On Charging of Oil Sands Systems Over Geological Time Scales
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2021-09-01
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Abstract
In typical reservoir simulation modelling, well placement and operating conditions are optimized to maximize the amount of oil that is extracted from the reservoir. Here, for the first time, the opposite is done – the filling of a point bar porous body with oil that biodegrades to yield a bitumen-filled reservoir is examined. For the first time, a detailed reactive reservoir model is explored where the geology of a point bar system is incorporated as well as a simple biodegradation model is used to determine how a bitumen reservoir results. The results show that the biodegradation oil charge model in a point bar geological model demonstrates that heterogeneity influences the compositional gradient distribution of heavy oil. Although during the charging process, oil distributes in the reservoir based on the geological properties, the deposition results in viscosity heterogeneity within the reservoir. Biodegradation occurs at the oil-water contact at the oil front eventually resulting in oil with viscosities orders of magnitude higher than that of the original charge oil. The results also demonstrate that the highest oil viscosity is found at the lower regions of the reservoir consistent with published oil sands core data.
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Chang, R. (20201). On Charging of Oil Sands Systems Over Geological Time Scales (Master's thesis, University of Calgary, Calgary, Canada). Retrieved from https://prism.ucalgary.ca.