Recent publications indicate that the injection of polymer solutions at concentrations larger than those conventionally used in polymer flooding can result in higher recovery at field scale. Typically, oil recovery more than 20% OOIP compared to waterflooding using these polymer solutions has been reported (Wang et al; 2011). However, injectivity issues have to be considered when injecting such concentrated polymer solutions. This study describes an alternative approach based on surfactant-based solutions. The technology has been developed to match the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitations even when considering very viscous surfactant solutions (i.e. up to 1000 cps) and low permeability cores. Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high-molecular-weight polymer solutions. The degree of non-linearity in the mechanical properties for both solutions has been expressed by Weissenberg number. The surfactant solution has much higher Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir, which indicates higher elasiticily of these surfactant solutions. The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of coreflood experiments has been performed in reservoir cores at reservoir conditions. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of 10 to 15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.