Surfactant enhanced alkaline flooding for Western Canadian heavy oil recovery

Abstract

For heavy oil reservoirs (with oil viscosities ranging from 1000 to more than 10,000 mPa s), primary production and waterflooding can only recover 5–10% of initial oil in place (IOIP) due to the unfavorable mobility ratio between water phase and oil phase. If heavy oil is dispersed in formation brine by a chemical injection, the mobility of oil can be greatly improved. In this study, sandpack flood tests were conducted for a heavy oil sample with a viscosity of 1800 mPa s at 22 °C. The heavy oil was emulsified and entrained in formation brine by alkaline/surfactant (A/S) flooding and then produced out of the core. The results of sandpack flood tests showed that the tertiary oil recovery could reach 24% IOIP by injecting a 0.5 pore volume (PV) of chemical slug. The tertiary oil recovery did not decrease with the sandpack length. The experimental results showed that the formation of an oil-in-water (O/W) emulsion and an oil bank was necessary to improve the heavy oil recovery in sandpack flood tests. This is viable by injecting a chemical slug containing Na 2CO 3, NaOH, and a very dilute surfactant. Na 2CO 3/surfactant had synergistic enhancement in lowering interfacial tension, leading to the formation of O/W emulsion. The addition of NaOH accelerated the neutralization of organic acids in oil in sandpack flood tests so that the emulsified oil accumulated to produce an oil bank. When an oil bank was generated, the pressure drop along the sandpack responded significantly.