Foam-based EOR techniques have surfaced as a promising approach for unconventional reservoirs with high heterogeneity, adverse wettability, and natural fractures. Constraints such as permeability contrast (PCF/M) between fractures and the matrix can delimit the effectiveness of gas injection-based EOR methods, resulting in an early gas breakthrough and poor sweep efficiency. Furthermore, the foam generation capacity of surfactants can be significantly affected by the permeability of fractures. Therefore, careful evaluation of the effects of variations in fracture permeability on foam performance in fractured oil-wet porous systems is warranted under reservoir conditions.

In this study, several fractured oil-wet Minnesota Northern Cream (MNC) core samples possessing comparable matrix permeabilities were employed. The fractures were packed with oil-wet proppants of different mesh sizes to create varying fracture permeabilities. A set of foam flooding experiments were conducted on these propped oil-wet fractured cores at reservoir conditions (3,500 psi and 115 °C). An amphoteric surfactant was used as the foaming agent. The foam was generated in situ via simultaneous injection of the surfactant's aqueous solution and gaseous methane into the fracture. The pressure gradients across the core samples were recorded during the flow process, and foam performance was quantified in terms of the foam's apparent viscosity and oil recovery from the oil-bearing matrix.

The results established the feasibility of the foam-based EOR approach in propped fractured oil-wet carbonate samples as an efficient alternative for gas injection. The foam significantly reduced the gas mobility in the fracture and diverted the gas to the tight matrix, resulting in notable mobilization of the matrix oil toward the fracture area. This behavior can be attributed to numerous factors associated with this study. For example, the amphoteric surfactant generated stable foam at the chosen operating parameters, resulting in enhanced fracture-matrix interactions and thereby recovering a significant portion of the oil hosted in the tight matrix. On the other hand, the permeability of the fracture played an essential role in governing the foam behavior in oil-wet porous media. It was observed that, in the lower range, the apparent viscosity of foam increases with permeability up to a specific permeability value, whereas at higher permeabilities, a drastic decrease in the foam strength was noticed. The optimum fracture permeability was identified, which facilitated the generation of small and stable bubbles, considerably reducing the gas mobility and resulting in increased oil recovery. The results also revealed that limiting capillary pressure conditions in tighter fractures adversely impacts the generation of stable foams.

This study presents new insights into the impact of fracture-matrix permeability contrast (PCF/M) on foam performance in fractured oil-wet carbonate systems at elevated pressure, temperature, and high salinity conditions. Additionally, it provides a novel understanding of fracture-matrix interactions that can be applied to field-based EOR applications in heterogeneous hydrocarbon reservoirs.

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