One grand challenge of surfactant technologies in high salinity sandstone reservoirs is the surfactant retention and its utilization for commercial projects. A proven mitigation strategy to reduce surfactant retention is to soften the seawater or produced brine and add alkali with the surfactant and polymer. However, softening produced brine can be costly and the addition of alkali can impose other issues such as scale and produced fluid separation. A comprehensive chemical enhanced oil recovery (CEOR) laboratory program was carried out to compare different surfactant formulations for both alkali-surfactant-polymer (ASP) and surfactant-polymer (SP) implementation in a giant Middle East sandstone oil reservoir with high salinity on the order of 160,000 ppm. The efficacies of ASP and SP floods were investigated in laboratory corefloods and simulations with emphasis on surfactant retention to improve techno-economic feasibility.Both ASP and SP floods were designed with low operational cost in mind and were tested in laboratory corefloods under reservoir conditions. Different injection water salinities were considered for practical field application. The handling and availability of injection water with a suitable composition has significant implications in CEOR projects. The SP design using produced brine with minimum water treatment is an attractive option for field commercial deployment. We considered different injection water salinities, surfactant molecules, and brine treatment requirements for several ASP and SP formulations and injection design strategies.ASP and SP corefloods recovered nearly all the remaining oil after waterflooding. The surfactant retention was lower for SP floods when brine with reduced concentration of Ca2+ and Mg2+ (hardness) was used. Both ASP and SP formulations were also tested for crude oil samples from different zones. A minimal adjustment in injection salinity was required for different oils with our surfactant formulations. Field implementation strategies were evaluated via numerical simulation. The effect of strong aquifer drive on SP performance was shown to be minimized with optimized injection/production strategies. SP was shown to be technically and economically an attractive candidate tertiary process.