Comparison of Secondary and Tertiary Recovery with Change in Injection Brine Composition for Crude Oil/Sandstone Combinations

Abstract Numerous examples of dependency of waterflood efficiency on brine composition have been observed for sandstones. Improved oil recovery depends on complex crude oil/brine/rock (COBR) interactions. Elucidation of the circumstances and mechanisms of increased oil recovery still requires extensive laboratory testing. Special attention is being given in laboratory and pilot tests to increased recovery by injection of low salinity brine in both secondary and tertiary modes. Investigation of connate brine composition as a key variable has been extended to variation in initial water saturation (Swi). Mixed-wettability (MXW) cores were prepared by aging with crude oil at reservoir temperature for a range of initial water saturations. Oil recovery as % original oil in place (OOIP) generally increased with initial water saturation for secondary recovery by injection of low salinity brine. CS crude oil/Berea sandstone combinations were essentially insensitive to displacement with low salinity brine in secondary mode even when the injection pressure was double that for oil recovery by injection of reservoir brine (RB). However, significant increase in tertiary mode (about 6% OOIP) was observed for the same COBR combination when low salinity brine was injected after establishing residual oil by injection of reservoir brine. Low salinity brine floods with Minnelusa oil and 400 md Berea sandstone showed more than 13% OOIP increase in recovery over that given by flooding with reservoir brine. For the Minnelusa oil, however, very little additional oil was produced in tertiary mode. From available data, response to injection of low salinity brine in tertiary mode was clearly highest for reservoir rock and crude oil. Overall, rock properties are the most important factor in improved recovery by injection of low salinity brine.