Simulação da injeção alternada de CO2 e salmoura em reservatórios de petróleo: efeito da densidade das fases no fator de recuperação de óleo

Abstract

The density of the oil, water and gas phases in fluid reservoirs is a key property to understanding the phenomena and mechanisms that govern oil recovery and other correlated properties such as CO2 solubility and phase viscosity. In this dissertation, the behavior of density, viscosity and CO2 solubility in the fluid phases were evaluated using oil recovery methods alternating or not with CO2, high salinity water (HSW), and low salinity water (LSW) (50,000 and 5,000 ppm were used as salinity values, respectively). Using the package GEM of the compositional simulator developed by Computer Modeling Group (CMG, Canada), the effects of these three properties on the oil recovery factor were evaluated, emphasizing density over time and by varying the position in the simulation grid. Only the physical effects were considered, disregarding the geochemical effects. The simulation was performed with oil and reservoir data from literature, and the Peng-Robinson (PR) cubic equation of state for each injection analyzed. The reservoir temperature was kept constant at 71.11ºC, and the simulation period was five years. The results obtained in the GEM for the water phase density were compared with those calculated by empirical correlations. High salinity water alternating CO2 (CO2HSWAG) and low salinity water alternating CO2 (CO2LSWAG) presented close oil recovery factors (difference of 0.25 % between both injections) and the highest values for this property in this dissertation: 53.07% and 52.84%, respectively. This should be due to neglecting geochemical effects and the closer phase densities (oil, water and gas). CO2WAG injection provided an oil recovery factor of 52.82% and CO2 injection obtained 52.18%. HSW, LSW and H2O injections were very close (maximum difference among them was 0.05%), the oil recovery factor was, approximately, 39.60%.