The Stakes of Foam Stability in Foam-Based EOR Processes Designed for Naturally-Fractured Reservoirs

Abstract Objective/Scope Enhanced-Oil-Recovery processes for Naturally-Fractured Reservoirs usually require fluids mobility control in the fractures, which can be ensured by foam-based processes. The latters have to demonstrate stability over very long distance as their efficiency rely on the pressure increase in the fractures network. Despite their potential, the ability of foams to propagate and regenerate in fractures, but also the most adapted design of foaming-surfactant formulations, are poorly documented. These issues are addressed in this experimental paper. The propagation of foams over long-distance fractures (from 100 to 1000 meters) is modelled at the lab-scale by a flow of pre-formed foams in long vertical and horizontal tubings (from 0.01m to 10 meters). The visualization of the flowing foam and the measurement of pressure allow identifying the physical phenomena which account for foam evolution in horizontal and vertical configurations. Comparison of performances is also conducted for several formulations differing by their foam performances in sandpack and by their wettability alteration properties. A preliminary test shows that co-injection of gas and liquid in a representative oil-wet fracture generates very poor foams, unlike classical porous media (sandpacks, rock core samples). This poor rejuvenation of foam evidences that foam flow in fracture strongly differs from observations in porous matrix and highlights the need for long-term foam stability. In long tubings, characterization of different formulations first shows that the most efficient foams do not correspond to the best formulations identified for porous media. Criteria to optimize a foam formulation for fracture network seem specific. Second, the evolution of flowing foams highly differs from static foams and highlights the difference of performances brought by the flow. The local foam flow structure is different from one formulation to another. These results suggest that the ability to create a high pressure gradient depends on wettability properties of formulation, due the strong interaction of foam lamellae with walls along the flow. To ensure an efficient foam-based process in a fractured reservoir, long-term stability is crucial yet not predicted by classical criteria based on porous media experiments. Besides, the best foaming-surfactant formulation for fractured systems corresponds to new criteria, likely related to wettability instead of apparent viscosity. This work has important implications on the design of foam injections in naturally fractured reservoirs regarding the calculation of liquid volumes, injection strategy to ensure foam propagation over long-distance.