An experimental investigation of the foam enhanced oil recovery process for a dual porosity and heterogeneous carbonate reservoir under strongly oil-wet condition

In this study, we investigate the feasibility of foam enhanced oil recovery (EOR) for a dual porosity and heterogeneous carbonate reservoir in the Middle East with medium temperature (55 °C) and high formation salinity (16% TDS). An Alkyl Poly-Glycoside (APG) surfactant was firstly selected based on the solubility tests and bulk foam tests. Afterwards, a series of core flooding experiments both in the absence and in the presence of crude oil were performed on Estaillades limestone, a dual-porosity and heterogeneous carbonate presenting reasonable similarities with the actual formation. In these foam tests, the influence of surfactant concentration, foam quality, injection velocity, brine composition, injection mode and permeability on foam strength and incremental oil recovery were systematically investigated. The optimal foam quality is found to be around 60–70% from foam quality scan tests in the absence of crude oil. Moreover, foam can still be generated in Estaillades under strongly oil-wet conditions, and the foam strength in the high-quality regime is largely dependent on surfactant concentration. More than 10% original oil in place (OOIP) of the water flooded residual oil was recovered after co-injecting 2.0 total pore volume (TPV) of nitrogen and 0.5 wt% APG surfactant (in synthetic seawater brine) at 65% foam quality and 4 ft./d. Interestingly, it was observed that the presence of lauryl betaine (LB) can significantly enhance the stability of APG foam in the presence of crude oil, though LB surfactant itself is not a good foamer. At last, the three phase co-injection tests proved the presence of foam at approximately 70% oil saturation. The results of this study may provide insights into the foam transport behavior in a dual porosity and heterogeneous porous media under strongly oil-wet condition.