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1 Petroleum Reservoir Group, Alberta Ingenuity Center for Insitu Energy, University of Calgary, Calgary, Alberta, Canada T2N 1N4; slarter{at}ucalgary.ca
2 Petroleum Reservoir Group, Alberta Ingenuity Center for Insitu Energy, University of Calgary, Calgary, Alberta, Canada T2N 1N4
3 Petroleum Reservoir Group, University of Calgary, Calgary, Alberta, Canada T2N 1N4
4 Petroleum Reservoir Group, Alberta Ingenuity Center for Insitu Energy, University of Calgary, Calgary, Alberta, Canada T2N 1N4
5 Petroleum Reservoir Group, Alberta Ingenuity Center for Insitu Energy, University of Calgary, Calgary, Alberta, Canada T2N 1N4
6 Petroleum Reservoir Group, University of Calgary, Calgary, Alberta, Canada T2N 1N4
7 NRG School of Civil Engineering and Geosciences, University of Newcastle, Newcastle-upon-Tyne, NE1 7RU, United Kingdom
8 NRG School of Civil Engineering and Geosciences, University of Newcastle, Newcastle-upon-Tyne, NE1 7RU, United Kingdom
9 Petroleum Reservoir Group, University of Calgary, Calgary, Alberta, Canada T2N 1N4
10 Geological Survey of Canada, Calgary, Alberta, Canada T2L 2A7
Steve Larter is the Canada Research Chair in Petroleum Geology at the Department of Geology and Geophysics at the University of Calgary in Canada, the J. B. Simpson Chair of Geology at the University of Newcastle-upon-Tyne (United Kingdom), and codirector of the Alberta Ingenuity Center for Insitu Energy. He is interested in the origin and clean production of heavy oils and tar sand bitumen and in technologies for reduced- or zero-carbon emission recovery of fossil fuel energy. His current research interests include the nature of the deep biospheres of Earth and Mars and dating of petroleum reservoir charging.
Haiping Huang is professor of petroleum geology at the China University of Geosciences (Ph.D. from University of Newcastle-upon-Tyne in organic geochemistry) and is currently a research fellow at the University of Calgary. His research interests include petroleum accumulation and secondary alteration processes and application of biomarkers, nitrogen-sulfur-oxygen compounds, and isotopic signatures to petroleum exploration and development, with recent emphasis on geochemical proxies to monitor in-situ heavy-oil and tar sand recovery.
Jennifer Adams received a B.Sc. degree in geology at the University of Waterloo and an M.Sc. degree in hydrogeology at the University of Alberta. She worked on CO2 sequestration and basinal fluid property estimation with the Alberta Geological Survey before starting doctoral studies in simulation of petroleum biodegradation and the evolution of fluid properties in heavy oil fields with Steve Larter at the University of Calgary.
Barry Bennett was educated at the University of Newcastle-upon-Tyne (M.Sc. degree in organic petrology and organic geochemistry) and the University of Bristol (Ph.D. in organic geochemistry). His most recent interests include linking petroleum reservoir geochemistry with petroleum engineering and the origin of heavy oil and tar sands, as well as oil production issues.
Olufemi Jokanola obtained a B.Sc. degree in geology from Obafemi Awolowo University (Nigeria) and an M.Sc. degree in petroleum geochemistry from the University of Newcastle-upon-Tyne in 2003. He is currently pursuing doctoral studies in petroleum geology at the University of Calgary with Steve Larter and Andrew Aplin (Newcastle). His research is in cap-rock petrophysics and geochemistry, pore-pressure prediction, and modeling fluid transport in mudstones.
Thomas Oldenburg holds his diploma in chemistry from the University of Oldenburg (Germany). After research in petroleum geochemistry to become a Dr. rer nat in chemistry at the Forschungszentrum Jülich and University of Oldenburg, he joined Steve Larter at the University of Newcastle-upon-Tyne in 2001 before joining the Petroleum Reservoir Group at the University of Calgary to focus on studying the biogeochemistry of nonconventional petroleum resources.
Martin Jones obtained his Ph.D. at the University of Newcastle-upon-Tyne, United Kingdom. After his postdoctoral study at Newcastle and at Bristol, United Kingdom, he returned to Newcastle in 1989 as a laboratory manager. His main research interests are the biodegradation of hydrocarbons in surface and subsurface environments, heavy oils, and the development of analytical methods for biogeochemical applications.
Ian Head is professor of environmental microbiology at the University of Newcastle-upon-Tyne, United Kingdom. He has been interested in aerobic hydrocarbon degradation in surface environments for more than 15 years. Collaboration with Steve Larter and other petroleum geochemists initiated his research on oil biodegradation in petroleum reservoirs, providing a unique window on the interactions between the deep biosphere and the geosphere.
Cindy Riediger received her Ph.D. in earth sciences from the University of Waterloo and her M.Sc. degree in geological sciences from the University of British Columbia. She has more than 20 years of experience in petroleum systems research at the University of Calgary (1985–2005) and recently joined Shell Canada Ltd.
Martin G. Fowler received his M.Sc. degree and his Ph.D. in organic geochemistry from the University of Newcastle-upon-Tyne. Since 1986, he has worked at the Geological Survey of Canada on problems relating to petroleum geochemistry, including the origin of the Alberta tar sands. He is currently program manager for the Secure Canadian Energy Supply program.
The principal controls on the fluid properties of biodegraded oil systems have been determined by a combination of petroleum geochemistry, numerical modeling of oil biodegradation in reservoirs, and analysis of oil property data sets from a variety of geological settings. Petroleum biodegradation proceeds under anaerobic conditions in any reservoir that has a water leg and has not been heated to temperatures more than 80°C. In most reservoirs with low concentrations of aqueous sulfate, methanogenic degradation is a primary mechanism of petroleum degradation, whereas in waters containing abundant sulfate, sulfate reduction and sulfide production may dominate. Net degradation of petroleum fractions in reservoirs is primarily controlled by the reservoir temperature, the chemical compounds being degraded, and relationships between the oil-water contact (OWC) area and oil volume. The relative volumes of water leg to oil leg, prior level of oil biodegradation, and reservoir water salinity act as second-order controls on the process. Typically, degradation fluxes (kilograms of petroleum destroyed per square meter of oil-water contact area per year or kg petroleum m–2 OWC yr–1) for fresh petroleum in clastic reservoirs are in the range of 10–3–10–4 kg petroleum m–2 OWC yr–1 and increase with decreasing reservoir temperature, from zero near 80°C, to a maximum flux at the OWC of less than 10–3 kg petroleum m–2 OWC yr–1 at a temperature less than 40°C. At very low reservoir temperatures and with severely degraded oils, such as are seen in the near-surface Canadian tar sands at the present day, the net degradation fluxes are much less than maximum values. Nutrient supply from the aquifer and adjacent shales, mostly buffered by mineral dissolution, probably provides the ultimate control on the range of degradation flux values.
Oil compositional gradients and resulting oil viscosity variations are common on both reservoir thickness and field scales in biodegraded oil reservoirs and are a defining characteristic of heavy oil fields produced by crude-oil biodegradation. Continuous vertical gradients in the oil columns document episodic degradation for many millions of years, suggesting that the time scales of oil-field degradation and petroleum charging are similar. The flux-temperature relationship we have derived, coupled with typical reservoir charge histories, defines the range of variation of fluid properties seen in many biodegraded oil provinces and identifies oil charge, mixing of biodegraded and fresh oils, and reservoir-temperature history as the primary controls on fluid properties. These flux-temperature relationships are easily integrated into prospect charge modeling procedures; sensitivity analyses show that the limiting factor in fluid property predictions, using even this first-level approach, are ultimately constrained by the accuracy of current oil-charge modeling estimates. The absence today of any functional geochemical proxies for assessing oil-residence time in oil fields and the substantial uncertainty in petroleum-charging times estimated by forward basin modeling is a major obstacle to more accurate fluid-property predictions that needs to be addressed.
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