Scale-up of SAG Foam Displacements

Worldwide, an average of only 1/3 of the initially residing oil is extracted from the reservoirs . It is possible  to increase the displacement efficiency virtually to 100% in the reservoir by injecting gas. However, geological heterogeneity remains a problem and gas’s much lower viscosity and density relative to water and oil gives rise to new challenges. Foam can be used to solve these problems.

The variation in mobility caused by the limiting capillary pressure effect is key when selecting the best method to place foam in the reservoir. Foam can be injected using co-injection of surfactant and gas at a fixed quality or alternating the injection of slugs of surfactant and gas (SAG). In general, SAG is preferred over co-injection for both operational and sweep-efficiency reasons. Rossen and Boeije (2013) pointed out the importance of collecting data at the driest conditions in order to correctly model a SAG process. Even more, Al Ayesh et al. (2016) determined that the way foam dries out greatly affects injectivity in an heterogeneous reservoir.

In this presentation, we will discuss our experimental results for foam in a Bentheimer formation. Two kind of experiments were performed, steady-state and dynamic starting from equilibrium. On one hand, the dynamic data does not behave smoothly even though foam dynamics is believed to be slow enough. We think that the entrance region where no foam is present may play a role in distorting the dynamics. On the other, the steady-state data look similar to the results of Kibodeaux and Rossen (1997) which suggest that a SAG could not be successful at the field scale as discussed by Rossen and Bruinig (2007). However, the results are not conclusive and further investigation is needed in order to determine the success of a SAG in the field scale.