Foam assisted gas–oil gravity drainage in naturally-fractured reservoirs

This paper introduces an enhanced-oil-recovery concept for naturally-fractured reservoirs. We use foam to improve the gas–oil gravity drainage process in the fractured reservoirs. We developed an expression that approximates the maximum oil rate depending on the injected gas rate and average properties of the foam generated in the fracture, which provides results that are in good agreement with the numerical results. We use two different foam models to simulate foam behavior in the matrix and the fracture. For the fracture we use the model developed by Hirasaki and Lawson (Hirasaki, G.J., Lawson, J.B., 1985. Mechanisms of foam flow in porous media: apparent viscosity in smooth capillaries. SPE J., 176–190), which considers the effects of flowrate, interfacial tension, and foam quality on the foam rheology. For the matrix we use the empirical foam model (mobility reduction model), which scales down the gas mobility based on empirical parameters. It is shown that foam generation in the fracture creates a viscous pressure drop along the fracture that is directly transferred to the oil-bearing matrix and accelerates oil production. It is also shown that gas and water are simultaneously diverted into the matrix via the creation of a horizontal pressure drop between the fracture and the matrix. This has consequences for foam rheology in the fracture as it change the local foam quality along the fracture. The effects of relevant physical parameters on the efficiency of the mechanism are also discussed in the paper.