The Viking Formation in the Alberta basin contains approximately 88.7 x 106 m3 (5.579 x 108 bbl) of recoverable oil, which migrated more than 200 km, as indicated by oil-source rock correlation. Simulating the mechanisms controlling secondary oil migration (hydrodynamics, buoyancy, and permeability heterogeneity) is beneficial for exploration, but it remains extremely difficult to predict oil occurrences. Although core-scale petrophysical data for the Viking Formation are abundant (> 69,000 core plugs), the extent of fracture permeability and permeability alteration due to diagenesis are unknown. Moreover, sampling bias may affect the permeability distribution in unpredictable ways. Numerical simulations of oil migration were conducted using the highest core-plug measurement of permeability from each borehole to obtain an upper bound on oil migration velocities. This permeability model is not appropriate for simulating stratigraphic entrapment of oil, but it does reveal that core-scale data are in the appropriate range of magnitude to have allowed significant oil migration. Regional groundwater flow was essential for charging several of the largest and most distant oil fields in the Viking Formation. Maximum core-plug permeability data are useful for modeling the extent of secondary oil migration and may have applications to fluid flow and transport modeling in other foreland settings.