Modeling the Combined Effect of Injecting Low Salinity Water and Carbon Dioxide on Oil Recovery from Carbonate Cores

Abstract

This paper investigates the combined effect of injecting low salinity water (LSWI) and carbon dioxide (CO 2 ) on oil recovery from carbonate cores. The combined effect of LSWI and CO 2 injection on oil recovery was predicted by performing several 1D simulations using measured reservoir rock and fluid data. These simulations included the effect of salinity on both miscible and immiscible continuous gas injection (CGI), simultaneous water-alternating-gas (SWAG), constant water-alternating-gas (WAG), and tapered (WAG). For SWAG and constant and tapered WAG, both seawater and its dilutions were simulated. CO 2 was injected above its minimum miscibility pressure. Baker's three-phase relative permeability model was modified to account for the effect of salinity on the water/oil relative permeability.The results show that SWAG, whether using seawater or its dilutions, outperformed all other tertiary injection modes in terms of oil recovery. Moreover, the SWAG process has both the highest tertiary recovery factor (TRF) and the lowest utilization factor (UF). This study highlights the advantage of using low salinity water along with miscible CO 2 . The miscible CO 2 displaces the residual oil saturation whereas the low salinity water boosts the production rate by increasing the oil relative permeability through wettability alteration towards more a water-wet state. The latter finding was supported by comparing our simulations with the two corefloods reported by Chandrasekhar and Mohanty (2014). These corefloods were conducted in SWAG tertiary mode using seawater and its dilutions. Fractional flow analysis shows that SWAG with low salinity water requires less injected solvent compared to SWAG with seawater and miscible CGI.

Ionic Interactions at the Crude Oil–Brine–Rock Interfaces Using Different Surface Complexation Models and DLVO Theory: Application to Carbonate Wettability

“… 88 This boundary condition provided an appropriate approximation of the analytical solution for the COBR interface. 88 , 89 Thus, the EDL interaction energy was calculated using eq 7 below 88 , 92 where ζ 1 and ζ 2 are the ζ-potential of the calcite–brine and crude oil–brine interfaces, respectively, ε w is the relative permittivity of water, ε is the absolute permittivity of the vacuum, 8.854 × 10 –12 F/m, 94 94 and k is the inverse of Debye length at the calcite/oil–brine interfaces. The Hamaker constant of 2.45 × 10 –21 J was used for calculating the vdW forces based on relative permittivity values and Lifshiftz theory.…”

“…The Hamaker constant of 2.45 × 10 –21 J was used for calculating the vdW forces based on relative permittivity values and Lifshiftz theory. 89 , 94 The structural interaction energy was ignored in the calculation similar to the approach by Mahani et al 88 The structural forces were neglected because they were assumed to be sensitive at a very small separating distance from the colloidal surface. 59 , 75 A negative total interaction energy indicated a negative total disjoining pressure and hence corresponded to an attraction between the oil–brine and rock–brine interfaces.…”

“…The EDL interaction free energy was calculated by assuming a constant potential–constant potential (CP–CP) boundary condition for solving the Poisson–Boltzmann equation . This boundary condition provided an appropriate approximation of the analytical solution for the COBR interface. , Thus, the EDL interaction energy was calculated using eq below , where ζ 1 and ζ 2 are the ζ-potential of the calcite–brine and crude oil–brine interfaces, respectively, ε w is the relative permittivity of water, ε is the absolute permittivity of the vacuum, 8.854 × 10 –12 F/m, and k is the inverse of Debye length at the calcite/oil–brine interfaces. The Hamaker constant of 2.45 × 10 –21 J was used for calculating the vdW forces based on relative permittivity values and Lifshiftz theory. , The structural interaction energy was ignored in the calculation similar to the approach by Mahani et al The structural forces were neglected because they were assumed to be sensitive at a very small separating distance from the colloidal surface. , A negative total interaction energy indicated a negative total disjoining pressure and hence corresponded to an attraction between the oil–brine and rock–brine interfaces.…”

Experimental Studies of Immiscible High-Nitrogen Natural Gas WAG Injection Efficiency in Mixed-Wet Carbonate Reservoir

“…The WAG performance is influenced by many factors that have been extensively studied, such as the reservoir parameters including wettability [12,13] and heterogeneity [6,14,15], the injected fluid parameters including water salinity [16,17] and gas type [18,19], the WAG parameters including the WAG ratio [20,21], the number of cycles, slug sizes [22], the timing of injection [23] and, finally, the injection rates of the gas and water phases [24]. The cyclic nature of the WAG process involves complex three phase-flow, which makes the prediction of WAG performance very difficult, and which was extensively studied by Fatemi, Sohrabi and Shahverdi [25][26][27].…”

Effects of Slug Size, Soaking, and Injection Schemes on the Performance of Controlled Ions Water Flooding in Carbonates

“…According to their outcomes, residual oil is a function of trapping number which is a function of the contact angle which is again, a function of electrical double layer thickness. Ultimately, they proposed that surface charge alteration and rock dissolution can change rock wettability toward a more water wet state. ,− …”