Examining the Desaturation Potential of Low and High-Salinity Viscoelastic Polymer Solutions at High Salinity and High Temperature Carbonate Reservoir Conditions

Over the last two decades, high interest has been shown to explore whether viscoelastic polymer solutions can reduce the capillary-trapped residual oil saturation (Sor) under practical reservoir conditions. To characterize this relatively less explored potential and identify the mechanisms that contribute to Sor reduction, we measured capillary desaturation curves (CDC) for viscoelastic polymer solutions, along with the evaluation of their ability to alter wettability. The studies were performed using both low-and high-salinity viscoelastic polymer solutions at high salinity and high temperature carbonate reservoir conditions. A combination of bulk and in-situ rheological measurements, contact angle experiments, and desaturation experiments were conducted. Desaturation experiments were performed using 2500-ppm and 4000-ppm acrylamide-ATBS-copolymer solutions prepared in 5760-ppm-TDS and 57600-ppm-TDS brines in 105-to-111-mD oil-wet limestone cores saturated with 2.8-cP oil and 257600-ppm formation brine at 95°C. The desaturation experiments involved: a) performing bump water flooding up to 64 ft/day and a subsequent sequential glycerin flood to ensure that the residual oil was highly discontinuous and strongly trapped, and the core was well-swept; and b) initiating the desaturation process with polymer solutions using an imposed flux of 0.05 ft/day and continuing up to 100 ft/day. Bump water flooding with high salinity brine and glycerin flood reduced the oil saturation by 25-30% in both experiments. At low flux rates (from 0.05 ft/day to 1 ft/day), both low and high salinity polymers did not reduce the oil saturation further. Such behavior is observed even though a) the shear thickening onset was noted at 0.25 ft/day for both solutions, and b) a slight reduction in contact angle (2-to-7 degrees) was observed. At 5 ft/day, both low and high polymer solutions showed a noticeable reduction in Sor—at computed critical capillary numbers of 4.0×10^-5 and 4.82×10^-5, respectively. Increasing the flux rate further up to 100 ft/day resulted in significant further oil desaturation, yielding additional residual oil recoveries of ~13% for the low salinity polymer solution and ~11% for the high salinity polymer solution. Although Sor reduction was observed at 5 ft/day in the lab, calculations indicate that achieving a flux above 5 ft/day in the target reservoir application and a significant Sor reduction would only be accomplished within ~30 ft from the wellbore. In this work, CDC curves for low and high-salinity viscoelastic polymer solutions were reported for the first time under high salinity and high temperature oil-wet carbonate conditions. Examinations and interpretations of the developed CDC curves indicate that the observed Sor reduction in the lab cannot be expected in the carbonate reservoirs for the well spacings typically used for polymer flood projects.