Oil Recovery Mechanisms of Alkali-Surfactant-Polymer Flooding

Abstract The experimental study includes phase behavior tests, measurements of interfacial tension (IFT), and coreflood tests. Effects of alkali (sodium carbonate) additives on micro-emulsion phase behavior were determined for a reservoir oil. No emulsion phase was generated for low surfactant concentrations without alkali additives, while an emulsion phase was always formed with alkali. Measurements of the dynamic IFT revealed that when the alkali concentration is as high as 0.7–1.0 wt%, the IFT rapidly increases after about 100 minutes, which suggests that the system shifts from the middle to upper-phase equilibrium. Based on tertiary alkali-surfactant-polymer (ASP) coreflood tests with surfactant and polymer concentrations of 1.0 wt% and 1200 ppm respectively, an optimum alkali concentration was confirmed as 0.2 wt% that allowed the highest recovery. Using the optimum ASP concentrations, another series of corefloods were conducted to evaluate the effect of remaining oil saturation at the start of ASP flood. Mobile oil helps alkali and surfactant slugs form an oil bank. In order to examine the oil recovery by high alkali and low surfactant concentrations (1.3 and 0.1 wt%, respectively), corefloods were conducted by changing the injection volume and scheme. Only a small incremental recovery is obtained with ASP slugs higher than 0.2 PV each. The injection scheme of polymer slugs is confirmed to be crucial for ASP flooding. Parallel coreflood tests as physical simulation of ASP flood in a two-layer system showed recovery performances complicated not only by permeability contrast but also by small-scale heterogeneity within inidividual cores. Acceptable matches between coreflood experiments and one-dimensional flow simulation were obtained by modeling ASP flood with recovery mechanisms of the surfactant-polymer flooding.