JP2013524056A - Insulated conductor heater having a semiconductor layer - Google Patents

Abstract

  A heater used to heat an underground formation includes an electrical conductor, a semiconductor layer that at least partially surrounds the electrical conductor, an insulating layer that at least partially surrounds the electrical conductor, and at least partially surrounds the insulating layer. A conductive sheath. A heater can be placed in a hole in the underground formation.

Description

  The present invention relates to systems and methods used for heating underground formations. More particularly, the present invention relates to a system and method for heating an underground hydrocarbon-containing layer.

  Hydrocarbons obtained from underground formations are frequently used as energy sources, raw materials, and consumer goods. Processes for more efficient recovery, treatment, and / or use of available hydrocarbon resources due to concerns over depletion of available hydrocarbon resources and concerns over the overall quality of the produced hydrocarbons Has led to the development of. Use in situ processes to remove hydrocarbon material from underground formations that were previously inaccessible and / or too expensive to extract using available methods can do. Change the chemical and / or physical properties of the hydrocarbon material in the underground formation so that it can be more easily removed from the underground formation and / or the value of the hydrocarbon material can be increased You may need to let Chemical and physical changes result in fluids that can be removed and / or changed in composition, solubility change, density change, phase change, and / or viscosity of the hydrocarbon material in the formation. In-situ reactions that cause change can be included.

  A heater can be placed in the borehole to heat the formation in the field process. There are many different types of heaters that can be used to heat the formation. Examples of in-situ processes utilizing downhole heaters are described in Ljungstrom US Pat. No. 2,634,961, Ljungstrom US Pat. No. 2,732,195, Ljungstrom US Pat. No. 2,780, 450, Ljungstrom US Pat. No. 2,789,805, Ljungstrom US Pat. No. 2,923,535, Van Meurs et al. US Pat. No. 4,886,118, and This is shown in US Pat. No. 6,688,387 to Wellington et al.

US Pat. No. 2,634,961 US Pat. No. 2,732,195 US Pat. No. 2,780,450 US Pat. No. 2,789,805 US Pat. No. 2,923,535 US Pat. No. 4,886,118 US Pat. No. 6,688,387

  Inorganic insulated (MI) cables (insulated conductors) for use in underground applications, such as heating hydrocarbon-bearing formations in some applications, are longer and larger than typical in the MI cable industry It may have an outer diameter and may operate at higher voltages and temperatures. There are a number of potential problems in the manufacture and / or assembly of long insulated conductors.

  For example, there is the potential for electrical and / or mechanical problems due to aging of electrical insulators used for insulated conductors. There is also a potential problem that the electrical insulator must overcome when assembling the insulated conductor heater. Problems such as core bulge or other mechanical defects can occur during assembly of the insulated conductor heater. Such a situation can lead to electrical problems in the use of the heater, and the heater can become inoperable for the intended purpose.

  In addition, there may be problems due to increased stress on the insulated conductor during assembly of the insulated conductor and / or installation in the basement. For example, winding an insulated conductor onto a spool used for transporting and installing the insulated conductor, and feeding the insulated conductor from such a spool is a machine for electrical insulation and / or other components of the insulated conductor Can lead to stress. Therefore, there is a need for a more reliable system and method for reducing or eliminating potential problems during the manufacture, assembly, and / or installation of insulated conductors.

  Embodiments described herein generally relate to systems, methods, and heaters for processing underground formations. Also, the embodiments described herein generally relate to heaters having novel components. Such a heater can be obtained by using the systems and methods described herein.

  In certain embodiments, the present invention provides one or more systems, methods, and / or heaters. In some embodiments, systems, methods, and / or heaters are used to process underground formations.

  In certain embodiments, a heater configured to heat an underground formation includes an electrical conductor, a semiconductor layer that at least partially surrounds the electrical conductor, and an insulating layer that at least partially surrounds the electrical conductor; A conductive sheath at least partially surrounding the insulating layer.

  In certain embodiments, a method for heating an underground formation is at least partially in a hole in a hydrocarbon-containing layer extending from the surface of the formation through a topsoil portion of the formation to the hydrocarbon-containing layer of the formation. And a heater comprising an electrical conductor, a semiconductor layer at least partially surrounding the electrical conductor, an insulating layer at least partially surrounding the electrical conductor, and a conductive sheath at least partially surrounding the insulating layer Providing heat to at least a portion of the formation's hydrocarbon-containing layer; fluidizing at least a portion of the hydrocarbon in the formation by transfer of heat to the formation; and at least one of the fluidized hydrocarbons. Producing a part from the formation.

  In further embodiments, features from individual embodiments can be combined with features from other embodiments. For example, features from one embodiment can be combined with features from any other embodiment.

  In further embodiments, processing of underground formations is performed using any of the methods, systems, power supplies, or heaters described herein.

  In further embodiments, additional features can be added to the individual embodiments described herein.

  The features and advantages of the method and apparatus of the present invention will be described with reference to the following detailed description of an embodiment according to the present invention (currently preferred embodiment, but only exemplary) in conjunction with the accompanying drawings. Will be more fully understood.

FIG. 2 shows a schematic diagram of an embodiment of a portion of an in situ heat treatment system for treating a hydrocarbon-containing layer. 1 illustrates an embodiment of an insulated conductor heat source. 1 illustrates an embodiment of an insulated conductor heat source. 1 illustrates an embodiment of an insulated conductor heat source. FIG. 3 shows a cross-sectional view of an embodiment of a temperature limited heater element used in an insulated conductor heater. FIG. 3 shows a cross-sectional view of an embodiment of a temperature limited heater element used in an insulated conductor heater. 1 illustrates one embodiment of an insulated conductor comprising a semiconductor layer adjacent to and surrounding a core. 1 illustrates one embodiment of an insulated conductor comprising a semiconductor layer positioned within an electrical insulator and surrounding a core. The vertical component of the electric field is shown as a function of position along the length of the heater. The electric field strength is shown with respect to the distance from the core. The ratio of the dielectric constant between the electrical insulator and the semiconductor layer with respect to the maximum electric field strength when there is no shielding (no semiconductor layer) and the normalized thickness of the semiconductor layer are shown. For some dielectric constant ratios, the electric field strength is shown relative to the distance from the core (normalized).

  While the invention is susceptible to various modifications and alternative forms, specific embodiments of the invention are shown by way of example in the drawings and will herein be described in detail. The drawings are not necessarily to scale. The drawings and detailed description are not intended to limit the invention to the particular form disclosed, but rather to the spirit and scope of the invention as defined by the appended claims. It is to be understood that all modifications, equivalents, and alternatives encompassed by are intended to be included.

  The following description relates generally to systems and methods for treating hydrocarbons in formations. Such formations can be processed to produce hydrocarbon products, hydrogen, and other products.

  “Alternating current (AC)” refers to a time-varying current that reverses direction substantially sinusoidally. AC creates a skin effect current flow in a ferromagnetic conductor.

  In the context of low heat output heating systems, devices, and methods, the term “automatic” means that such systems, devices, and methods are externally controlled (eg, controllers with temperature sensors and feedback loops, PID controllers, , Or an external controller such as a predictive controller).

  “Coupled” means a direct or indirect connection (eg, one or more intervening connections) between one or more objects or components. The expression “directly connected” means directly between objects or components such that the objects or components are directly connected to each other so that they function in a “point of use” manner. Connection.

  “Curie temperature” is the temperature above which a ferromagnetic material loses all of its ferromagnetism. In addition to losing all of the ferromagnetism above the Curie temperature, ferromagnetic materials begin to lose ferromagnetism as more current passes through the ferromagnet.

  “Geological formation” includes one or more hydrocarbon-containing layers, one or more non-hydrocarbon layers, overburden, and / or underburden. “Hydrocarbon layer” refers to a layer in the formation that contains hydrocarbons. The hydrocarbon layer can include non-hydrocarbon materials and hydrocarbon materials. “Topsoil” and / or “Subsoil” includes one or more different types of impermeable materials. For example, the topsoil and / or subsoil can include rocks, shale, mudstone, or wet / tight carbonates. In some embodiments of the in situ heat treatment process, the topsoil and / or subsoil is relatively impervious and significant characteristics of the hydrocarbon-containing layer of the topsoil and / or subsoil during the in situ heat treatment One or more hydrocarbon-containing layers can be included that are not exposed to temperatures that lead to changes in. For example, the subsoil can include shale or mudstone, but the subsoil is not heated to the pyrolysis temperature during the in situ heat treatment process. In some cases, the topsoil and / or subsoil may be permeable to some extent.

  “Geological fluid” refers to fluid present in the geological formation, and “geological fluid” can include pyrolysis fluid, synthesis gas, mobilized hydrocarbons, and water (steam). The formation fluid can include hydrocarbon fluids and non-hydrocarbon fluids. The term “fluidizing fluid” refers to a fluid in a hydrocarbon-containing layer that is capable of flowing as a result of heat treatment of the formation. “Production fluid” refers to fluid removed from the formation.

“Heat flux” is the flow of energy per unit area and unit time (eg watts / meter ² ).

  A “heat source” is any system for providing heat to at least a portion of the formation by heat transfer substantially by conduction and / or radiation. For example, the heat source may include an electrical heater such as a conductive material and / or a conductor disposed in an insulated conductor, an elongated member, and / or a conduit. The heat source can also include a system that generates heat by burning fuel outside or in the formation. Such systems may be surface burners, downhole gas burners, flameless distributed combustors, and naturally distributed combustors. In some embodiments, heat supplied to one or more heat sources, or generated in one or more heat sources, can be supplied by other energy sources. Other energy sources can heat the formation directly, and this energy may be applied to a transmission medium that heats the formation directly or indirectly. It should be understood that the one or more heat sources that apply heat to the formation may use a variety of energy sources. That is, for a given formation, for example, some heat sources can supply heat from conductive materials, electrical resistance heaters, some heat sources can supply heat from combustion, and some heat sources Can supply heat from one or more other energy sources (eg, chemical reaction, solar energy, wind energy, biomass, or other renewable energy sources). Examples of the chemical reaction include an exothermic reaction (for example, an oxidation reaction). In addition, the heat source can include a conductive material and / or a heater that provides heat to and near a heating location such as a heater well.

  A “heater” is any system or heat source for generating heat in a wellbore or in an area near a borehole. The heater may be, but is not limited to, an electric heater, a burner, a combustor that reacts with material in the formation or material produced from the formation, and / or combinations thereof.

  “Hydrocarbon” is generally defined as a molecule formed primarily by carbon and hydrogen atoms. The hydrocarbon may include other elements such as, but not limited to, halogens, metal elements, nitrogen, oxygen, and / or sulfur. The hydrocarbon may be, but is not limited to, kerogen, bitumen, pyrobitumen, oil, natural mineral wax, and asphaltite. The hydrocarbon can be located on the mineral substrate in the soil or can be located adjacent to the mineral substrate in the soil. Substrates can include, but are not limited to, sedimentary rock, sand, silicilite, carbonate, diatomaceous earth, and other porous media. A “hydrocarbon fluid” is a fluid containing hydrocarbons. The hydrocarbon fluid can include non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia, or can incorporate such non-hydrocarbon fluids, or Such non-hydrocarbon fluids may be incorporated.

  “In-situ conversion process” refers to a process in which a hydrocarbon-containing layer is heated from a heat source to raise the temperature of at least a portion of the formation above the pyrolysis temperature to produce a pyrolysis fluid in the formation.

  An “in-situ heat treatment process” involves heating a hydrocarbon-containing layer with a heat source to cause the temperature of at least a portion of the formation to exceed the fluidization fluid, visbreaking, and / or pyrolysis of the hydrocarbon-containing material. The process of generating fluidized fluid, viscosity reducing fluid, and / or pyrolysis fluid in the formation.

  "Insulated conductor" refers to any elongated material that can conduct electricity and is wholly or partially covered by an electrically insulating material.

  “Modulated direct current (DC)” refers to any non-sinusoidal time-varying current that causes skin-effect electrical flow in a ferromagnetic conductor.

  “Nitride” refers to a compound of nitrogen and one or more other elements of the periodic table. Nitrides include, but are not limited to, silicon nitride, boron nitride, or alumina nitride.

  “Perforations” include holes, slits, openings, or holes in the walls of conduits, tubes, pipes, or other channels that allow inflow or outflow into the conduits, tubes, pipes, or other channels.

  The “phase transformation temperature” of a ferromagnet refers to the temperature or temperature range at which the material undergoes a phase change that reduces the magnetic permeability of the ferromagnet (eg, a phase change from ferrite to austenite). The decrease in permeability is very similar to the decrease in permeability due to the magnetic transition of the ferromagnetic material at the Curie temperature.

  “Pyrolysis” is the breaking of chemical bonds by the application of heat. For example, pyrolysis can include converting a compound into one or more other substances only by heat. Heat can be transferred to a site in the formation to cause pyrolysis.

  “Pyrolysis fluid” or “pyrolysis product” refers to a fluid that is substantially produced during the pyrolysis of hydrocarbons. The fluid generated by the pyrolysis reaction can mix with other fluids in the formation. It is believed that the mixture is a pyrolysis fluid or pyrolysis product. As used herein, a “pyrolysis zone” refers to a mass of a formation (eg, a relatively permeable formation such as a tar sand formation) that forms a pyrolysis fluid by reaction.

  “Heat superposition” refers to the influence of a heat source on the temperature of the formation in at least one position between the heat sources by supplying heat from two or more heat sources to a predetermined part of the formation.

  “Temperature limited heaters” generally regulate heat output above a specified temperature (eg, reduce heat output) without using external controls such as a temperature controller, output regulator, rectifier, or other device. ) Refers to the heater. The temperature limited heater may be an electrical resistance heater driven by AC (alternating current) or modulated (eg, “chopped”) DC (direct current).

  The “thickness” of a layer refers to the thickness of the cross section of the layer, the cross section being perpendicular to the plane of the layer.

  “Time-varying current” refers to a current having a magnitude that varies with time causing a skin effect current flow in a ferromagnetic conductor. Time-varying currents include both alternating current (AC) and modulated direct current (DC).

  The “turn-down ratio” of a temperature limited heater in which current is directly applied to the heater is the ratio of the highest AC or modulated DC resistance below the Curie temperature to the lowest resistance above the Curie temperature at a given current. . The turndown ratio of an induction heater is the ratio of the highest heat output below the Curie temperature to the lowest heat output above the Curie temperature when a given current is applied to the heater.

  A “u-shaped drill hole” refers to a drill hole that extends from a first opening in the formation through at least a portion of the formation and exits from a second opening in the formation. In this context, a drilling hole is considered to be “u-shaped” and the “legs” of “u” do not necessarily have to be parallel to each other and are perpendicular to the “bottom” of “u”. The shape of “v” or “u” may be used with the understanding that it may not be necessary.

  The term “drilling hole” refers to a hole in the formation created by drilling the formation or inserting a conduit into the formation. The borehole can have a substantially circular cross section or other cross-sectional shape. As used herein, the terms “well” and “hole” can be used interchangeably with the term “drilling hole” when referring to formation holes.

  The formation can be processed in a variety of ways to produce a number of different products. Various stages or processes can be used to treat the formation in an in situ heat treatment process. In some embodiments, one or more sites of the formation are solution mined to extract soluble minerals from the sites. Mineral solution mining can be performed before, during and / or after the in situ heat treatment process. In some embodiments, the average temperature of one or more sites that are solution mined can be maintained below about 120 ° C.

  In some embodiments, one or more sites of the formation are heated to remove water from the sites and / or to remove methane and other volatile hydrocarbons from the sites. In some embodiments, the average temperature can be raised from ambient temperature to a temperature below about 220 ° C. as water and volatile hydrocarbons are removed.

  In some embodiments, one or more sites of the formation are heated to a temperature that allows hydrocarbon migration and / or viscosity reduction in the formation. In some embodiments, the average temperature of one or more sites of the formation is the hydrocarbon fluidization temperature of the site (e.g., 100C-250C, 120C-240C, or 150C-230). Temperature).

  In some embodiments, one or more sites are heated to a temperature that allows a pyrolysis reaction in the formation. In some embodiments, the average temperature of one or more sites of the formation is determined from the hydrocarbon pyrolysis temperature (eg, 230 ° C to 900 ° C, 240 ° C to 400 ° C, or 250 ° C to 350 ° C). Temperature).

  Heating the hydrocarbon-containing layer with a plurality of heat sources can establish a thermal gradient around the heat source that raises the temperature of the hydrocarbons in the formation to the desired temperature at the desired heating rate. The rate of temperature rise through the fluidization temperature range and / or pyrolysis temperature range of the desired product can affect the quality and quantity of formation fluids produced from the hydrocarbon-containing formation. By slowly raising the temperature through the fluidization temperature range and / or the pyrolysis temperature range, it is possible to produce high quality and high API specific gravity hydrocarbons from the formation. By slowly increasing the formation temperature through the fluidization temperature range and / or the pyrolysis temperature range, it is possible to extract a large amount of hydrocarbons present in the formation as hydrocarbon products.

  In some in situ heat treatment embodiments, a portion of the formation is heated to the desired temperature instead of slowly increasing the temperature through a temperature range. In some embodiments, the desired temperature is 300 ° C, 325 ° C, or 350 ° C. Other temperatures can also be selected as the desired temperature.

  The superposition of heat from the heat source can establish the desired temperature in the formation relatively quickly and efficiently. The input of energy from the heat source to the formation can be adjusted to maintain the formation temperature at a substantially desired temperature.

  Fluidized products and / or pyrolysis products can be produced from the formation by production wells. In some embodiments, the average temperature of one or more sites is raised to the fluidization temperature to produce hydrocarbons from the production well. After production by fluidization falls below a predetermined value, the average temperature of one or more sites can be raised to the pyrolysis temperature. In some embodiments, the average temperature of one or more sites can be raised to the pyrolysis temperature without producing enough before the pyrolysis temperature is reached. A formation fluid containing pyrolysis products can be produced by the production well.

  In some embodiments, the average temperature of one or more sites can be raised to a temperature sufficient to allow synthesis gas production after fluidization and / or pyrolysis. In some embodiments, the hydrocarbon is brought to a temperature sufficient to allow synthesis gas production without producing enough before reaching a temperature sufficient to allow synthesis gas production. Can be raised. For example, synthesis gas can be produced at a temperature range of 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 (eg, water vapor and / or water) can be introduced into the site for generating synthesis gas. Syngas can be produced from a production well.

  Solution mining, volatile hydrocarbon and water removal, hydrocarbon fluidization, hydrocarbon pyrolysis, synthesis gas generation, and / or other processes may be performed during the in situ heat treatment process. In some embodiments, some processes can be performed after the in situ heat treatment process. Such processes include, but are not limited to, heat recovery from the site to be treated, storage of fluids (eg, water and / or hydrocarbons) at previously treated sites, and / or already treated. And carbon dioxide sequestration at the site.

  FIG. 1 shows a schematic diagram of an embodiment of a portion of an in situ heat treatment system for treating a hydrocarbon-containing layer. The in situ heat treatment system can include a barrier well 200. Barrier wells are used to form a barrier around the processing area. The barrier prevents fluid flow from entering or exiting the processing region. Barrier wells include, but are not limited to, water removal wells, vacuum wells, capture wells, injection wells, grout wells, frozen wells, or combinations thereof. In some embodiments, the barrier well 200 is a water removal well. The water removal well can remove liquid water and / or prevent liquid water from entering the site of the formation to be heated or the formation being heated. In the embodiment shown in FIG. 1, the barrier well 200 extends only on one side of the heat source 202, but the barrier well is typically used to heat the processing region of the formation. Surrounds all heat sources 202 in or used.

  The heat source 202 is disposed in at least a portion of the formation. The heat source 202 can include heaters such as insulated conductors, conductor-in-conduct heaters, surface burners, flameless distributed combustors, and / or natural distributed combustors. The heat source 202 may include other types of heaters. A heat source 202 provides heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy can be supplied to the heat source 202 by the supply line 204. The supply line 204 may vary structurally depending on the type of one or more heat sources used to heat the formation. The supply line 204 for the heat source can conduct electricity for the electric heater, can transport fuel for the combustor, or can transport heat exchange fluid that circulates through the formation. In some embodiments, electricity for the in situ heat treatment process can be supplied by one or more nuclear power plants. By using nuclear power, carbon dioxide emissions from on-site heat treatment processes can be reduced or eliminated.

  When the formation is heated, the heat input to the formation can cause expansion and geotechnical movement of the formation. The heat source can be turned on before the water removal process, simultaneously with the water removal process, or during the water removal process. Computer simulation can model the response of the formation to heating. Use computer simulation to develop patterns and time sequences that operate heat sources in the formation so that the geotechnical movement of the formation does not adversely affect the heat source, production wells, and other equipment in the formation can do.

  Heating the formation can increase the permeability and / or porosity of the formation. The increase in permeability and / or porosity may be due to a decrease in mass in the formation due to vaporization and removal of water, removal of hydrocarbons, and / or formation of fissures. Increased formation permeability and / or porosity allows fluid to flow more easily in the heated portion of the formation. The fluid in the heated portion of the formation can travel a significant distance through the formation due to high permeability and / or porosity. The substantial distance can exceed 1000 meters, depending on various factors such as formation permeability, fluid properties, formation temperature, and pressure gradients that allow fluid movement. Because the fluid can travel a significant distance within the formation, production wells 206 can be located relatively far apart in the formation.

  Production well 206 is used to remove formation fluid from the formation. In some embodiments, production well 206 includes a heat source. A heat source within the production well can heat one or more portions of the formation located near the production well or the production well. In some embodiments of the on-site heat treatment process, the amount of heat per meter of production well supplied from the production well to the formation is greater than the amount of heat per meter of heat source supplied from the heat source that heats the formation to the formation. There are few. Heat applied from the production well to the formation vaporizes and removes the liquid phase fluid adjacent to the production well, and / or forms a macro and / or micro fissure adjacent to the production well By increasing the permeability, the permeability of the formation adjacent to the production well can be increased.

  More than one heat source can be placed in the production well. The heat source at the bottom of the production well may be turned off if the superposition of heat from adjacent heat sources heats the formation sufficiently enough to negate the benefits provided by heating the formation by the production well. it can. In some embodiments, the heat source at the top of the production well can be turned on after the heat source at the bottom of the production well is turned off. The heat source at the top of the well can prevent the formation fluid from condensing and returning.

  In some embodiments, the heat source of the production well 206 can remove the gas phase of the formation fluid from the formation. By supplying heat in the production well or through the production well, (1) it is possible to prevent condensation and / or backflow of the production fluid when moving in the production well near the topsoil (2 ) Heat input to the formation can be increased, (3) production rate from production wells can be increased compared to production wells without heat sources, and (4) high carbon in production wells Condensation of several compounds (C6 or higher hydrocarbons) can be prevented and / or (5) the formation penetration in the production well or in the vicinity of the production well can be increased.

  The underground pressure in the formation can correspond to the fluid pressure generated in the formation. As the temperature of the heated portion of the formation increases, the pressure of the heated portion can increase as a result of the thermal expansion of the in-situ fluid and the increased fluid generation and water vaporization. By controlling the rate of fluid removal from the formation, it is possible to control the pressure in the formation. The pressure in the formation can be measured at a number of different locations (such as near a production well or production well, near a heat source or heat source, or a monitoring well).

  In some hydrocarbon-containing formations, hydrocarbon production from the formation is suppressed until at least some of the hydrocarbons in the formation are fluidized and / or pyrolyzed. If the formation fluid is of a predetermined quality, formation fluid can be produced from the formation. In some embodiments, the predetermined quality includes an API specific gravity of at least about 20 °, 30 °, or 40 °. Suppressing production until at least some of the hydrocarbons are fluidized and / or pyrolyzed can increase the conversion of heavy hydrocarbons to light hydrocarbons. Suppressing initial production can minimize the production of heavy hydrocarbons from the formation. Production of large amounts of heavy hydrocarbons may require expensive equipment and / or shorten the life of the production equipment.

  In some hydrocarbon-containing layers, the hydrocarbons in the formation can be heated to fluidization and / or pyrolysis temperatures before significant penetration occurs in the heated portion of the formation. Due to the lack of initial permeability, the resulting fluid can be prevented from moving to the production well 206. During initial heating, the pressure of the fluid in the formation can be increased near the heat source 202. The increased fluid pressure can be released, monitored, altered, and / or controlled by one or more heat sources 202. For example, a given heat source 202 or a separate pressure relief well can include a pressure relief valve that allows for removal of some fluid from the formation.

  In some embodiments, the formation may not yet have an open path to the production well 206 or any other pressure reservoir, but the fluidized fluid, pyrolysis fluid, or other generated in the formation The pressure generated by the expansion of the fluid can be increased. It is possible to increase the fluid pressure to ground pressure. As the fluid approaches ground pressure, cracks may form in the hydrocarbon-containing layer. For example, cracks can form from the heat source 202 to the production well 206 in the heated portion of the formation. The generation of cracks in the heated part can relieve part of the pressure in this part. The formation pressure may need to be maintained below a predetermined pressure to prevent unwanted production, topsoil or subsoil damage, and / or coking of hydrocarbons in the formation.

  After the fluidization temperature and / or pyrolysis temperature is reached and production from the formation is possible, the pressure in the formation can be changed and / or controlled by the composition of the formation fluid produced, and the non- It can be varied to control the ratio of condensable fluid to condensable fluid and / or to control the API gravity of the formation fluid being produced. For example, reducing the pressure can result in the production of more condensable fluid components. The condensable fluid component may contain a greater proportion of olefins.

  In some in situ heat treatment process embodiments, the pressure in the formation can be maintained high enough to facilitate the production of formation fluids having an API gravity greater than 20 °. By maintaining a high pressure in the formation, subsidence of the formation during on-site heat treatment can be suppressed. Maintaining high pressure can reduce or eliminate the need for compressing formation fluids at the ground surface to transport the fluid to a treatment facility via a collection conduit.

  By maintaining a high pressure in the heated part of the formation, it is surprisingly possible to produce large quantities of high quality and relatively low molecular weight hydrocarbons. The pressure can be maintained so that the amount of compounds above a given carbon number in the formation fluid produced is minimized. The predetermined carbon number may be 25 or less, 20 or less, 12 or less, or 8 or less. Some high carbon number compounds can be incorporated into the vapor in the formation and can be removed from the formation along with the vapor. Maintaining a high pressure in the formation can prevent high carbon number compounds and / or polycyclic hydrocarbon compounds from entering the vapor. High carbon number compounds and / or polycyclic hydrocarbon compounds can remain in the liquid phase within the formation for a significant amount of time. A considerable amount of time can provide sufficient time for the pyrolysis of the compound to form a lower carbon number compound.

The generation of relatively low molecular weight hydrocarbons is believed to be due in part to the spontaneous generation and reaction of hydrogen in a portion of the hydrocarbon-containing layer. For example, by maintaining a high pressure, hydrogen generated during pyrolysis can be pushed into the liquid phase in the formation. By heating this part to a temperature in the pyrolysis temperature range, hydrocarbons in the formation can be pyrolyzed to generate a liquid pyrolysis fluid. The components of the resulting liquid phase pyrolysis fluid may contain double bonds and / or radicals. Hydrogen (H ₂ ) in the liquid phase can reduce double bonds in the resulting pyrolysis fluid and reduce the likelihood of polymerization or formation of long chain compounds from the resulting pyrolysis fluid. Furthermore, H ₂ can neutralize radicals in the resulting pyrolysis fluid. The H ₂ in the liquid phase can prevent the resulting pyrolysis fluids from reacting with each other and / or with other compounds in the formation.

  The formation fluid produced from the production well 206 can be transported through the collection piping 208 to the processing facility 210. Formation fluid may be produced from the heat source 202. For example, by producing fluid from the heat source 202, the pressure in the formation adjacent to the heat source can be controlled. The fluid produced from the heat source 202 can be transported through a tube or pipe to the collection piping 208, or the produced fluid may be transported directly to the processing facility 210 through the tube or pipe. The processing facility 210 may include separation units, reaction units, quality enhancement units, fuel cells, turbines, storage vessels, and / or other systems and units for processing produced formation fluids. The treatment facility can form transportation fuel from at least a portion of the hydrocarbons produced from the formation. In some embodiments, the transportation fuel may be a jet fuel such as JP-8.

  The insulated conductor can be used as an electric heater element of a heater or heat source. The insulated conductor can comprise an inner electrical conductor (core) surrounded by an electrical insulator and an outer electrical conductor (jacket). The electrical insulator can comprise inorganic insulation (eg, magnesium oxide) or other electrical insulation.

  In certain embodiments, an insulated conductor is placed in the hole of the hydrocarbon-containing layer. In some embodiments, the insulated conductor is placed in an unenclosed hole in the hydrocarbon-containing layer. Placing the insulated conductor in an unenclosed hole in the hydrocarbon-containing layer allows the transfer of heat from the insulated conductor to the formation by radiation and conduction. Using unenclosed holes can facilitate the recovery of the insulated conductor from the holes when necessary.

  In some embodiments, the insulated conductor can be placed in a casing in the formation and cemented into the formation, or the hole can be filled with sand, gravel, or other filler material. The insulated conductor can be supported by a support member disposed in the hole. The support member may be a cable, a rod, or a conduit (eg, a pipe). The support member can be made of metal, ceramic, inorganic material, or a combination thereof. Since a part of the support member may be exposed to the formation fluid and heat during use, the support member can have chemical resistance and / or heat resistance.

  Ties, spot welds, and / or other types of connectors can be used to couple the insulated conductor to the support member at various positions in the length of the insulated conductor. A support member can be attached to the wellhead at the top surface of the formation. In some embodiments, the insulated conductor has sufficient structural strength such that a support member is not required. Insulated conductors can often have at least some flexibility to prevent damage due to thermal expansion when subjected to temperature changes.

  In certain embodiments, the insulated conductor is placed in the borehole without the use of a support member and / or a centralizer. Insulated conductors that do not have support members and / or centralizers must have a combination of heat resistance and corrosion resistance, creep strength, length, thickness (diameter), and metallurgically appropriate to prevent failure of the insulated conductor during use Is possible.

  FIG. 2 shows a perspective view of the end of one embodiment of the insulated conductor 252. Insulated conductor 252 has any desired cross-sectional shape, such as, but not limited to, a circle (shown in FIG. 2), a triangle, an ellipse, a rectangle, a hexagon, or an irregular shape. Can do. In certain embodiments, the insulated conductor 252 includes a core 218, an electrical insulator 214, and a jacket 216. The core 218 can be resistively heated as current passes through the core. Alternating current or time-varying current and / or direct current can be used to provide power to the core 218 to resistively heat the core.

  In some embodiments, electrical insulator 214 prevents current leakage and electrical arc to jacket 216. The electrical insulator 214 can conduct heat generated in the core 218 to the jacket 216. A jacket 216 can conduct heat to the formation by radiation or conduction. In certain embodiments, the insulated conductor 252 is 1000 m or longer. Longer or shorter insulated conductors can also be used to meet the needs of individual applications. The dimensions of the core 218, the electrical insulator 214, and the jacket 216 of the insulated conductor 252 can be selected so that the insulated conductor has sufficient strength to support itself even at the upper operating temperature. Such insulated conductors can be suspended from a support located near the wellhead or near the boundary between the hydrocarbon-containing layer and the topsoil without having to extend the support member with the insulated conductor to the hydrocarbon-containing layer. Is possible.

  The insulated conductor 252 can be designed to operate at power levels up to about 1650 watts / meter or more. In certain embodiments, the insulated conductor 252 operates at a power level between about 300 watts / meter and about 1150 watts / meter when heating the formation. The insulated conductor 252 can be designed such that substantial thermal and / or electrical breakdown of the electrical insulator 214 does not occur even at the highest voltage level at typical operating temperatures. The insulated conductor 252 can be designed such that the jacket 216 does not exceed a temperature at which a significant reduction in the corrosion resistance of the jacket material occurs. In certain embodiments, the insulated conductor 252 can be designed to reach a temperature in the range between about 650 ° C and about 900 ° C. Insulated conductors having other operating ranges can be formed to meet individual operating requirements.

  FIG. 2 shows an insulated conductor 252 having a single core 218. In some embodiments, the insulated conductor 252 has more than one core 218. For example, one insulated conductor can have three cores. The core 218 can be made of metal or other conductive material. Materials used to form the core 218 include, but are not limited to, nichrome, copper, nickel, carbon steel, stainless steel, and combinations thereof. In certain embodiments, the core material 218 has a resistance derived from Ohm's law for a given power dissipation per meter, heater length, and / or maximum voltage allowed for the core material. It is selected to have a diameter and resistivity at operating temperature that will be electrically and structurally stable.

  In some embodiments, the core 218 is made of a different material over the length of the insulated conductor 252. For example, the first portion of the core 218 can be made of a material that has a significantly lower resistance than the second portion of the core. The first site can be placed adjacent to a layer of the formation that does not need to be heated to a higher temperature than the second layer of the formation adjacent to the second site. The resistivity of various parts of the core 218 can be adjusted by changing the diameter and / or can be adjusted by making each part of the core from a different material.

The electrical insulator 214 can be made of a variety of materials. Commonly used powders can include, but are not limited to, MgO, Al ₂ O ₃ , zirconia, BeO, various chemical variants of spinel, and combinations thereof. MgO can provide good thermal conductivity and electrical insulation. Desirable electrical insulation properties include low leakage current and high dielectric strength. When the leakage current is small, the possibility of thermal failure is low, and when the dielectric strength is high, the possibility of an electric arc crossing the insulator is low. Thermal failure can occur when the insulator temperature rises due to leakage current and leads to an electric arc across the insulator.

  The jacket 216 may be an outer metal layer or a conductive layer. Jacket 216 can come into contact with hot formation fluids. The jacket 216 can be made of a material that has high corrosion resistance at high temperatures. Alloys that can be used in the desired operating temperature range of jacket 216 include, but are not limited to, 304 stainless steel, 310 stainless steel, Incoloy® 800, and Inconel® 600 (US West Virginia) Inco Alloys International) in the state of Huntington. The thickness of the jacket 216 may have to be sufficient to have a 3-10 year life in high temperature and corrosive environments. The thickness of jacket 216 may typically vary between about 1 mm and about 3.5 mm. For example, a 1.3 mm thick outer layer made of 310 stainless steel can be used as the jacket 216 to provide good chemical resistance to sulfidation corrosion in the heated zone of the formation over a period of more than three years. Thicker or thinner jackets can be used to meet individual application requirements.

  One or more insulated conductors can be placed in the formation holes to form one or more heat sources. The formation can be heated by passing a current through each insulated conductor in the hole. Alternatively, current can be passed through selected insulated conductors in the holes. Unused conductors can be used as spare heaters. The insulated conductor can be electrically connected to the power source in any convenient manner. Each end of the insulated conductor can be connected to a lead-in cable that passes through the wellhead. Such a configuration typically has a 180 degree bend ("hairpin" bend) or turn around the lower end of the heat source. Insulated conductors with a 180 degree bend or turn can eliminate the need for lower end termination, but a 180 degree bend or turn can be an electrical and / or mechanical weakness in the heater. Insulated conductors can be electrically connected in series, parallel, or a combination of series and parallel. In some embodiments of the heat source, by connecting the core 218 to the jacket 216 (shown in FIG. 2) at the lower end of the heat source, current is passed through the conductor of the insulated conductor, You can go back through.

  In some embodiments, three insulated conductors 252 are electrically connected to the power supply in a three-phase Y-shape configuration. FIG. 3 shows an embodiment of three insulated conductors in a hole in the underground formation connected to a Y configuration. FIG. 4 shows an embodiment of three insulated conductors 252 that can be removed from formation holes 238. For the three insulated conductors in the Y configuration, a lower end connection may not be required. Alternatively, all three insulated conductors in a Y configuration can be connected together near the bottom of the hole. The connection can be made directly at the end of the heated portion of the insulated conductor or at the end of a low temperature pin (low resistance portion) connected to the heated portion at the lower end of the insulated conductor. The lower end connection can be made by a canister filled with an insulator and sealed, or a canister filled with epoxy. The insulator may be the same composition as the insulator used as electrical insulation.

The three insulated conductors 252 shown in FIGS. 3 and 4 can be coupled to the support member 220 using the centralizer 222. Alternatively, the insulated conductor 252 can be secured directly to the support member 220 using a metal strap. The centralizer 222 can maintain the position of the insulated conductor 252 in the support member 220 and / or suppress the movement. The centralizer 222 can be made of metal, ceramic, or a combination thereof. The metal may be stainless steel or any other type of metal that can withstand corrosive and high temperature environments. In some embodiments, the centralizer 222 may be a bent metal strip that is welded to the support member at a spacing of less than approximately 6 meters. The ceramic used for the centralizer 222 may be, but is not limited to, Al ₂ O ₃ , MgO, or other electrical insulator. The centralizer 222 can maintain the position of the insulated conductor 252 on the support member 220 such that the movement of the insulated conductor is suppressed at the operating temperature of the insulated conductor. Further, the insulated conductor 252 may be flexible to some extent so as to withstand expansion of the support member 220 during heating.

  Support member 220, insulated conductor 252, and centralizer 222 can be disposed in hole 238 of hydrocarbon layer 240. Insulated conductor 252 can be connected to lower end conductor joint 224 using low temperature pin 226. The lower end conductor joint 224 can electrically couple each insulated conductor 252 to each other. The bottom conductor joint 224 may comprise a material that is conductive and does not melt at the temperature found in the hole 238. The low temperature pin 226 may be an insulated conductor having an electrical resistance lower than that of the insulated conductor 252.

  The lead-in conductor 228 can be connected to the wellhead 242 to supply power to the insulated conductor 252. The lead conductor 228 can be made of a conductor having a relatively low electrical resistance so that heat from the current passing through the lead conductor is relatively low. In some embodiments, the lead-in conductor is a copper strand that is insulated with rubber or polymer. In some embodiments, the lead-in conductor is an inorganic insulating conductor having a copper core. The lead conductor 228 can be connected to the wellhead 242 of the surface 250 by a seal flange located between the topsoil 246 and the surface 250. The seal flange can prevent fluid escape from the hole 238 to the surface 250.

  In certain embodiments, the lead conductor 228 is connected to the insulated conductor 252 using the tether conductor 230. The connecting conductor 230 may be a portion where the resistance of the insulated conductor 252 is low. The connecting conductor 230 can be referred to as a “cold pin” of the insulated conductor 252. The tether conductor 230 can be designed to have an output dissipation per unit length of about 1/10 to about 1/5 compared to the dissipation in unit length of the main heated portion of the insulated conductor 252. . The tether 230 may typically be between about 1.5 m and about 15 m, but should use shorter or longer lengths to meet the needs of individual applications. Is also possible. In one embodiment, the conductor of the connecting conductor 230 is copper. The electrical insulator of the connecting conductor 230 may be the same type as the electrical insulator used for the main heating part. The jacket of the connecting conductor 230 can be made of a corrosion resistant material.

  In certain embodiments, the tether conductor 230 is connected to the lead conductor 228 by a splice or other coupling joint. A splice can also be used to connect the tether conductor 230 to the insulated conductor 252. The splice must withstand a temperature approaching the target region operating temperature (eg, a temperature equal to half the target region operating temperature) depending on the number of conductors in the hole and whether the splices are staggered. The density of electrical insulation in the splice often has to be high enough to withstand the required temperature and operating voltage.

  In some embodiments, packing material 248 is disposed between topsoil casing 244 and hole 238, as shown in FIG. In some embodiments, the topsoil casing 244 can be secured to the topsoil 246 by the reinforcing material 232. The packing material 248 can inhibit the outflow of fluid from the hole 238 to the surface 250. Reinforcing material 232 can include, for example, Class G or Class H Portland cement, slag or silica powder, and / or mixtures thereof mixed with silica powder for improved high temperature performance. In some embodiments, the reinforcing material 232 extends radially by a width of about 5 cm to about 25 cm.

  As shown in FIGS. 3 and 4, the support member 220 and the lead-in conductor 228 can be connected to the wellhead 242 at the formation surface 250. A surface conductor 234 can be coupled to the wellhead 242 surrounding the reinforcing material 232. Some embodiments of surface conductors can extend into the formation holes to a depth of about 3 m to about 515 m. Alternatively, the surface conductor can be extended into the formation to a depth of about 9 m. Current can be supplied from the power source to the insulated conductor 252 and heat can be generated by the electrical resistance of the insulated conductor. Heat generated from the three insulated conductors 252 can be conducted through the holes 238 to heat at least a portion of the hydrocarbon layer 240.

  The heat generated by the insulated conductor 252 can heat at least a portion of the hydrocarbon-containing layer. In some embodiments, heat is transferred to the formation by radiation of the substantially generated heat to the formation. Some heat can be transferred by heat conduction or convection by the gas present in the hole. The hole may be an unopened hole as shown in FIGS. Unenclosed holes eliminate the cost of cement thermal fixation to the heater formation, the cost of the casing, and / or the cost of packing the heater into the hole. Furthermore, because heat transfer by radiation is typically more efficient than heat transfer, the heater can be operated at a lower temperature in open drill holes. Heat transfer by conduction during the initial operation of the heat source can be enhanced by adding gas to the holes. The gas can be maintained at a pressure of up to about 27 bar (absolute pressure). The gas can include, but is not limited to, carbon dioxide and / or helium. The open borehole insulated conductor heater is advantageously free to expand or contract to accommodate thermal expansion and contraction. The insulated conductor heater may conveniently be removed from an open drilling hole or repositioned.

  In certain embodiments, the insulated conductor heater assembly is installed or removed using a spool assembly. More than one spool assembly can be used to install the insulated conductor and the support member simultaneously. Alternatively, the support member can be installed using a coiled tubing unit. When the support is inserted into the hole, the heater can be unwound from the spool and connected to the support. An electric heater and support member can be unwound from the spool assembly. Spacers can be combined with the support member and heater along the length of the support member. Additional spool assemblies can be used for additional electric heater elements.

  The temperature limited heater may be configurable and / or may comprise materials that provide automatic temperature limiting characteristics to the heater at a specific temperature. In certain embodiments, a ferromagnetic material is used in the temperature limited heater. Ferromagnetic materials limit themselves at or near the Curie temperature and / or phase transformation temperature range of the material, reducing the amount of heat that is generated when a time-varying current is applied to the material. In certain embodiments, the ferromagnetic material limits the temperature of the temperature limited heater itself at a predetermined temperature that is approximately at the Curie temperature and / or in the phase transformation temperature range. In certain embodiments, the predetermined temperature is within the Curie temperature and / or phase transformation temperature range of about 35 ° C, within the range of about 25 ° C, within the range of about 20 ° C, or within the range of about 10 ° C. It is. In certain embodiments, the ferromagnet may have other materials (eg, highly conductive materials, high strength materials, corrosion resistant materials, or the like to provide various electrical and / or mechanical properties. A combination of these). Some portions of the temperature limited heater may have a lower resistance (due to shape differences and / or the use of different ferromagnetic and / or non-ferromagnetic materials) than other portions of the temperature limited heater. Each portion of the temperature limited heater can be of various materials and / or dimensions so that the heat output from each portion of the heater can be tailored as desired.

  Temperature limited heaters can have higher reliability than other heaters. Temperature limited heaters can reduce the tendency for destruction or failure due to hot spots in the formation. In some embodiments, the temperature limited heater allows for substantially uniform heating of the formation. In some embodiments, the temperature limited heater can heat the formation more efficiently by operating at a higher average heat output for the entire length of the heater. Temperature limited heaters, when the temperature at any point in the heater exceeds, or is about to exceed, the maximum operating temperature of the heater, like the typical constant wattage heater, Operating at higher average heat output for the entire length of the heater. In temperature limited heaters, the heat output from the heater's near Curie temperature and / or phase transformation temperature range is automatically reduced without the need for controlled adjustment of the time-varying current applied to the heater. To do. The automatic decrease in heat output is due to changes in the electrical properties (eg, electrical resistance) of each part of the temperature limited heater. Thus, temperature limited heaters provide more power in more parts of the heating process.

  In certain embodiments, when the temperature limited heater is driven by a time-varying current, the system including the temperature limited heater first provides a first heat output and then the Curie temperature of the electrical resistance portion of the heater. And / or at a temperature near, above or above the phase transformation temperature range, resulting in a reduced heat output (second heat output). The first heat output is the heat output at a temperature below the temperature at which the temperature limited heater starts automatic limiting. In some embodiments, the first heat output is below the Curie temperature and / or phase transformation temperature range of the ferromagnet in the temperature limited heater at about 50 ° C., about 75 ° C., about 100 ° C., or Heat output at a temperature of about 125 ° C.

  The temperature limited heater can be driven by a time-varying current (alternating current or modulated direct current) supplied at the wellhead. The wellhead may include other components (eg, modulation components, transformers, and / or capacitors) used to provide power to the power source and temperature limited heater. The temperature limited heater may be one of a number of heaters used to heat a portion of the formation.

  In some embodiments, the relatively thin conductive layer is responsible for the majority of the thermal output due to the electrical resistance of the temperature limited heater at temperatures up to or near the Curie temperature of the ferromagnetic conductor and / or the phase transformation temperature range. Used to bring Such a temperature limited heater can be used as a heating member in an insulated conductor heater. The heating member of the insulated conductor heater can be disposed inside the sheath with an insulating layer between the sheath and the heating member.

  5A and 5B show cross-sectional views of an embodiment of an insulated conductor heater including a temperature limiting heater as a heating member. The insulated conductor 252 includes a core 218, a ferromagnetic conductor 236, an inner conductor 212, an electrical insulator 214, and a jacket 216. The core 218 is a copper core. The ferromagnetic conductor 236 is, for example, iron or an iron alloy.

The inner conductor 212 is a relatively thin conductive layer made of a non-ferromagnetic material having a higher conductivity than the ferromagnetic conductor 236. In certain embodiments, the inner conductor 212 is copper. The inner conductor 212 may be a copper alloy. Copper alloys typically have a flatter resistance transition over temperature than pure copper. A more flat transition of resistance with respect to temperature can reduce the change in heat output as a function of temperature down to the Curie temperature and / or phase transformation temperature range. In some embodiments, the inner conductor 212 is copper (eg, CuNi ₆ or LOHM (TM)) with 6 wt% nickel. In some embodiments, the inner conductor 212 is a CuNi ₁₀ Fe ₁ Mn alloy. Below the Curie temperature and / or phase transformation temperature range of the ferromagnetic conductor 236, the magnetic properties of the ferromagnetic conductor limit the majority of the current flow to the inner conductor 212. Thus, below the Curie temperature and / or the phase transformation temperature range, the inner conductor 212 provides the majority of the heat output due to the resistance of the insulated conductor 252.

In certain embodiments, the inner conductor 212, along with the core 218 and the ferromagnetic conductor 236, are dimensioned such that the inner conductor provides the desired amount of heat output and the desired turndown ratio. For example, the inner conductor 212 can have a cross-sectional area that is about one-half or one-third of the cross-sectional area of the core 218. Typically, the inner conductor 212 must have a relatively small cross-sectional area to provide the desired heat output when the inner conductor is copper or a copper alloy. In one embodiment having a copper inner conductor 212, the core 218 has a diameter of 0.66 cm, the ferromagnetic conductor 236 has an outer diameter of 0.91 cm, and the inner conductor 212 has 1 0.03 cm outer diameter, electrical insulator 214 has an outer diameter of 1.53 cm, and jacket 216 has an outer diameter of 1.79 cm. In one embodiment having a CuNi ₆ inner conductor 212, the core 218 has a diameter of 0.66 cm, the ferromagnetic conductor 236 has an outer diameter of 0.91 cm, and the inner conductor 212 has The outer diameter of 1.12 cm, the electrical insulator 214 has an outer diameter of 1.63 cm, and the jacket 216 has an outer diameter of 1.88 cm. Such insulated conductors are typically smaller and less expensive than insulated conductors that do not use a thin inner conductor to provide the majority of the thermal output below the Curie temperature and / or phase transformation temperature range. Can be manufactured.

  The electrical insulator 214 may be magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or a combination thereof. In certain embodiments, the electrical insulator 214 is a compressed magnesium oxide powder. In some embodiments, the electrical insulator 214 comprises silicon nitride beads.

  In certain embodiments, a thin material layer is disposed between the electrical insulator 214 and the inner conductor 212 to prevent migration of copper to the electrical insulator at higher temperatures. For example, a thin nickel layer (eg, about 0.5 mm nickel) can be disposed between the electrical insulator 214 and the inner conductor 212.

  Jacket 216 is made of a corrosion resistant material such as, but not limited to, 347 stainless steel, 347H stainless steel, 446 stainless steel, or 825 stainless steel. In some embodiments, the jacket 216 provides a degree of mechanical strength to the insulated conductor 252 at or above the Curie temperature and / or phase transformation temperature range of the ferromagnetic conductor 236. In certain embodiments, the jacket 216 is not used to conduct current.

  In certain embodiments, the semiconductor layer is disposed outside the core of the insulated conductor heater. The semiconductor layer can at least partially surround the core. The semiconductor layer can be placed adjacent to the core (between the core and the insulating layer (electrical insulator)), or the semiconductor layer can be located in the insulating layer. By arranging the semiconductor layer outside the core in the insulated conductor heater, the fluctuation of the electric field in the heater can be reduced and / or the electric field strength in the heater can be reduced. Thus, a higher voltage is applied to the insulated conductor heater with the semiconductor layer, but the same maximum electric field strength achieved between the core and the sheath is achieved with the lower voltage applied to the insulated conductor heater without the semiconductor layer. . Alternatively, when the two heaters are operated at the same voltage, the maximum electric field strength is lower in an insulated conductor heater having a semiconductor layer.

FIG. 6 illustrates an embodiment of an insulated conductor 252 in which the semiconductor layer 254 is adjacent to the core 218 (at the surface of the core) and surrounds the core 218. The insulated conductor 252 may be an insulated conductor heater that provides thermal output due to resistance. Electrical insulator 214 and jacket (sheath) 216 surround semiconductor layer 254 and core 218. FIG. 7 illustrates an embodiment of an insulated conductor 252 having a semiconductor layer 254 located inside the electrical insulator 214 and surrounding the core 218. The semiconductor layer 254 may be, for example, BaTiO ₃ or other suitable semiconductor material (including but not limited to Ba _x Sr _1-x TiO ₃ , CaCu ₃ (TiO ₃ ) ₄ , or La ₂ Ba ₂ CaZn ₂ Ti ₃ O ₄ , etc.). In certain embodiments, the core 218 is copper or a copper alloy (eg, a copper-nickel alloy), the electrical insulator 214 is magnesium oxide, and the jacket 216 is stainless steel.

  The semiconductor layer 254 reduces the electric field strength outside the core 218. Further, by surrounding the core 218 with the semiconductor layer 254, variation in electric field strength due to defects or irregularities on the surface of the core can be reduced or reduced. Reduction of electric field strength and / or reduction of variation in electric field strength can reduce stress on the electrical insulator 214, reduce the potential for electrical breakdown of the electrical insulator, and extend the operating life of the heater.

  In certain embodiments, the semiconductor layer 254 has a dielectric constant greater than that of the electrical insulator 214. In certain embodiments, the electric field strength around the core is minimized by optimizing the dielectric constant of the semiconductor layer and the thickness of the semiconductor layer. To optimize the effect on the electric field, the dielectric constant of the semiconductor layer 254 and / or the electrical insulator 214 can be graded (varied with radial distance from the central axis of the core 218). In some embodiments, multiple layers (semiconductor layers or electrical insulator layers) each having a different dielectric constant can be used to provide the desired gradient.

  For long and vertical temperature limited heaters (eg, heaters with a length of at least 300 mm, at least 500 m, or at least 1 km), the hanging stress is important in selecting the material for the temperature limited heater. If the choice of material is not appropriate, the support member may not have sufficient mechanical strength (eg, creep rupture strength) to support the weight of the temperature limited heater at the heater operating temperature.

  In certain embodiments, the material of the support member is modified to increase the maximum allowable suspension stress at the operating temperature of the temperature limited heater and thus increase the maximum operating temperature of the temperature limited heater. Changing the material of the support member will affect the thermal output of the temperature limited heater below the Curie temperature and / or the phase transformation temperature range because the change in resistance will change with the temperature of the support member due to the material change. Effect. In certain embodiments, the temperature limited heater supports the heater while maintaining the desired operating characteristics as much as possible (eg, resistance transition with temperature below the Curie temperature and / or phase transformation temperature range). The support member is made of two or more materials along the entire length of the heater so as to provide sufficient mechanical properties to achieve. In some embodiments, tethered sections are used between each section of the heater to provide an intensity that compensates for temperature differences between the individual sections of the heater. In certain embodiments, one or more portions of the temperature limited heater have outer diameters and / or materials that change to provide the desired characteristics to the heater.

  Some non-limiting examples are described below.

Example of Semiconductor Layer in Insulated Conductor A simulation called COMSOL (R) was used to evaluate the influence of the use of the semiconductor layer in an insulated conductor heater such as the insulated conductor heater shown in FIGS. 6 and 7 on the electric field. In the first simulation, the irregular surface (undulated core surface) of the nickel-copper core is the surface of the core (as shown in FIG. 6) or of the magnesium oxide electrical insulator (as shown in FIG. 7). The electric field component was calculated for the insulated conductor heater surrounded by the BaTiO ₃ semiconductor layer located inside. The electric field components were calculated for the basic case without any semiconductor layer.

  FIG. 8 shows the vertical component (V / m) of the electric field as a function of position (m) along the length of the heater. Curve 256 shows the electric field in the basic case. A curve 258 shows the electric field when the semiconductor layer is located on the surface. Curve 260 shows the electric field when the semiconductor layer is located in an electrical insulator. As shown in FIG. 8, it is best to reduce the variation in the electric field strength caused by the irregular (wavy) surface of the core (the change in the vertical component of the electric field is minimized). It is.

In the second simulation, the surface of the nickel copper core with defects (core surface depressions) is the surface of the core (as shown in FIG. 6) or of the magnesium oxide electrical insulator (as shown in FIG. 7). The electric field strength was calculated for the insulated conductor heater surrounded by the BaTiO ₃ semiconductor layer located inside. The field strength was calculated for the basic case without any semiconductor layers.

  FIG. 9 shows the electric field strength (V / m) with respect to the distance (m) from the core. Curve 262 shows the electric field strength in the basic case. A curve 264 indicates the electric field strength when the semiconductor layer is located on the surface. Curve 266 shows the electric field strength when the semiconductor layer is located in the electrical insulator. As shown in FIG. 9, when the semiconductor layer is located on the surface (curve 264), the electric field strength near the core is reduced.

  Using the analytical calculation, the electrical characteristics and the effectiveness of the semiconductor layer were evaluated for the insulated conductor heater as shown in FIG. FIG. 10 shows the ratio of the dielectric constant ratio between the electrical insulator and the semiconductor layer (dielectric constant of the electrical insulator / dielectric constant of the semiconductor layer) to the maximum electric field strength when there is no shielding (no semiconductor layer) (left side). And the normalized semiconductor layer thickness (right axis). As shown in FIG. 10, for a given dielectric constant ratio (shown by a vertical arrow), it corresponds to the thickness of the semiconductor layer that minimizes the maximum electric field strength.

  FIG. 11 is for a semiconductor layer that is one-third the thickness of an electrical insulator, and for several dielectric constant ratios, the electric field strength (V / inch) versus the distance from the core (normalized). It shows. A curve 268 shows the electric field strength when the dielectric constant ratio is 0.1. Curve 270 shows the electric field strength when the dielectric constant ratio is 0.5. A curve 272 shows the electric field strength when the dielectric constant ratio is 0.676. A curve 274 indicates the electric field strength when the dielectric constant ratio is 0.8. Curve 276 shows the electric field strength for an insulated conductor heater having no semiconductor layer (dielectric strength ratio is 1). As shown in FIG. 11, the maximum electric field strength between the core and the jacket (sheath) is the smallest when the dielectric constant ratio is 0.676 (curve 272).

  It should be understood that the present invention is not limited to the particular systems described herein, which can, of course, vary. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, the singular forms “a”, “an”, and “the” include the case where there are two or more references unless the context clearly indicates otherwise. Thus, for example, “a core” includes a combination of two or more cores, and “a material” includes a mixture of materials.

  Further modifications and alternative embodiments of the various aspects of the invention will be apparent to those skilled in the art in view of this specification. 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 should be understood that the form of the invention shown and described herein is to be construed as the presently preferred embodiment. The components and materials illustrated and described herein can be replaced, parts and processes can be reversed, and certain features of the invention can be utilized independently, Both will be apparent to those skilled in the art who have the benefit of this description of the invention. Changes may be made in the components described herein without departing from the spirit and scope of the invention as described in the following claims.

  It is to be understood that each of the claims features described below can be combined with features from other claims or can be separated from features from other claims. For example, the features of two or more dependent claims can be combined to form a complex dependent claim.

Claims (22)

A heater configured to heat an underground formation,
An electrical conductor;
A semiconductor layer at least partially surrounding the electrical conductor;
An insulating layer at least partially surrounding the electrical conductor;
A heater comprising: a conductive sheath at least partially surrounding the insulating layer.   The heater according to claim 1, wherein the semiconductor layer is located inside the insulating layer.   The heater of claim 1, wherein the semiconductor layer is at least partially surrounded by an insulating layer.   The heater of claim 1, wherein the insulating layer at least partially surrounds the semiconductor layer.   The heater of claim 1, wherein the semiconductor layer is configured to reduce an electric field in the electrical conductor in use.   The heater of claim 1, wherein the semiconductor layer is configured to reduce electrical stress in the insulating layer during use.   The heater according to claim 1, wherein the insulating layer contains magnesium oxide.   The heater according to claim 1, wherein the semiconductor layer has a dielectric constant higher than that of the insulating layer.   The heater according to claim 1, wherein the semiconductor layer includes a plurality of semiconductor layers having different dielectric constants.   The heater of claim 1, wherein the semiconductor layer has a dielectric constant that varies with a radial distance from the central axis of the electrical conductor.   The heater according to claim 1, further comprising a further semiconductor layer located on a side of the insulating layer opposite to the semiconductor layer.   The heater of claim 1, wherein the heater is configured to provide a resistive heat output to heat at least a portion of the underground formation.   The heater according to claim 1, wherein the heater is disposed in a hole of a hydrocarbon-containing layer in an underground formation.   2. Located in a hydrocarbon-containing layer in an underground formation and configured to heat at least a portion of the underground formation to provide a thermal output due to resistance to fluidize the hydrocarbon in the formation. The heater described in 1.   2. Located in a hydrocarbon-bearing layer in an underground formation and configured to heat at least a portion of the underground formation to provide a thermal output due to resistance to pyrolyze hydrocarbons in the layer. The heater described in 1. A method for heating an underground formation,
Disposed at least partially in a hole in the hydrocarbon-containing layer extending from the surface of the formation through the topsoil portion of the formation to the hydrocarbon-containing layer of the formation;
An electrical conductor;
A semiconductor layer at least partially surrounding the electrical conductor;
An insulating layer at least partially surrounding the electrical conductor;
Providing heat from a heater comprising a conductive sheath at least partially surrounding the insulating layer to at least a portion of the hydrocarbon-containing layer of the formation;
Fluidizing at least some of the hydrocarbons in the formation by transfer of heat to the formation;
Producing at least a portion of the fluidized hydrocarbon from the formation.   The method of claim 16, wherein the semiconductor layer is located inside the insulating layer.   The method of claim 16, wherein the semiconductor layer is at least partially surrounded by an insulating layer.   The method of claim 16, wherein the insulating layer at least partially surrounds the semiconductor layer.   The method of claim 16, wherein the semiconductor layer has a higher dielectric constant than the insulating layer.   The method of claim 16, wherein the semiconductor layer has a dielectric constant that varies with radial distance from the central axis of the electrical conductor. A heater configured to heat an underground formation,
An electrical conductor;
A semiconductor layer;
An insulating layer;
A heater comprising a conductive sheath.

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