This study documents and attempts to describe the processes leading to the formation and preservation of exposed oil, water, and paleo-gas contacts at the McMurray Formation type section, Alberta, Canada. The McMurray Formation type section, a part of the Athabasca Oil Sands Deposit (AOSD), the largest exhumed oil reservoir on Earth, is unparralled, still underutilized, natural laboratory for veryfing and refining existing, and developing new concepts, for oil migration and post oil-emplacement fluid diffusion and biodegradation processes in a sedimentologically complex reservoir setting. Exposures, coupled with adjacent borehole data, provide a three-dimensional insight into reservoir heterogeneities and their influence on oil migration, entrapment, post-emplacement fluid mixing, and biodegradation processes and products, in a hierarchical and chronological order from early charge to present-day conditions. The principles of oil above water and of horizontal or tilted oil/water contacts are challenged by outstanding examples of: (i) centimetre to decimetre scale inter-fingering oil-water stringers/contacts, created by capillary pressure differences and partial charge; (ii) irregular oil-water contacts in both clean and heterogeneous reservoirs characterized by gravitational effects caused by severe biodegradation that caused the formation of extra heavy-oil commonly referred to as “bitumen” that sank through the water column; (iii) occurrences of multiple metre-scale intervals with less than 50% oil saturation, commonly referred to as lean zones that formed during microbial gas generation following oil entrapment. Studied contacts provided excellent opportunity to study oil migration and charging mechanisms from pore and sedimentary bed to reservoir scale at various stages of oil migration into the reservoir, as well as oil, water, and gas re-migration within the reservoir (trap). Described exposures can play an additional role in advancing geoscience education, petroleum exploration, reservoir characterization, field development, and production optimization studies.

Bitumen reservoirs dominated by inclined heterolithic stratification (IHS) formed in large point bars of the Aptian (Lower Cretaceous) McMurray Formation in the northwestern part of the Corner oil sand lease (Alberta, Canada) were investigated to establish their value. Hybrid production technologies were applied to thin pay, typified by homogeneous reservoir sand units thicker than 5 m at the base overlain by IHS (so-called ‘thin pay’), as well as IHS-dominated reservoirs in which the IHS extends down to the base of the reservoir. High-resolution seismic data and well data (core, dipmeter, HMI) were used to map four facies associations, comprising a total of 16 sedimentary facies, as well as various fluid contacts to assist in reservoir characterization and risk assessment. The conceptual depositional model was based on the analysis of the migration and re-orientation history of the IHS-dominated point bars reflecting lateral accretion, downstream migration, rotation and relocation of the bars. Multiple reactivation events, which control the heterolithic nature and reservoir quality of the deposits, create developable “pools”. Seven electrofacies (with generally increasing mud content) were defined and used as input to construct vertical proportion curves that relate the electrofacies distribution to geomodel statistics in the main reservoir zone. At the electrofacies scale, numerical effective porosity-permeability models were created using micromodeling and minimodeling concepts. The geometrical shape of the electrofacies in the geomodel was investigated using non-stationary Truncated Gaussian (TG) facies simulation to enforce the stacking patterns. Each geomodel area was characterized using one variogram to efficiently compute the horizontal and vertical variogram ranges and average azimuths. Sequential Gaussian simulation (SGS) was used to map the distribution of key petrophysical parameters such as effective porosity, effective water saturation and V_shale. Empirically derived saturation versus elevation profiles for each electrofacies were included in the modeling. The distributions from the micro- and mini-modeling were introduced using probability field (P-field) simulation. To investigate the amount of connected resources (the degree of connectivity of good sand as well as IHS) were extractable flow simulation studies were performed at the pad scale. In preparation for reservoir simulation, connectivity calculations within the local pool geomodel realizations were tailored for the reservoir heterogeneities (i.e., IHS) that are expected to have a major impact on the specific thermal and gravity drainage extraction processes. The geomodel realizations were ranked by expected pseudo-dynamic behaviour with connected exploitable pay as a critical parameter.