Nuclear Energy for Oil Extraction in Canadian Tar Sands: Integration of Nuclear Power with In-Situ Oil Extraction
Professor Andrew C. KadakProfessor of the Practice
Massachusetts Institute of TechnologyNuclear Science & Engineering
Life Cycle Assessment Special Nuclear Session
November 3rd, 2006, 1:30pm-3:00pm
University of Calgary
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Integration of Nuclear Power with In-Situ Oil Extraction
Outline• SAGD• Plant Scenarios• Nuclear Plant Designs • Thermo-hydraulic Analysis• Economics• Carbon Dioxide• Conclusion• Future Work
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Integration of Nuclear Power with In-Situ Oil Extraction
In-situ SAGD
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Integration of Nuclear Power with In-Situ Oil Extraction
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
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Integration of Nuclear Power with In-Situ Oil Extraction
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
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Integration of Nuclear Power with In-Situ Oil Extraction
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
Based on a 100,000 Bbl/day bitumen extraction plant
Pressure
2 Mpa 6 MPa
Heat Transfer Required
(MWth)
Low Performance
1230 1264
High Performance
820 843
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Integration of Nuclear Power with In-Situ Oil Extraction
Layout for Steam Cycles
• Either two ACR-700s or two AP600s in parallel would be acceptable for this scenario
Scenario Bitumen (Bbl/day) SynCrude (Bbl/day)
1 332,000 -
2 199,000 -
3 - 114,000
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Integration of Nuclear Power with In-Situ Oil Extraction
Layout for Gas Cycles
• Eight PBMRs would be acceptable for this scenario
Scenario Bitumen (Bbl/day)
SynCrude (Bbl/day)
1 253,000 -
2 166,000 -
3 - 98,000
850°C
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Integration of Nuclear Power with In-Situ Oil Extraction
Economics
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Integration of Nuclear Power with In-Situ Oil Extraction
Purpose of economic analysis
1.Should natural gas or nuclear be used for the SAGD extraction process?
2.Should the electricity requirements of the plant be fulfilled by buying electricity off the power grids, or by making it at the plant?
3.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.
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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 $8.00/mmBtu
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Integration of Nuclear Power with In-Situ Oil Extraction
Economic Assumptions, Cont’d.• A 90% learning curve is assumed for building additional
nuclear reactors
• Costs do not include that of processing and upgrading plants as these are held constant and independent of heat source used.
• 4 categories of cost: capital, O&M, fuel, and decommissioning
• 3 final types of costs looked at: Cost of Process Heat, Cost of Electricity, and Cost of Hydrogen Production
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Integration of Nuclear Power with In-Situ Oil Extraction
Nuclear Power Cost AssumptionsAP600
1 unit
AP600
2 units
ACR-700
1 unit
ACR-700
2 units
PBMR
Capital Rate ($US/kW)
1687.2 1520 1693.40 1525.55 1250
Fuel Rate (US mills/kWhe)
5.0 5.0 2.6 2.6 6.0
O&M Rate (US mills/kWhe)
8.0 10.0 7.05 8.82 3.0
Decommisioning Rate (US mills/kWhe)
1.25 1.0 0.6175 0.494 0.6
Operating Life (yrs)
30 30 30 30 30
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Integration of Nuclear Power with In-Situ Oil Extraction
Hydrogen Production Costs
Natural Gas PBMR ACR-700 AP600
Hydrogen Cost per unit bitumen ($US/Bbl)
Make Hydrogen
1.754 1.636 1.901 1.811
Buy Hydrogen
2.506 2.506 2.506 2.506
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Cost Comparison of Natural Gas v. NuclearCost Comparison of Natural Gas vs. Nuclear
0
500
1000
1500
2000
2500
3000
3500
Process Heat Electricity Hydrogen
Type of Cost
Lif
etim
e C
ost
ove
r 30
yea
rs (
$M)
Market Natural Gas PBMR ACR-700 AP600
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Integration of Nuclear Power with In-Situ Oil Extraction
Sensitivity of Total Cost to Changes in Capital Cost
PBMR ACR-700 AP600
Change in Total Cost for a 25% increase in Capital Cost
11.3% 13.9% 12.5%
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%.
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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
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•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)
Kyoto Protocol
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Integration of Nuclear Power with In-Situ Oil Extraction
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.
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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
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AcknowledgementsThis 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.