Chemical Formulation Design in High Salinity, High Temperature Carbonate Reservoir for a Super Giant Offshore Field in Middle East

Abstract The super-giant offshore carbonate oil field started production in 1968 and has been under pattern water flood since 1982. The field is undergoing a major redevelopment utilizing artificial islands and maximum reservoir contact 10,000 ft horizontal wells in a 1:1 line drive. As part of the re-development, Chemical EOR (CEOR) is being assessed for potential application in one of the main oil producing reservoirs. This paper reports on laboratory results of a CEOR study addressing the major challenge of chemical retention in carbonate reservoirs and investigates the feasibility of increasing oil recovery through CEOR processes. In this paper, CEOR processes investigated include surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) for temperature of 100°C, formation salinity of 200K ppm total dissolved solids, hardness of 15K ppm, and reservoir permeability of <10 mD. In the screening and optimization process, more than 100 surfactant formulations and 3,000 pipette tests at ambient pressure and reservoir temperature utilizing surrogate oil were completed to identify two potential formulations: a SP and an ASP which were stable under reservoir conditions. The polymer qualification includes the polymer rheology and transport tests in reservoir cores using different polymer molecules (HPAM, AMPS), pre-shearing rates, and co-solvent types and concentrations. The identified high-performance SP and ASP formulations were further tested in two live oil corefloods where oil recovery and retention were evaluated. A history match of the core flood experiments was performed and input data were obtained for large scale simulations. The chemical formulation design results showed that an SP formulation having high solubilization ratio can be prepared in Arabian Gulf seawater. Large-hydrophobe alkoxy carboxylate surfactant and sulfonate cosurfactant showed promising performance for the given harsh reservoir conditions. Polymer injectivity core flood tests were also performed to assess transport of the identified polymers. Results indicate that the pre-sheared viscous polymer solution transported without plugging or filtering out in a 1 -ft long 6 mD composite core. The live oil corefloods of the SP and ASP formulations resulted in an overall recovery factors of 97% and 93.5%, respectively. However, surfactant retention was high at 0.99 and 0.58 mg surfactant/g rock for the SP and ASP core floods under similar injected PV of chemicals. The analysis of the surfactant retention indicates phase trapping and adsorption on minerals are believed to be the dominant mechanisms for most of surfactant retained in the core. The current study represents a continued expansion of industry experience and includes the identification of two high-performance surfactant formulations which are stable and provide ultra-low IFT under the high temperature, high salinity, and high-hardness characteristic of Middle East carbonate reservoirs.