A significant challenge facing the heavy oil and shale oil industry is supplying energy for the purpose of steam generation or direct heat for use in a variety of in-situ heavy oil production schemes. Typically, natural gas or oil is combusted on site to fuel steam generation units, which creates two problems. First, it exposes the project to economic risk through the highly variable nature of natural gas cost, which is significant given the large volume of fuel that will be consumed over the life of the project. Second, natural gas combustion is the primary source of greenhouse gas emissions for an in-situ project.  This puts growth in this industry sector at odds with carbon emission mandates set by regulatory agencies, and also creates negative public, sentiment towards ongoing development of the resource.  

Many attempts have been made in the past to show how nuclear power (both with established and pre-commercial technologies) may be used to supply the energy demand created by the growth of the development in heavy oil reserve regions, with assessments being carried out for mining, steam assisted gravity drainage (SAGD), upgrading, and integrated operations. The proposed configurations fail in one or more critical areas such as improper steam conditions at the plant outlet, excessively high capital requirements, or a mismatch in the scale of operations.  

The Molten Salt Reactor (MSR) is a Generation IV fission nuclear reactor that was first built and operated in the 1960s and was demonstrated to be a practical, safe and economically viable tool for heat generation. 

For years there have been proponents of integrating nuclear power with oil sands and shale development in order to supply low cost base load electric power and steam production. The most basic allure is that it would create a scenario where the carbon emissions produced from oil sands and shale production would drop to virtually zero. Many studies also argue that the power produced would also be able to assist in the production of hydrogen for the purpose of bitumen upgrading. These are clearly benefits to oil and gas producers, but a project that would be willing to build a new reactor for EOR (Enhanced Oil Recovery) has never materialized because of a lack of a regulatory environment for MSRs and the litigious nature of siting and licensing a MSR.  

The world is running out of light crude oil and is increasingly using heavier fossil feedstocks such as heavy oils, tar sands, oil shale, and coal for the production of liquid fuels (gasoline, diesel, and jet fuel). With heavier feedstocks, more energy is needed to convert the feedstocks into liquid fuels. In the case of coal liquefaction, the energy consumed in the liquefaction process is almost twice the energy value of the liquid fuel. This trend implies large increases in carbon dioxide releases per liter of liquid transport fuel that is produced if carbon based fuel is used to drive the conversion process.  

Oil provides 39% of the energy needs of the United States, and oil refineries consume over 7% of the total energy produced within the U.S. As the world transitions to heavier crude resources as lighter crudes become harder to find, these energy consumption figures will only increase, and if we use fossil fuels to power the conversion of heavy fossil feedstocks into lighter crude we will also produce exponentially more carbon dioxide and air pollution — unless carbon free and pollution free nuclear energy is used. 

People are often confused about the overall extent of U.S. oil reserves. Some claim that the U.S. has hundreds of billions or even trillions of barrels of oil waiting to be produced if bureaucrats will simply stop blocking development.  

Oil production has been increasing in the U.S. for the past few years, primarily driven by expanding production from the Bakken Shale Formation in North Dakota and the Eagle Ford Shale in Texas. The oil that is being produced from these shale formations is sometimes improperly referred to as shale oil. But when some people speak of hundreds of billions or trillions of barrels of U.S. oil, they are most likely talking about the oil shale in the Green River Formation in Colorado, Utah, and Wyoming. Since the shale in North Dakota and Texas is producing oil, some have assumed that the Green River Formation and its roughly 2-3 trillion barrels of oil resources will be developed next because they think it is a similar type of resource. But it is not. 

Although the oil in the Bakken and Eagle Ford is being extracted from shale formations, the term shale oil has been used for over 100 years to describe a very different resource. This has led some to confusion over the differences between current production in North Dakota and potential production in Colorado. The oil in the Bakken and Eagle Ford formations actually exists as oil, but the shale does not allow the oil to flow very well. This oil is properly called “tight oil“, and advances in hydraulic fracturing (fracking) technology have allowed some of this oil to be economically extracted.  

The estimated amount of oil in place (the resource) varies widely, with some suggesting that there could be 400 billion barrels of oil in the Bakken. Because of advances in fracking technology, some of the resource has now been classified as reserves (the amount that can be technically and economically produced). However, the official reserve is a very small fraction of the resource at 2 to 4 billion barrels (although some industry estimates put the proven recoverable resources as high as 20 billion barrels or so).  

Like the Bakken, the Eagle Ford formation in Texas consists of oil (and natural gas) in tight formations that are being accessed via fracking. The amount of technically recoverable oil in the Eagle Ford is estimated by the U.S. Department of Energy to be 3.35 billion barrels of oil. 

Without a doubt, these two formations are a major factor in the current resurgence of U.S. oil production. But the Green River formation is the source of talk of those enormous oil resources — larger than those of Saudi Arabia — and it is a very different prospect than the tight oil being produced in North Dakota and Texas. The oil shale in the Green River looks like rock. Unlike the hydrocarbons in the tight oil formations, the oil shale (kerogen) consists of very heavy hydrocarbons that are solid. In that way, oil shale more resembles coal than oil. Oil shale is essentially oil that Mother Nature did not finish cooking. 

To convert this resource into actual oil, heat has to be added. The energy requirements — plus the fact that oil shale production requires a lot of water in a very dry environment — have kept oil shale commercialization out of reach for over 100 years. 

Thus, while the U.S. might indeed have greater oil resources than Saudi Arabia, U.S. oil reserves (per the BP Statistical Review of World Energy) are only about 1/10th those of Saudi Arabia.  

The traditional processes for recovery of shale oil release large quantities of carbon dioxide to the atmosphere and are expensive. These processes involve heating the oil shale to temperatures in excess of 480°C (~900°F) by injecting air and burning some of the organics to produce heat, which then drives the chemical reactions that release the oil from the rock. The process can be conducted above ground in retorts or underground.  

In underground operations, a volume below the retort zone is mined, the shale to be retorted is rubble-ized by staged explosives, and air is pumped in to burn some of the carbon to produce the required heat. It is currently estimated that for the initial commercial plants, the production costs will be between $70 and $95 per barrel.  

Since the 1980s, Shell and several other companies have been developing new types of in-situ retorting processes. The Shell “In-Situ Conversion Process (ISCPs)” is the closest to commercial deployment. It has been tested on a small scale and is now being scaled up to a pre–commercial size. While many uncertainties remain, these processes represent a potential revolution in oil shale processing that may produce a premium shale oil with projected production costs of ~$30 per barrel, a cost that is competitive with that of lower-quality crude oil priced in the mid-$20s per barrel. Current oil prices exceed these production costs by large margins.  

In the Shell ISCP process, electrical heaters are emplaced in the oil shale formation and are used to heat a quantity of oil shale through its entire volume. Each acre requires 15 to 25 heaters. After 2 to 3 years, the volume of shale is heated to between 650° and 700°F (370°C). This slow heating and the relatively low temperature compared with traditional oil shale retorts causes the rock to release oil as well as a gas similar to natural gas. About two-thirds of the energy content is in the oil, and about one-third is in the gas.  

The low thermal conductivity of oil shale (poor heat conduction), the economic requirement to heat the bulk rock in a time period of economic interest (several years), and practical necessity of line (well) heating (versus bulk heating) imply peak heater-well temperatures between 600° and 800°C, with higher temperatures reducing the number of required heaters or decreasing the heating time.  

The other technological component is the use of freeze-wall technology to isolate the underground retort from the geological formation. This process, an existing industrial technology, involves drilling wells around the perimeter of the extraction zone and using cooling coils to freeze the groundwater to create a sealed ice wall. The freeze wall (1) allows dewatering of the oil shale and avoids in-leakage of groundwater; (2) keeps the light hydrocarbon products from escaping during ground heating, product extraction, and post-extraction ground cooling; and (3) allows post-treatment of the impacted rock zone to minimize the potential for long-term groundwater contamination.  

The technology for using nuclear heat for recovery of shale oil is potentially applicable to depleted oil fields, tar sands, soft coal, and other hydrocarbon deposits. The economics strongly depend upon the characteristics of the specific fossil fuel and the local geology, which determine the investment in drilling and other activities required per barrel of oil ultimately produced.  

In the specific case of coal, multiple processes have been fully or partly developed to heat coal and produce a solid high-carbon char, hydrocarbon liquids, and gases. The classical example is the production of coke that is used, in turn, for the production of pig iron from iron ore.  

More recently there has been work on development of new processes that slowly heats coal to increase yields of liquid hydrocarbons and gases. Various experiments have shown that slow heating (versus rapid heating) of the coal produces larger liquid yields and a higher quality synthetic crude oil. These new processes can be implemented in above ground and underground locations. The intrinsic characteristic of underground refining using nuclear heat is that it is a slow process because of the low thermal conductivity of rock. Increasing the yield of liquids per ton of coal has major impacts on the economics.  

Additionally, the use of super critical carbon dioxide pumped into the heated shale formations can greatly reduce the time to produce premium crude. 

Heavy crude oil or extra heavy crude oil is oil that is highly viscous, and cannot easily flow to production wells under normal reservoir conditions. Heavy crude oil is closely related to natural bitumen from oil sands. Petroleum geologists categorize bitumen from oil sands as ‘extra-heavy oil’ due to its density. Bitumen is the heaviest, thickest form of petroleum. 

Natural bitumen, also called tar sands or oil sands, shares the attributes of heavy oil but is yet more dense and viscous. Often, bitumen is more viscous than cold molasses and does not flow at ambient conditions. 

An estimated 68.3 billion barrels of proven heavy oil reserves exist in 535 U.S. reservoirs. An undetermined additional amount remains in 490 less well documented U.S. reservoirs, including at least 25 to 40 billion barrels of heavy oil on Alaska’s North Slope. 

Most of the proven heavy oil reserves (62.8 billion barrels) are located in California (half of which lies in seven fields), and 3.5 billion barrels are located in the Gulf Region (Alabama, Mississippi, Louisiana, Southern Arkansas, and Texas, excluding the Permian Basin). Most of the U.S. heavy oil is likely to be produced from California where resource and production characteristics are more favorable. Any program effectively targeting heavy oil production is likely to impact California production operations.  

The next largest heavy oil resource is in Alaska, although actual size of the resource is less certain (it could possibly be much larger than California’s resource). This is the only other large domestic heavy oil resource in the U.S. Heavy oil production is possible in Alaska if technological and economic challenges are met. However, the window of opportunity may quickly close if light oil production rates decline as projected. The Trans Alaskan Pipeline System (TAPS) may close before significant amounts of heavy oil can be produced. The Gulf Region is the third largest region in the U.S. with deposits of heavy oil. Existing refining capacity in this region can accommodate increased production, making the economic adjustments more realizable. However, the thinner reservoirs in this region present a production challenge.  

Steam based thermal recovery processes are the most extensively used in harvesting heavy oil. This involves injecting steam into heavy oil formations to make the oil less viscous and thereby more easily pumpable. 

The challenges of steam injection EOR (Enhanced Oil Recovery) are economics and environmental. 

Steam injection is usually applied in large fields where economics of scale apply. The upfront capital costs are considerable, involving expensive steam generation and production facilities and insulated flow lines. Availability and cost of fuel for heating water or generating steam are important. For environmental reasons most steam generators are fired with natural gas, which historically, has represented a significant fraction of total operating costs.   

Environmental concerns present a considerable obstacle to steam injection operations. Municipalities, competing with quantities for human consumption, will supply some, or all, of the water for EOR steam injection. Clean air can be an issue with the combustion products of the steam generators, which are normally powered by natural gas or by oil produced from the process. 

If Molten Salt Reactors power the process, the cost of steam is dramatically reduced, and any pollution concerns are eliminated. The cost of steam, when heated by traditional means, can exceed half the cost of the oil produced. When steam is produced by an MSR, crude oil can be produced at less than $20 per barrel.  

Large refineries are among the largest industrial facilities on earth, with capital costs of several tens of billions of dollars each and equally large rates of internal energy consumption. About 7% o f the total U.S. energy demand is used within the 149 refineries located in the United States.  

As a class, refineries are the largest energy consumers in the United States. The scale of operation of a large integrated refinery exceeds that of a nuclear power plant. Such refineries cost several tens of billions of dollars each and are the largest private industrial facilities on earth. They potentially present two major markets for nuclear energy.  

• High-temperature heat. For high-quality crude oil, the refinery demand for high- temperature heat is about 10% of the energy value of the final liquid product. Assuming that a refinery uses this quantity of heat, about 7.08 GW(t) would be required for every million barrels of oil that are refined per day. With a national consumption of about 20 million barrels of oil per day, that implies 142 GW(t) of heat. For lower-grade crude oils, more heat is required. To provide that heat, the reactor coolant temperatures will need to be 600 to 700°C. Most of that heat is now provided by natural gas—a premium and expensive fuel.  

• Hydrogen. Hydrogen is the second prospective market. This market is potentially several times larger. Some understanding of scale can be provided by example. Recently Kuwait announced the construction of another hydrogen plant to provide more hydrogen to their refinery. When fully operational, the rate of energy release if that hydrogen is burned will be ~3000 MW(t).  

Because refineries use large quantities of high- temperature heat that is primarily produced by high-cost natural gas, there is commercial interest in using high-temperature reactors to provide that heat.  

The longer-term option is the production of hydrogen. This is potentially a major market, but there are two limitations. First, the need for alternative sources of oil is not addressed, and secondly, the use of nuclear heat implies retrofitting of existing refineries—a serious constraint at some refinery sites.