The average primary oil recovery worldwide is around 35% of the original oil in place (OOIP). Various enhanced oil recovery (EOR) approaches are generally required to recover the remaining OOIP. Apart from the reservoir properties, the capillary pressure that governs fluid distribution and displacement behavior in the reservoir is also affected by the interfacial tension and wettability. Both IFT and wettability are considered to be key effective factors that affect EOR.
This study investigated the effect of reservoir brine compositions on the interfacial tension (IFT) between synthetic formation brines and an Australian crude oil with pressures and temperatures up to 4000 psi and 140 °F, respectively. A series of measurements on the density, viscosity and IFT have been conducted.
The brines, with total dissolved solids ranging from 3,820 to 38,200 ppm, consist of a diverse range of ions including sodium, lithium, magnesium, calcium, bromide, chloride, sulfate, bicarbonate and carbonate.
The experimental results indicate that with all the synthetic brines investigated, the IFT declines with increasing temperature and pressure. Furthermore, it was observed that the IFT reduction with temperature was dependent on the pH values of the brine. Bicarbonate, carbonate, sulfate, and magnesium ions significantly decreased the IFT by up to 40% through either lowering the free surface energy or increasing the surface area. Coreflooding experiments using low salinity water have yielded an incremental EOR of 5.4% OOIP, suggesting that wettability alteration caused by the change of ion balance in the residual water may be responsible for the observed EOR.
Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions
