rocks tested were limestone and dolomite samples known as analogous to Brazilian pre-salt reservoirs. The testing fluids were a medium gravity crude oil, seawater concentration brine, formation equivalent brine and the carbonated version of these brines. Results shown additional oil recovery directly associated with wettability alteration driven by brine concentration switches. Oil recovery increases were observed independently if the brine concentration decreased or increased over the water replacement process. Wettability alteration took place in both carbonate types starting at oil-wet to neutral-wet conditions. Similar tests carried out with equivalent carbonated brines showed similar alterations in the wetting properties, trending no dependence on salt concentration. However, CO 2 and its derived ions dissolved in the brines seem to inhibit the wettability alteration mechanism.

A new methodology to study naturally fracture reservoir with an induced fracture model was proposed using a representative sample of the Pre-salt reservoir. A core was cut longitudinally while the fracture was simulated using a polyoxymethylene spacer (POM). This fracture configuration was adapted based on the studies performed by Lie (2013) and improved with filling the voids with spheres with controlled grain size to represent a porous medium and increase the permeability and porosity of the fracture. To study the effect of injection of low salinity waterflooding, a forced displacement test was performed under pressure conditions of 1000 psi, temperature of 63°C, and flow rate of 0.1 ml/min. The core sample was prepared at initial water saturation (Swi). This process was carried out by forced displacement and a vacuum procedure in the coreholder using synthetic formation water and dead oil of the same field as the core. The sample was aged for 34 days to simulate the wettability reservoir conditions. During the test, the syntethic seawater (SW) injection was started, and, after eight days, it was switched to ten times diluted seawater (SW10x) for 22 days. Oil production was calculated by mass balance. The X-ray computed tomography (CT) technique was used to evaluate the heterogeneity of the porosity distribution and the saturations at different injection times during the Swi process. To validate the petrophysical properties, it was performed a systematic routine for the determination of the petrophysical properties of the induced fracture model and its components: matrices and fracture. The porosity and permeability for the matrices were 11% and 31 mD for part A and are 10% and 22 mD for part B. respectively. The porosity of the fracture was analytically calculated resulting in 1.6% while the permeability of the fracture was adjusted according to the theory of flow in parallel layers resulting in 129 D. Finally, the induced fractured rock showed a porosity and permeability of 21% and 3.6 D, respectively. The Swi reached 32% and 33% by using mass balance and computed tomography (CT), respectively. Additionally, CT scans provided the Swi profiles throughtout the sample. The results of production have shown that oil recovery with injection SW was 20.8% original oil in place (OOIP) and additional recovery from the injection of SW10X of 17.33%OOIP while the final recovery was around 38.13%OOIP.

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