A comprehensive chemical enhanced oil recovery (CEOR) laboratory evaluation program was carried out to compare surfactants for alkali-surfactant-polymer (ASP) and surfactant-polymer (SP) implementation in a giant Middle East sandstone oil reservoir. The efficacies of ASP and SP floods were investigated in laboratory corefloods and simulations with emphasis on surfactant retention to improve techno-economic feasibility.

ASP and SP flooding processes were designed with low operational cost in mind and tested in laboratory corefloods. 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. SP design using produced brine with minimum water treatment is an attractive option for commercial deployment. We considered different injection water salinities, surfactant molecules, and brine treatment requirements for several ASP and SP designs.

ASP and SP corefloods recovered nearly all of 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. Surfactants designed for easy manufacturing and supply availability performed well with brine compositions that require minimal treatment. 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.

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