Deposits of unconventional fuels—both crude oil and natural gas—occur in geological environments with very low energy. In oil shales, such fuels initially were deposited as hydrocarbon material called bitumens in host sedimentary rocks. In oil sands, the bitumens migrated from their original depositional environment into more porous deposits.
Such deposits, whether asphaltic sandstones in western Canada (tar sands) or pyrobituminous shales in the western United States (oil shales), have very low fluid transmissibility reflecting in part the compaction of fine-grained detritus and their absorption of hydrocarbons. The exploitation of these low-energy deposits/reservoirs will require significant external energy to replace that lost or never provided by Mother Nature’s handiwork. Such input of energy must reflect the geological nature of the deposit, which largely will determine the nature of extraction (in-situ or mining) and of processing (upgrading and blending). To achieve a marketable product at a price that justifies significant long-term capital investments—both initial and sustaining—is the challenge facing the oil industry today. Bitumen-derived heavy oil is not strictly a commodity like lighter crudes. It sells at a discount (typically +/- $20/bbl) because it is unmarketable until dilutent pipelines, refineries, and product pipelines are built. The products are diluted bitumen blends and synthetic crude oil (SCO).
Bitumen production requires energy chiefly from electrical power for extraction and for upgrading. Such energy is produced by the combustion of fuels that include natural gas, gasification of heavy oil, residual coke, and coal. Nuclear energy has the potential to displace these hydrocarbon fuels.
Energy-intensive processes are costly. Only the most efficient sources of energy can provide economic competition with oil products derived from conventional crudes, the prices of which largely are set at the ceiling price for unconventional oil. The development of North America’s vast unconventional oil resources and the potential application of nuclear power share the same economic and regulatory hurdles to their development: Environmental mitigation of the disposal of the waste products, CO2 and spent fuel. Uncertainty of governmental policy on sequestration of CO2 and of spent fuel from new nuclear facilities are major encumbrances for financing the development of North America’s unconventional crude oil and the application of nuclear power as the energy source. If these uncertainties are resolved, the result may be a direct and competitive replacement of transportation fuels dependent imported conventional crude oil.
The Western Hemisphere contains the majority of currently defined unconventional crude oils. The Western Hemisphere has abundant technologically recoverable unconventional oil (see Figure 1).
Canada holds a large repository of oil sands, and out of some 1,700 billion bbl of in-place bitumen, approximately 175 billion bbl of bitumen technologically is recoverable, with 22 billion bbl under active development.
In the United States, oil-shale potential is estimated at 2,000 billion bbl of in-place kerogen, with 80 percent located in Colorado, Utah and Wyoming and the remainder in Kentucky, Tennessee and Indiana (see Figure 2). There is currently no commercial production, only pilot-scale field tests in the Green River Formation in Colorado, Utah, and Wyoming.
Oil has no inherent energy to produce itself, whether in unconventional or conventional reservoirs. The natural energy in a reservoir available to move oil into a well bore is the potential energy of the reservoir pressure. This energy is stored mainly in the interstitial fluids (and to a lesser extent in the rock) compressed by gravity. This reservoir energy must be great enough to move the oil to the well by overcoming surface tension holding oil within the pore system and the viscous resistance of the oil to movement. This is accomplished by capillary pressure formed by a dynamic pressure gradient from the oil-bearing pore to the well. The differences in reservoir energy separate conventional oil deposits from unconventional deposits, as does the nature of their bitumen.
Bitumen and kerogen are naturally occurring hydrocarbons with geological differences that control their commercial exploitation, in particular the application of nuclear energy.
Bitumen is a generic term applied to natural inflammable substances composed principally of a mixture of hydrocarbons substantially free from oxygenated matter. Petroleums, asphaltites, and mineral waxes all are considered bitumens. Kerogen is a mineraloid of indefinite composition consisting of a complex mixture of macerated organic debris, which are chiefly forms of plant life that lived in the enclosed basin where it formed. An asphaltic sandstone (e.g., Alberta tar sands) and a kerogen shale (e.g., Colorado oil shale) are examples of bituminous rocks that yield oil on destructive distillation.
Oil Sands: Disseminated deposits of liquid bitumens can be degraded by geological processes that release dissolved gasses, by oxidation, and by bacterial digestion into high specific gravity (density measured in degrees API gravity), and into high viscosity (ability to flow measured in centipoises) liquids and semi-solid materials. The greater the loss of dissolved gas, the greater the specific gravity (the lower the API gravity), the greater the viscosity, and the lower the calorific value (measured as calories per gram) of the residual oils. The viscosity of bitumen distinguishes bitumen (tar) sands from extra heavy oil.
The tar sands of Alberta belong to this category of degraded bitumens. Such hydrocarbons migrated from their source rock and were captured in a “conventional” reservoir. These deposits are called “unconventional” because geological processes subsequently released their original reservoir energy, and they now require supplemental energy to mobilize them, such as reinjected gas, miscible fluids (e.g., natural gas liquids) or thermal energy (e.g., steam or direct heat) to achieve commercial rates of recovery.
Oil Shale: Surface deposits of bitumen known as kerogen shales are composed of fossilized insoluble organic material found in their original sedimentary rocks. In the chemical classification of hydrocarbon materials, kerogen is on the border between petroleum hydrocarbons and the coals. Kerogen shales do not decompose into gaseous and liquid petroleum hydrocarbons until they are heated to temperatures of 350 degrees Centigrade or more. They are a subclass of bitumens called pyrobitumens.
The United States Geological Survey (USGS) refers to these bitumen deposits as “continuous,” not having migrated from their source rock into a conventional reservoir. Industry refers to the extraction of kerogen and its upgraded products as manufactured oil.
The migrated and concentrated nature of the degraded bitumen in oil sands, and the non-migrated and disseminated nature of pyrobitumens in oil shales, largely account for the differences in economic exploitation and in the application of nuclear power as a thermal energy source for mobilization of bitumen, especially for in-situ extraction.
The more favorable (higher) the porosity and permeability of the host sandstone reservoir that originally received the liquid hydrocarbons, the lower the extraction temperature and greater recovery efficiency of in-place bitumens. If the source rock is composed of oil shales, higher extraction temperatures are needed. Typically, 15 percent to 20 percent of the oil-in-place can be recovered from host sandstones, depending on the level of bitumen degradation and of residual reservoir energy. Only 5 percent to 10 percent of the oil-in-place currently can be recovered from kerogen shales. The injection of thermal energy from hydrocarbon combustion for steam generation can increase in-situ recovery by up to 40 percent (rarely 70 percent) in bitumen sandstones and up to 20 percent in bitumen shales.
Some 80 percent of North America’s technologically recoverable bitumen is extractable by in-situ methods. Nuclear power for direct heat without steam potentially could economically displace use of hydrocarbon fuels as an energy source. However, nuclear power as a thermal heat source must accommodate the following geologic parameters of the deposit:
Depth of burial (geothermal and rock/fluid pressure gradients);
• “Reservoir” heterogeneity including geochemical distribution (thermal maturity, total organic content) and petrophysics (mineralogy and rock fabric);
• Deposit geometry (shape of core and periphery of bitumen distribution);
• Size of the extraction pool and extraction rate; and
• Maximum transportation distance between injection well and reactor (approximately 4,000 feet).
The lease-block configuration also is important. Avoiding fragmentation of surface rights can minimize the purchase of surplus electricity.
Nuclear thermal discharge can heat the host sandstone and shale directly, eliminating the need for steam and electricity for wellbore heaters from fossil fuels, and reducing the energy requirement for retorting by as much as 50 percent. It also uses less water and produces less greenhouse gases, essentially avoiding CO2 emissions from the production of electricity. Direct heating of bitumen-bearing rocks also can produce more bitumen than traditional surbsurface recovery because in-situ volumes will not be required to heat the host rock.
Nuclear heat can be operated for decades to transfer heat to an intermediate heat-transfer fluid within insulated loops that are limited to short distances. The likely maximum reactor-to-wellhead distance is approximately 4,000 feet, due to heat degradation. This factor is very similar to transfer of thermal energy in geothermal brines to binary heat recovery systems for power generation. Nuclear heat transfer technology can recover 100,000 bbl/d of bitumen in the Piceance basin from 30 acres/year, and would require a 600-MW reactor.1
Production of Canada’s oil sand is projected at 3 million barrels and will require thermal energy from approximately 2 bcf/d of natural gas (approximately 50 percent of the current exports to the United States). Each barrel of synthetic crude oil (SCO) currently requires the following volumes of natural gas:
• Mining extraction: 0.75 Mcf;
• In-situ extraction: Cyclic steam circulation (CSC) – 1.5 Mcf and
Steam assisted gravity drainage (SAGD) – 1 Mcf; and
• Upgrading (hydrogen production): 0.70 Mcf.
Each barrel of SCO also requires:
• 2.5-4 bbl water, typically recycled (1.16 bbl of bitumen to produce 1 bb1 SCO);
• 5.8-6 kW power (5 kW/bbl bitumen); and
• Disposal of 0.10 tons CO2.
If current production of 1 MMbbl/d of Canadian oil sands reaches 3 MMbb/d by 2017, 40 million tons of CO2 per year will be generated, equivalent to 8 percent of Canada’s Kyoto Limit at 2012.
Mining and in-situ extraction both require electricity for retorting and upgrading. This typically has been satisfied by gas-fired cogeneration, with plant size ranging from 80 to 420 MW, and averaging 180 MW.
For oil sands, nuclear power can compete with hydrocarbon fuels as a thermal energy source for in-situ extraction and for upgrading with combustion of fossil fuels, and would greatly reduce CO2 emissions. Nuclear reactors have low fuel costs but high capital costs. A 25 percent increase in capital cost (ACR-700 technology) increases the total cost of steam by 20 percent (1 percent capital/0.8 percent steam ratio).
There has been an approximately 200 percent increase in cost components per ton of oil sand between 2003 and 2008 (see Figure 3). Overnight costs2 for nuclear capacity at $3.6 billion ($4,325/kW) and at $5 billion ($6,840/kW) for ACR-700 technology with design capacity of 731 MW have break-even gas prices with natural gas combined cycle with the same MW capacity of $7.50/MMBtu and $10.15/MMBtu, respectively.
The costs as shown in Figure 3 also exclude the cost (tax or CO2 credits) of carbon regulation, a major driver of the uncertainty in projecting variable cost of incremental nuclear energy. There is a relationship not expressed in the figure between carbon cost and natural gas cost due to the displacement of coal-fired generation. For example, the break-even gas price at $7.50/MMBtu at a capital cost of $4,325/kW can increase to $9.00/MMBtu with a $20/ton CO2 cost. The break-even gas price can increase to $11/MMBtu with a $40/ton CO2 cost, and with a capital cost of approximately $5,700/kW.
Economical recovery from existing oil sands production requires a sustainable price for light sweet crude (e.g., WTI) ranging from approximately $30-$40/bbl. For incremental production, this price is approximately $50/bbl (2008 dollars) to generate an internal rate of return from 15 percent to 20 percent. Application of nuclear power for future production would need a similar price range ($30-$50/bbl WTI).
There is currently no commercial production of oil shale and therefore accurate estimates are difficult to make of major cost components. However, whether surface or subsurface, the major production cost and environmental impact derive from the generation of electricity for heating needed for retorting.
Oil shale has a low thermal conductivity that requires high temperatures to liquefy kerogen. Traditional recovery requires rapid burning by injecting oxygen, and by heating the shale with high-temperature electric heaters to 480 degrees to 540 degrees Centigrade (900 degrees to 1,000 degrees Fahrenheit) for two to three years to chemically convert and mobilize the kerogen. The produced kerogen is infused with hydrogen to produce SCO.
Subsurface retort technology originated by Shell Oil, called the In-Situ Conversion Process (ICP), allows more of the hydrogen molecules to be liberated from the kerogen and to react with carbon compounds over two to three years at a lower temperature of approximately 345 degrees to 370 degrees C (650 degrees to 725 degrees F). This process is reported to initiate chemical reactions that release light crude oil (65 percent) and syngas (35 percent) similar to natural gas. The electric power needed for the heating and cooling for a freeze wall perimeter can be generated entirely from the onsite syngas produced by the ICP. The conversion efficiency is 60 percent. This process requires 250-300/kWh of electrical energy per barrel of SCO. The ratio of energy produced to energy used is reported to range from 3-to-1 to 7-to-1, depending on the scale of the project.
Domestic oil-shale recovery using traditional recovery methods has been estimated to have a production cost of $35/bbl SCO. These economics require a $5/bbl production tax credit and a price guarantee (floor) in the low $40s/bbl (2006 dollars) for development of high-risk, cost-shared demonstration projects.3 Due to continued hyper-inflation since 2006, the floor price could be in the low $50s/bbl. Shell’s ICP is reported to have a bitumen production cost of $30-$40/bbl in 2008 dollars. In addition, a demonstration plant is under construction in Utah, assisted by the Idaho National Labs and the DOE. It will use coal-gasification as the heat source. The production cost is reported at $30/bbl SCO. A sustainable WTI price of $50/bbl could provide a globally competitive risk-weighted return on equity with continued technology improvements.
Nuclear energy now is being proposed as an alternative to natural gas-powered electricity as a heat source for domestic in-situ oil recovery. Heat-transfer technology using nuclear power requires a downhole heat circulating system between cold and hot wells in the heat transfer loop with a high volumetric heat capacity to ensure efficient heat transfer.
Several existing reactor technologies could be used in oil-shale recovery. One near-term option is a high-temperature modular gas-cooled reactor. The long-term option could be the Advanced CANDU Reactor-700 (ACR-700 at 731 MW) and a very-high temperature, liquid-salt cooled reactor, the Advanced High-Temperature Reactor (AHTR at around 500 MW).
There are fundamental uncertainties surrounding use of nuclear power in the proposed applications. The following questions frame them:
• Will the cost of input energy equal the price of output energy needed for a competitive ROI?
• Is there reasonable certainty of capital cost for nuclear capacity versus cost and price volatility of alternative combustion fuels?
• Can reactors be sized for “aggregated” extraction at multiple sites and well patterns, and for maximum distance between reactor and injection well?
• Can sale of surplus electrical power benefit project economics?
• Will favorable governmental policy and public opinion provide opportunity to deploy capital for this purpose?
Regulatory uncertainties do make it difficult to resolve these issues. For example:
• The future cost of carbon;
• The permanent sequestration of CO2 and spent nuclear fuel; 4
• Any modification to the March 13, 2007 one-year moratorium prohibiting preparation of final regulations;
• Any amendment to the Energy Independence and Security Act of 2007 that explicitly limits U.S. imports of oil from unconventional source;5
• Access to resources on public land; and
• Incentives to fast-track technology and commercial-scale development.
Until these uncertainties are resolved, applying nuclear power in North America’s petroleum industry will remain inherently high-risk.6
1. Charles W. Forsberg, U.S. Department of Energy’s Oak Ridge National Laboratory, presentation at the American Nuclear Society’s 2006 International Congress on Advances in Nuclear Power Plants, Reno Nevada, June 7, 2006.
2. Excludes costs of financing and escalation.
3. Task Force on Strategic Unconventional Fuels – September 2006.
4. For a current review of nuclear waste issues, see “Is Yucca Enough,” Public Utilities Fortnightly, July 2008, Greg Turk and Tom Sweet.
5. “Spurring Unconventional Oil,” Oil & Gas Journal, April 7, 2008. Volume 106, Issue 13.
6. For a current review of the contracting risk management, see “Navigating Nuclear Risks,” Public Utilities Fortnightly, July 2008, Tom Flaherty, Jim Hendrickson, and Marco Bruzzano.