The effects of polymers on waterflooding of a limestone reservoir with or without a bottom water zone, as well as the effect of vertical and horizontal production wells on oil recovery, have been investigated in laboratory models. Sixteen core flood displacement tests were conducted to study the effect of relative oil-water layer thickness, polymer slug size, and well configuration in a production port. A qualitative comparison was made to show the difference between waterflooding and polymer-augmented waterflooding runs, where a light crude oil with a viscosity of 14.5 mPa.s was used. The results of the displacement tests showed that as the thickness of the bottom water zone increases, the ultimate oil recovery decreases. The selected polymer solution had a favorable impact on the waterflood performance. However the worse the conventional waterflood performance was, the more effective was the polymer as a mobility control agent. For instance, when the bottom water zone was approximately as thick as the oil zone, only about 25% of Original Oil in Place (OOIP) was recovered by a waterflood, whereas with a polymer as the mobility control agent, more than 55% of OOIP was recovered. For polymer injection, the effect of slug size was discussed with the aid of concentration curves and retention rate values; and a slug of 0.60 PV was obtained as optimal. In a conventional waterflood, the horizontal production well showed slightly better oil recovery than the vertical production well with a thin bottom water zone. In polymer-augmented waterflooding, higher oil recoveries were obtained with vertical production wells as compared to horizontal production wells. This was because of the early production of polymer solutions and reductions of the swept area from investigation of concentration curves.