The impact of geological and microbiological processes on oil composition and fluid property variations in heavy oil and bitumen reservoirs
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AbstractOil fluid property gradients at regional, field and reservoir scales are ubiquitous in heavy oil and bitumen deposits in the Alberta Basin and develop via biodegradation at oilwater transition zones, oil charge to the reservoir top and advective-diffusive mixing controlled by oil composition and reservoir geometry. Orders of magnitude variations in bitumen viscosity with reservoir depth adversely impact total recovery from SAGD and cold production operations which require uniform fluid mobility. Regional decreasing biodegradation trends to the west in northern Alberta result from reservoir pasteurization near 80°C, west of Peace River oil sands (PROS), and increasingly cooler time-integrated reservoir temperatures to the east, in the PROS and Athabasca oil sands. Simple charge-degrade box models of these deposits show that early oil charge around 100 to 90 Ma and limitation of the biodegradation rate due to reservoir temperature, water and nutrient availability and oil composition are required to predict observed westerly decreasing trends in oil biodegradation. Reservoir-scale concentration gradients in PROS reservoirs are related to reservoir geometry, local shale barriers and biodegradation rates controlled by water saturation, biodegradation susceptibility and diffusivity of hydrocarbon substrates. 1D compositional diffusion models match observed oil component concentration gradients by inclusion of geological barriers, variable thickness oil-water biodegradation zones. Numerical models of carbon isotope systematics identify the dominant reaction pathway of subsurface hydrocarbon biodegradation as methanogenic alkane degradation using carbon dioxide reduction, which produces isotopically light methane and heavy CO2 in solution gas. Basin models show that regional biodegradation significantly impacts oil quality, and fill, spill and leakage histories due to generation and migration of biogenic gas. Full physics models of hydrocarbon biodegradation predict replacement of thermogenic gas with biogenic gas, dissolution of biogenic CO2 into the water leg and development of gas caps over geological time. None of these models adequately predict fluid properties required for exploration and production operations, thus multivariate statistics models of hydrocarbon composition were developed to predict PROS dead oil viscosity. Oil viscosity assessed from core samples can increase dramatically during core storage and oil recovery and a core storage time correction algorithm was developed to minimize "noise" in calibration data sets.
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