Developing surfactant formulations for high temperature (100°C), high salinity (>50,000 ppm) and especially high hardness (>2000 ppm) reservoirs is challenging. Alkali-surfactant-polymer processes have been developed in the past, but require a mild brine injection. The objective of this work is to develop a surfactant polymer (SP) process for a high temperature, high salinity (HTHS) reservoir that can be injected with available hard brines (such as seawater) to achieve ultra-low IFT, residual level low. oil saturation and low surfactant retention in carbonate rocks. Phase behaviour experiments were performed to identify a combination of anionic and zwitterionic surfactants.
Four Tertiary chemical core floods were conducted on Indiana limestone cores to test for oil recovery and surfactant retention. A copolymer containing tertiary-butyl acrylamide sulfonate, SAV10xv, was identified to be stable under this HTHS condition. Sodium polyacrylate (NaPA) was identified as a sacrificial chemical to reduce surfactant adsorption. Chemical flooding managed to reduce residual oil saturation to 8-11%. A NaPA prewash reduced surfactant retention from 0.133 mg/g to 0.017–0.038 mg/g rock. Including the NaPA in the chemical slug was not as effective. The use of this surfactant formulation with a sodium polyacrylate prewash can improve oil recovery in high-temperature, high-salinity carbonate reservoirs with very low surfactant retention polymer.
Laboratory salts, including sodium chloride, calcium chloride dihydrate, magnesium chloride hexahydrate and sodium sulfate, and sodium polyacrylate (NaPA; molecular weight 2100) were purchased at least 99% pure. .5% from Fisher Scientific. The salts were mixed with deionized water to create a synthetic injection of brine. Synthetic injection brine is very similar in composition to real injection brine, except that the bicarbonate has been removed to prevent precipitation under laboratory conditions.
Phase behaviour experiments
Many SP formulations were tested. Salinity explorations and aqueous stability tests were carried out at 100 °C. If the formulation exhibited undesirable characteristics during the early stages of the test (such as high IFT or macroemulsions with slow equilibration time), then no further data was measured. Formulations SP-1 and SP-2 exhibited ultra-low interfacial tension and Winsor type III phase behaviour.
In this work, an ultra-low IFT SP formulation was developed for a high-temperature, high-salinity (and high-hardness) carbonate reservoir. Cumulative oil recovery was 77–83% OOIP (or 72–77% ROIP tertiary recovery) for the SP flood with a NaPA prewash for Indiana limestone cores (Fig. 11). This oil recovery is high considering that Indiana Limestone has a bimodal pore system. Initial oil saturation (about 0.5) and oil recovery by water injection were also low due to the complexity of the pores.
The surfactant polymer formulations were developed for a high temperature (100°C), high salinity (57,000ppm) and especially high hardness (2760ppm) carbonate reservoir producing ultra-low interfacial tension. The inclusion of 0.5% by weight sodium polyacrylate did not change the behaviour of the oil-brine-surfactant phase. A copolymer containing tertiary-butyl acrylamide sulfonate, SAV10xv, was identified to be stable under this HTHS condition.