This paper reports the results of laboratory scale screening of different chemicals for their microeumlsion generation capabilities to be eventually recommended for non-thermal heavy oil recovery (chemical flooding). The study was performed through visualization of microemulsions generated using vials and microscopic images. The impact of salinities of brine on the emulsification was studied thoroughly in order to identify the synergy between the selected chemicals and the heavy oil. An alcohol propoxy sulfate surfactant from the Alfoterra series, Alfoterra S23-7S-90, a nonionic surfactant HORA-W10, gave good emulsion formation results at low salinity conditions (2.5 wt. %, 3.8 wt. %). Polysorbate-type nonionic surfactant Tween 20 gave good emulsion formation at high salinity conditions (6.35 wt. %, 7.6 wt.%). Their emulsion formation performance with a crude heavy oil of viscosity 4,812cP and 11.74 °API helped create an initial correlation of performance with the composition of crude oil and synthetic brine samples of various salinities. Attempts were also made to stabilize oil-in-water emulsions formed with Alfoterra S23-7S-90, HORA-W10, Tween 20 using nanofluids (metal oxides), sodium carbonate, and an anionic polyacrylamide-based polymer (PolyFlood MAX-165). Emulsions were visualized under the Axiostar plus transmitted-light microscope and their stability was studied in order to screen the most optimal chemical (or chemical combinations) available for low cost heavy oil recovery.

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