Performance forecasting of polymer flooding in Lower Fars heavy oil reservoir

Heavy oil reservoirs suffer from high oil viscosity, unfavorable mobility ratios, and poor sweep efficiency under waterflooding, particularly in the shallow Lower Fars sandstone reservoir of North Kuwait. This study develops a field-representative three-dimensional black-oil reservoir simulation model to optimize polymer flooding under these reservoir conditions. The model represents a 6-acre sector containing one vertical injector and one vertical producer separated by approximately 238 m. Reservoir heterogeneity, fluid properties, and initial pressure and saturation distributions were incorporated using a finely gridded geological model calibrated with core data. Concentration-dependent viscosity and adsorption of partially hydrolyzed polyacrylamide (HPAM) were included. Sensitivity analyses evaluated the effects of polymer concentration, polymer solution salinity, injection rate, and injection timing on oil recovery, reservoir pressure, and water cut. Waterflooding recovered only about 20% of the original oil in place. Under optimum conditions, polymer flooding increased recovery to approximately 47%, representing an incremental gain of 27%. The optimum design consisted of a polymer concentration of 283 ppm, salinity of 2,830 ppm, and an injection rate of 350 bbl/day. Under these conditions, polymer flooding increased the oil production rate by nearly sixfold and maintained the average reservoir pressure at approximately 290 psi. In contrast, higher salinities reduced recovery and weakened water-cut control, whereas initiating polymer flooding five years after waterflooding produced the highest recovery. The novelty of this work lies in the integrated optimization of key polymer flooding parameters, providing practical design guidelines for the Lower Fars reservoir and similar heavy oil reservoirs.