Pore-Scale Displacement Dynamics of Oil Recovery during Viscoelastic Fluid Injection in Oil-Wet Carbonates

Heavy oil recovery from oil-wet carbonate reservoirs remains a major challenge due to the high oil viscosity, unfavorable mobility ratio, and poor sweep efficiency in such systems. Understanding oil production under various enhanced oil recovery (EOR) mechanisms and predictive modeling/simulation in these reservoirs has also been particularly difficult due to the limited knowledge of the governing pore-scale displacement processes. This gap in understanding becomes even more evident for viscoelastic fluids. Hence, this study is designed to probe these pore-scale subtleties while injecting viscoelastic polymer and surfactant-polymer (SP) solutions. To this end, a series of multistage waterflooding, polymer flooding, and SP flooding tests were conducted across both capillary-dominated and viscous-dominated flow regimes under reservoir-representative conditions and on oil-wet miniature Prairie Shell carbonate rock samples. The flow tests were performed using a core-flooding apparatus integrated with a high-resolution X-ray imaging system to acquire three-dimensional pore-scale fluid distribution maps. These data were analyzed to characterize in situ wettability, quantify fluid saturations, and evaluate sweep efficiencies and displacement mechanisms. The results showed that the waterfloods recovered only 51-54% of the initial oil in place under capillary-dominated conditions and 67-68% under viscous-dominated conditions. In contrast, polymer and SP flooding increased recovery factors to, respectively, 61 and 69% under the capillary-dominated flow regime and 91 and 93% under the viscous-dominated flow regime. Pore-scale data analysis revealed that oil production occurred primarily through interface movement and piston-like displacements. The polymer and SP solutions have also mobilized wetting oil layers on pore walls and in the corners through viscoelastic pulling effects, which were not observed during the waterfloods. Moreover, the SP flooding outperformed polymer flooding at low injection rates since the surfactant solution lowered the oil-brine interfacial tension, reduced the entry capillary pressures, and emulsified some of the trapped oil clusters into smaller globules. Both polymer and SP solutions yielded comparable recoveries at higher flow rates as globule mobilization and ganglion dynamics dominated the displacement processes in both cases. These findings were further validated through pore-by-pore analysis of fluid occupancies.