Alkaline-surfactant-polymer formulation development for a HTHS carbonate reservoir

Abstract

There are many HTHS (high temperature, high salinity) carbonate reservoirs where temperature (>80 °C) and salinity (>30,000 ppm) are high. The goal of this study was to develop an alkaline-surfactant-polymer (ASP) formulation for a high temperature (~100 °C), high salinity (~60,000 ppm) giant carbonate reservoir with low surfactant retention, an essential requirement for low chemical cost. Phase behavior tests were conducted with anionic surfactants, alkali, co-solvents, brine, and crude oil to identify chemical formulations with ultra-low IFT under reservoir conditions. Corefloods were first conducted in outcrop carbonate cores and then in reservoir cores. The effluent was analyzed for oil, surfactant, pH, salinity and viscosity. Surfactant adsorption on carbonate surfaces decreases at high pH. Ammonia and a new organic alkali ethoxylated diisopropylamine (DIPA-10EO) were studied for this application since there is both anhydrite and dolomite in the formation. Sodium carbonate cannot be used as the alkali in rocks containing anhydrite, and sodium hydroxide cannot be used as the alkali in rocks containing dolomite. Ultralow IFT (~0.001 mN/m) was achieved with several ASP formulations using the reservoir oil. The first three core floods in Indiana limestone yielded excellent tertiary oil recoveries of 85.2, 89.5 and 91.8%, and very low surfactant retentions of 0.06, 0.02, and 0.11 mg/g-rock, respectively. The reservoir coreflood resulted in 93.6% tertiary oil recovery and a final oil saturation of 1.2%. The surfactant retention was 0.083 mg/g-rock. The chemical formulation developed here is applicable to this high permeability, non-fractured, HTHS carbonate reservoir. Future research should address other carbonate reservoir issues such as fractures and low permeability.