Experimental investigation and modelling of CO2-foam flow in heavy oil systems

Abstract

In this work, the C14-16 alpha olefin sulphonate (AOS) surfactant, octylphenol ethoxylate (TX-100), and methyl bis[Ethyl(Tallowate)]-2-hydroxyethyl ammonium methyl sulphate (VT-90) surfactant were selected as representatives of anionic, nonionic, and cationic surfactant to stabilize foam. The effects of surfactant concentration and gas/liquid injection rates on foam performance were examined by performing a series of oil-free foam flow tests by injecting CO2 and a foaming surfactant simultaneously into sandpacks. Foam flooding was conducted as a tertiary enhanced oil recovery (EOR) method after conventional water flooding and surfactant flooding. Furthermore, a new method was proposed to determine the residual oil saturation. The foam stability in the presence and absence of heavy oil was studied by a comparative evaluation of the mobility reduction factor (FMR) in both cases. The foam fractional flow modelling by Dholkawala and Sarma[36] was modified based on experimental results obtained in this study. The range of the ratio of two important model parameters (Cg/Cc) at various foam qualities was determined and could be used for large-scale predictions. The results showed that during the oil-free foam displacement experiments higher foam apparent viscosities (μapp) were attained at lower gas flow rates and the maximum was attained at a total gas and liquid injection rate of 0.25 cm3/min with a gas fractional flow ratio of 0.8 for the foam in the absence of oil. The presence of oil reduced the foam mobility reduction factors (FMR) to different degrees with FMR-without oil / FMR-with oil ranging from 4.25–13.69, indicating that the oil had a detrimental effect on the foam texture. The foam flooding successfully produced an additional 8.1–21.52 % of OOIP, which can be attributed to the combined effect of increasing the pressure gradient and oil transporting mechanisms.