This paper presents a comprehensive simulation study on the impact of natural fractures on the performance of surfactant polymer flood in a field wide scale. The simulation model utilized for the study is a dual porosity dual permeability model representing 1/8 of a 20-acre 5-spot pattern. The model parameters studied include wettability alteration, interfacial-tension changes and mobility reduction effect. The results of this study clearly indicate the importance of reservoir description and fracture modeling for a successful surfactant-polymer flood. This may lead in huge difference in reserves booking from such EOR method.
Naturally fractured carbonate reservoirs are usually characterized by mixed wettablility and low matrix permeability which leads to low oil recovery and high remaining oil saturation. Enhanced oil recovery methods such as surfactant-polymer flood (SPF) enhance the recovery by increasing the spontaneous imbibitions either by lowering the interfacial tension or altering the wettability in the matrix. However, one of the main reasons for failed surfactant-polymer floods is under-estimating the importance of the reservoir and fluid characteristics especially the description of natural fractures and their effect on recovery.
Sensitivity runs were made in field size scale in order to compare oil recovery by capillary force, buoyancy force and viscous force. The simulation study indicates a relationship between water saturation and the start of altering wettability and/or interfacial tension to maximize oil recovery. Also, when a surfactant alters the rock wettability, an optimum IFT should be identified for faster and higher imbibitions. In addition, the study shows effect on recovery by permeability contrast between that of the fracture and that of the matrix as well as fracture orientation with respect to injector-producer direction.