Outline

2. Outline • SAGD • Plant Scenarios • Nuclear Plant Designs • Thermo-hydraulic Analysis • Economics • Carbon Dioxide • Conclusion • Future Work

3. In-situ SAGD

4. Scenario One: • Production – SAGD Process Heat Only • Electricity from off-site source • Product – Diluted bitumen • Scenario Two: • Production – SAGD Process Heat and Electricity for on-site needs • Product – Diluted bitumen • Scenario Three: • Production – SAGD Process Heat, Electricity for on-site needs, and Hydrogen for upgrading needs • Syncrude

5. Evaluation of Reactor Options • ACR-700 (1983MWth, 731MWe) • Primary coolant: Light Water, Moderator: Heavy Water • Primary Outlet: 326°C, Fuel: Canflex bundle; SEU(slightly enriched Uranium) ~2% • PBMR (400MWth, 165MWe) • Primary coolant: Helium, Moderator: Graphite • Primary outlet: 900°C, Fuel Pebbles: 60mm, outer dia., encloses ~11,000 C/SiC coated fuel microspheres of UO2 • AP600 (1940MWth, 600MWe) • Primary Coolant and Moderator: Light Water • Primary Outlet: 316°C, Fuel: 4.20 wt % 235U, sometimes MOX (mixed oxide) fuel

6. Extraction Parameters • The conditions for extraction vary depending on the quality of the tar sand bed • Calculations for this study were conducted using low quality tar sand bed conditions

7. Layout for Steam Cycles • Either two ACR-700s or two AP600s in parallel would be acceptable for this scenario

8. Layout for Gas Cycles 850°C • Eight PBMRs would be acceptable for this scenario

9. Economics

10. Purpose of economic analysis • Should natural gas or nuclear be used for the SAGD extraction process? • Should the electricity requirements of the plant be fulfilled by buying electricity off the power grids, or by making it at the plant? • Should the hydrogen required for the bitumen upgrading process be bought from private suppliers, or produced at the plant? **This is meant to be a comparison between nuclear and natural gas energy sources for this application, not an estimate of the actual full cost of the facility.

11. Economic Assumptions • All costs are in US dollars (US$) • The lifetime for the plants are assumed to be 30 years, and the Net Present Value (NPV) is calculated for a 10% discount rate • No inflation is assumed • Easy access to Alberta electricity power grid is assumed, price is ~US$0.05/kWhr • Buying price of hydrogen is assumed to be ~US$2.50/kg of H2 • Natural gas price is assumed to be $8.00/mmBtu

12. Economic Assumptions, Cont’d. • A 90% learning curve is assumed for building additional nuclear reactors • Costs do not include that of processing and upgrading plants as these are held constant and independent of heat source used. • 4 categories of cost: capital, O&M, fuel, and decommissioning • 3 final types of costs looked at: Cost of Process Heat, Cost of Electricity, and Cost of Hydrogen Production

13. Nuclear Power Cost Assumptions

14. Hydrogen Production Costs

15. Cost Comparison of Natural Gas v. Nuclear

16. Sensitivity of Total Cost to Changes in Capital Cost Capital cost is an initial fixed cost, unlike natural gas cost which is a recurring cost over the lifetime, i.e. capital cost has no future volatility For a 25% increase in the price of natural gas, the gas extraction costs rise 18%.

17. Economic Conclusions • Given current natural gas costs, nuclear is a viable alternative for producing process heat for SAGD. • Producing electricity using nuclear power is more cost-effective than buying it off the Alberta power grid or producing it using natural gas. • While Steam-Methane Reforming has historically been a cheaper process than High Temperature Steam Electrolysis, the cost of HTSE with nuclear power is now comparable to SMR due to high natural gas cost. • Overall, using nuclear power is a competitive alternative to natural gas due to high prices and volatility of natural gas, and new compliance regulations of the Kyoto protocol

18. Kyoto Protocol • Canada has agreed to reduce greenhouse gas emissions by 6% relative to the 1990 level of 612 Mt by 2012. (575 Mt) • Canada’s Climate Change Plan (2002/2005) • Reduce emissions to 305 Mt by 2012 • In 2012 (at 100Mt CO2) oil sands emissions would represent 17% of the total Kyoto target (575 Mt), and 29% of Climate Change Plan target (305 Mt)

19. Conclusions • Nuclear Process Heat applications in Oil Recovery from Tar Sands are possible for steam production, electricity generation and syncrude refining with hydrogen production at costs that are lower than natural gas. • Canadian Kyoto agreements will be challenged without the use of nuclear energy in oil sands extraction processes. Approximately 100 Mt CO2 emissions are avoided. • Additional site specific analyses are needed to refine the nuclear energy applications to meet industry needs.

20. Updates & Extensions Needed • Updated process requirements • Updated nuclear capital costs • Hard look at practical implementation challenges • Safety implications • More in-depth CO2 analysis • More in-depth natural gas displacement analysis • Regulatory needs and insurance issues • Conceptual business plan possibilities

21. Acknowledgements This study was prepared as an MIT class design project in the Department of Nuclear Science & Engineering. The authors of the original study included: G. Becerra, E. Esparza, E. Helvenston, S. Hembrador, K. Hohnholt, T. Khan, D. Legault, M. Lyttle, C. Murray, N. Parmar, S. Sheppard, C. Sizer, E. Zakszewski, K. Zeller Assistance and information were also provided by: Ryan Hannink of MIT, Dr. Julian Lebenhaft of AECL, William Green of MIT, The Canadian Nuclear Safety Commission, Westinghouse Electric Company, James Fong of Petro-Canada, Bilge Yildiz of Argonne National Laboratory, Brian Rolfe of AECL, Michael Stawicki and Professor Mujid Kazimi of the MIT Nuclear Science and Engineering Department, Thomas Downar of Purdue, Daniel Bersak of DRB photography, MIT alumnus Curtis Smith of INL, and the faculty members of the MIT Department of Nuclear Science and Engineering.

22. Questions