Heavy oil reservoirs under consideration for polymer flooding typically contain greater than 85% of the original oil in place (OOIP) after primary recovery and waterflooding. Many of these fields are operated at high producing water/oil ratios (WORs) only marginally above their economic limit due to additional production, handling, and treatment expenses that can average $3/m3 of water. Depending on timing of implementation, operators could achieve very high incremental recoveries approaching 20% OOIP and beyond, as suggested by the experiments conducted in this work. The main premise behind this thesis study is to develop fundamental knowledge of the rheology and flow behavior of polymeric fluids that is essential in creating a detailed screening protocol. The evaluation of these critical parameters is based upon the following: 1) fundamental rheological measurements of non-Newtonian polymeric fluids; 2) injectivity sandpack floods to determine in-situ dynamic viscosities through the concept of Resistance Factor, Fr; 3) immiscible displacement of heavy oil by water and polymers to determine microscopic displacement efficiency; 4) larger-scale, 3D physical modeling of the polymer flood process; and, lastly 5) numerical simulation. A specialized rheometer was used to determine the viscoelastic properties of both hydrolyzed polyacrylamides (HPAM) and hydrophobically associating polyacrylamides (HAP) used in heavy enhanced oil recovery (EOR) processes. The rheometric analyses indicated that improved resistance to flow due to elastic phenomenon were observed as a function of the polymer type, concentration, molecular weight, degree of hydrophobicity; however, solution shear history, salinity and temperature were found to have a slightly negative effect. Compared to traditional HPAMs, a medium density HAP showed an earlier onset of elastically-dominated flow as determined by its increased elasticity, characteristic relaxation time and Weissenberg number. Sandpack flood results suggested that HAP polymers can exhibit lower Fr values at higher injection rate (easier to inject near wellbore) and higher Fr values at in-situ, reservoir flow rates, i.e. 0.3 m/d (1 ft/d). Immiscible displacement tests from 1D sandpacks showed accelerated recovery from floods employing HAP polymers over HPAM polymers and incremental polymer flood recovery varied from 13.9 %OOIP (low concentration HPAM) to as high as 43 %OOIP (high concentration HAP). A 3D physical model was designed and fabricated to replicate the heavy oil recovery process. The data sets generated were representative of some of the average field recoveries from vertically-developed inverted 5-spot or staggered line drive heavy oil recovery schemes. The 3D model also provided unique insight into the visual renderings of the improved polymer over water displacement of heavy oil during the excavation of the model. The displacement was quite chaotic and fractal during waterflood (RF = 19.5 %OOIP after 0.78 PVs); while the subsequent polymer flood greatly expanded the floodable zones contacted by polymer, increasing the heavy oil recovery by an incremental 34.0 %OOIP (after 0.66 PVs). An additional 7.1 %OOIP was recovered during the 0.70 PVs of extended waterflood; however, much of this was due to displacement by polymer solution still remaining in the model, as oil recovery diminished greatly after dye breakthrough. The simulation of both 1D and 3D experimental physical models indicates that a unique solution to recovery and pressure behaviour could be found using CMG’s CMOST module by using experimental and chemical data inputs. Therefore the processes were satisfactorily modeled numerically.