A defining characteristic of heavy and super heavy oilfields is the large spatial variation in fluid properties, such as oil viscosity, commonly seen within the reservoirs. Traditional heavy oil and tar sand exploration and production strategies rely significantly on the characterization of key reservoir heterogeneities and assessment of fluid saturations. While it is important to understand how these properties vary, the spatial distribution of fluid properties can often dominate production behaviour but surprisingly, are usually ignored! Heavy oil and tar sands are formed by microbial degradation of conventional crude oils over geological timescales. Constraints such as oil charge mixing, reservoir-temperature dependant biodegradation rate and supply of water and nutrients to the organisms ultimately dictate the final distribution of API gravity and viscosity found in heavy oil fields. Large-scale lateral and smallscale vertical variations in fluid properties due to interaction of biodegradation and charge mixing are common, with up to orders of magnitude variation in viscosity over the thickness of a reservoir. These variations are often predictable and can be integrated into reservoir simulation models in a manner similar to specifying geological heterogeneity. In this work, we describe and illustrate quantitative geological controls on fluid property variations and show how petroleum geochemistry can be used to rapidly produce high resolution fluid property images of tar sand and heavy oil reservoirs. The impact of viscosity variations in a heavy oil reservoir on production depends on recovery method. Numerical thermal reservoir simulations reveal that oil viscosity heterogeneity (i.e. a vertical viscosity profile in the reservoir) lowers the oil production volumes from steam assisted gravity drainage (SAGD) in geologically realistic reservoirs compared to results from equivalent models run with uniform average viscosity profiles. Similar results are found for the cyclic steam stimulation (CSS) process. In cases with viscosity profiles, the relatively high viscosity at the base of the reservoir slows the growth of the steam chambers relative to that in uniform viscosity reservoirs. We also describe how the chemical fluid heterogeneities can be used to predict oil viscosity from well cuttings and/or core or to: de-mix produced oils into zonal contributions from different parts' of the production well.