Simulation Study for Optimizing Injected Surfactant Volume in a Miscible Carbon Dioxide Flood

The viability of any Enhanced Oil Recovery (EOR) method lies with its ability to increase oil recovery in an economically efficient manner. The practicality of carrying out a CO₂/surfactant enhanced oil recovery operation is affected by the high cost and large volume of surfactant needed in the field.

This paper presents the results of a numerical simulation study that was carried out to analyze and establish critical parameters that can be used to obtain the minimum but most effective volume of surfactant needed for generation of foam in a porous medium which will in turn yield optimum oil production. The results obtained from laboratory experiments, which were based on the comparison of a low and high injected surfactant concentration, serve as inputs to a reservoir simulator for modeling and estimating surfactant requirements.

Numerical models were designed to simulate the co-injection of carbon dioxide and surfactant solution into a Berea sandstone core that was saturated with brine and oil after a waterflood process. Some of the values of parameters used include surfactant concentrations of 0.1 wt % and 0.5 wt %, average back pressure of 2350 psi and total flowrate of 0.4 cm³/min, with CO₂ injected at 0.3 cm³/min and surfactant solution at 0.1 cm³/min, which gives a volumetric flow ratio of 3:1 and foam quality of 75%.

Results indicate that injecting a solution with a larger surfactant concentration increased foam strength with a corresponding increase in pressure drop. A decrease in CO₂ relative permeability is also observed as more gas is trapped within the rock due to foam blocking. Carbon dioxide is thereby able to contact more of the oil contained within the reservoir.