Modelling foam displacement in fractured carbonate reservoirs

Foam displacement has been employed in several field pilots which report improvement in mobility control, sweep efficiency, delayed gas breakthrough and EOR. However, foam behavior in highly heterogeneous porous media in general and fractured reservoir in particular is not well understood. Effective application of foam for enhanced oil recovery requires a good understanding of physical displacement processes (e.g. adsorption, foam generation, foam decay) at the laboratory and field scale. This is particularly important for the more complex fractured carbonate reservoirs which host over half of the world's remaining conventional oil reserves. We investigate the effect of foam displacement in fractured carbonate reservoirs using numerical simulations tuned to experimental data to compare recovery for different injection strategies at different scales. In the experiments, high quality foam was generated by the injection of surfactant solution and N₂ gas either in-situ or prior to injection. A mechanistic Lamella Density model was used to simulate core-scale laboratory experiments and history match the unknown foam parameters. We applied our understanding of foam displacement processes at the core scale to a reservoir model at the inter-well scale where additional heterogeneities were encountered. For this model we used a cross section of highly heterogeneous simulation model of a middle Jurassic carbonate ramp that is an analogue to the Arab D formation in Qatar. We used this model to test the effect of foam injection for different injection mechanisms, analyze the displacement processes, and compare the overall sweep and recovery. Foam injection showed very promising results by diverting the flow from the high permeability fractures to the matrix, allowing for a better sweep efficiency that lead to a noticeable increase in differential pressure. Pre-formed foam yielded a higher recovery (around 78% of OOIP) compared to the in-situ generated foam in the core samples. This might be due to the smooth nature of the fractures leading to fewer snap off sites for foam generation. Varying the foam injection strategies (i.e. pre-formed foam, co-injection, and SAG) resulted in at least a 12% change in recovery compared to conventional water flooding and water-alternating gas injection. Foam quality, foam stability and injection mechanism were all factors that controlled sweep efficiency. Our results illustrate how the laboratory-scale displacement mechanisms could operate on a larger (i.e. inter-well) scale where additional heterogeneities are encountered and the ratio of viscous to capillary and gravity forces changes. Our simulations also demonstrate that uncertainties in parameterizing foam models using experimental data from core floods translate into considerable uncertainties for predicting recovery at the field-scale. Still, foam can be an effective agent to increase oil recovery in fractured carbonate reservoirs by improving sweep efficiency and reducing gravity override.