Thermal expansion accommodation for circulated fluid systems used to heat subsurface formations

Abstract

A method for accommodating thermal expansion of a heater in a formation includes flowing a heat transfer fluid through a conduit to provide heat to the formation and providing substantially constant tension to an end portion of the conduit that extends outside the formation. At least a portion of the end portion of the conduit is wound around a movable wheel used to apply tension to the conduit.

Description

RELATED PATENTS

This patent application incorporates by reference in its entirety each of U.S. Pat. No. 6,688,387 to Wellington et al.; U.S. Pat. No. 6,991,036 to Sumnu-Dindoruk et al.; U.S. Pat. No. 6,698,515 to Karanikas et al.; U.S. Pat. No. 6,880,633 to Wellington et al.; U.S. Pat. No. 6,782,947 to de Rouffignac et al.; U.S. Pat. No. 6,991,045 to Vinegar et al.; U.S. Pat. No. 7,073,578 to Vinegar et al.; U.S. Pat. No. 7,121,342 to Vinegar et al.; U.S. Pat. No. 7,320,364 to Fairbanks; U.S. Pat. No. 7,527,094 to McKinzie et al.; U.S. Pat. No. 7,584,789 to Mo et al.; U.S. Pat. No. 7,533,719 to Hinson et al.; U.S. Pat. No. 7,562,707 to Miller; and U.S. Pat. No. 7,798,220 to Vinegar et al.; U.S. Patent Application Publication Nos. 2009-0189617 to Burns et al.; 2010-0071903 to Prince-Wright et al.; 2010-0096137 to Nguyen et al.; 2010-0258265 to Karanikas et al.; and 2011-0247808 to Nguyen.

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. More particularly, the invention relates to systems and methods for heating subsurface 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.

U.S. Pat. No. 7,575,052 to Sandberg et al., which is incorporated by reference as if fully set forth herein, describes an in situ heat treatment process that utilizes a circulation system to heat one or more treatment areas. The circulation system may use a heated liquid heat transfer fluid that passes through piping in the formation to transfer heat to the formation.

U.S. Patent Application Publication No. 2008-0135254 to Vinegar et al., which is incorporated by reference as if fully set forth herein, describes systems and methods for an in situ heat treatment process that utilizes a circulation system to heat one or more treatment areas. The circulation system uses a heated liquid heat transfer fluid that passes through piping in the formation to transfer heat to the formation. In some embodiments, the piping is positioned in at least two wellbores.

U.S. Patent Application Publication No. 2009-0095476 to Nguyen et al., which is incorporated by reference as if fully set forth herein, describes a heating system for a subsurface formation includes a conduit located in an opening in the subsurface formation. An insulated conductor is located in the conduit. A material is in the conduit between a portion of the insulated conductor and a portion of the conduit. The material may be a salt. The material is a fluid at operating temperature of the heating system. Heat transfers from the insulated conductor to the fluid, from the fluid to the conduit, and from the conduit to the subsurface formation.

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. There is also 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, methods, and heaters for treating a subsurface formation. Embodiments described herein also generally relate to heaters that have novel components therein. Such heaters can be obtained by using the systems and methods described herein.

In certain embodiments, the invention provides one or more systems, methods, and/or heaters. In some embodiments, the systems, methods, and/or heaters are used for treating a subsurface formation.

In certain embodiments, a method for accommodating thermal expansion of a heater in a formation, includes: flowing a heat transfer fluid through a conduit to provide heat to the formation; and providing substantially constant tension to an end portion of the conduit that extends outside the formation, wherein at least a portion of the end portion of the conduit is wound around a movable wheel used to apply tension to the conduit.

In certain embodiments, a system for accommodating thermal expansion of a heater in a formation, includes: a conduit configured to apply heat to the formation when a heat transfer fluid flows through the conduit; and a movable wheel, wherein at least part of an end portion of the conduit is wound around the wheel, and the movable wheel is used to maintain substantially constant tension on the conduit to absorb expansion of the conduit when the heat transfer fluid flows through the conduit.

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 methods, systems, power supplies, or heaters 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 in which:

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 a system for heating a formation using a circulation system.

FIG. 3 depicts a representation of a bellows.

FIG. 4A depicts a representation of piping with an expansion loop above a wellhead for accommodating thermal expansion.

FIG. 4B depicts a representation of piping with coiled or spooled piping above a wellhead for accommodating thermal expansion.

FIG. 4C depicts a representation of piping with coiled or spooled piping in an insulated volume above a wellhead for accommodating thermal expansion.

FIG. 5 depicts a portion of piping in an overburden after thermal expansion of the piping has occurred.

FIG. 6, depicts a portion of piping with more than one conduit in an overburden after thermal expansion of the piping has occurred.

FIG. 7 depicts a representation of a wellhead with a sliding seal.

FIG. 8 depicts a representation of a system where heat transfer fluid in a conduit is transferred to or from a fixed conduit.

FIG. 9 depicts a representation of a system where a fixed conduit is secured to a wellhead.

FIG. 10 depicts an embodiment of seals.

FIG. 11 depicts an embodiment of seals, a conduit, and another conduit secured in place with locking mechanisms.

FIG. 12 depicts an embodiment with locking mechanisms set in place using soft metal seals.

FIG. 13 depicts a representation of a u-shaped wellbore with a heater positioned in the wellbore.

FIG. 14 depicts a representation of a u-shaped wellbore with a heater coupled to a tensioning wheel.

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° C. (60° F.). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298.

“ASTM” refers to American Standard Testing and Materials.

In the context of reduced heat output heating systems, apparatus, and methods, the term “automatically” means such systems, apparatus, and methods function in a certain way without the use of external control (for example, external controllers such as a controller with a temperature sensor and a feedback loop, PID controller, or predictive controller).

“Asphalt/bitumen” refers to a semi-solid, viscous material soluble in carbon disulfide. Asphalt/bitumen may be obtained from refining operations or produced from subsurface formations.

“Carbon number” refers to the number of carbon atoms in a molecule. A hydrocarbon fluid may include various hydrocarbons with different carbon numbers. The hydrocarbon fluid may be described by a carbon number distribution. Carbon numbers and/or carbon number distributions may be determined by true boiling point distribution and/or gas-liquid chromatography.

“Condensable hydrocarbons” are hydrocarbons that condense at 25° C. and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4. “Non-condensable hydrocarbons” are hydrocarbons that do not condense at 25° C. and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.

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.

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 a 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° 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.

“Kerogen” is a solid, insoluble hydrocarbon that has been converted by natural degradation and that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples of materials that contain kerogen. “Bitumen” is a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide. “Oil” is a fluid containing a mixture of condensable hydrocarbons.

“Perforations” include openings, slits, apertures, or holes in a wall of a conduit, tubular, pipe or other flow pathway that allow flow into or out of the conduit, tubular, pipe or other flow pathway.

“Pyrolysis” 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.

“Rich layers” in a hydrocarbon containing formation are relatively thin layers (typically about 0.2 m to about 0.5 m thick). Rich layers generally have a richness of about 0.150 L/kg or greater. Some rich layers have a richness of about 0.170 L/kg or greater, of about 0.190 L/kg or greater, or of about 0.210 L/kg or greater. Lean layers of the formation have a richness of about 0.100 L/kg or less and are generally thicker than rich layers. The richness and locations of layers are determined, for example, by coring and subsequent Fischer assay of the core, density or neutron logging, or other logging methods. Rich layers may have a lower initial thermal conductivity than other layers of the formation. Typically, rich layers have a thermal conductivity 1.5 times to 3 times lower than the thermal conductivity of lean layers. In addition, rich layers have a higher thermal expansion coefficient than lean layers of the formation.

“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.

“Synthesis gas” is a mixture including hydrogen and carbon monoxide. Additional components of synthesis gas may include water, carbon dioxide, nitrogen, methane, and other gases. Synthesis gas may be generated by a variety of processes and feedstocks. Synthesis gas may be used for synthesizing a wide range of compounds.

“Tar” is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10°.

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.

“Temperature limited heater” generally refers to a heater that regulates heat output (for example, reduces heat output) above a specified temperature without the use of external controls such as temperature controllers, power regulators, rectifiers, or other devices. Temperature limited heaters may be AC (alternating current) or modulated (for example, “chopped”) DC (direct current) powered electrical resistance heaters.

“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.

“Viscosity” refers to kinematic viscosity at 40° C. unless otherwise specified. Viscosity is as determined by ASTM Method D445.

“Wax” refers to a low melting organic mixture, or a compound of high molecular weight that is a solid at lower temperatures and a liquid at higher temperatures, and when in solid form can form a barrier to water. Examples of waxes include animal waxes, vegetable waxes, mineral waxes, petroleum waxes, and synthetic waxes.

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° 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° 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° C. to 250° C., from 120° C. to 240° C., or from 150° C. to 230° 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° C. to 900° C., from 240° C. to 400° C. or from 250° C. to 350° 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 the mobilization temperature range and/or the 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 raising the temperature through a temperature range. In some embodiments, the desired temperature is 300° C., 325° C., or 350° 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° C. to about 1200° C., about 500° C. to about 1100° C., or about 550° C. to about 1000° 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 200. 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 200 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 200 are shown extending only along one side of heat sources 202, but the barrier wells typically encircle all heat sources 202 used, or to be used, to heat a treatment area of the formation.

Heat sources 202 are placed in at least a portion of the formation. Heat sources 202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 202 may also include other types of heaters. Heat sources 202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 202 through supply lines 204. Supply lines 204 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 204 for heat sources may transmit electricity for 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.

When the formation is heated, the heat input into the formation may cause expansion of the formation and geomechanical motion. The heat sources may be turned on before, at the same time, or during a dewatering process. Computer simulations may model formation response to heating. The computer simulations may be used to develop a pattern and time sequence for activating heat sources in the formation so that geomechanical motion of the formation does not adversely affect the functionality of heat sources, production wells, and other equipment in the formation.

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 206 to be spaced relatively far apart in the formation.

Production wells 206 are used to remove formation fluid from the formation. In some embodiments, production well 206 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.

More than one heat source may be positioned in the production well. A heat source in a lower portion of the production well may be turned off when superposition of heat from adjacent heat sources heats the formation sufficiently to counteract benefits provided by heating the formation with the production well. In some embodiments, the heat source in an upper portion of the production well may remain on after the heat source in the lower portion of the production well is deactivated. The heat source in the upper portion of the well may inhibit condensation and reflux of formation fluid.

In some embodiments, the heat source in production well 206 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 (C₆ 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 hydrocarbon containing formations, hydrocarbons in the formation may be heated to mobilization and/or pyrolysis temperatures before substantial permeability has been generated in the heated portion of the formation. An initial lack of permeability may inhibit the transport of generated fluids to production wells 206. During initial heating, fluid pressure in the formation may increase proximate heat sources 202. The increased fluid pressure may be released, monitored, altered, and/or controlled through one or more heat sources 202. For example, selected heat sources 202 or separate pressure relief wells may include pressure relief valves that allow for removal of some fluid from the formation.

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 206 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 202 to production wells 206 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.

Generation of relatively low molecular weight hydrocarbons is believed to be due, in part, to autogenous generation and reaction of hydrogen in a portion of the hydrocarbon containing formation. For example, maintaining an increased pressure may force hydrogen generated during pyrolysis into the liquid phase within the formation. Heating the portion to a temperature in a pyrolysis temperature range may pyrolyze hydrocarbons in the formation to generate liquid phase pyrolyzation fluids. The generated liquid phase pyrolyzation fluids components may include double bonds and/or radicals. Hydrogen (H₂) in the liquid phase may reduce double bonds of the generated pyrolyzation fluids, thereby reducing a potential for polymerization or formation of long chain compounds from the generated pyrolyzation fluids. In addition, H₂ may also neutralize radicals in the generated pyrolyzation fluids. H₂ in the liquid phase may inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation.

Formation fluid produced from production wells 206 may be transported through collection piping 208 to treatment facilities 210. Formation fluids may also be produced from heat sources 202. For example, fluid may be produced from heat sources 202 to control pressure in the formation adjacent to the heat sources. Fluid produced from heat sources 202 may be transported through tubing or piping to collection piping 208 or the produced fluid may be transported through tubing or piping directly to treatment facilities 210. Treatment facilities 210 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 some in situ heat treatment process embodiments, a circulation system is used to heat the formation. Using the circulation system for in situ heat treatment of a hydrocarbon containing formation may reduce energy costs for treating the formation, reduce emissions from the treatment process, and/or facilitate heating system installation. In certain embodiments, the circulation system is a closed loop circulation system. FIG. 2 depicts a schematic representation of a system for heating a formation using a circulation system. The system may be used to heat hydrocarbons that are relatively deep in the ground and that are in formations that are relatively large in extent. In some embodiments, the hydrocarbons may be 100 m, 200 m, 300 m or more below the surface. The circulation system may also be used to heat hydrocarbons that are shallower in the ground. The hydrocarbons may be in formations that extend lengthwise up to 1000 m, 3000 m, 5000 m, or more. The heaters of the circulation system may be positioned relative to adjacent heaters such that superposition of heat between heaters of the circulation system allows the temperature of the formation to be raised at least above the boiling point of aqueous formation fluid in the formation.

In some embodiments, heaters 220 are formed in the formation by drilling a first wellbore and then drilling a second wellbore that connects with the first wellbore. Piping may be positioned in the u-shaped wellbore to form u-shaped heater 220. Heaters 220 are connected to heat transfer fluid circulation system 226 by piping. In some embodiments, the heaters are positioned in triangular patterns. In some embodiments, other regular or irregular patterns are used. Production wells and/or injection wells may also be located in the formation. The production wells and/or the injection wells may have long, substantially horizontal sections similar to the heating portions of heaters 220, or the production wells and/or injection wells may be otherwise oriented (for example, the wells may be vertically oriented wells, or wells that include one or more slanted portions).

As depicted in FIG. 2, heat transfer fluid circulation system 226 may include heat supply 228, first heat exchanger 230, second heat exchanger 232, and fluid movers 234. Heat supply 228 heats the heat transfer fluid to a high temperature. Heat supply 228 may be a furnace, solar collector, chemical reactor, nuclear reactor, fuel cell, and/or other high temperature source able to supply heat to the heat transfer fluid. If the heat transfer fluid is a gas, fluid movers 234 may be compressors. If the heat transfer fluid is a liquid, fluid movers 234 may be pumps.

After exiting formation 224, the heat transfer fluid passes through first heat exchanger 230 and second heat exchanger 232 to fluid movers 234. First heat exchanger 230 transfers heat between heat transfer fluid exiting formation 224 and heat transfer fluid exiting fluid movers 234 to raise the temperature of the heat transfer fluid that enters heat supply 228 and reduce the temperature of the fluid exiting formation 224. Second heat exchanger 232 further reduces the temperature of the heat transfer fluid. In some embodiments, second heat exchanger 232 includes or is a storage tank for the heat transfer fluid.

Heat transfer fluid passes from second heat exchanger 232 to fluid movers 234. Fluid movers 234 may be located before heat supply 228 so that the fluid movers do not have to operate at a high temperature.

In some embodiments, the heat transfer fluid is a molten salt and/or molten metal. U.S. Published Patent Application 2008-0078551 to DeVault et al., which is incorporated by reference as if fully set forth herein, describes a system for placement in a wellbore, the system including a heater in a conduit with a liquid metal between the heater and the conduit for heating subterranean earth. Heat transfer fluid may be or include molten salts such as solar salt, salts presented in Table 1, or other salts. The molten salts may be infrared transparent to aid in heat transfer from the insulated conductor to the canister. In some embodiments, solar salt includes sodium nitrate and potassium nitrate (for example, about 60% by weight sodium nitrate and about 40% by weight potassium nitrate). Solar salt melts at about 220° C. and is chemically stable up to temperatures of about 593° C. Other salts that may be used include, but are not limited to LiNO₃ (melt temperature (T_m) of 264° C. and a decomposition temperature of about 600° C.) and eutectic mixtures such as 53% by weight KNO₃, 40% by weight NaNO₃ and 7% by weight NaNO₂ (T_m of about 142° C. and an upper working temperature of over 500° C.); 45.5% by weight KNO₃ and 54.5% by weight NaNO₂ (T_m of about 142-145° C. and an upper working temperature of over 500° C.); or 50% by weight NaCl and 50% by weight SrCl₂ (T_m of about 19° C. and an upper working temperature of over 1200° C.).

	TABLE 1
	Material	Tm (° C.)	Tb (° C.)
	Zn	420	907
	CdBr2	568	863
	CdI2	388	744
	CuBr2	498	900
	PbBr2	371	892
	TlBr	460	819
	TlF	326	826
	ThI4	566	837
	SnF2	215	850
	SnI2	320	714
	ZnCl2	290	732

Heat supply 228 is a furnace that heats the heat transfer fluid to a temperature in a range from about 700° C. to about 920° C., from about 770° C. to about 870° C., or from about 800° C. to about 850° C. In an embodiment, heat supply 228 heats the heat transfer fluid to a temperature of about 820° C. The heat transfer fluid flows from heat supply 228 to heaters 220. Heat transfers from heaters 220 to formation 224 adjacent to the heaters. The temperature of the heat transfer fluid exiting formation 224 may be in a range from about 350° C. to about 580° C., from about 400° C. to about 530° C., or from about 450° C. to about 500° C. In an embodiment, the temperature of the heat transfer fluid exiting formation 224 is about 480° C. The metallurgy of the piping used to form heat transfer fluid circulation system 226 may be varied to significantly reduce costs of the piping. High temperature steel may be used from heat supply 228 to a point where the temperature is sufficiently low so that less expensive steel can be used from that point to first heat exchanger 230. Several different steel grades may be used to form the piping of heat transfer fluid circulation system 226.

When heat transfer fluid is circulated through piping in the formation to heat the formation, the heat of the heat transfer fluid may cause changes in the piping. The heat in the piping may reduce the strength of the piping since Young's modulus and other strength characteristics vary with temperature. The high temperatures in the piping may raise creep concerns, may cause buckling conditions, and may move the piping from the elastic deformation region to the plastic deformation region.

Heating the piping may cause thermal expansion of the piping. For long heaters placed in the wellbore, the piping may expand from zero to 20 m or more. In some embodiments, the horizontal portion of the piping is cemented in the formation with thermally conductive cement. Care may need to be taken to ensure that there are no significant gaps in the cement to inhibit expansion of the piping into the gaps and possible failure. Thermal expansion of the piping may cause ripples in the pipe and/or an increase in the wall thickness of the pipe.

For long heaters with gradual bend radii (for example, about 10° of bend per 30 m), thermal expansion of the piping may be accommodated in the overburden or at the surface of the formation. After thermal expansion is completed, the position of the heaters relative to the wellheads may be secured. When heating is finished and the formation is cooled, the position of the heaters may be unsecured so that thermal contraction of the heaters does not destroy the heaters.

FIGS. 3-13 depict schematic representations of various methods for accommodating thermal expansion. In some embodiments, change in length of the heater due to thermal expansion may be accommodated above the wellhead. After substantial changes in the length of the heater due to thermal expansion cease, the heater position relative to the wellhead may be fixed. The heater position relative to the wellhead may remain fixed until the end of heating of the formation. After heating is ended, the position of the heater relative to the wellhead may be freed (unfixed) to accommodate thermal contraction of the heater as the heater cools.

FIG. 3 depicts a representation of bellows 246. Length L of bellows 246 may change to accommodate thermal expansion and/or contraction of piping 248. Bellows 246 may be located subsurface or above the surface. In some embodiments, bellows 246 includes a fluid that transfers heat out of the wellhead.

FIG. 4A depicts a representation of piping 248 with expansion loop 250 above wellhead 214 for accommodating thermal expansion. Sliding seals in wellhead 214, stuffing boxes, or other pressure control equipment of the wellhead allow piping 248 to move relative to casing 216. Expansion of piping 248 is accommodated in expansion loop 250. In some embodiments, two or more expansion loops 250 are used to accommodate expansion of piping 248.

FIG. 4B depicts a representation of piping 248 with coiled or spooled piping 252 above wellhead 214 for accommodating thermal expansion. Sliding seals in wellhead 214, stuffing boxes, or other pressure control equipment of the wellhead allow piping 248 to move relative to casing 216. Expansion of piping 248 is accommodated in coiled piping 252. In some embodiments, expansion is accommodated by coiling the portion of the heater exiting the formation on a spool using a coiled tubing rig.

In some embodiments, coiled piping 252 may be enclosed in insulated volume 254, as shown in FIG. 4C. Enclosing coiled piping 252 in insulated volume 254 may reduce heat loss from the coiled piping and fluids inside the coiled piping. In some embodiments, coiled piping 252 has a diameter between 2′ (about 0.6 m) and 4′ (about 1.2 m) to accommodate up to about 50′ or up to about 30′ (about 9.1 m) of expansion in piping 248. In some embodiments, coiled piping 252 has a diameter between 4″ (about 0.1016 m) and 6″ (about 0.1524 m).

FIG. 5 depicts a portion of piping 248 in overburden 218 after thermal expansion of the piping has occurred. Casing 216 has a large diameter to accommodate buckling of piping 248. Insulating cement 242 may be between overburden 218 and casing 216. Thermal expansion of piping 248 causes helical or sinusoidal buckling of the piping. The helical or sinusoidal buckling of piping 248 accommodates the thermal expansion of the piping, including the horizontal piping adjacent to the treatment area being heated. As depicted in FIG. 6, piping 248 may be more than one conduit positioned in large diameter casing 216. Having piping 248 as multiple conduits allows for accommodation of thermal expansion of all of the piping in the formation without increasing the pressure drop of the fluid flowing through piping in overburden 218.

In some embodiments, thermal expansion of subsurface piping is translated up to the wellhead. Expansion may be accommodated by one or more sliding seals at the wellhead. The seals may include Grafoil® gaskets, Stellite® gaskets, and/or Nitronic® gaskets. In some embodiments, the seals include seals available from BST Lift Systems, Inc. (Ventura, Calif., U.S.A.).

FIG. 7 depicts a representation of wellhead 214 with sliding seal 238. Wellhead 214 may include a stuffing box and/or other pressure control equipment. Circulated fluid may pass through conduit 244. Conduit 244 may be at least partially surrounded by insulated conduit 236. The use of insulated conduit 236 may obviate the need for a high temperature sliding seal and the need to seal against the heat transfer fluid. Expansion of conduit 244 may be handled at the surface with expansion loops, bellows, coiled or spooled pipe, and/or sliding joints. In some embodiments, packers 256 between insulated conduit 236 and casing 216 seal the wellbore against formation pressure and hold gas for additional insulation. Packers 256 may be inflatable packers and/or polished bore receptacles. In certain embodiments, packers 256 are operable up to temperatures of about 600° C. In some embodiments, packers 256 include seals available from BST Lift Systems, Inc. (Ventura, Calif., U.S.A.).

In some embodiments, thermal expansion of subsurface piping is handled at the surface with a slip joint that allows the heat transfer fluid conduit to expand out of the formation to accommodate the thermal expansion. Hot heat transfer fluid may pass from a fixed conduit into the heat transfer fluid conduit in the formation. Return heat transfer fluid from the formation may pass from the heat transfer fluid conduit into the fixed conduit. A sliding seal between the fixed conduit and the piping in the formation, and a sliding seal between the wellhead and the piping in the formation, may accommodate expansion of the heat transfer fluid conduit at the slip joint.

FIG. 8 depicts a representation of a system where heat transfer fluid in conduit 244 is transferred to or from fixed conduit 258. Insulating sleeve 236 may surround conduit 244. Sliding seal 238 may be between insulated sleeve 236 and wellhead 214. Packers between insulating sleeve 236 and casing 216 may seal the wellbore against formation pressure. Heat transfer fluid seals 284 may be positioned between a portion of fixed conduit 258 and conduit 244. Heat transfer fluid seals 284 may be secured to fixed conduit 258. The resulting slip joint allows insulating sleeve 236 and conduit 244 to move relative to wellhead 214 to accommodate thermal expansion of the piping positioned in the formation. Conduit 244 is also able to move relative to fixed conduit 258 in order to accommodate thermal expansion. Heat transfer fluid seals 284 may be uninsulated and spatially separated from the flowing heat transfer fluid to maintain the heat transfer fluid seals at relatively low temperatures.

In some embodiments, thermal expansion is handled at the surface with a slip joint where the heat transfer fluid conduit is free to move and the fixed conduit is part of the wellhead. FIG. 9 depicts a representation of a system where fixed conduit 258 is secured to wellhead 214. Fixed conduit 258 may include insulating sleeve 236. Heat transfer fluid seals 284 may be coupled to an upper portion of conduit 244. Heat transfer fluid seals 284 may be uninsulated and spatially separated from the flowing heat transfer fluid to maintain the heat transfer fluid seals at relatively low temperatures. Conduit 244 is able to move relative to fixed conduit 258 without the need for a sliding seal in wellhead 214.

FIG. 10 depicts an embodiment of seals 284. Seals 284 may include seal stack 260 attached to packer body 262. Packer body 262 may be coupled to conduit 244 using packer setting slips 264 and packer insulation seal 266. Seal stack 260 may engage polished portion 268 of conduit 258. In some embodiments, cam rollers 270 are used to provide support to seal stack 260. For example, if side loads are too large for the seal stack. In some embodiments, wipers 272 are coupled to packer body 262. Wipers 272 may be used to clean polished portion 268 as conduit 258 is inserted through seal 284. Wipers 272 may be placed on the upper side of seals 284, if needed. In some embodiments, seal stack 260 is loaded for better contact using a bow spring or other preloaded means to enhance compression of the seals.

In some embodiments, seals 284 and conduit 258 are run together into conduit 244. Locking mechanisms such as mandrels may be used to secure the seals and the conduits in place. FIG. 11 depicts an embodiment of seals 284, conduit 244, and conduit 258 secured in place with locking mechanisms 274. Locking mechanisms 274 include insulation seals 276 and locking slips 278. Locking mechanisms 274 may be activated as seals 284 and conduit 258 enter into conduit 244.

As locking mechanisms 274 engage a selected portion of conduit 244, springs in the locking mechanisms are activated and open and expose insulations seals 276 against the surface of conduit 244 just above locking slips 278. Locking mechanisms 274 allow insulations seals 276 to be retracted as the assembly is moved into conduit 244. The insulation seals are opened and exposed when the profile of conduit 244 activates the locking mechanisms.

Pins 280 secure locking mechanisms 274, seals 284, conduit 244, and conduit 258 in place. In certain embodiments, pins 280 unlock the assembly after a selected temperature to allow movement (travel) of the conduits. For example, pins 280 may be made of materials that thermally degrade (for example, melt) above a desired temperature.

In some embodiments, locking mechanisms 274 are set in place using soft metal seals (for example, soft metal friction seals commonly used to set rod pumps in thermal wells). FIG. 12 depicts an embodiment with locking mechanisms 274 set in place using soft metal seals 282. Soft metal seals 282 work by collapsing against a reduction in the inner diameter of conduit 244. Using metal seals may increase the lifetime of the assembly versus using elastomeric seals.

In certain embodiments, lift systems are coupled to the piping of a heater that extends out of the formation. The lift systems may lift portions of the heater out of the formation to accommodate thermal expansion. FIG. 13 depicts a representation of u-shaped wellbore 222 with heater 220 positioned in the wellbore. Wellbore 222 may include casings 216 and lower seals 286. Heater 220 may include insulated portions 288 with heater portion 290 adjacent to treatment area 240. Moving seals 284 may be coupled to an upper portion of heater 220. Lifting systems 292 may be coupled to insulated portions 288 above wellheads 214. A non-reactive gas (for example, nitrogen and/or carbon dioxide) may be introduced in subsurface annular region 294 between casings 216 and insulated portions 288 to inhibit gaseous formation fluid from rising to wellhead 214 and to provide an insulating gas blanket. Insulated portions 288 may be conduit-in-conduits with the heat transfer fluid of the circulation system flowing through the inner conduit. The outer conduit of each insulated portion 288 may be at a substantially lower temperature than the inner conduit. The lower temperature of the outer conduit allows the outer conduits to be used as load bearing members for lifting heater 220. Differential expansion between the outer conduit and the inner conduit may be mitigated by internal bellows and/or by sliding seals.

Lifting systems 292 may include hydraulic lifters, powered coiled tubing reels, and/or counterweight systems capable of supporting heater 220 and moving insulated portions 288 into or out of the formation. When lifting systems 292 include hydraulic lifters, the outer conduits of insulated portions 288 may be kept cool at the hydraulic lifters by dedicated slick transition joints. The hydraulic lifters may include two sets of slips. A first set of slips may be coupled to the heater. The hydraulic lifters may maintain a constant pressure against the heater for the full stroke of the hydraulic cylinder. A second set of slips may periodically be set against the outer conduit while the stroke of the hydraulic cylinder is reset. Lifting systems 292 may also include strain gauges and control systems. The strain gauges may be attached to the outer conduit of insulated portions 288, or the strain gauges may be attached to the inner conduits of the insulated portions below the insulation. Attaching the strain gauges to the outer conduit may be easier and the attachment coupling may be more reliable.

Before heating begins, set points for the control systems may be established by using lifting systems 292 to lift heater 220 such that portions of the heater contact casing 216 in the bend portions of wellbore 222. The strain when heater 220 is lifted may be used as the set point for the control system. In other embodiments, the set point is chosen in a different manner. When heating begins, heater portion 290 will begin expanding and some of the heater section will advance horizontally. If the expansion forces portions of heater 220 against casing 216, the weight of the heater will be supported at the contact points of insulated portions 288 and the casing. The strain measured by lifting system 292 will go towards zero. Additional thermal expansion may cause heater 220 to buckle and fail. Instead of allowing heater 220 to press against casing 216, hydraulic lifters of lifting systems 292 may move sections of insulated portions 288 upwards and out of the formation to keep the heater against the top of the casing. The control systems of lifting systems 292 may lift heater 220 to maintain the strain measured by the strain gauges near the set point value. Lifting system 292 may also be used to reintroduce insulated portions 288 into the formation when the formation cools to avoid damage to heater 220 during thermal contraction.

In certain embodiments, thermal expansion of the heater is completed in a relatively short time frame. In some embodiments, the position of the heater is fixed relative to the wellbore after thermal expansion is completed. The lifting systems may be removed from the heaters and used on other heaters that have not yet been heated. Lifting systems may be reattached to the heaters when the formation is cooled to accommodate thermal contraction of the heaters.

In some embodiments, the lifting systems are controlled based on the hydraulic pressure of the lifters. Changes in the tension of the pipe may result in a change in the hydraulic pressure. The control system may maintain the hydraulic pressure substantially at a set hydraulic pressure to provide accommodation of thermal expansion of the heater in the formation.

In certain embodiments, a tensioning wheel (movable wheel) is coupled to the piping of a heater that extends out of the formation. The wheel may lift portions of the heater out of the formation to accommodate thermal expansion and provide tension to the heater to inhibit buckling in the heater in the formation. FIG. 14 depicts a representation of u-shaped wellbore 222 with heater 220 coupled to tensioning wheel 296. Wellbore 222 may include casings 216 and lower seals 286. Heater 220 may include insulated portions 288 with heater portion 290 adjacent to treatment area 240.

In some embodiments, heater 220 has a horizontal length of at least about 8000 feet (about 2400 m) and vertical section with depths of at least 1000 feet (about 300 m) or at least about 1500 feet (about 450 m). In certain embodiments, heater 220 includes tubing with outside diameters of about 3.5″ or larger (for example, about 5.625″ diameter tubing). In certain embodiments, heater 220 includes coiled tubing. Heater 220 may include materials such as, but not limited to, carbon steel, 9% by weight chromium steels such as (P91 steel or T91 steel), or 12% by weight chromium steels (such as 410 stainless steel, 410Cb stainless steel, or 410Nb stainless steel).

In certain embodiments, upper portions of heater 220 are coupled to tensioning wheels 296 on each end of the heater. In some embodiments, upper portions of heater 220 are spooled onto and off of tensioning wheels 296. For example, heater 220 may have portions wrapping onto the tension wheel while another portion is coming off of the same wheel 296. One or more ends of heater 220 is coupled to circulation system 226 after spooling on tensioning wheel 296. In certain embodiments, the ends of heater 220 are fixably coupled to circulation system 226 (for example, the ends of the heater are coupled to the circulation system using a static connection (no movement in the connection)). Wheels 296 allow static connections to the ends of heater 220 to be made without any moving seals being in contact with hot fluids coming out of circulation system 226.

In some embodiments, tensioning wheels 296 have a diameter between about 10 feet (about 3 m) and about 30 feet (about 9 m) or between about 15 feet (about 4.5 m) and about 25 feet (about 7.6 m). In certain embodiments, tensioning wheels 296 have a diameter of about 20 feet (about 6 m).

In certain embodiments, tensioning wheels 296 provide tension on heater 220. In some embodiments, tensioning wheels 296 provide constant tension on heater 220. In some embodiments, tension is applied by putting the end portions of heater 220 in a moving arc. Tensioning wheels 296 may be allowed to move up and down (for example, up and down along a wall in a vertical plane) while tensioning heater 220. For example, tensioning wheels 296 may move up and down about 40 feet (about 12 m) to accommodate expansion or any other suitable amount depending on the expected expansion of heater 220. In some embodiments, tensioning wheels 296 are movable in a horizontal plane (left and right directions parallel to the surface of the formation). Allowing up and down movement while under tension may inhibit or reduce the severity of buckling in heater 220 due to thermal expansion of the heater.

It is to be understood the invention is not limited to particular systems described which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used in this specification, the singular forms “a”, “an” and “the” include plural referents unless the content clearly indicates otherwise. Thus, for example, reference to “a core” includes a combination of two or more cores and reference to “a material” includes mixtures of materials.

In this patent, certain U.S. patents and U.S. patent applications have been incorporated by reference. The text of such U.S. patents and U.S. patent applications is, however, only incorporated by reference to the extent that no conflict exists between such text and the other statements and drawings set forth herein. In the event of such conflict, then any such conflicting text in such incorporated by reference U.S. patents and U.S. patent applications is specifically not incorporated by reference in this patent.

Further modifications and alternative embodiments of various aspects of the invention will 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.

Claims

1. A method for accommodating thermal expansion of a heater in a formation, comprising: flowing a heat transfer fluid through a conduit to provide heat to the formation; andproviding substantially constant tension to an end portion of the conduit that extends outside the formation, wherein at least a portion of the end portion of the conduit is wound around a movable wheel, the movable wheel being movable at least in a vertical plane while the end portion of the conduit is wound around the movable wheel, and wherein the movable wheel moves at least in the vertical plane to provide the substantially constant tension to the end portion of the conduit.

2. The method of claim 1, further comprising absorbing expansion of the conduit while providing heat to the formation by providing the substantially constant tension to the end portion of the conduit.

3. The method of claim 1, wherein at least part of the end portion of the conduit outside the formation is insulated.

4. The method of claim 1, wherein the movable wheel is movable in both the vertical plane and a horizontal plane.

5. The method of claim 1, wherein the conduit comprises 410 stainless steel, 410Cb stainless steel, 410Nb stainless steel, or P91 steel.

6. The method of claim 1, wherein the heat transfer fluid comprises molten salt.

7. The method of claim 1, wherein the end of the conduit is coupled to a supply unit for heating and/or storing the heat transfer fluid.

8. The method of claim 1, wherein the movable wheel has a diameter of at least about 15 feet.

9. The method of claim 1, wherein the movable wheel moves at least in the vertical plane while the conduit is positioned in the formation.

10. A system for accommodating thermal expansion of a heater in a formation, comprising: a conduit configured to apply heat to the formation when a heat transfer fluid flows through the conduit; anda movable wheel, wherein at least part of an end portion of the conduit is wound around the movable wheel, the movable wheel being movable at least in a vertical plane while the end portion of the conduit is wound around the movable wheel, and wherein the movable wheel is configured to move at least in the vertical plane to maintain substantially constant tension on the end portion of the conduit to absorb expansion of the conduit when the heat transfer fluid flows through the conduit.

11. The system of claim 10, wherein at least part of the end portion of the conduit outside the formation is insulated.

12. The system of claim 10, wherein the movable wheel is movable in both a vertical plane and a horizontal plane.

13. The system of claim 10, wherein the conduit comprises 410 stainless steel, 410Cb stainless steel, 410Nb stainless steel, or P91 steel.

14. The system of claim 10, wherein the heat transfer fluid comprises molten salt.

15. The system of claim 10, wherein the end of the conduit is coupled to a supply unit for heating and/or storing the heat transfer fluid.

16. The system of claim 10, wherein the movable wheel has a diameter of at least about 15 feet.

17. The system of claim 10, wherein the movable wheel is configured to move at least in the vertical plane while the conduit is positioned in the formation.