Experimental Evaluation of Foam-Assisted Gas Injection in Proppant-Packed Fractured Oil-Wet Carbonate

Click to copy article linkArticle link copied!

Foam flooding in fractured tight oil reservoirs can enhance gas mobility and conformance control by diverting gas flow from high-permeability zones (fractures) to low-permeability ones (matrices). Several factors, including operating conditions, foam generation parameters, fluid injection schemes, and properties of injected and resident fluids, affect the fracture–matrix interactions. However, thus far, the literature provides a limited understanding of the effects of such factors on the fluid displacement mechanisms between matrices and fractures in propped fractured rocks under reservoir conditions. In this study, two different methane foam injection schemes were investigated for their impact on foamability and oil recovery from propped fractured oil-wet carbonate cores at 115 °C and 3500 psi: (1) foam-alternating-gas injection (FAGI-D) and (2) foam-alternating-wet gas-alternating-gas injection (FAGI-W-D). The aqueous solutions consisted of high-salinity brine containing two foaming agents: surfactant A (anionic) and surfactant B (amphoteric). The macro-scale foam flooding tests showed that the performance of foam in oil-wet porous media was significantly influenced by the number of cycles, foam slug size, total injection rate, and gas fraction. Surfactants A and B exhibited different foaming behaviors irrespective of the foam injection scheme at a fixed concentration (4000 ppm) and foam quality (85%). For surfactant A, a large foam slug size (i.e., six pore volumes) and a high injection rate were necessary to generate foam. In contrast, a lower slug size (i.e., three pore volumes) and a lower injection rate were sufficient for surfactant B. The latter also showed better tolerance toward oil and produced foam of good strength in oil-wet porous media. Therefore, the foam generated by surfactant B significantly reduced the gas mobility and enhanced the fluid displacement from the matrix, leading to higher oil recovery (20.61%) compared with its counterpart (12.96%). Interestingly, the performance of both surfactants was improved at a lower foam quality of 70% and resulted in better foamability, stability, and oil production from tight matrices. This behavior can be attributed to the high water content in the foam, which depleted the oil saturation inside the porous medium more efficiently, leading to increased foamability and higher foam stability. The results also demonstrated that a higher total injection rate of 3 cc/min supported the generation of gas bubbles and caused significant fracture–matrix interactions, diverting more gas from the fracture to the rock matrix.