Applicability of alkyl polyglucosides for surfactant flood in high temperature-high salinity carbonate reservoir through low tension displacement and wettability alteration

Characteristics of the giant Thamama reservoir of ADNOC concession reveals that it could be an ideal candidate for surfactant enhanced oil recovery project. With known oil wetting characteristics of this carbonate (limestone with minor dolomite) formation and capillary trapping of huge quantity of oil in the relatively low permeable and transition zones, the potential is enormous. This work endeavors to design of a surfactant aided EOR for this super giant oil reservoir, focusing on lowering oil-brine interfacial tension and altering wettability, considering the high reservoir temperature (250 °F), high salinity (220,000 ppm) and hardness (28,000 ppm) of formation and injection water and also the environment concerns for a high volume chemical injection.;Several biodegradable surfactants (produced from renewable resources) were screened for their thermal stability, brine and hardness compatibility through IFT, phase behavior and UV-Vis absorption studies to determine their suitability for surfactant EOR in the harsh conditions stated above. A non-ionic alkyl polyglucoside (APG) with C10/12 chain structure, a blend of nonionic-anionic APG surfactant and a cationic fatty amine based betaine surfactant were evaluated for this study. These surfactants were selected based on the fact that they are synthesized from renewable resources such as starch and coco derivatives, easily bio-degradable and have very low ecotoxicity.;Thermal stability studies were carried out at 250 °F in non saline and hard brine media for 72 hours. The UV absorbance profiles of the surfactants before and after ageing were compared to evaluate molecular level degradation upon prolong thermal exposure. A chemically diminished profile was observed for betaine surfactant after ageing in non saline medium, suggesting that the surfactant was degraded because of thermal exposure while the profiles of the alkyl polyglucosides were not altered before and after ageing in non saline medium. However, the C10/12 APG showed diminished absorbance after ageing in hard brine while the APG blend is seen to be stable under the Thamama reservoir conditions (both salinity and temperature).;Surfactant-brine compatibility studies at 90°C showed that the betaine surfactant will precipitate when brine salinity is in excess of 130, 000 ppm and divalent cations in excess of 18,000 mg/l, making it unfit for extreme salinity environments.;By investigating the effect of hardness on the performance of the surfactants, we realized that by stripping off divalent cations from the injection brine, the performance of the APG blend surfactant was enhanced even in extreme salinity in terms of micro-emulsion phase behavior and interfacial tension. Due to the robustness of the APG blend as observed from various tests, it was further evaluated for oil recovery efficiency on a set of oil wet core plugs from Thamama reservoir.;As the salinity and hardness of injection water seemed to be vital for efficiency of the surfactant, three scenarios were investigated to evaluate incremental oil recovery that can be achieved from APG surfactant flood. First scenario is surfactant flood with de-ionized water (as injection water) which is set as benchmark, case two is the surfactant flood with hard brine having a salinity of 263,000 ppm and specific hardness of 0.248. The last case is soft water with salinity maintained at 263, 000 ppm. Incremental recoveries achieved after tertiary surfactant flood on core plugs with similar properties were 18%, 9% and 13% respectively. The results are discussed in terms of rock-fluid and fluid-fluid interaction and possible detrimental effect of water hardness.