Polymer injection as a tertiary EOR method has been carried out in both, vertical and horizontal wells, to improve oil recovery because of its lower mobility ratio. The advantages of horizontal polymer flooding seem to outweigh those of vertical wells. It has been shown, that polymer flooding in horizontal wells allows higher injection rates and injection under matrix conditions, which is more difficult to achieve in vertical wells. It has been shown that polymer injection into horizontal wells can significantly improve incremental oil production by enhancing the sweep efficiency – as compared to vertical wells. Polymers being non-Newtonian fluids, thus having a non-linear shear stress and shear rate relationship, undergo shear thinning or shear thickening at high Darcy velocities, which affects their effectiveness. In this respect, the first part of this thesis is devoted to the investigation of the polymer rheology as it flows through the liner slots into the formation – hence injectivity investigations. The thereby considered parameters include the pressure losses that occur in the horizontally lying liner and the Darcy velocities encountered in the liner slots as well as during radial flow of the polymer solution into the near wellbore region. The results reveal an insignificant frictional pressure drop along the horizontal wells and the velocities at which polymer degradation would occur were not reached. The second part of this thesis concentrates on the evaluation of cumulative incremental oil recovery at different well spacings and well lengths of horizontal wells from homogeneous and heterogeneous reservoir models. It is necessary to investigate this matter in order to optimise the size of the injection and production pattern i.e. the chemically affected reservoir volume (CARV). The size of the pattern has a major importance on the economics because this determines for example, the operational expenditure (opex) arising from the costs of polymers and the capital expenditure (capex) arising from the drilling and completion costs. Hence, the technical costs, which when set in relation to the discounted cumulative incremental barrels of oil produced, yield the unit technical cost and an optimum well length. The utility factor of each model is calculated and compared to the injection duration. The results of the homogeneous and heterogeneous simulations indicate that polymer solutions create a stable flooding front accounting for the better sweep efficiency as compared to water flooding. From the homogeneous simulations, the results showed that lager CARV should be preferred over smaller ones. In the heterogeneous models, the variograms with their azimuths perpendicular to the wells had higher incremental oil production.