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 () 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.