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AAPG Bulletin


AAPG Bulletin, V. 86, No. 1 (January 2002), P. 55-74.

Copyright ©2002. The American Association of Petroleum Geologists. All rights reserved.

Modeling secondary oil migration with core-scale data: Viking Formation, Alberta basin

Elise B. Bekele,1 Mark A. Person,2 Benjamin J. Rostron,3 Randal Barnes4

1CSIRO Land and Water, Private Bag No. 5, Wembley, Western Australia, Australia 6913; email: [email protected]
2Department of Geological Sciences, Indiana University, 1001 East Tenth Street, Bloomington, Indiana, 47405
3Department of Earth and Atmospheric Sciences, University of Alberta, 1-26 Earth Sciences Building, Edmonton, Alberta, Canada, T6G 2E3
4Department of Civil Engineering, University of Minnesota, 500 Pillsbury Drive, Southeast, Minneapolis, Minnesota, 55455


Elise Bekele is currently a research scientist at Commonwealth Scientific and Industrial Research Organization (CSIRO) Division of Land and Water and collaborates with researchers in the Petroleum Division. She received her B.A. degree in geology from Cornell University (1991), M.S. degree in hydrology from the University of New Hampshire (1994), and Ph.D. in geology from the University of Minnesota (1999). Her graduate research focused on numerical simulations of abnormal fluid pressures and secondary oil migration in the Alberta basin, western Canada.

Mark Person received a B.S. degree in geology from Franklin and Marshall College in 1980. In 1990, Person received a Ph.D. in hydrogeology from Johns Hopkins University. For the past decade, he has studied the role of groundwater in petroleum generation and migration using mathematical modeling. He is a professor in the Department of Geological Sciences at Indiana University, where he holds the Malcolm and Sylvia Boyce Chair in Geological Sciences.

Ben Rostron obtained a B.Sc. degree in geological engineering from the University of Waterloo, Ontario (1986) and an M.Sc. degree (1990)and Ph.D.(1995) in geology from the University of Alberta. He is currently an assistant professor in the Department of Earth and Atmospheric Sciences at the University of Alberta. His research interests include petroleum hydrogeology, regional groundwater flow, hydrochemistry, numerical modeling, petroleum geology, and hydrocarbon migration/entrapment.

Randal J. Barnes is currently an associate professor at the University of Minnesota, Department of Civil Engineering. He received a B.S. degree in civil engineering from the University of Washington and an M.S. degree and Ph.D. in mining engineering from the Colorado School of Mines. His research interests focus on stochastic and deterministic modeling for geologic site characterization, geomechanics design, and natural resource exploitation.


This article comprised part of Elise Bekele's Ph.D. thesis and was funded in part by a doctoral dissertation fellowship from the University of Minnesota. Additional support was provided by grants from the Petroleum Research Fund, administered by the American Chemical Society under PRF 27964-AC8, 32479-AC2, the National Science Foundation Instrumentation and Facilities Grant to Mark Person, and the George and Orpha Gibson Hydrogeology Endowment at the University of Minnesota. We also gratefully acknowledge support from the Malcolm and Sylvia Boyce Geoscience Endowment at Indiana University. We appreciate the thoughtful review comments of Grant Garven and two anonymous reviewers.


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.

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