The Athabasca oil sand deposit, the world's largest petroleum accumulation, contains an estimated 1.7 trillion bbl of heavily to severely biodegraded oil, with API gravities ranging from 6 to 10. Although reservoir characterization has been the subject of many studies in the region, very little attention has been given to petroleum (bitumen) characterization and particularly to its reservoir-scale relationship with the host sediments.

In this study, variation in the bitumen physical and chemical properties were measured on a suite of samples. These were obtained from numerous cores from various reservoir types and geographic areas of the Athabasca oil sand deposits. The variation in bitumen viscosities and changes in the hydrocarbon composition caused by varying levels of biodegradation were interpreted using molecular markers. These data were integrated into the reservoir facies framework and interpreted in the context of various reservoir configurations.

The bitumen composition and physical properties are highly variable on vertical and lateral scales. In general, the viscosity of the bitumen residing at the base of an oil column may be an order of magnitude greater than the bitumen located shallower in the reservoir. Although this is a general rule, results also locally show anomalous inverse gradients and steps in compositional trends. These coincide with paleo- and/or present-day geologic features that include the presence and/or absence of oil-water contacts, vertical and lateral barriers that create reservoir compartments, and variation in lithologies, porosity, and permeability. Qualitative and quantitative analyses of bitumen molecular composition within the sedimentologic framework demonstrate that each reservoir compartment behaves as an independent bioreactor; bitumen is more degraded within porous and permeable strata than within the comparable interbedded sand shale sequences, and bitumen biodegradation is intensified in highly water-saturated zones within the petroleum column. In addition to biodegradation along the basal (paleo-) oil-water contact, these complex variations are explained by the complex geohistory of the petroleum charge and in-reservoir fluid (petroleum, water, and gas) mixing, including associated variations in oil biodegradation behavior.

In addition, our interpretation of the interplay through time and space of depositional setting and biodegradation suggests that top water and other highly water-saturated zones are related to the formation and the subsequent depletion of gas caps likely derived from microbial gas generation that followed petroleum entrapment.

Implications to reservoir developments are immense. We suggest that integrated baseline studies of sedimentologic and geochemical variation interpretation allow for mapping and prediction away from well control of the extent of top gas, top water and low-bitumen, high-water saturation zones, as well as bitumen properties variation throughout the reservoir. Geochemical data from integrated baseline studies are a powerful tool for identifying barriers or baffles to vertical fluid communication, whereas they may also be applied toward production optimization and allocating production along horizontal wells, including the assessment of steam chamber growth in oil sand operations.