Abstract
Abstract
Both laboratory experiments and field tests indicate that waterflooding with low salinity brine can improve oil recovery. The brine composition and the extent of dilution along with the oil phase and rock properties are all important in the process. Two consolidated reservoir cores with permeability of about 600 md were waterflooded up to 5 cycles by injection of high salinity formation brine of 29,690 ppm, low salinity brine of 1,479 ppm, and two concentrations of sodium chloride. Each core was tested with two crude oils. Either the more viscous crude oil or a viscous mineral oil was used to establish the desired initial water saturation at which mixed wettability was subsequently induced by adsorption from crude oil at reservoir temperature. Displacement tests showed that tertiary recovery from mixed wettability cores by injection of the low salinity brine was significantly higher (7 to 14% OOIP) than given by injection of the high salinity brine. Increased oil recovery was accompanied by slight change in the pH of the effluent brine and sharp increase in the pressure drop across the cores followed by slower decline. No clay was observed in the production stream and the oil/brine interface in the oil/brine separator was clear. No tertiary response occurred when the injection brine was changed to 8000 ppm NaCl solution. Further lowering to 1500 ppm NaCl resulted in 13% OOIP recovery. An additional 4% OOIP recovery was obtained by injection of low salinity brine. For a core that gave strong tertiary response, after replacement of crude oil by refined oil there was only slight recovery and small pressure response to low salinity brine flooding, even though the core was mixed wet because an adsorbed film still remained on the rock surface. Reversion to crude oil as the oil phase restored strong tertiary recovery and pressure response. A large increase in oil recovery was observed for secondary recovery by injection of low versus high salinity brine. Increase in pressure drop across the core was closely related to increase in oil recovery for both secondary and tertiary modes.
Introduction
The question of the effect of the salinity of injection brine on oil recovery was raised at least 65 years ago. Smith (1942) mentioned that initial studies with Kansas crude oil and cores showed no significant difference in recoveries for brine versus fresh water. Documented results for recovery of Bradford crude oil and sandstones with a range of permeabilities showed recoveries overall to be less for fresh water than for a brine of 40% higher viscosity (Smith 1942). The difference was ascribed to clay swelling. However, Martin (1959) observed increased recovery of heavy oil through injection of fresh water and suggested that the effects of clay swelling and emulsification were possible causes. Bernard (1967) concluded from laboratory tests on recovery of mineral oil that swelling clays and/or dispersion accompanied by increased pressure drop resulted in additional oil production by injection of fresh water or 1,000 ppm NaCl. In studies of recovery of crude oils, it was demonstrated that differences in mono- and divalent ion concentration in brine can affect oil recovery by spontaneous imbibition and by waterflooding and that the direction of change could depend on the crude oil (Jadhunandan and Morrow, 1995; Yildiz and Morrow, 1996; Morrow et al, 1998; Yildiz et al., 1999). Tang and Morrow (1997, 1999) obtained higher oil recovery by waterflooding with low salinity brine (LSB) down to salt concentrations that fall in the category of fresh water (up to about 1000 ppm) for both outcrop and reservoir rocks. Laboratory tests showed that necessary conditions for improved oil recovery by LSB flooding included the presence of clays, crude oil, and an initial water saturation. Tang and Morrow (1999) hypothesized that the mechanism of improved recovery involved mobilization of oil by limited release of clay from the rock surface.