Spontaneous Imbibition of Aqueous Surfactant Solutions into Neutral to Oil-Wet Carbonate Cores: Effects of Brine Salinity and Composition

Abstract

Improved oil recovery from oil-wet, low-permeability, and fractured carbonate reservoirs is a great challenge. Water injection based on spontaneous imbibition from the fractures into the matrix blocks, in combination with a wettability alteration process, seems to be an actual method. The present paper adds more important information about the mechanism for wettability alteration of oil-wet carbonate rock, using cationic surfactants of the alkyltrimethylammonium type, in regard to brine salinity and composition. The oil recovery at low temperature (40 °C) is delayed as the salinity increases, because of a decrease in the critical micelle concentration of the surfactant, but the salinity effect seems to vanish at higher temperatures (70 °C). In chalk, improved oil recovery has been observed when sulfate is added to the imbibing fluid, especially at low temperatures (40 °C). At higher temperatures (70 °C), the effects of sulfate also vanish in this case. The catalytic effect of sulfate is of minor importance when dolomite cores are used. A model for the catalytic effect of sulfate is suggested and confirmed by advancing contact-angle measurements on calcite, dolomite, and magnesite crystals.