BACKGROUND 1. Field of the Invention

The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various subsurface formations such as hydrocarbon containing formations. 2. Description of Related Art Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.

Heaters may be placed in wellbores to heat a formation during an in situ process. There are many different types of heaters which may be used to heat the formation. The energy necessary to transform and/or remove hydrocarbon materials from a subsurface formation more than anything will determine the efficiency and profitability of the produced hydrocarbon materials. Hence any systems and/or methods which may result in the reduction of the energy requirements and/or energy costs required to produce hydrocarbon materials. U.S. Patent No. 3,170,842 to Kehler describes a subcritical, nuclear reactor and neutron- producing means suitable for use in the borehole of a well. Kehler describes logging a borehole with a nuclear reactor, heating a borehole with a nuclear reactor, or in situ pyrolysis of oil shales by heating, employing a nuclear reactor in a borehole as a heat source in said shale. The nuclear reactor having a widely variable, predetermined power output and rate of neutron production and to means to vary or to hold constant said power output or rate of neutron production at a predetermined level suitable for the selected purpose for which the nuclear reactor is to be used. The nuclear reactor including a plurality of subcritical stages energized to a level of neutron production or power output dependent on the position of a primary neutron generator which is movable relative to the body of the nuclear reactor by suitable mechanical means.

U.S. Patent No. 3,237,689 to Justheim describes a method and plant for distilling deposits of oil shale and other solid carbonaceous materials in situ, whereby more effective and complete distillation is accomplished and significant working economies are achieved. A nuclear reactor, adjacent to the area concerned, is employed to provide heat to a heat- exchange medium circulated through one or more heat-exchangers which provide heat to one or more thermal fronts to carry out in situ distillation of the deposits of oil shale. U.S. Patent No. 3,598,182 to Justheim describes a method of distilling and hydrogenating the hydrocarbon content of carbonaceous materials using hot hydrogen to release and distill the hydrocarbon content. Preferred apparatus for practicing the method includes a source of hydrogen, means for varying the temperature of the hydrogen, an underground cavern in the carbonaceous material, and temperature modulating means at the face of the shale for regulating the temperature of the hydrogen. The hot hydrogen can be from any source, but preferably will be obtained from a nuclear reactor utilizing hydrogen as a coolant or from carbonization of coal.

U.S. Patent No. 3,766,982 to Justheim describes a method of in-situ treatment of oil shale or other hydrocarbonaceous material by a hot fluid, such as air or flue gas, as a heat transfer agent to volatilize kerogen or other hydrocarbonaceous matter and preferably also as a carrier of sufficient heat to crack and fissure the material to make it permeable to gas flow therethrough. Recovery of the volatilized hydrocarbonaceous material is through one or more bore holes remote from the location of hot gas introduction. The heating of the air or other relatively inexpensive heat-exchange gas to requisite temperature, either above or below ground is accomplished in a nuclear reactor, pebble heater, or other suitable heating device.

U.S. Patent No. 4,765,406 to Frohling describes a method of test recovery of crude oil by injection of a heat carrier into the oil stratum. The method is affected by generating thermal energy in the crude oil deposit or at a location at which a well enters this deposit by carrying out a catalytic methanization reaction and transferring the resulting heat to the heat carrier which can be steam or an inert gas. The heat carrier is introduced into the crude oil stratum and increases the mobility of the crude oil. A variety of energy sources can be used, including coal, oil, gas-fired heaters, solar energy plants and the like, although we preferably make use of a high temperature nuclear reactor.

U.S. Patent No. 4,930,574 to Jager describes a method for tertiary oil recovery and gas utilization by the introduction of nuclear-heated steam into an oil field and the removal, separation and preparation of an escaping oil-gas-water mixture. The method includes heating a steam reformer and producing steam in a steam generator with heat from a helium-cooled high-temperature reactor, partly feeding the steam produced in the steam generator through a pipe into an oil field, separating methane and other components from the escaping oil-gas-water mixture, preheating the methane in a preheater, and subsequently partly feeding the steam produced in the steam generator and the methane to the steam reformer for separating methane into hydrogen and carbon monoxide. U.S. Patent Application Publication No. 20070181301 to O'Brien describes a system and method for extracting hydrocarbon products from oil shale using. The method includes using nuclear energy sources for energy to fracture the oil shale formations and provide sufficient heat and pressure to produce liquid and gaseous hydrocarbon products. The method also includes steps for extracting the hydrocarbon products from the oil shale formations.

There has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is a need for improved methods and systems that reduce energy costs for treating the formation, reduce emissions from the treatment process, facilitate heating system installation, and/or reduce heat loss to the overburden as compared to hydrocarbon recovery processes that utilize surface based equipment.

SUMMARY Embodiments described herein generally relate to systems and methods for treating a subsurface formation. In certain embodiments, the invention provides one or more systems and one or more methods for treating a subsurface formation. The invention, in some embodiments provides, an in situ heat treatment system for producing hydrocarbons from a subsurface formation, comprising: a plurality of wellbores in the formation; at least one heater positioned in at least two of the wellbores; and a self- regulating nuclear reactor configured to provide energy to at least one of the heaters to raise the temperature of the formation to temperatures that allow for hydrocarbon production from the formation.

The invention, in some embodiments provides, an in situ heat treatment system for producing hydrocarbons from a subsurface formation, comprising: a plurality of wellbores in the formation; at least one heater positioned in at least two of the wellbores; and a self- regulating nuclear reactor configured to provide energy to at least one of the heaters to raise the temperature of the formation to temperatures that allow for hydrocarbon production from the formation; wherein heat input to at least a portion of the formation over time at least approximately correlates to a rate of decay of the self-regulating nuclear reactor. The invention, in some embodiments provides, an in situ heat treatment system for producing hydrocarbons from a subsurface formation, comprising: a plurality of wellbores in the formation; at least one heater positioned in at least two of the wellbores; and a self- regulating nuclear reactor configured to provide energy to at least one of the heaters to raise the temperature of the formation to temperatures that allow for hydrocarbon production from the formation; wherein a spacing between at least a portion of the plurality of wellbores in the formation is at least partially correlated to a rate of decay of the self- regulating nuclear reactor.

The invention, in some embodiments provides, an in situ heat treatment system for producing hydrocarbons from a subsurface formation, comprising: a plurality of wellbores in the formation; at least one heater positioned in at least two of the wellbores; and a self- regulating nuclear reactor configured to provide energy to at least one of the heaters to raise the temperature of the formation to temperatures that allow for hydrocarbon production from the formation; wherein the self-regulating nuclear reactor decays at a rate of about 1/E. The invention, in some embodiments provides, a method of producing hydrocarbons from a subsurface formation may include the system as described herein. In further embodiments, features from specific embodiments may be combined with features from other embodiments. For example, features from one embodiment may be combined with features from any of the other embodiments. In further embodiments, treating a subsurface formation is performed using any of the systems and methods described herein. In further embodiments, additional features may be added to the specific embodiments described herein. BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description and upon reference to the accompanying drawings.

FIG. 1 shows a schematic view of an embodiment of a portion of an in situ heat treatment system for treating a hydrocarbon containing formation.

FIG. 2 depicts a schematic representation of an embodiment of an in situ heat treatment system that uses a nuclear reactor.

FIG. 3 depicts an elevational view of an embodiment of an in situ heat treatment system using pebble bed reactors. FIG. 4 depicts a schematic representation of an embodiment of a self-regulating nuclear reactor.

FIG. 5 depicts a schematic representation of an embodiment of an in situ heat treatment system with u-shaped wellbores using self-regulating nuclear reactors.

FIG. 6 depicts power (W/ft)(y-axis) versus time (yr)(x-axis) of in situ heat treatment power injection requirements.

FIG. 7 depicts power (W/ft)(y-axis) versus time (days)(x-axis) of in situ heat treatment power injection requirements for different spacings between wellbores.

FIG. 8 depicts reservoir average temperature (°C)(y-axis) versus time (days)(x-axis) of in situ heat treatment for different spacings between wellbores. While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and may herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims. DETAILED DESCRIPTION

The following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products. "API gravity" refers to API gravity at 15.5 ⁰ C (60 ⁰ F). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298.

"Fluid pressure" is a pressure generated by a fluid in a formation. "Lithostatic pressure" (sometimes referred to as "lithostatic stress") is a pressure in a formation equal to a weight per unit area of an overlying rock mass. "Hydrostatic pressure" is a pressure in a formation exerted by a column of water.

A "formation" includes one or more hydrocarbon containing layers, one or more non- hydrocarbon layers, an overburden, and/or an underburden. "Hydrocarbon layers" refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The "overburden" and/or the "underburden" include one or more different types of impermeable materials. For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate. In some embodiments of in situ heat treatment processes, the overburden and/or the underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden. For example, the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable. "Formation fluids" refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. The term "mobilized fluid" refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. "Produced fluids" refer to fluids removed from the formation.

A "heat source" is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer. For example, a heat source may include electrically conducting materials and/or electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed in a conduit. A heat source may also include systems that generate heat by burning a fuel external to or in a formation. The systems may be surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In some embodiments, heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation. It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. Thus, for example, for a given formation some heat sources may supply heat from electrically conducting materials, electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (for example, an oxidation reaction). A heat source may also include electrically conducting material and/or a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.

A "heater" is any system or heat source for generating heat in a well or a near wellbore region. Heaters may be, but are not limited to, electric heaters, burners, combustors that react with material in or produced from a formation, and/or combinations thereof. "Heavy hydrocarbons" are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20°. Heavy oil, for example, generally has an API gravity of about 10-20°, whereas tar generally has an API gravity below about 10°. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15 ⁰ C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons. Heavy hydrocarbons may be found in a relatively permeable formation. The relatively permeable formation may include heavy hydrocarbons entrained in, for example, sand or carbonate. "Relatively permeable" is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy). "Relatively low permeability" is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy. One darcy is equal to about 0.99 square micrometers. An impermeable layer generally has a permeability of less than about 0.1 millidarcy. Certain types of formations that include heavy hydrocarbons may also include, but are not limited to, natural mineral waxes, or natural asphaltites. "Natural mineral waxes" typically occur in substantially tubular veins that may be several meters wide, several kilometers long, and hundreds of meters deep. "Natural asphaltites" include solid hydrocarbons of an aromatic composition and typically occur in large veins. In situ recovery of hydrocarbons from formations such as natural mineral waxes and natural asphaltites may include melting to form liquid hydrocarbons and/or solution mining of hydrocarbons from the formations. "Hydrocarbons" are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. "Hydrocarbon fluids" are fluids that include hydrocarbons. Hydrocarbon fluids may include, entrain, or be entrained in non- hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.

An "in situ conversion process" refers to a process of heating a hydrocarbon containing formation from heat sources to raise the temperature of at least a portion of the formation above a pyrolysis temperature so that pyrolyzation fluid is produced in the formation. An "in situ heat treatment process" refers to a process of heating a hydrocarbon containing formation with heat sources to raise the temperature of at least a portion of the formation above a temperature that results in mobilized fluid, visbreaking, and/or pyrolysis of hydrocarbon containing material so that mobilized fluids, visbroken fluids, and/or pyrolyzation fluids are produced in the formation. "Insulated conductor" refers to any elongated material that is able to conduct electricity and that is covered, in whole or in part, by an electrically insulating material. "Pyro lysis" is the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis. "Pyrolyzation fluids" or "pyrolysis products" refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, "pyrolysis zone" refers to a volume of a formation (for example, a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid. "Superposition of heat" refers to providing heat from two or more heat sources to a selected section of a formation such that the temperature of the formation at least at one location between the heat sources is influenced by the heat sources.

A "tar sands formation" is a formation in which hydrocarbons are predominantly present in the form of heavy hydrocarbons and/or tar entrained in a mineral grain framework or other host lithology (for example, sand or carbonate). Examples of tar sands formations include formations such as the Athabasca formation, the Grosmont formation, and the Peace River formation, all three in Alberta, Canada; and the Faja formation in the Orinoco belt in Venezuela. "Thickness" of a layer refers to the thickness of a cross section of the layer, wherein the cross section is normal to a face of the layer.

A "u-shaped wellbore" refers to a wellbore that extends from a first opening in the formation, through at least a portion of the formation, and out through a second opening in the formation. In this context, the wellbore may be only roughly in the shape of a "v" or "u", with the understanding that the "legs" of the "u" do not need to be parallel to each other, or perpendicular to the "bottom" of the "u" for the wellbore to be considered "u- shaped".

"Upgrade" refers to increasing the quality of hydrocarbons. For example, upgrading heavy hydrocarbons may result in an increase in the API gravity of the heavy hydrocarbons. "Visbreaking" refers to the untangling of molecules in fluid during heat treatment and/or to the breaking of large molecules into smaller molecules during heat treatment, which results in a reduction of the viscosity of the fluid.

The term "wellbore" refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used herein, the terms "well" and "opening," when referring to an opening in the formation may be used interchangeably with the term "wellbore."

A formation may be treated in various ways to produce many different products. Different stages or processes may be used to treat the formation during an in situ heat treatment process. In some embodiments, one or more sections of the formation are solution mined to remove soluble minerals from the sections. Solution mining minerals may be performed before, during, and/or after the in situ heat treatment process. In some embodiments, the average temperature of one or more sections being solution mined may be maintained below about 120 ⁰ C.

In some embodiments, one or more sections of the formation are heated to remove water from the sections and/or to remove methane and other volatile hydrocarbons from the sections. In some embodiments, the average temperature may be raised from ambient temperature to temperatures below about 220 ⁰ C during removal of water and volatile hydrocarbons.

In some embodiments, one or more sections of the formation are heated to temperatures that allow for movement and/or visbreaking of hydrocarbons in the formation. In some embodiments, the average temperature of one or more sections of the formation are raised to mobilization temperatures of hydrocarbons in the sections (for example, to temperatures ranging from 100 ⁰ C to 250 ⁰ C, from 120 ⁰ C to 240 ⁰ C, or from 150 ⁰ C to 230 ⁰ C). In some embodiments, one or more sections are heated to temperatures that allow for pyrolysis reactions in the formation. In some embodiments, the average temperature of one or more sections of the formation may be raised to pyrolysis temperatures of hydrocarbons in the sections (for example, temperatures ranging from 230 ⁰ C to 900 ⁰ C, from 240 ⁰ C to 400 ⁰ C or from 250 ⁰ C to 350 ⁰ C).

Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that raise the temperature of hydrocarbons in the formation to desired temperatures at desired heating rates. The rate of temperature increase through mobilization temperature range and/or pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product. In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature instead of slowly heating the temperature through a temperature range. In some embodiments, the desired temperature is 300 ⁰ C, 325 ⁰ C, or 350 ⁰ C. Other temperatures may be selected as the desired temperature.

Superposition of heat from heat sources allows the desired temperature to be relatively quickly and efficiently established in the formation. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at a desired temperature.

Mobilization and/or pyrolysis products may be produced from the formation through production wells. In some embodiments, the average temperature of one or more sections is raised to mobilization temperatures and hydrocarbons are produced from the production wells. The average temperature of one or more of the sections may be raised to pyrolysis temperatures after production due to mobilization decreases below a selected value. In some embodiments, the average temperature of one or more sections may be raised to pyrolysis temperatures without significant production before reaching pyrolysis temperatures. Formation fluids including pyrolysis products may be produced through the production wells.

In some embodiments, the average temperature of one or more sections may be raised to temperatures sufficient to allow synthesis gas production after mobilization and/or pyrolysis. In some embodiments, hydrocarbons may be raised to temperatures sufficient to allow synthesis gas production without significant production before reaching the temperatures sufficient to allow synthesis gas production. For example, synthesis gas may be produced in a temperature range from about 400 ⁰ C to about 1200 ⁰ C, about 500 ⁰ C to about 1100 ⁰ C, or about 550 ⁰ C to about 1000 ⁰ C. A synthesis gas generating fluid (for example, steam and/or water) may be introduced into the sections to generate synthesis gas. Synthesis gas may be produced from production wells. Solution mining, removal of volatile hydrocarbons and water, mobilizing hydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/or other processes may be performed during the in situ heat treatment process. In some embodiments, some processes may be performed after the in situ heat treatment process. Such processes may include, but are not limited to, recovering heat from treated sections, storing fluids (for example, water and/or hydrocarbons) in previously treated sections, and/or sequestering carbon dioxide in previously treated sections.

FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation. The in situ heat treatment system may include barrier wells 100. Barrier wells are used to form a barrier around a treatment area. The barrier inhibits fluid flow into and/or out of the treatment area. Barrier wells include, but are not limited to, dewatering wells, vacuum wells, capture wells, injection wells, grout wells, freeze wells, or combinations thereof. In some embodiments, barrier wells 100 are dewatering wells. Dewatering wells may remove liquid water and/or inhibit liquid water from entering a portion of the formation to be heated, or to the formation being heated. In the embodiment depicted in FIG. 1, the barrier wells 100 are shown extending only along one side of heat sources 102, but the barrier wells typically encircle all heat sources 102 used, or to be used, to heat a treatment area of the formation. Heat sources 102 are placed in at least a portion of the formation. Heat sources 102 may include electrically conducting material. In some embodiments, heat sources include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 102 may also include other types of heaters. Heat sources 102 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 102 through supply lines 104. Supply lines 104 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 104 for heat sources may transmit electricity for electrically conducting material or electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated in the formation. In some embodiments, electricity for an in situ heat treatment process may be provided by a nuclear power plant or nuclear power plants. The use of nuclear power may allow for reduction or elimination of carbon dioxide emissions from the in situ heat treatment process. Heating the formation may cause an increase in permeability and/or porosity of the formation. Increases in permeability and/or porosity may result from a reduction of mass in the formation due to vaporization and removal of water, removal of hydrocarbons, and/or creation of fractures. Fluid may flow more easily in the heated portion of the formation because of the increased permeability and/or porosity of the formation. Fluid in the heated portion of the formation may move a considerable distance through the formation because of the increased permeability and/or porosity. The considerable distance may be over 1000 m depending on various factors, such as permeability of the formation, properties of the fluid, temperature of the formation, and pressure gradient allowing movement of the fluid. The ability of fluid to travel considerable distance in the formation allows production wells 106 to be spaced relatively far apart in the formation. Production wells 106 are used to remove formation fluid from the formation. In some embodiments, production well 106 includes a heat source. The heat source in the production well may heat one or more portions of the formation at or near the production well. In some in situ heat treatment process embodiments, the amount of heat supplied to the formation from the production well per meter of the production well is less than the amount of heat applied to the formation from a heat source that heats the formation per meter of the heat source. Heat applied to the formation from the production well may increase formation permeability adjacent to the production well by vaporizing and removing liquid phase fluid adjacent to the production well and/or by increasing the permeability of the formation adjacent to the production well by formation of macro and/or micro fractures.

In some embodiments, the heat source in production well 106 allows for vapor phase removal of formation fluids from the formation. Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (Ce hydrocarbons and above) in the production well, and/or (5) increase formation permeability at or proximate the production well.

Subsurface pressure in the formation may correspond to the fluid pressure generated in the formation. As temperatures in the heated portion of the formation increase, the pressure in the heated portion may increase as a result of thermal expansion of in situ fluids, increased fluid generation and vaporization of water. Controlling rate of fluid removal from the formation may allow for control of pressure in the formation. Pressure in the formation may be determined at a number of different locations, such as near or at production wells, near or at heat sources, or at monitor wells. In some hydrocarbon containing formations, production of hydrocarbons from the formation is inhibited until at least some hydrocarbons in the formation have been mobilized and/or pyrolyzed. Formation fluid may be produced from the formation when the formation fluid is of a selected quality. In some embodiments, the selected quality includes an API gravity of at least about 20°, 30°, or 40°. Inhibiting production until at least some hydrocarbons are mobilized and/or pyrolyzed may increase conversion of heavy hydrocarbons to light hydrocarbons. Inhibiting initial production may minimize the production of heavy hydrocarbons from the formation. Production of substantial amounts of heavy hydrocarbons may require expensive equipment and/or reduce the life of production equipment.

In some embodiments, pressure generated by expansion of mobilized fluids, pyrolysis fluids or other fluids generated in the formation may be allowed to increase although an open path to production wells 106 or any other pressure sink may not yet exist in the formation. The fluid pressure may be allowed to increase towards a lithostatic pressure. Fractures in the hydrocarbon containing formation may form when the fluid approaches the lithostatic pressure. For example, fractures may form from heat sources 102 to production wells 106 in the heated portion of the formation. The generation of fractures in the heated portion may relieve some of the pressure in the portion. Pressure in the formation may have to be maintained below a selected pressure to inhibit unwanted production, fracturing of the overburden or underburden, and/or coking of hydrocarbons in the formation. After mobilization and/or pyrolysis temperatures are reached and production from the formation is allowed, pressure in the formation may be varied to alter and/or control a composition of formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.

In some in situ heat treatment process embodiments, pressure in the formation may be maintained high enough to promote production of formation fluid with an API gravity of greater than 20°. Maintaining increased pressure in the formation may inhibit formation subsidence during in situ heat treatment. Maintaining increased pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to treatment facilities. Maintaining increased pressure in a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality and of relatively low molecular weight. Pressure may be maintained so that formation fluid produced has a minimal amount of compounds above a selected carbon number. The selected carbon number may be at most 25, at most 20, at most 12, or at most 8. Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. Maintaining increased pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor. High carbon number compounds and/or multi-ring hydrocarbon compounds may remain in a liquid phase in the formation for significant time periods. The significant time periods may provide sufficient time for the compounds to pyrolyze to form lower carbon number compounds.

Formation fluid produced from production wells 106 may be transported through collection piping 108 to treatment facilities 110. Formation fluids may also be produced from heat sources 102. For example, fluid may be produced from heat sources 102 to control pressure in the formation adjacent to the heat sources. Fluid produced from heat sources 102 may be transported through tubing or piping to collection piping 108 or the produced fluid may be transported through tubing or piping directly to treatment facilities 110. Treatment facilities 110 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and/or other systems and units for processing produced formation fluids. The treatment facilities may form transportation fuel from at least a portion of the hydrocarbons produced from the formation. In some embodiments, the transportation fuel may be jet fuel, such as JP-8. In certain embodiments, heat sources, heat source power sources, production equipment, supply lines, and/or other heat source or production support equipment are positioned in tunnels to enable smaller sized heaters and/or smaller sized equipment to be used to treat the formation. Positioning such equipment and/or structures in tunnels may also reduce energy costs for treating the formation, reduce emissions from the treatment process, facilitate heating system installation, and/or reduce heat loss to the overburden as compared to hydrocarbon recovery processes that utilize surface based equipment. In some embodiments, nuclear energy is used to heat the heat transfer fluid used in a circulation system to heat a portion of the formation. Nuclear energy may be provided by a nuclear reactor, such as a pebble bed reactor, a light water reactor, or a fissile metal hydride reactor. The use of nuclear energy provides a heat source with little or no carbon dioxide emissions. Also, in some embodiments, the use of nuclear energy is more efficient because energy losses resulting from the conversion of heat to electricity and electricity to heat are avoided by directly utilizing the heat produced from the nuclear reactions without producing electricity.

In some embodiments, a nuclear reactor heats a heat transfer fluid such as helium. For example, helium flows through a pebble bed reactor, and heat transfers to the helium. The helium may be used as the heat transfer fluid to heat the formation. In some embodiments, the nuclear reactor heats helium, and the helium is passed through a heat exchanger to provide heat to another heat transfer fluid used to heat the formation. The nuclear reactor may include a pressure vessel that contains encapsulated enriched uranium dioxide fuel. Helium may be used as a heat transfer fluid to remove heat from the nuclear reactor. Heat may be transferred in a heat exchanger from the helium to the heat transfer fluid used in the circulation system. The heat transfer fluid used in the circulation system may be carbon dioxide, a molten salt, or other fluids. It is of course possible that a heat transfer fluid may not actually be a fluid at certain temperatures. A heat transfer fluid may have many of the properties of a solid at lower temperatures and a fluid at higher temperatures. Pebble bed reactor systems are available, for example, from PBMR Ltd (Centurion, South Africa). FIG. 2 depicts a schematic diagram of a system that uses nuclear energy to heat treatment area 200. The system may include helium system gas mover 202, nuclear reactor 204, heat exchanger unit 206, and heat transfer fluid mover 208. Helium system gas mover 202 may blow, pump, or compress heated helium from nuclear reactor 204 to heat exchanger unit 206. Helium from heat exchanger unit 206 may pass through helium system gas mover 202 to nuclear reactor 204. Helium from nuclear reactor 204 may be at a temperature between about 900 ⁰ C and about 1000 ⁰ C. Helium from helium gas mover 202 may be at a temperature between about 500 ⁰ C and about 600 ⁰ C. Heat transfer fluid mover 208 may draw heat transfer fluid from heat exchanger unit 206 through treatment area 200. Heat transfer fluid may pass through heat transfer fluid mover 208 to heat exchanger unit 206. The heat transfer fluid may be carbon dioxide, a molten salt, and/or other fluids. The heat transfer fluid may be at a temperature between about 850 ⁰ C and about 950 ⁰ C after exiting heat exchanger unit 206.

In some embodiments, the system includes auxiliary power unit 210. In some embodiments, auxiliary power unit 210 generates power by passing the helium from heat exchanger unit 206 through a generator to make electricity. The helium may be sent to one or more compressors and/or heat exchangers to adjust the pressure and temperature of the helium before the helium is sent to nuclear reactor 204. In some embodiments, auxiliary power unit 210 generates power using a heat transfer fluid (for example, ammonia or aqua ammonia). Helium from heat exchanger unit 206 may be sent to additional heat exchanger units to transfer heat to the heat transfer fluid. The heat transfer fluid may be taken through a power cycle (such as a Kalina cycle) to generate electricity. In an embodiment, nuclear reactor 204 is a 400 MW reactor and auxiliary power unit 210 generates about 30 MW of electricity. FIG. 3 depicts a schematic elevational view of an arrangement for an in situ heat treatment process. Wellbores (which may be U-shaped or in other shapes) may be formed in the formation to define treatment areas 200A, 200B, 200C, 200D. Additional treatment areas could be formed to the sides of the shown treatment areas. Treatment areas 200A, 200B, 200C, 200D may have widths of over 300 m, 500 m, 1000 m, or 1500 m. Well exits and entrances for the wellbores may be formed in well openings area 212. Rail lines 214 may be formed along sides of treatment areas 200. Warehouses, administration offices, and/or spent fuel storage facilities may be located near ends of rail lines 214. Facilities 216 may be formed at intervals along spurs of rail lines 214. Facilities 216 may include a nuclear reactor, compressors, heat exchanger units, and/or other equipment needed for circulating hot heat transfer fluid to the wellbores. Facilities 216 may also include surface facilities for treating formation fluid produced from the formation. In some embodiments, heat transfer fluid produced in facility 216' may be reheated by the reactor in facility 216" after passing through treatment area 200A. In some embodiments, each facility 216 is used to provide hot treatment fluid to wells in one half of the treatment area 200 adjacent to the facility. Facilities 216 may be moved by rail to another facility site after production from a treatment area is completed.

In some embodiments, nuclear energy is used to directly heat a portion of a subsurface formation. The portion of the subsurface formation may be part of a hydrocarbon treatment area. As opposed to using a nuclear reactor facility to heat a heat transfer fluid, which is then provided to the subsurface formation to heat the subsurface formation, one or more self-regulating nuclear heaters may be positioned underground to directly heat the subsurface formation. The self-regulating nuclear reactor may be positioned in or proximate to one or more tunnels. In some embodiments, treatment of the subsurface formation requires heating the formation to a desired initial upper range (for example, between about 250 ⁰ C and 350 ⁰ C). After heating the subsurface formation to the desired temperature range, the temperature may be maintained in the range for a desired time (for example, until a percentage of hydrocarbons have been pyrolyzed or an average temperature in the formation reaches a selected value). As the formation temperature rises, the heater temperature may be slowly lowered over a period of time. Currently, certain nuclear reactors described herein (for example, nuclear pebble bed reactors), upon activation, reach a natural temperature output limit of about 900 ⁰ C, eventually decaying as the uranium-235 fuel is depleted and resulting in lower temperatures produced over time at the heater. The natural power output curve of certain nuclear reactors (for example, nuclear pebble bed reactors) may be used to provide a desired heating versus time profile for certain subsurface formations. In some embodiments, nuclear energy is provided by a self-regulating nuclear reactor (for example, a pebble bed reactor or a fissile metal hydride reactor). The self-regulating nuclear reactor may not exceed a certain temperature based upon its design. The self- regulating nuclear reactor may be substantially compact relative to traditional nuclear reactors. The self-regulating nuclear reactor may be, for example, approximately 2 m, 3 m, or 5 m square or even less in size. The self-regulating nuclear reactor may be modular. FIG. 4 depicts a schematic representation of self-regulating nuclear reactor 218. In some embodiments, the self-regulating nuclear reactor includes fissile metal hydride 220. The fissile metal hydride may function as both fuel for the nuclear reaction as well as a moderator for the nuclear reaction. A core of the nuclear reactor may include a metal hydride material. The temperature driven mobility of the hydrogen isotope contained in the hydride may function to control the nuclear reaction. If the temperature increases above a set point in core 222 of self-regulating nuclear reactor 218, a hydrogen isotope dissociates from the hydride and escapes out of the core and the power production decreases. If the core temperature decreases, the hydrogen isotope reassociates with the fissile metal hydride reversing the process. In some embodiments, the fissile metal hydride may be in a powdered form, which allows hydrogen to more easily permeate the fissile metal hydride.

Due to its basic design, the self-regulating nuclear reactor may include few, if any, moving parts associated with the control of the nuclear reaction itself. The small size and simple construction of the self-regulating nuclear reactor may have distinct advantages, especially relative to conventional commercial nuclear reactors used commonly throughout the world today. Advantages may include relative ease of manufacture, transportability, security, safety, and financial feasibility. The compact design of self-regulating nuclear reactors may allow for the reactor to be constructed at one facility and transported to a site of use, such as a hydrocarbon containing formation. Upon arrival and installation, the self- regulating nuclear reactor may be activated.

Self-regulating nuclear reactors may produce thermal power on the order of tens of megawatts per unit. Two or more self-regulating nuclear reactors may be used at the hydrocarbon containing formation. Self-regulating nuclear reactors may operate at a fuel temperature ranging between about 450 ⁰ C and about 900 ⁰ C, between about 500 ⁰ C and about 800 ⁰ C, or between about 550 ⁰ C and about 650 ⁰ C. The operating temperature may be in the range between about 550 ⁰ C and about 600 ⁰ C. The operating temperature may be in the range between about 500 ⁰ C and about 650 ⁰ C. Self-regulating nuclear reactors may include energy extraction system 224 in core 222. Energy extraction system 224 may function to extract energy in the form of heat produced by the activated nuclear reactor. The energy extraction system may include a heat transfer fluid that circulates through piping 224A and 224B. At least a portion of the tubing may be positioned in the core of the nuclear reactor. A fluid circulation system may function to continuously circulate heat transfer fluid through the piping. Density and volume of piping positioned in the core may be dependent on the enrichment of the fissile metal hydride. In some embodiments, the energy extraction system includes alkali metal (for example, potassium) heat pipes. Heat pipes may further simplify the self-regulating nuclear reactor by eliminating the need for mechanical pumps to convey a heat transfer fluid through the core. Any simplification of the self-regulating nuclear reactor may decrease the chances of any malfunctions and increase the safety of the nuclear reactor. The energy extraction system may include a heat exchanger coupled to the heat pipes. Heat transfer fluids may convey thermal energy from the heat exchanger.

The dimensions of the nuclear reactor may be determined by the enrichment of the fissile metal hydride. Nuclear reactors with a higher enrichment result in smaller relative reactors. Proper dimensions may be ultimately determined by particular specifications of a hydrocarbon containing formation and the formation's energy needs. In some embodiments, the fissile metal hydride is diluted with a fertile hydride. The fertile hydride may be formed from a different isotope of the fissile portion. The fissile metal hydride may include the fissile hydride U ²³⁵ and the fertile hydride may include the isotope U ²³⁸ . In some embodiments, the core of the nuclear reactor may include a nuclear fuel formed from about 5% of U ²³⁵ and about 95% of U ²³⁸ .

Other combinations of fissile metal hydrides mixed with fertile or non-fissile hydrides will also work. The fissile metal hydride may include plutonium. Plutonium's low melting temperature (about 640 ⁰ C) makes the hydride particles less attractive as a reactor fuel to power a steam generator, but may be useful in other applications requiring lower reactor temperatures. The fissile metal hydride may include thorium hydride. Thorium permits higher temperature operation of the reactor because of its high melting temperature (about 1755 ⁰ C). In some embodiments, different combinations of fissile metal hydrides are used in order to achieve different energy output parameters.

In some embodiments, nuclear reactor 218 may include one or more hydrogen storage containers 226. A hydrogen storage container may include one or more non-fissile hydrogen absorbing materials to absorb the hydrogen expelled from the core. The non- fissile hydrogen absorbing material may include a non-fissile isotope of the core hydride. The non-fissile hydrogen absorbing material may have a hydride dissociation pressure close to that of the fissile material.

Core 222 and hydrogen storage containers 226 may be separated by insulation layer 228. The insulation layer may function as a neutron reflector to reduce neutron leakage from the core. The insulation layer may function to reduce thermal feedback. The insulation layer may function to protect the hydrogen storage containers from being heated by the nuclear core (for example, with radiative heating or with convective heating from the gas within the chamber).

The effective steady-state temperature of the core may be controlled by the ambient hydrogen gas pressure. The ambient hydrogen gas pressure may be controlled by the temperature at which the non-fissile hydrogen absorbing material is maintained. The temperature of the fissile metal hydride may be independent of the amount of energy being extracted. The energy output may be dependent on the ability of the energy extraction system to extract power from the nuclear reactor. Hydrogen gas in the reactor core may be monitored for purity and periodically repressurized to maintain the correct quantity and isotopic content. In some embodiments, the hydrogen gas is maintained via access to the core of the nuclear reactor through one or more pipes (for example, pipes 230A and 230B). The temperature of the self-regulating nuclear reactor may be controlled by controlling a pressure of hydrogen supplied to the self-regulating nuclear reactor. The pressure may be regulated based upon the temperature of the heat transfer fluid at one or more points (for example, at the point where the heat transfer fluid enters one or more wellbores). In some embodiments, the nuclear reaction occurring in the self-regulating nuclear reactor may be controlled by introducing a neutron-absorbing gas. The neutron-absorbing gas may, in sufficient quantities, quench the nuclear reaction in the self-regulating nuclear reactor (ultimately reducing the temperature of the reactor to ambient temperature). Neutron-absorbing gases may include xenon ¹³⁵ . In some embodiments, the nuclear reaction of an activated self-regulating nuclear reactor is controlled using control rods. Control rods may be positioned at least partially in at least a portion of the nuclear core of the self-regulating nuclear reactor. Control rods may be formed from one or more neutron-absorbing materials. Neutron-absorbing materials may include, but not be limited to, silver, indium, cadmium, boron, cobalt, hafnium, dysprosium, gadolinium, samarium, erbium, and europium.

Currently, self-regulating nuclear reactors described herein, upon activation, reach a natural temperature output limit of about 900 ⁰ C, eventually decaying as the fuel is depleted. The natural power output curve of self-regulating nuclear reactors may be used to provide a desired heating versus time profile for certain subsurface formations. In some embodiments, self-regulating nuclear reactors may have a natural energy output which decays at a rate of about 1/E (E is sometimes referred to as Euler's number and is equivalent to about 2.71828). In some embodiments, self-regulating nuclear reactors may have a natural power output that decays to 1/E of the initial power in a period of time of about 4 years to about 8 years. Typically, once a formation has been heated to a desired temperature, less heat is required and the amount of thermal energy put into the formation in order to heat the formation is reduced over time. In some embodiments, heat input to at least a portion of the formation over time approximately correlates to a rate of decay of the power from the self-regulating nuclear reactor. Due to the natural decay of at least some self-regulating nuclear reactors, heating systems may be designed such that the heating systems take advantage of the natural rate of decay of the power from a nuclear reactor. Heating systems typically include two or more heaters. Heaters are typically positioned in wellbores placed throughout the formation. Wellbores may include, for example, U- shaped and L-shaped wellbores or other shapes of wellbores. In some embodiments, spacing between wellbores is determined based on the decay rate of the power output of self-regulating nuclear reactors.

The self-regulating nuclear reactor may initially provide, to at least a portion of the wellbores, a power output of about 300 watts/foot; and, thereafter, decreasing over a predetermined time period to about 120 watts/foot. The predetermined time period may be determined by the design of the self-regulating nuclear reactor itself (for example, fuel used in the nuclear core as well as the enrichment of the fuel). The natural decrease in power output may match power injection versus time dependence of the formation. Either variable (for example, power output and/or power injection) may be adjusted so that the two variables at least approximately correlate or match. The self-regulating nuclear reactor may be designed to decay over a period of 4-9 years, 5-7 years, or about 7 years. The decay period of the self-regulating nuclear reactor may correspond to an IUP (in situ upgrading process) and/or an ICP (in situ conversion process) heating cycle. In some embodiments, spacing between heater wellbores depends on a rate of decay of one or more nuclear reactors used to provide power. In some embodiments, spacing between heater wellbores ranges between about 8 meters and about 11 meters, between about 9 meters and about 10 meters, or between about 9.4 meters and about 9.8 meters. In certain situations, it may be advantageous to continue a particular level of power output of the self-regulating nuclear reactor for a longer period than the natural decay of the fuel material in the nuclear core would normally allow. In some embodiments, in order to keep the level of output within a desired range, a second self-regulating nuclear reactor may be coupled to the formation being treated (for example, being heated). The second self- regulating nuclear reactor may, in some embodiments, have a decayed power output. The power output of the second reactor may have already decreased due to prior use. The power output of the two self-regulating nuclear reactors may be substantially equivalent to the initial power output of the first self-regulating nuclear reactor and/or a desired power output. Additional self-regulating nuclear reactors may be coupled to the formation as needed to achieve the desired power output. Such a system may advantageously increase the effective useful lifetime of the self-regulating nuclear reactors. The effective useful lifetime of self-regulating nuclear reactors may be extended by using the thermal energy produced by the nuclear reactor to produce steam, which, depending upon the formation and/or systems used, may require far less thermal energy than other uses outlined herein. Steam may be used for a number of purposes including, but not limited to, producing electricity, producing hydrogen on site, converting hydrocarbons, and/or upgrading hydrocarbons. Hydrocarbons may be converted and/or mobilized in situ by injecting the produced steam in the formation.

A product stream (for example, a stream including methane, hydrocarbons, and/or heavy hydrocarbons) may be produced from a formation heated with heat transfer fluids that are heated by the nuclear reactor. Steam produced from heat generated by the nuclear reactor or a second nuclear reactor may be used to reform at least a portion of the product stream. The product stream may be reformed to make at least some molecular hydrogen. The molecular hydrogen may be used to upgrade at least a portion of the product stream. The molecular hydrogen may be injected in the formation. The product stream may be produced from a surface upgrading process. The product stream may be produced from an in situ heat treatment process. The product stream may be produced from a subsurface steam heating process. At least a portion of the steam may be injected into a subsurface steam heating process. At least some of the steam may be used to reform methane. At least some of the steam may be used for electrical generation. At least a portion of the hydrocarbons in the formation may be mobilized by the steam and/or heat from the steam.

In some embodiments, self-regulating nuclear reactors may be used to produce electricity (for example, via steam driven turbines). The electricity may be used for any number of applications normally associated with electricity. Specifically, the electricity may be used for applications associated with in situ heat treatment processes requiring energy. Electricity from self-regulating nuclear reactors may be used to provide energy for downhole electric heaters. Electricity may be used to cool fluid for forming a low temperature barrier (frozen barrier) around treatment areas, and/or for providing electricity to treatment facilities located at or near the in situ heat treatment process site. In some embodiments, the electricity produced by the nuclear reactors is used to resistively heat the conduits used to circulate heat transfer fluid through the treatment area. In some embodiments, nuclear power is used to generate electricity that operates compressors and/or pumps (compressors/pumps provide compressed gases (such as oxidizing fluid and/or fuel to a plurality of oxidizer assemblies) to a treatment area) needed for the in situ heat treatment process. A significant cost of the in situ heat treatment process may be operating the compressors and/or pumps over the life of the in situ heat treatment process if conventional electrical energy sources are used to power the compressors and/or pumps of the in situ heat treatment process.

Converting heat from self-regulating nuclear reactors into electricity may not be the most efficient use of the thermal energy produced by the nuclear reactors. In some embodiments, thermal energy produced by self-regulating nuclear reactors is used to directly heat portions of a formation. In some embodiments, one or more self-regulating nuclear reactors are positioned underground in the formation such that thermal energy produced directly heats at least a portion of the formation. One or more self-regulating nuclear reactors may be positioned underground in the formation below the overburden thus increasing the efficient use of the thermal energy produced by the self-regulating nuclear reactors. Self-regulating nuclear reactors positioned underground may be encased in a material for further protection. For example, self-regulating nuclear reactors positioned underground may be encased in a concrete container. In some embodiments, thermal energy produced by self-regulating nuclear reactors may be extracted using heat transfer fluids. Thermal energy produced by self-regulating nuclear reactors may be transferred to and distributed through at least a portion of the formation using heat transfer fluids. Heat transfer fluids may circulate through the piping of the energy extraction system of the self-regulating nuclear reactor. As heat transfer fluids circulate in and through the core of the self-regulating nuclear reactor, the heat produced from the nuclear reaction heats the heat transfer fluids.

In some embodiments, two or more heat transfer fluids may be employed to transfer thermal energy produced by self-regulating nuclear reactors. A first heat transfer fluid may circulate through the piping of the energy extraction system of the self-regulating nuclear reactor. The first heat transfer fluid may pass through a heat exchanger and used to heat a second heat transfer fluid. The second heat transfer fluid may be used for treating hydrocarbon fluids in situ, powering electrolysis unit, and/or for other purposes. The first heat transfer fluid and the second heat transfer fluid may be different materials. Using two heat transfer fluids may reduce the risk of unnecessary exposure of systems and personnel to any radiation absorbed by the first heat transfer fluid. Heat transfer fluids that are resistant to absorbing nuclear radiation may be used (for example, nitrite salts or nitrate salts).

In some embodiments, the energy extraction system includes alkali metal (for example, potassium) heat pipes. Heat pipes may further simplify the self-regulating nuclear reactor by eliminating the need for mechanical pumps to convey a heat transfer fluid through the core. Any simplification of the self-regulating nuclear reactor may decrease the chances of malfunctions and increase the safety of the nuclear reactor. The energy extraction system may include a heat exchanger coupled to the heat pipes. Heat transfer fluids may convey thermal energy from the heat exchanger.

Heat transfer fluids may include natural or synthetic oil, molten metal, molten salt, or other types of high temperature heat transfer fluids. The heat transfer fluid may have a low viscosity and a high heat capacity at normal operating conditions. When the heat transfer fluid is a molten salt or other fluid that has the potential to solidify in the formation, piping of the system may be electrically coupled to an electricity source to resistively heat the piping when needed and/or one or more heaters may be positioned in or adjacent to the piping to maintain the heat transfer fluid in a liquid state. In some embodiments, an insulated conductor heater is placed in the piping. The insulated conductor may melt solids in the pipe. FIG. 5 depicts a schematic representation of an embodiment of an in situ heat treatment system positioned in formation 232 with u-shaped wellbores 234 using self-regulating nuclear reactors 218. Self-regulating nuclear reactors 218, depicted in FIG. 5, may produce about 70 MWthermal. In some embodiments, spacing between wellbores 234 is determined based on the decay rate of the energy output of self-regulating nuclear reactors 218.

U-shaped wellbores may run down through overburden 236 and into hydrocarbon containing layer 238. The piping in wellbores 234 adjacent to overburden 236 may include insulated portion 240. Insulated storage tanks 242 may receive molten salt from the formation 232 through piping 244. Piping 244 may transport molten salts with temperatures ranging from about 350 ⁰ C to about 500 ⁰ C. Temperatures in the storage tanks may be dependent on the type of molten salt used. Temperatures in the storage tanks may be in the vicinity of about 350 ⁰ C. Pumps may move the molten salt to self-regulating nuclear reactors 218 through piping 246. Each of the pumps may need to move, for example, 6 kg/sec to 12 kg/sec of the molten salt. Each self-regulating nuclear reactor 218 may provide heat to the molten salt. The molten salt may pass from piping 248 to wellbores 234. The heated portion of wellbore 234 that passes through layer 238 may extend, in some embodiments, from about 8,000 feet (about 2400 m) to about 10,000 feet (about 3000 m). Exit temperatures of the molten salt from self-regulating nuclear reactors 218 may be about 550 ⁰ C. Each self-regulating nuclear reactor 218 may supply molten salt to about 20 or more wellbores 234 that enter the formation. The molten salt flows through the formation and back to storage tanks 242 through piping 244.

In some embodiments, nuclear energy is used in a cogeneration process. In an embodiment for producing hydrocarbons from a hydrocarbon containing formation (for example, a tar sands formation), produced hydrocarbons may include one or more portions with heavy hydrocarbons. Hydrocarbons may be produced from the formation using more than one process. In certain embodiments, nuclear energy is used to assist in producing at least some of the hydrocarbons. At least some of the produced heavy hydrocarbons may be subjected to pyrolysis temperatures. Pyrolysis of the heavy hydrocarbons may be used to produce steam. Steam may be used for a number of purposes including, but not limited to, producing electricity, converting hydrocarbons, and/or upgrading hydrocarbons. In some embodiments, a heat transfer fluid is heated using a self-regulating nuclear reactor. The heat transfer fluid may be heated to temperatures that allow for steam production (for example, from about 550 ⁰ C to about 600 ⁰ C). In some embodiments, in situ heat treatment process gas and/or fuel passes to a reformation unit. In some embodiments, in situ heat treatment process gas is mixed with fuel and then passed to the reformation unit. A portion of in situ heat treatment process gas may enter a gas separation unit. The gas separation unit may remove one or more components from the in situ heat treatment process gas to produce the fuel and one or more other streams (for example, carbon dioxide or hydrogen sulfide). The fuel may include, but not be limited to, hydrogen, hydrocarbons having a carbon number of at most 5, or mixtures thereof.

The reformer unit may be a steam reformer. The reformer unit may combine steam with a fuel (for example, methane) to produce hydrogen. For example, the reformation unit may include water gas shift catalysts. The reformation unit may include one or more separation systems (for example, membranes and/or a pressure swing adsorption system) capable of separating hydrogen from other components. Reformation of the fuel and/or the in situ heat treatment process gas may produce a hydrogen stream and a carbon oxide stream. Reformation of the fuel and/or the in situ heat treatment process gas may be performed using techniques known in the art for catalytic and/or thermal reformation of hydrocarbons to produce hydrogen. In some embodiments, electrolysis is used to produce hydrogen from the steam. A portion or all of the hydrogen stream may be used for other purposes such as, but not limited to, an energy source and/or a hydrogen source for in situ or ex situ hydrogenation of hydrocarbons.

Self-regulating nuclear reactors may be used to produce hydrogen at facilities located adjacent to hydrocarbon containing formations. The ability to produce hydrogen on site at hydrocarbon containing formations is highly advantageous due to the plurality of ways in which hydrogen is used for converting and upgrading hydrocarbons on site at hydrocarbon containing formations.

In some embodiments, the first heat transfer fluid is heated using thermal energy stored in the formation. Thermal energy may result in the formation following a number of different heat treatment methods.

Self-regulating nuclear reactors have several advantages over many current constant output nuclear reactors. However, there are several new nuclear reactors whose designs have received regulatory approval for construction. Nuclear energy may be provided by a number of different types of available nuclear reactors and nuclear reactors currently under development (for example, generation IV reactors).

In some embodiments, nuclear reactors include very high temperature reactors (VHTR). VHTRs may use, for example, helium as a coolant to drive a gas turbine for treating hydrocarbon fluids in situ, powering an electrolysis unit, and/or for other purposes. VHTRs may produce heat up to about 950 ⁰ C or more. In some embodiments, nuclear reactors include a sodium-cooled fast reactor (SFR). SFRs may be designed on a smaller scale (for example, 50MWe) and therefore may be more cost effective to manufacture on site for treating hydrocarbon fluids in situ, powering electrolysis units, and/or for other purposes. SFRs may be of a modular design and potentially portable. SFRs may produce temperatures ranging between about 500 ⁰ C and about 600 ⁰ C, between about 525 ⁰ C and about 575 ⁰ C, or between 540 ⁰ C and about 560 ⁰ C.

In some embodiments, pebble bed reactors are employed to provide thermal energy. Pebble bed reactors may produce up to 165 MWe. Pebble bed reactors may produce temperatures ranging between about 500 ⁰ C and about 1100 ⁰ C, between about 800 ⁰ C and about 1000 ⁰ C, or between about 900 ⁰ C and about 950 ⁰ C. In some embodiments, nuclear reactors include supercritical-water-cooled reactors (SCWR) based at least in part on previous light water reactors (LWR) and supercritical fossil-fired boilers. SCWRs may produce temperatures ranging between about 400 ⁰ C and about 650 ⁰ C, between about 450 ⁰ C and about 550 ⁰ C, or between about 500 ⁰ C and about 550 ⁰ C. In some embodiments, nuclear reactors include lead-cooled fast reactors (LFR). LFRs may be manufactured in a range of sizes, from modular systems to several hundred megawatt or more. LFRs may produce temperatures ranging between about 400 ⁰ C and about 900 ⁰ C, between about 500 ⁰ C and about 850 ⁰ C, or between about 550 ⁰ C and about 800 ⁰ C. In some embodiments, nuclear reactors include molten salt reactors (MSR). MSRs may include fissile, fertile, and fission isotopes dissolved in a molten fluoride salt with a boiling point of about 1,400 ⁰ C. The molten fluoride salt may function as both the reactor fuel and the coolant. MSRs may produce temperatures ranging between about 400 ⁰ C and about 900 ⁰ C, between about 500 ⁰ C and about 850 ⁰ C, or between about 600 ⁰ C and about 800 ⁰ C.

In some embodiments, two or more heat transfer fluids (for example, molten salts) are employed to transfer thermal energy to and/or from a hydrocarbon containing formation. A first heat transfer fluid may be heated (for example, with a nuclear reactor). The first heat transfer fluid may be circulated through a plurality of wellbores in at least a portion of the formation in order to heat the portion of the formation. The first heat transfer fluid may have a first temperature range in which the first heat transfer fluid is in a liquid form and stable. The first heat transfer fluid may be circulated through the portion of the formation until the portion reaches a desired temperature range (for example, a temperature towards an upper end of the first temperature range). A second heat transfer fluid may be heated (for example, with a nuclear reactor). The second heat transfer fluid may have a second temperature range in which the second heat transfer fluid is in a liquid form and stable. An upper end of the second temperature range may be hotter and above the first temperature range. A lower end of the second temperature range may overlap with the first temperatures range. The second heat transfer fluid may be circulated through the plurality of wellbores in the portion of the formation in order to heat the portion of the formation to a higher temperature than is possible with the first heat transfer fluid.

The advantages of using two or more different heat transfer fluids may include, for example, the ability to heat the portion of the formation to a much higher temperature than is normally possible while using other supplementary heating methods (for example, electric heaters) as little as possible to increase overall efficiency. Using two or more different heat transfer fluids may be necessary if a heat transfer fluid with a temperature range capable of heating the portion of the formation to the desired temperature is not available.

In some embodiments, after the portion of the hydrocarbon containing formation has been heated to a desired temperature range, the first heat transfer fluid may be recirculated through the portion of the formation. The first heat transfer fluid may not be heated before recirculation through the formation (other than heating the heat transfer fluid to the melting point if necessary in the case of molten salts). The first heat transfer fluid may be heated using the thermal energy already stored in the portion of the formation from prior in situ heat treatment of the formation. The first heat transfer fluid may then be transferred out of the formation such that the thermal energy recovered by the first heat transfer fluid may be reused for some other process in the portion of the formation, in a second portion of the formation, and/or in an additional formation. Examples Non-limiting examples are set forth below. Power Requirement Simulation. A simulation to determine the power requirements to heat a formation with a molten salt was performed. Molten salt was circulated through wellbores in a hydrocarbon containing formation and the power requirements to heat the formation using molten salt were assessed over time. The distance between the wellbores was varied to determine the effect upon the power requirements. FIG. 6 depicts curve 250 of power (W/ft)(y-axis) versus time (yr)(x-axis) of in situ heat treatment power injection requirements. FIG. 7 depicts power (W/ft)(y-axis) versus time (days)(x-axis) of in situ heat treatment power injection requirements for different spacings between wellbores. Curves 252-260 depict the results in FIG. 7. Curve 252 depicts power required versus time for heater wellbores with a spacing of about 14.4 meters. Curve 254 depicts power required versus time for heater wellbores with a spacing of about 13.2 meters. Curve 256 depicts power required versus time for the Grosmont formation in Alberta, Canada, with heater wellbores laid out in a hexagonal pattern and with a spacing of about 12 meters. Curve 258 depicts power required versus time for heater wellbores with a spacing of about 9.6 meters. Curve 260 depicts power required versus time for heater wellbores with a spacing of about 7.2 meters.

From the graph in FIG. 7, wellbore spacing represented by curve 258 is the spacing which approximately correlates to the power output over time of certain nuclear reactors (for example, at least some nuclear reactors having a power output that decays to about 1/E, for example, in about 4 to about 9 years). Curves 252-256, in FIG. 7, depict the required power output for heater wellbores with spacing ranging from about 12 meters to about 14.4 meters. Spacing between heater wellbores greater than about 12 meters may require more energy input than certain nuclear reactors may be able to provide. Spacing between heater wellbores less than about 8 meters (for example, as represented by curve 260 in FIG. 7) may not make efficient use of the energy input provided by certain nuclear reactors. FIG. 8 depicts reservoir average temperature (°C)(y-axis) versus time (days)(x-axis) of in situ heat treatment for different spacings between wellbores. Curves 252-260 depict the temperature increase in the formation over time based upon the power input requirements for the well spacing. A target temperature for in situ heat treatment of hydrocarbon containing formations, in some embodiments, for example may be about 350 ⁰ C. The target temperature for a formation may vary depending on, at least, the type of formation and/or the desired hydrocarbon products. The spacing between the wellbores for curves 252-260 in FIG. 8 are the same for curves 252-260 in FIG. 7. Curves 252-256, in FIG. 8, depict the increasing temperature in the formation over time for heater wellbores with spacing ranging from about 12 meters to about 14.4 meters. Spacing between heater wellbores greater than about 12 meters may heat the formation too slowly such that more energy may be required than certain nuclear reactors may be able to provide (especially after about 5 years in the current example). Spacing between heater wellbores less than about 8 meters (for example, as represented by curve 260 in FIG. 8) may heat the formation too quickly for some in situ heat treatment situations. From the graph in FIG. 8, wellbore spacing represented by curve 258 may be the spacing that achieves a typical target temperature of about 350 ⁰ C in a desirable time frame (for example, about 5 years). Further modifications and alternative embodiments of various aspects of the invention may be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims. In addition, it is to be understood that features described herein independently may, in certain embodiments, be combined.