Outline

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Outline

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

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In-situ SAGD
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• 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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Evaluation of Reactor Options

• ACR-700 (1983MWth, 731MWe)
• Primary coolant Light Water, Moderator Heavy
  Water
• Primary Outlet 326C, Fuel Canflex bundle
  SEU(slightly enriched Uranium) 2
• PBMR (400MWth, 165MWe)
• Primary coolant Helium, Moderator Graphite
• Primary outlet 900C, 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 316C, Fuel 4.20 wt 235U,
  sometimes MOX (mixed oxide) fuel

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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 Based on a 100,000 Bbl/day bitumen extraction plant Pressure Pressure
Based on a 100,000 Bbl/day bitumen extraction plant Based on a 100,000 Bbl/day bitumen extraction plant 2 Mpa 6 MPa
Heat Transfer Required (MWth) Low Performance 1230 1264
Heat Transfer Required (MWth) High Performance 820 843
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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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Layout for Gas Cycles
850C

• Eight PBMRs would be acceptable for this scenario

Scenario Bitumen (Bbl/day) SynCrude (Bbl/day)
1 253,000 -
2 166,000 -
3 - 98,000
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Economics
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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.

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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 US0.05/kWhr
• Buying price of hydrogen is assumed to be
  US2.50/kg of H2
• Natural gas price is assumed to be 8.00/mmBtu

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Economic Assumptions, Contd.

• 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, OM, 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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Nuclear Power Cost Assumptions
AP600 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
OM 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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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
Hydrogen Cost per unit bitumen (US/Bbl) Buy Hydrogen 2.506 2.506 2.506 2.506
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Cost Comparison of Natural Gas v. Nuclear
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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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Kyoto Protocol

• Canada has agreed to reduce greenhouse gas
  emissions by 6 relative to the 1990 level of 612
  Mt by 2012. (575 Mt)
• Canadas 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)

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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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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.

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Questions