As the world energy demand increases, and the discovery of new conventional reservoirs diminishes, the need of using enhanced oil recovery (EOR) methods, such as chemical flooding, grows. A widely used type of chemical EOR is surfactant-polymer flooding (SP). In SP flooding, a surfactant reduces the interfacial tension between oil and water to ultra low values, allowing residual oil to be mobilized and recovered. On the other hand, polymer increases the viscosity of the SP slug, thus providing better sweep efficiency than waterflooding. This EOR method shows promising results in clastic formations. Although SP flooding works well in sandstone reservoirs, it faces major drawbacks when applied in high-temperature, high-salinity carbonate formations. Such harsh environment leads to both surfactant and polymer degradation. Moreover, because of the positive charge of carbonate surfaces and the large concentration of divalent cations, large surfactant retention occurs. Here we present the performance of a novel SP formulation that achieves ultra-low interfacial tension between oil and water at injected brine salinity of 57,000 ppm, with lower surfactant retention than current retention values in carbonates. We conducted four core-flooding experiments in Indiana limestone cores at 100°C to evaluate the performance of the SP formulation in recovering residual oil. The formulation consists of carboxylates, internal olefin sulfonates and lauryl betaine surfactants. A mixture of dead oil and 20 wt.% toluene was used to represent the live oil at ambient pressure. The first three core floods recovered 75.5%, 72% and 71% respectively. However, when 1wt% NaPA was injected before the chemical flood in the fourth experiment, 90% of the original oil-in-place was recovered, reducing the residual oil to only 4.5%. We found that the optimum SP slug size is 0.39PV at which the surfactant retention is 0.29mg/g-rock. In addition, reducing the frontal velocity to 0.5ft/day resulted in doubling the retention. The moderate surfactant retention makes SP flooding in carbonates feasible because less surfactant is needed to reach ultra-low interfacial tension. This new formulation enables application of SP flooding in high-temperature, high-salinity carbonate reservoirs, which, in return, will increase ultimate oil recovery from conventional reservoirs