Micro Emulsion Phase Behavior of a Cationic Surfactant at Intermediate Interfacial Tension in Sandstone and Carbonate Rocks

Abstract

Based on the conventional approach, the trapped oil in rock pores can be easily displaced when a Winsor type (III) microemulsion is formed in the reservoir during surfactant flooding. On the other hand, the Winsor type (III) involves three phase flow of water, oil, and microemulsion that causes considerable oil phase trapping and surfactant retention. This work presents an experimental study on the effect of microemulsion phase behavior during surfactant flooding in sandstone and carbonate core samples. In this study, after accomplishing salinity scan of a cationic surfactant (C16–N(CH3)3Br), the effects of Winsor (I), Winsor (III) and Winsor (II) on oil recovery factor, differential pressure drop, relative permeability, and relative permeability ratio were investigated extensively. To carry out a comparative study, homogeneous and similar sandstone and carbonate rocks were selected and the effects of wettability alteration and dynamic surfactant adsorption were studied on them. The results of oil recovery factor in both rock types showed that Winsor (I) and Winsor (III) are preferred compared to Winsor (II) phase behavior. In addition, comparison of normalized relative permeability ratio at high water saturations revealed that Winsor (I) has more appropriate oil and water relative permeability than Winsor (II). The results presented in this paper demonstrate that optimum salinity which results in higher recovery factor and better oil displacement may occur at salinities out of Winsor (III) range. Therefore, the best way to specify optimum salinity is to perform core flood experiments at several salinities, which cover all phase behaviors of Winsor (I), Winsor (III), and Winsor (II).